D R I L L I N G
OFFICIAL MAGAZINE OF THE
INTERNATIONAL ASSOCIATION OF DRILLING CONTRACTORS
Drilling
C O N T R A C T O R M AY / J U N E 2 0 1 2
W W W. D R I L L I N G C O N T R A C T O R . O R G
CONTRACTOR W W W. D R I L L I N G C O N T R A C T O R . O R G
Offshore& ShaleReport
Liquids-rich shale plays, deepwater exploration poised to push industry to new heights
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Security programs must incorporate terrorism prevention, crisis management
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CONTENTS OFFICIAL MAGAZINE OF THE INTERNATIONAL ASSOCIATION OF DRILLING CONTRACTORS
Well Control
Tactical Technology™ in action:
W W W. D R I L L I N G C O N T R A C T O R . O R G SM
Onshore Drilling
22 The great migration to wet plays Liquids-rich US shales shine as industry sweet spot B Y KA T IE M A ZEROV, C ONT RI B U T I NG EDI T OR
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Analyst: Numbers show that US is drilling its way to zero net oil imports
Gain a sense of security with Weatherford’s expanded range of services that minimize risk and optimize life-of-well performance. Personnel and asset protection XJUI UIF JOEVTUSZnT üSTU "1* 3$% DFSUJüFE SPUBUJOH DPOUSPM EFWJDF
BY KATH E RINE S COTT, ED I TORI AL C OORD I NATOR
38 The water challenge Innovative solutions emerge to address one of hydraulic fracturing’s most critical concerns B Y KA T IE M A ZEROV, C ONT RI B U T I NG EDI T OR
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Secure Drilling Services
Well depth extended in geothermal project using controlled pressure drilling BY E S S AM S AMMA T, STEPHEN O’ SHEA, GARETH I NNES, WE ATH E RF O RD U K ; JULI O K EMENY FY , D ARK O PI SC EV I C , G E O E NE RG IE BAYERN
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Detection and management with BEWBODFE LJDL MPTT JEFOUJĂĽDBUJPO BOE QSFTTVSF NBOBHFNFOU TZTUFNT Reservoir evaluation UP PCUBJO SFTFSWPJS EBUB UIBU ESJWF ESJMMJOH BOE DPNQMFUJPO EFDJTJPOT Performance optimization VTJOH SFTFSWPJS EBUB BOE PUIFS SFTPVSDFT GPS PQUJNVN MJGF PG XFMM QFSGPSNBODF
Onshore MPD system enables lower mud weights for challenging wells BY J. MO NTILVA, J. MOTA, R. BI LLA, SHELL EXPLORATI ON & P RO DU CTIO N CO MPANY
Offshore Activities & Outlook
70 Global deepwater exploration
sustains strong rig activity
Emerging East African markets add to strength of Golden Triangle B Y J E R R Y G R E ENB ERG, C ONT R I BU T I NG EDI T OR
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80 Navigating safe waters Industry takes proactive approach to safety while anticipating GOM ramp-up B Y KA T IE M A Z E ROV, C ONT RI B U T I NG EDI T OR
COVER: Things in the drilling industry are looking up – for both the offshore and land segments of the business. Onshore, the US shale boom pushes on despite low natural gas prices, and the great migration to liquids-rich shale plays continues. Offshore, deepwater exploration is driving strong rig demand around the world. Even in the US Gulf of Mexico, signs point to a strong recovery. See our shale report beginning on p22 and our offshore report beginning on p70. Photos courtesy of Nabors and Statoil/Heine Melkevik.
D R I L L I N G CONTRACTOR
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Find out how to change to the secure way to drill—a better way to drill.
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A L L D R Well Control
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Drilling C O N T R A C T O R OFFICIAL MAGAZINE OF THE INTERNATIONAL ASSOCIATION OF DRILLING CONTRACTORS
M AY / J U N E 2 0 1 2 VOL. 68, NO. 3 W W W. D R I L L I N G C O N T R A C T O R . O R G
Offshore Activities & Outlook 90
Dashboard concept aims to facilitate diagnostics, decision-making on BOPs B Y J I M MCKAY, ALLE N P E RE , BP ; CLAY TON SI MMONS, MI K E D OTY , NAT I ONAL O ILWE LL VARCO ; TO NY H O GG, ENSC O; GAV I N STARLI NG, R O C K O ILF IE LD G RO U P
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Reentry campaign gives first-round subsea fields second chance to produce B Y S E AN S TRIG H T, NE LS O N TE ARS , G REGORY K I NG, EXXONMOBI L DE VE LO P ME NT CO MP ANY; VIKAS S RIV ASTAV A, D AV I D W. SMI TH, E XXO NMO BIL U P S TRE AM RE S E ARCH COMPANY
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Completions: Sand Control
110 Refining the grip on nature’s fine grains Complementary tools, approaches enhance tried-and-true sand control methods B Y J O A N N E L IO U , E DIT O R IA L COORDI NAT OR
Regional Focus: Asia Pacific 120 Stable market pushes Asia Pacific rig demand B Y J E RE MY CRE S S WE LL, CO NTRIBU TING ED I TOR
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126 Legal trends shape Asia Pacific contracts B Y DE NYS H ICKE Y AND RO BIN ACWO RTH, I NC E & C O SI NGAPORE
Contracts & Risk Management 130
Drilling contracts evolve with industry expansion, legislative, judicial trends B Y C ARY A. MO O MJIAN JR., CAM O ILSERV AD V I SORS
Drilling Optimization 140
Drilling optimization culture built on real-time data, communication B Y A UG U S TO BO RE LLA H O U G AZ, DANI LO S. GOZZI , I SAO FUJI SHI MA, K LAUS L . VE LLO , P E TRO BRAS ; S ANDRO ALVE S , I AN THOMSON, RAUL K RASUK , F R A N K BU ZZE RIO , BAKE R H U G H E S Some articles now feature QR codes to access web-exclusive, enhanced editorial on DrillingContractor.org. Scan the codes using your smartphone.
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Liked an article? Disliked one? We want to know what you think of our magazine. Is there a topic you’d like us to cover? Let us know. Please include your full name, company, address and phone number. Send e-mails to editor@iadc.org or send letters to: 10370 Richmond Ave, Suite 760 • Houston, TX 77042 USA
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DRILLING CONTRACTOR WANTS TO HEAR FROM YOU
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Well Control
CONTENTS
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Education & Training
Find out why we are SUPERIOR
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Houston programs provide industry edge BY JOANNE LI OU AND K ATHERI NE SC OTT, ED I TORI AL C OORD I NATORS
IADC Connection 150
From the President: Sparking performance improvement BY STEPHEN C OLV I LLE, I AD C PRESI D ENT
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News Cuttings
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Wirelines
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Conference Calendar
Departments 9
Drilling Ahead – Are we laggards in technology adoption? BY MI K E K I LLALEA, ED I TOR & PUBLI SHER
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D&C News
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D&C Tech Digest
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HSE&T Corner: Security programs must incorporate terrorism prevention, crisis management BY JI M THATC HER, ENC ANA
- API, NS1, DS1, IRP - Prompt delivery
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People, Companies & Products
- Extensive inventory
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Advertisers Index
- Competitive pricing
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Perspectives: Goran Andersson, Chevron – Experiential training is the way forward
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BY K ATHERI NE SC OTT, ED I TORI AL C OORD I NATOR
DRILLING CONTRACTOR MAY/JUNE 2012 VOL. 68, NO. 3
DRILLING CONTRACTOR is the official magazine of the International Association of Drilling Contractors (IADC) and is a wholly owned publication of IADC, which is also the publisher of the Annual IADC Membership Directory. DRILLING CONTRACTOR also represents the Drilling Engineering Association (DEA). DRILLING CONTRACTOR strives to ensure that the articles and information it publishes are accurate and reliable. However, DC cannot warranty the information provided in its editorial content, and publication in DC is not a guarantee that the material presented is accurate. DC wants to hear from its readers. Our editors welcome your comments. We hope you will enjoy and benefit from DC’s editorial. However, should you wish to complain, please contact the publisher. Our complaint policy is posted at www.drillingcontractor.org. DRILLING CONTRACTOR (ISSN 0046-0702) is issued six times per year by the International Association of Drilling Contractors. Subscriptions are free to operational personnel employed by contract-drilling firms or by major or independent oil companies. Subscription prices are $110 per year, US; $180, outside the US. Publisher reserves the right to refuse non-qualified subscriptions. For advertising rates or information, call DRILLING CONTRACTOR or our representatives worldwide Atlantic Communications, or check our website at www.drillingcontractor.org. Postmaster: Please send address changes to DRILLING CONTRACTOR magazine, Box 4287, Houston, TX, 77210. © 2012 Drilling Contractor. All rights reserved. Printed in the USA.
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PUBLISHED BY International Association of Drilling Contractors 10370 Richmond Ave., Suite 760 Houston, TX 77042 USA +1 713 292 1945; fax, +1 713 292 1946 drilling.contractor@iadc.org • www.drillingcontractor.org IADC OFFICERS Chairman Dan Rabun Vice Chairman David Williams Secretary-Treasurer Scott Daniels Vice President, Land Ronnie Witherspoon Vice President, Offshore Thomas Burke Vice President, Drilling & Well Services David Reid President Stephen A Colville Executive Vice President-Government Affairs Brian T Petty EDITORIAL CONTRIBUTORS Group Vice President & Publisher Mike Killalea Managing Editor Linda Hsieh Contributing Editors Katie Mazerov, Jerry Greenberg, Jeremy Cresswell Creative Director Brian Parks Editorial Coordinators Joanne Liou, Katherine Scott Middle East/African Affairs Dave Geer European Affairs Jens Hoffmark HSE, Land Affairs Joe Hurt, Paul Breaux Asian Affairs Chit Hlaing Accreditation Programs Steve Kropla, Mark Denkowski, Brenda Kelly Offshore Affairs Alan Spackman, John Pertgen
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Drilling Ahead
Departments
Are we laggards in technology adoption? BY MIKE KILLALEA, EDITOR & PUBLISHER
W
e pride ourselves on innovation, but are actually laggards at technology adoption. “The oil and gas industry tends to have a technology adoption cycle of roughly 30 years from concept to 50% market penetration,” remarked Dustin Torkay, Seadrill, IADC Advanced Rig Technology (ART) Committee vice chairman-Future Technology, adding that this is an eightyear process in the medical industry. Mr Torkay is the driving force behind our 12 June ART Workshop on technology adoption. The afternoon workshop will convene in Barcelona the day before IADC World Drilling 2012. (See link below.) Tom Bates, Lime Rock Partners, an ART workshop panelist, agrees that the pace of technology adoption is “painfully slow.” Mr Bates should know. His long career prior to joining investment firm Lime Rock as a managing director began with Shell and includes leadership positions at Baker Hughes, Weatherford Enterra and Schlumberger. “There is almost an order of magnitude difference from other industries,” he said. “It’s a bit of a conundrum, (because) overall, our industry is not risk averse.”
STAGNATION GENERATION One case in point is stagnation in directional MWD, which, according to sponsors of a new Drilling Engineering Association joint industry project (JIP), has not appreciably advanced in a generation. Now, before MWD partisans rouse to Check out the full program for the IADC ART Workshop on 12 June in Barcelona.
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churn out indignant emails championing their companies’ achievements, let me stress that MWD overall has seen many advances. But, according to the DEA JIP sponsors, the process for directional MWD has barely budged in 30 years. “The perception is that it’s good enough, because we are able to get to the production target,” said Robert Estes, Baker Hughes, which, along with ConocoPhillips and Bench Tree Group, are current sponsors. The need for more precise directional MWD is pressing, Mr Estes says. A nextgeneration MWD tool drilling a relief well could reduce time to intersection and enhance accuracy. For infill drilling amid a spider’s web of directional wells, avoiding collision through pinpoint placement might prevent a blowout. For steam-assisted gravity-drainage wells, more precision can maximize production by optimizing well placement. The organizers are seeking another seven or so JIP participants, at about $30,000 each. (See link below for more on the JIP.)
DRAGGING INNOVATION The question remains. Why does innovation drag? ART workshop participant Jan Brakel, manager for wells R&D with Shell, suspects that with activity booming, the status quo suits most. “Is there a need to innovate?” he asks, though he himself is a strong proponent of change. He points out that, rig newbuilding notwithstanding, a plethora of ancient
IADC World Drilling 2012, Barcelona, 13-14 June
equipment still keeps turning to the right. “In general, as a drilling industry we have a significant catch-up opportunity in terms of technology,” Mr Brakel said.
BUSINESS UNITS LIMIT VISION Mr Bates suggests that innovation began to flag when major oil companies switched to the business unit model. “Business units are great for giving objectives and giving senior manager accountability for results,” he said. On the other hand, a business-unit leader’s focus on that narrow bottom line is hardly an incentive to try something new, expensive and with potentially large downside risk. Independents harbor a more entrepreneurial spirit, Mr Bates noted. “It wasn’t a supermajor that developed the Barnett, with 25 frac jobs and 15,000ft laterals,” he pointed out. A corollary of narrowed vision is a dearth of test sites, he added. “One of the frustrating things for me,” Mr Bates said, “is the inability to get products in the field and tested. That is a real barrier to progress.” Mr Bates urges industry to develop a cooperative means to test promising technologies without jeopardizing wells, thereby helping to move technology forward. “At the end of the day, technology works.” Mike Killalea can be reached via email at mike.killalea@iadc.org.
Complete information about DEA JIP 164 on nextgeneration MWD.
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Departments
Drilling & Completion News
Ensco orders sixth Samsung DP3 drillship for Q3 2014 delivery Ensco has ordered an advancedcapability, ultra-deepwater drillship to be built by Samsung Heavy Industries in Geoje, South Korea. The vessel, ENSCO DS-8, will be the sixth Samsung DP3 drillship in the Ensco fleet. It is scheduled for delivery in Q3 2014. The contract also includes options for two additional drillships of the same design. Consistent with the previous five Samsung ultra-deepwater drillships ordered since 2007, the new unit will
have advanced capabilities to meet the demands of ultra-deepwater drilling in water depths up to 12,000 ft and a total vertical drilling depth of 40,000 ft. New features include retractable thrusters, enhanced safety and environmental features, improved dynamic positioning capabilities and advanced drilling and completion functionality, including below-main-deck riser storage, triple fluid systems, offline conditioning capability and enhanced client and third-party facilities.
Petrobras confirms Tupi Northeast discovery, expands exploration with BP in four blocks Petrobras has confirmed the discovery of oil in the Tupi Northeast, in the Santos Basin pre-salt. The well, 1-BRSA-976-RJS, is northeast of the Lula field, at a water depth of 2,131 meters and 255 km off the coast of Rio de Janeiro. The discovery was confirmed by 26° API oil samples, collected from 4,960 meters. An oil column with more than 290 meters in thickness has been identified in the pre-salt carbonate reservoirs. Petrobras also has a floating, production, storage and offloading vessel, BW Cidade de São Vicente, in
the Iracema area (Block BM-S-11) of the Santos Basin. The platform was connected to well RJS-647 at a water depth of 2,212 meters. The platform will operate for about six months to gather data on the behavior of the reservoirs and the oil flow in the subsea lines. The information will support the development of the final production system, expected to start operations at the end of 2014. In exploration, BP has been approved to explore four blocks with Petrobras: BM-BAR-3 and BM-BAR-5 in the Barreirinhas basin and BM-CE-1 and BM-CE-2 in the Ceará Basin.
ONRR bills $4 million for BSEE rig inspections The US Office of Natural Resources Revenue (ONRR) has billed a total of $4,091,100 for the inspection of drilling rigs in Q1 of fiscal year (FY) 2012, specifically billing $1,397,100 in October 2011, $1,447,200 in November and $1,246,800 in December. An estimated 111 oil and gas operating companies were retroactively billed by ONRR in January 2012 after the agency received the authority to do so from Congress. According to the Bureau of Safety and Environmental Enforcement (BSEE) NTL 2012-N02, lessees and operators have been informed that ONRR will be collecting inspection
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fees on behalf of BSEE, covering all bottom-founded structures, floating production facilities and drilling rigs. The NTL took effect as of 1 October 2011. BSEE’s statistics show that 3,964 rigs on the US Outer Continental Shelf were inspected in Q1 FY12. The average weekly number of rigs and non-rig units conducting well operations was 81 in the Gulf of Mexico and 18 in the Pacific region. The Alaska region currently has one federal/state production operation and no drilling activities. All rigs are inspected on a monthly basis.
Latshaw unveils 1,700-hp diesel-electric/SCR rig Latshaw Drilling Co recently added Rig 18 to its fleet. The rig is a 1,700-hp diesel-electric/SCR rig with a 500-ton AC top drive unit and is skiddable for multiwell pad drilling. The rig recently moved to its first location in New Mexico and will be drilling multiple wells from the same pad, with laterals up to 10,000 ft long. The company is now building Rig 19, a 1,500-hp SCR top drive, skiddable rig with 1,600-hp mud pumps that are rated to 7,500 psi.
Ocean Rig receives Letter of Award for deepwater ship Ocean Rig UDW received a Letter of Award in April for its ultra-deepwater drillship Ocean Rig Olympia from a major oil company. The Letter of Award is for a three-year contract for drilling offshore West Africa. The contract is expected to commence in continuation of the Ocean Rig Olympia’s existing contract in West Africa. With this contract, Ocean Rig does not have any rigs available in 2012. M AY / J U N E 2 0 1 2
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Departments
Drilling & Completion News
Eni starts production offshore Norway, makes discovery in Mozambique Eni started production in April from the Marulk field in the Norwegian offshore, about 80 km from the coast. The Marulk field is the first that Eni has directly operated in Norway and is part of the PL122 license held by Eni (20%) with Statoil (50%) and DONG Energy (30%). Marulk is a gas and condensate field,
Tullow exploratory, appraisal wells strike oil in Kenya Tullow Oil has encountered in excess of 20 meters of net oil pay in its Ngamia-1 exploration well in Kenya. The well, in the Turkana County of Kenya Block 10BB, was drilled to an intermediate depth of 1,041 meters and has been successfully logged and sampled. Movable oil with an API rating of more than 30° has been recovered. The Ngamia structure is the first prospect to be tested as part of a multi-well drilling campaign in Kenya and Ethiopia. In March, Tullow’s Enyenra-4A appraisal well in the Deepwater Tano licence offshore Ghana encountered oil in sandstone reservoirs. The Owo-1 discovery wells and the Enyenra appraisal well confirm the extent of the Enyenra light oil field. Results of drilling, wireline logs, samples of reservoir fluids and pressure data show that Enyenra-4A has intersected 32 meters of net oil pay. Pressure data from the oil leg indicates a continuous oil column of approximately 600 meters.
Talisman Energy finds light oil in Kurdamir-2 well Talisman Energy confirmed the presence of light oil at the Kurdamir-2 well in the Kurdistan Region of northern Iraq in March. The well flowed at unstimulated rates of 7.3 mmcf/d of natural gas and 950 bbls/day of oil and condensate, with no indications of water and no observed decline. The Kurdamir-2 well is a re-drill of the Kurdamir-1 gas/condensate discovery well, 2 km away, which was drilled in 2009 but not completed.
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with estimated reserves of 74.7 million bbls of oil equivalent and produces 20,000 boed. Separately, Eni recently discovered natural gas in Area 4, offshore Mozambique, at the Mamba North East 1 exploration prospect. The results of this well, drilled in the Eastern part of Area 4, increases the resource base of Area 4
by at least 10 trillion cu ft (Tcf). The discovery improves the potential of the Mamba complex in Area 4 offshore Mozambique, now estimated to have at least 40 Tcf of gas in place. Eni plans to drill at least four more wells this year in nearby structures to fully assess the upside potential of the Mamba Complex.
Keppel wins contract to build jackup based on LeTourneau design for Perforadora Central Keppel AmFELS has won a contract from Mexico’s Perforadora Central to build a repeat jackup rig. Slated for delivery in Q1 2014, the latest high-specification unit will be based on the LeTourneau Super 116E design with leg lengths of 511 ft and the capability to drill wells up to 30,000 ft in a water depth of up to 375 ft. Keppel AmFELS completed Tonala, an ultra-premium KFELS B Class jackup rig for Perforadora Central in 2004, followed by Tuxpan, a LeTourneau S116E rig in 2010. Perforadora Central ordered the Papaloapan jackup in March 2011, and it is under construction and on track for delivery in Q1 2013. “We have endured the post-Macondo challenges well,” Tan Geok Seng, president of Keppel AmFELS, said. “Having recently secured the Ocean Onyx semisubmersible major upgrade
and a series of repairs, this newbuild jackup adds to a healthy workload through Q1 2014.”
Apache expands production in Faghur Basin, Egypt
BRS begins to drill its first well in Italy’s Po Valley
Apache Corp recently received approval of seven new development leases in the Faghur Basin, which enables the company to add 5,200 bbl/ day of production in Egypt’s Western Desert. Neilos-2, Apache’s latest Faghur Basin well, test-flowed 6,301 bbls of oil and 4.2 MMcf of gas per day. The well, 0.8 km north from the Neilos-1X discovery, was drilled to appraise the north flank of the Neilos Field and logged 33 ft of net pay in the Jurassic Safa reservoir.
BRS Resources announced in March that drilling has commenced on its first well. Located in Italy’s Po Valley, it is a development well in a partially depleted field where 3D seismic technology was used to identify remaining natural gas reserves. “Using conventional drilling techniques, it will be drilled to a total depth of approximately 6,500 ft (2,000 meters),” Steve Moore, president and CEO of BRS, said. “We have employed state-of-the-art technology to target the reserves and have minimal impact.”
Keppel AmFELS won a contract to build another repeat jackup rig for Perforadora Central.
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Departments
Drilling & Completion News
US Interior Department initiates system to accelerate permits, leases US Secretary of the Interior Ken Salazar recently unveiled initiatives to expedite the development of domestic energy resources on US public lands and Indian trust lands in the Dakotas, Montana and other states. The Bureau of Land Management
(BLM) will implement new automated tracking systems that aim to reduce the review period for drilling permits by two-thirds and to expedite the sale and process of federal oil and gas leases. The system will track permit applications through the review process and
flag missing or incomplete information to reduce the back-and-forth between BLM and industry applicants currently needed to amend paper applications. BLM expects to process 5,500 applications for permits to drill in fiscal year 2012.
Anadarko encounters natural gas in Mozambique
Helix Well Ops UK’s Well Enhancer mono-hull intervention vessel has completed West Africa’s first well intervention campaign.
Helix completes West African intervention campaign
Anadarko Petroleum’s Barquentine-4 appraisal well proved successful offshore Mozambique, the company said in April. The well in Offshore Area 1 of the Rovuma Basin encountered approximately 525 net ft (160 meters) of natural gas pay and became the Anadarko partnership’s ninth successful well in the complex. In March, the company achieved oil production at the Caesar/Tonga development in the Green Canyon area of the deepwater Gulf of Mexico. Production from Caesar/Tonga, with an estimated resource base of 200 million to 400 million bbls of oil equivalent, is expected to ramp up to approximately 45,000 boed from the first three subsea wells.
Helix Well Ops UK has completed a three-month campaign for West Africa’s first well intervention work and subsea well operations conducted from a monohull intervention vessel. Operating the 132-meter (433-ft) long Well Enhancer, Helix performed a subsea tree change-out, well suspensions, well maintenance and production enhancement on seven wells in water depths up to 471 meters (1,545 ft). The project represents the deepest operation conducted from Well Enhancer since it joined the fleet in 2009.
Well Enhancer marks the emergence of mono-hull-based well intervention services in the region. Intervention programs delivered from mono-hull vessels can provide operational and cost benefits to operators. “Because Well Enhancer deploys more quickly than a rig and is designed specifically for well intervention work, she reduces down time and helps operators return as quickly as possible to their business of oil and gas production,” Steve Nairn, Helix Well Ops regional vice president of Europe and Africa, said.
North Atlantic confirms order of harsh-environment semi
BG Group begins first production from the Gaupe
Atwood awarded contract for newbuild jackup
North Atlantic Drilling has entered a turnkey construction contract with Jurong Shipyard in Singapore for the construction of a new harsh-environment semisubmersible drilling rig. The rig will be of a Moss CS60 design, N-Class compliant and be fully winterized.
BG Group has begun production from the Gaupe field in the Norwegian North Sea. With estimated gross recoverable reserves of approximately 30 million bbls of oil equivalent, production from Gaupe is expected to reach a plateau production rate of around 15,000 boed in Q3 this year.
Atwood Oceanics has been awarded a contract by Salamander Energy (Bualuang) for the newbuild jackup Atwood Mako. The award is for a firm duration of 12 months for work offshore Thailand. The rig is under construction with PPL Shipyard in Singapore.
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Departments
Drilling & Completion Tech Digest
Single bit drills intermediate section of Tattoo field A single Ulterra polycrystalline diamond compact bit has drilled the entire intermediate section of the Tattoo field in Northwest Canada. An 8.5-in. (216-mm) U513M drilled both the vertical and build sections with the same bottomhole assembly, saving the operator two trips and $570,000 compared with the average of six section offsets in the field in March. U513M maintains high instantaneous rates of penetration required in the drill-out, as well as the ability to aggressively build angle with tool face control.
Darcy installs downhole sand control system Darcy Technologies recently completed the first downhole installation of its next-generation sand control system following the success of a robust system integrity test in Aberdeen, which was supported by several global operators and an international oilfield service company. Darcy’s sand control system was run from a land rig integrating it with standard third-party completion accessories to make up the full sand face completion system. The system was placed on depth and set into a variable wellbore some 1,000 ft below the surface. The system’s construction and high collapse resistance provides a solution for low pressure, shallow and heavy oil reservoirs. The solution can be used in remote or environmentally sensitive locations because gravel pack fluids, pumping equipment, installation and excess personnel are eliminated from the process, and its modular design is integrated with common completion equipment. The system’s activation by applying pressure from surface eliminates the time, effort and cost of gravel pack completions.
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A new Baker Hughes service identifies potential drilling issues before they occur by pinpointing similar case histories in real time using a global library of drilling practices and expert advice to provide operators with suggestions on how to respond or take corrective actions while drilling. WellLink Radar Remote Drilling Advisory Service is an integrated solution that uses case-based reasoning and event detection. It leverages Verdande Technology’s DrillEdge software to reduce uncertainty, minimize nonproductive time and increase safety. The service allows for the remote monitoring of multiple wells simultaneously and enhances drilling efficiency.
At-bit inclination technology optimizes well placement PathFinder, a Schlumberger company, recently introduced the iPZIG atbit inclination, gamma ray and imaging service. iPZIG helps optimize well placement in target zones through early bed boundary detection. Developed for unconventional oil and gas markets and high-efficiency drilling applications, the iPZIG service allows for greater directional control and accuracy while drilling versus conventional technologies, with sensors placed directly behind the drill bit. Using data from the iPZIG service, changes in lithology and bottomhole assembly orientation are quickly identified. Darcy Technologies recently installed its next-generation sand control system about 1,000 ft below the surface.
CNPC, Shell sign China’s first shale gas PSC China National Petroleum Corp (CNPC) and Shell China have signed a production-sharing contract (PSC) for shale gas exploration, development and production in the Fushun-Yongchuan block in the Sichuan Basin. Subject to government approval, this is the first shale gas PSC signed in China. The contract area covers approximately
Service diagnoses drilling challenges ahead of time
3,500 sq km. Shell will apply its technology, expertise and experience. “We are delighted about this new milestone in our strategic cooperation with CNPC. China has huge shale gas potential, and we are committed to making a contribution in bringing that potential into reality,” Peter Voser, CEO of Royal Dutch Shell, said.
ABB to supply vessel with DC-based power grid ABB recently won an order from ship owner Myklebusthaug Management to supply the first direct-current (DC) power grid onboard a ship. The equipment will allow a new offshore platform support vessel, under construction in Norway, to operate at the highest energy efficiency level to minimize emissions. The Onboard DC Grid will allow vessels to cut fuel consumption and emissions by up to 20%. M AY / J U N E 2 0 1 2
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Departments
Drilling & Completion Tech Digest Baker Hughes’ TeleCoil downhole communication system maximizes the efficiency of coiled tubing (CT) interventions by assuring depth accuracy while optimizing the operational effectiveness of downhole processes. System flexibility also enables CT-conveyed, real-time electric logging and perforating applications. By integrating intervention and logging operations, equipment and personnel are minimized on location.
Baker Hughes has introduced an innovative rotary sidewall coring service, MaxCOR. It acquires sidewall cores that are 225% more volume per unit length, enhancing accuracy of reservoir rock and fluid analysis. MaxCOR enables operators to more efficiently and effectively evaluate complex reservoirs to maximize hydrocarbon recovery.
The ClampOn Subsea CorrosionErosion Monitor provides real-time measurement and monitoring of wall thickness loss in pipes and other metal structures. The nonintrusive instrument can be retrofitted or pre-installed on the outside of a pipe to provide pipe wear rates over entire sections up to 2 meters in length.
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The Dockwise Vanguard is an innovative and the largest semisubmersible vessel built. At 275 meters (902 ft) long and 70 meters (230 ft) wide, the Vanguard can carry 110,000 tones and travel across oceans at 14 knots. Virtually all of the space on deck is clear and available for cargo. The vessel has been designed by Dockwise for both the dry-transport and the offshore dry-docking market. Delivery is planned by Q4 2012.
2012 OTC Spotlight on New Technology Awards
The Offshore Technology Conference has announced the 13 winning technologies that will receive the 2012 Spotlight on New Technology Awards recognizing innovative technologies significantly impacting offshore exploration and production. Winning technologies are selected based on five criteria: • New: The technology must be less than two years old. • Innovative: The technology must be original, groundbreaking and capable of revolutionizing the offshore E&P industry. • Proven: The technology must be proven, either through full-scale application or successful prototype testing. • Broad interest: The technology must have broad interest and appeal for the industry. • Significant impact: The technology must provide significant benefits beyond existing technologies.
FMC Technologies’ Pazflor is the first full-scale green field development with subsea separation and boosting to produce two different grades of hydrocarbons from four independent reservoirs. The system enables economic development of a reservoir that could not have been developed utilizing conventional subsea production systems.
Marlim SSAO, developed by Petrobras and FMC Technologies, will debottleneck the floating production facility and increase production by removing unwanted water from the production stream at the seabed. This system will also be the first to use water reinjection to increase reservoir pressure and boost production. M AY / J U N E 2 0 1 2
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Departments
Drilling & Completion Tech Digest
Halliburton’s EquiFlow, an autonomous inflow control device, is a simple, reliable device with no moving parts that improves completion reliability and efficiency by smoothing production throughout the interval, delaying water and gas breakthrough, greatly reducing water and gas production after breakthrough, and increasing ultimate recovery from the well.
Reelwell Downhole Isolation System (RDIS) provides double barrier elements for use in a dual drill string (DDS) arrangement. The RDIS enables unlimited number of open/ close operations providing downhole isolation of the well whenever required. RDIS provides a unique solution for improving safety and reliability during DDS drilling operations.
The highresolution ultra highpressure, hightemperature Schlumberger Signature Quartz Gauges provide precise, reliable pressure measurements in the most extreme environments. Utilizing ceramic multichip components bonded onto a single substrate, the gauges can withstand pressures up to 30,000 psi at temperatures of 410°F (210°F), while delivering high-resolution pressure measurements at recording rates as fast as 0.1 sec.
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The PowerDrive Archer high-build rate rotary steerable (RSS) system from Schlumberger delivers well profiles previously possible only with motors, yet with the rate of penetration and wellbore quality of a fully rotating RSS. It has repeatedly and consistently delivered high build rates, at times over 17°/100 ft, which can maximize reservoir exposure, reduce risk and increase potential hydrocarbon production.
The Claw is a subsea grappling device used in conjunction with Versabar’s VB 10,000 Heavy Lift System. It was developed in response to operator requests to minimize diver exposure during salvage and decommissioning operations. Enhancing the project schedule while reducing hazardous exposure has been
ShawCor’s new Simulated Service Vessel (SSV) is the industry’s largest and most advanced deepwater test chamber for end-to-end thermal insulation systems, capable of simulating water depths to 3,000 meters and temperatures to 356°F (180°C). With realtime data acquisition, the SSV validates the long-term integrity of any subsea insulation system.
Tesco’s patented Liner Drilling System enables the simultaneous drilling of a directional wellbore and running of the liner in a single trip with the option to set the liner in tension anywhere in the parent casing and the ability to retrieve the bottomhole assembly without having to pull the liner the surface.
the Claw’s most significant contribution to subsea salvage operations. M AY / J U N E 2 0 1 2
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Onshore Drilling
The great migration to wet plays Liquids-rich US shales shine as industry sweet spot BY KATIE MAZEROV, CONTRIBUTING EDITOR
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Onshore Drilling
T
he paradigm has shifted. US land rigs that just two years ago were at work in prolific shale gas plays are on the move, delivering an oil and liquids boom that has yet to be fully quantified. Whatever trends are occurring globally, US shales are the big story for 2012, driven by new play discoveries, technology advances and favorable pricing. Drilling contractors are seeing steady and rising dayrates and high utilization as operators shift their focus from the dry gas basins and set their sights on liquids-rich regions, such as the Bakken, Eagle Ford and the Niobrara, along with emerging plays believed to hold huge reserves. “There’s a boom going on,” said professor Jeremy Boak, director of the Center for Oil Shale Technology and Research and chair of the Oil Shale Committee’s Energy Minerals Division at the Colorado School of Mines. “There are three or four significant oil-producing plays in the US today and a huge amount of excitement, with companies moving rigs as fast as they can.
While gas is much easier to get out of impermeable rock, the technology in multi-stage fracturing has advanced to the point that we can now produce oil and wet gas in these areas. In many regions, such as the Bakken, the best-producing horizons are in silty rocks, siltstones and dolomites that are interbedded in the shale.” Since the industry cracked the shale oil code in the Bakken in 1999, production in the play has increased 55% per year, a phenomenal growth rate for a new resource, Dr Boak noted. “Potential for the Bakken is predicted to reach one million bbls per day by 2019, just 20 years after production started. It took the US 65 years to reach that number in conventional oil production and 40 years for the Canadian oil sands to achieve that.” Meanwhile, there is a debate among some geologists over what to call the oil produced from shale. As the Bakken play developed, the industry called it shale oil, a term used since the
Nomac Drilling’s Rig 245 drills well Gribi 1-9-1 3H in Tuscarawas County, Ohio. Photo courtesy of Chesapeake Energy Corp
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Onshore Drilling
early 1900s to refer to organic-rich shale that requires heating to produce oil. However, Dr Boak prefers to call shale containing liquid hydrocarbons “oil-bearing shale,” and the product, “shale-hosted oil.” Aside from increased production in the Eagle Ford and Niobrara plays, operators such as Chesapeake Energy are ramping up activity in the newer hot plays, including the Utica, underlying much of eastern Ohio, and the Mississippi Lime, or Mississippi Chat, spanning across northern Oklahoma and southern Kansas. The Tuscaloosa Marine play, a deep (10,000 to 15,000 ft) formation in central Louisiana and southwest Mississippi is believed to hold seven billion bbls of recoverable oil, an estimate made as far back as 1997, Dr Boak noted. Despite concerns about hydrogen sulfide (sour gas) and high levels of produced water, particularly in the Tuscaloosa, there are no signs of a slowdown, he said. “Oil prices right now are high enough that an operator can spend a good deal of money going after the oil.”
RATES STEADY AND RISING
Above: Big E Drilling’s Rig #1 operates for Rosseta Resources in the Eagle Ford. Top right: Crews on Nomac Rig 245 work to drill well Gribi 1-9-1 3H in Tuscarawas County, Ohio.
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Nomac Drilling, an affiliate of Chesapeake Energy, has 113 marketable rigs with 110 active in the Eagle Ford, the Mid-Continent (including the Granite Wash, Cleveland, Tonkawa and Mississippi Lime), the Barnett, the Haynesville, the Bakken, the Marcellus and the Utica. In the M AY / J U N E 2 0 1 2
4/13/2012 11:14:02 AM
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4/9/2012 2:12:22 PM
Onshore Drilling
A Precision Drilling Super-Triple (ST) 1200 rig moves to the next well on a pad in the Marcellus play. The self-moving rig can move with a full setback of tubulars.
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Utica, Chesapeake plans to increase the rig count to 20 by year-end and to 30 by year-end 2014. “Like most contractors, we are experiencing migration from dry gas plays to wet plays,” said Jay Minmier, Nomac president. “Fortunately, due to our relationship with Chesapeake, these changes do not impact Nomac’s utilization, only its deployments.” Mr Minmier reports that rig rates have remained favorably steady since Q3 2011 and currently range from $18,500 in the Barnett to $29,750 in the Bakken. “Nomac’s rates are market-based so we aren’t immune to price fluctuations. We do believe that, to the extent wet plays can absorb the capacity leaving the dry plays, overall pricing will remain stable, although weakness is expected in certain areas like the Barnett and Haynesville.” All of Nomac’s marketable rigs are either working or undergoing upgrades for upcoming jobs. “Our utilization has historically stayed between 95% and 100%, and we will be fully employed again once the upgrades are fielded,” Mr Minmier said. Twelve new rigs are slated for delivery through April 2013, with two 1,500-hp rigs for oil drilling in the Powder River, Wyo., region and 10 1,200-hp rigs for the Utica. Dual-fuel systems are being added to the majority of its fleet to allow the rigs to run on compressed natural gas or liquefied natural gas, as well as diesel. “Many of our existing rigs and all our newbuilds have walking systems to facilitate efficient, slot-to-slot moves on a single pad,” Mr Minmier said. “Our newest rigs also include certain innovations to reduce location-to-location move times. We are focusing heavily on mobilization times as this portion of the well manufacturing process has become much more visible due to faster drilling times.” From a technology perspective, the company has not been limited on lateral lengths. “To the extent that some laterals are shorter than preferred, it is almost always a leasing issue,” he added. Nomac is implementing an accelerated development program for drillers, directional drillers and rig managers aimed at reducing the time required to train competent rig leaders by 60% over traditional methods, Mr Minmier noted. The program is targeted to young, motivated professionals with no industry experience. Big E Drilling has shifted its fleet from the Haynesville to the Eagle Ford play, a move president and CEO Lyle Eastham said was justified given the current pricing environment. “We decided to go where the liquids are,” Mr Eastham said. “There could conservatively be 10 to 15 years of drilling in the Eagle Ford. When we moved into the play three years ago, there were only 30 rigs. Now there are nearly 240 operating.” Today, the company’s five rigs are all operating in the Eagle Ford, including one the company built 18 months ago. “We have added a lot of automation equipment, including top drives, catwalks, blowout preventer lifts and rig walking systems, to our rigs, which have enhanced safety and efficiency and aided in the contracts we’ve been awarded,” Mr Eastham continued. The fleet is designed for horizontal M AY / J U N E 2 0 1 2
4/12/2012 5:42:39 PM
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Onshore Drilling
Nabors Drilling USA Rig 681 (above) and Rig B4 (left) are both working in the Bakken Shale of North Dakota. Rig 681 is under contract to XTO Energy while Rig B4 is working for Hess.
and directional drilling at depths from 15,000 to 25,000 ft, with dayrates in the mid-$20,000s. But he also gives considerable credit to the company’s stable work force. “All our pushers have a minimum 20 years of experience, and we have a lot of 30-year employees with little turnover. We keep our rigs busy, and run a safe, efficient operation.”
WALKING THE WALK Newbuild activity is also healthy in North America, with many of the major companies ramping up their fleets with efficient, highly mobile rigs suited for shale wells and pad drilling. Calgary-based Precision Drilling delivered 18 new rigs in 2011 and has contracts on 33 more to be delivered by the end of 2012 in North America. “These are state-of-the-art, tier one rigs that are equipped with pipe-handling systems and integrated top drives, and all run range three (45-ft) tubulars. They are designed with a small footprint in mind,” said Doug Evasiuk, senior vice president of sales and marketing, North America for Precision.
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Onshore Drilling
Nabors Drilling’s Rig 109 is working for XTO Energy in the Bakken Shale, where Nabors remains the largest drilling contractor.
“Pad drilling continues to be attractive to operators wanting to minimize the environmental footprint, limit truck traffic and reduce move times,” he said. “All the major companies are building rigs that have the capability to walk from wellbore to wellbore to eliminate trucks. With our Canadian roots, we understand how to do that, especially for cold-weather environments. All our rigs going forward will have walking systems or the capability to accommodate them.” Precision’s newbuilds for the US market include seven 1,200hp rigs and 17 1,500-hp models. All are AC Super Triple rigs.
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For Canada, where wells are generally shallower, the bulk of the rigs are the Precision Super Single design. The Super Single rigs also run range three tubulars and have fully automated pipe-handling systems. “In Canada, because we have a compressed drilling season and have to be very efficient, we’ve always been focused on highly mobile rigs,” Mr Evasiuk continued. “Over the years, technology has enabled operators to drill considerably faster. Wells now are taking far less time than they did in the past, meaning we’re moving a lot more than we once did. When we’re M AY / J U N E 2 0 1 2
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Onshore Drilling From a technology standpoint, Mr Evasiuk believes the push for longer laterals will be achieved by further development of completion designs. “The industry has the capability to go out a lot farther, but it really becomes an economic decision by the operator to determine what the length of the horizontal section should be.” Outside North America, Precision has two rigs operating in Villahermosa, Mexico, and three in Saudi Arabia. All are 3,000hp rigs for deeper wells.
INCREASING AUTOMATION
A lack of service infrastructure has led to low unconventional production in Australia. “If there is a rig operating, it will be for one well, and it will be extremely costly,” said Warrego Energy’s Dennis Donald. The company holds a permit for a block in the North Perth Basin, estimated to hold one of the world’s largest shale gas reserves.
moving, we’re not drilling the well, and that translates to nonproductive time, which is costly for our customers.” Dayrates have been solid, particularly in the liquid plays. Precision began shifting from the dry gas plays to the liquids last year, a trend that will continue, Mr Evasiuk said. The company’s large presence in the Haynesville has shrunk from the peak level of 26 rigs to just three. “There has been enough activity in the liquids plays to absorb rigs coming out of the dry gas markets.” US utilization is above the industry average. Of the company’s 150 US rigs, 104 are operating in all the major plays, including the Bakken, Eagle Ford, West Texas, Mississippi Lime and Tuscaloosa. Precision has yet to enter the Utica but has been approached by operators in that region. As the largest drilling contractor in Canada, Precision has operations in every major basin, notably the Cardium, Viking, Duvernay, Canadian Bakken, oil sands and heavy oil. Utilization in February was around 85% but has recently declined due to the spring “break-up,” which occurs late in Q1 and can carry into Q2. The thawing makes transporting equipment difficult. Traditionally, 35% to 40% of drilling activity in Canada occurs in the winter months.
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Nabors Drilling has seen an uptick in US land rig utilization, primarily in the 1,000- to 1,500-hp size being deployed in most of the shale plays, said Denny Smith, director of corporate development. “Overall, US land rig utilization is around 80%, but utilization is virtually 100% for our rigs in the highest demand window.” He sees dayrates averaging in the mid-$20,000s. Commodity pricing is the key driver for the shifting market, a trend that began back in 2010. The weak gas price phenomenon is isolated to North America. Nabors initially shifted several rigs from the Haynesville to the Eagle Ford. Two years ago, 58 Nabors rigs were working in the Haynesville; today there are 26. Along with a significant presence in the Eagle Ford and the Permian Basin, the company has several rigs in the Mississippi Lime, with plans to move two more from the Haynesville. The company also plans to move one or two additional 1,500- to 2,000-hp rigs into the deep Tuscaloosa play to go after gas liquids and oil, Mr Smith said. Additionally, Nabors remains the biggest drilling contractor in the Bakken. By the end of 2012, the company will have 76 rigs, including several newbuilds, in the play. “The market will continue to be this way for awhile. Gas continues to be oversupplied, in part because of the associated gas that is being produced with the liquids and oil,” he continued. “There is a broad range of pricing right now. I think there is a lot of latitude for prices to even moderate some and still keep a pretty robust market. Our customers have indicated they would continue drilling if oil prices get as low as $75 to $80 in the Bakken and $60 to $65 in the Permian.”
There are three or four significant oil-producing plays in the US today and a huge amount of excitement, with companies moving rigs as fast as they can.” Professor Jeremy Boak Center for Oil Shale Technology and Research M AY / J U N E 2 0 1 2
4/12/2012 6:14:41 PM
The Next Generation of Shale Shakers
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Onshore Drilling Mr Smith said shale production, particularly horizontal drilling, has benefitted from an increase in pad drilling and major advances in downhole logging and real-time technologies. “I think there is going to be a trend toward more automation and remote control of the drilling processes that will spark further improvement in the next two to five years in rig efficiency, with increasing numbers of AC rigs featuring digital controls and automatic drillers.” Through its wholly owned subsidiary, Canrig Drilling Technology, Nabors manufactures top drives and other rig systems and intelligent software technologies. At year-end 2011, the company had 119 AC rigs in the US, with 31 newbuilds planned this year. Most of the contracts are for the US market, but at least two have been designated for Canada and three for other markets. Outside the US, the market is recovering, with Nabors’ land rig count expected to increase from 116 at year-end 2011 to 130 by the end of 2012. The company saw peak activity during the seasonal Canadian market, with close to 50 rigs operating in the oil-rich Montney, Duvernay and Cardium plays, Saskatchewan, and the Horn River gas basin. There is more gas drilling in the Middle East, particularly Saudi Arabia. “We do the majority of the gas drilling in Saudi Arabia with very high-spec, 2,000-hp rigs with multiple blowout preventer stacks for the high-pressure wells,” Mr Smith said. Nabors also has 15 rigs in the Llanos Basin of Colombia and is drilling oil for two major operators in Russia.
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AN ANTICIPATED BONANZA But there is one area of the globe where drilling activity is at a near standstill. Despite favorable market conditions, a lack of service infrastructure is retarding progress. Dayrates in Western Australia are at least 48% higher than US rates, despite gas prices that are $8-$10 (and rising) per gigajoule, considerably higher than North American prices, with acre lease costs of $500 or less, said Dennis Donald, a partner at Warrego Energy. The company holds an unconditional permit to develop an 86-sq-mile block in the North Perth Basin, which is estimated to hold the fifth-largest reserve of shale gas in the world. The block contains the West Erregulla tight-gas field, which underlies the Kockatea shale play recently mapped by the US Energy Information Administration. The company plans to do seismic testing this year and begin drilling in early 2013. Mr Donald cites lack of service infrastructure as the primary reason for the low unconventional production in the vast region, in part a function of the cannibalization of rigs being used for the vigorous coal seam gas activity in the eastern sector the country, thousands of miles away. “But with the government’s push for gas to replace diesel in Western Australia, operators have been given permission to utilize hydraulic fracturing to open up the gas shales,” Mr Donald said. “There eventually will come a tipping point, and when production does open up, this will be a massive market, and we will see a bonanza for rigs and fracturing.”
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T E R R A I N VA D E R 3 5 0 / 4 5 0
MODERN HYDRAULIC DEEP DRILLING RIGS FOR THE DEVELOPMENT OF UNDERGROUND ENERGY SOURCES. Whether the search for and utilization of new underground energy deposits are economically reasonable also depends on the efficiency of the drilling technology applied. This is why the German company Herrenknecht Vertical GmbH has developed the innovative Terra Invader deep drilling rigs. Both slingshot and box-on-box substructure rig types set new standards in terms of safety, cost-effectiveness and environmental protection thanks to their hydraulic design. They have already proved their efficiency in geothermal energy and oil & gas projects at drilling depths of more than 5,000 meters. The safety of the personnel and the drilling operations benefits through the application of hands-off technology and a hydraulic hoisting system which are integrated in the new high-tech rigs. Both pipe handling and drilling operations are remote-controlled and highly automated. No technical staff needs to work directly in the danger areas increasing work safety considerably and reducing personnel costs. The sensitive hydraulic hoisting system additionally allows for push and pull operations. An intelligent energy sharing concept for less power consumption, the compact rig design for fast and easy rig moves and the sophisticated noise-protection for all rig components for a utilization also in urban areas round off the Terra Invader rig design.
T E R R A I N VA D E R 3 5 0 / 4 5 0 Max. hook load TI-350:
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350 mt (385 sht)
Max. hook load TI-450:
450 mt (500 sht)
Substructure:
Slingshot or box-on-box
Hoisting system:
Hydraulic cylinder system
Hoisting power:
1,600 kW (2,200 hp)
Top drive type:
HV TD H 500-1000
Top drive power:
800 kW (1,000 hp)
www.herrenknecht-vertical.comM A Y / J U N E 2 0 1 2
4/12/2012 5:43:11 PM
Onshore Drilling
Analyst: Numbers show that US is drilling its way to zero net oil imports Total US Crude Produc on vs Imports (Excludes NGL's & Biofuels)
10.0 9.5 9.0 8.5 8.0 7.5 7.0 6.5 6.0 5.5 5.0
Crude Produc on
Horizontal drilling, 16
US Imports Falling!
14
multi-stage fracturing
Crude Imports
12
MMBbls/d
US Supply Up ~4 MMBpd in 5 yrs???
10 8
drive surge in onshore volumes, key to
6 4 US Supply Down ~4 MMBpd in 35 yrs.
reversing decades-long
2 0
production decline BY KATHERINE SCOTT, EDITORIAL COORDINATOR
An increasing US crude production coupled with declining oil demand is resulting in a sharp reduction in the nation’s oil imports, according to Raymond James and Associates. They believe that US oil and gas companies have already worked toward reversing a nearly four-decade-long decline in oil supply. Source: EIA, RJ estimates
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H
orizontal drilling and multi-stage fracturing are working hard for the industry, and the results are paying off. According to research by Raymond James and Associates, by opening the door to vast resources of unconventional liquids, the industry has radically reshaped the trajectory of US oil production. This is reversing a nearly four-decade-long decline in oil production. Coupled with declining US oil demand due in part to better vehicle efficiency, the shift is moving the country toward energy independence. Owed to fact that US oil and gas companies have already overcome government road blocks and geological challenges to increase oil supply, and a change in transportation habits has decreased oil demand, Raymond James expects that US net oil imports could reach essentially zero by 2020.
On 22 March at Ohio State University, US President Barack Obama made the claim that the US cannot become energy independent solely by doing more drilling, saying that “we can’t simply drill our way out of the problem.” Marshall Adkins, managing director, head of energy research for Raymond James, strongly disagrees. “The facts say something very different. The facts say that we are drilling our way out of this. (We’re moving toward being) totally oil independent.” The recent boost in US oil production, which reached 8.1 million bbl/day last year, and cuts in oil demand are causing imports to fall, which Mr Adkins said is a major part of attaining oil independence for the US. “It appears that demand will continue to drift lower, but the real driver is D R I L L I N G CONTRACTOR
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MAKE A CLEAN BREAK. NATURALLY.
US: Declining Oil Demand and Growing Production 25
US Biofuels Supply US Oil Supply ex-Biofuels US Oil Demand
MMbbls/d
20
Delta = 9.8 MMbbls/d
Delta = 13.5 MMbbls/d
15
10
5
0 2005
2007
2009
2011
2013E
2015E
2017E
2019E
Source: EIA, IEA, RJ estimates
Falling oil demand is a smaller but relevant part of the overall story. US oil demand has fallen in every year but one – even in the good economic years of 2006-2007, according to Raymond James and Associates.
more supply, so you combine roughly two barrels of supply growth for every one barrel of decline in demand, and you’re getting pretty meaningful reduction in the amount of oil we need to import,” he explained. Safe and easy to use, this EPAauthorized enzyme breaker is a direct replacement for corrosive acids
INCREASING OIL SUPPLY Research by Raymond James suggests that the US produced more incremental
oil supply than any other country from 2009 to 2011. The growth doesn’t stop there; it is projected that, compared with 2011, there will be a 6% increase in oil production this year and an average 11% growth per year between 2013 and 2015, most of it driven by the ongoing surge in onshore volumes. The use of horizontal drilling and multi-stage fracturing in areas like the Bakken, Eagle Ford and
and hazardous oxidizers. And, as a naturally bio-degradable solution, it does no harm to the environment. Pyrolase® cellulase is the only enzyme breaker that delivers superior
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11%
• It is projected that there will be a base decline in oil demand of through 2020.
1.5% each year
• US net oil imports are expected to reach essentially
US Pat. 5,962,258, 6,008,032, 6,245,547 and other patents pending. © 2012 Verenium Corporation.
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zero by 2020.
• With an approximately 2.2 million bbl/ day reduction in imports since 2008, the US has reduced that part of its trade deficit by approximately $80 billion annually.
M AY / J U N E 2 0 1 2
4/12/2012 4:26:52 PM
Onshore Drilling Permian Basin is allowing the industry to get more oil out of the ground.
DECLINING OIL DEMAND Likewise, Raymond James projected that there will be a base decline in oil demand of 1.5% each year through 2020. US oil demand peaked in 2005 at 20.8 million bbl/day, having grown in every year but one since 1992. However, since then, demand has fallen in every year but one, and Raymond James estimates that there will be a decline of 2.5% for 2012 relative to a year ago. Mr Adkins said that the decline in US oil demand has largely come from higher energy prices, which in turn are pushing better vehicle efficiency, more natural gas vehicles and reduced travel patterns.
every year since 2005, with further declines projected. With an approximately 2.2 million bbl/day reduction in imports since 2008, the US has reduced that part of the deficit by approximately $80 billion annually. Mr Adkins believes that the resulting savings in the trade deficit are highly meaningful, especially when the benefits of cheaper energy for US manufacturing are taken into account. Further, their
research states that the trends of lower oil import costs, cheaper US natural gas prices and decreasing non-oil related trade deficit point to a reduction in the total US trade deficit of 82% by 2020. Despite these findings, however, Mr Adkins believes there are still additional steps that need to be taken. “(If we increase access to drilling), it will speed up the process of becoming energy independent.”
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DECREASING OIL IMPORTS In light of this increased supply and decreased demand scenario, Raymond James concluded that the US is poised to sharply decrease its dependence on other countries for imported oil. Their research shows net US oil imports already falling from 13.5 million bbl/day (65% of demand) in 2005 to approximately 9.8 million bbl/day (52% of demand) in 2011, and that may fall to an estimated 4.5 million bbl/day (26% of demand) by 2015. Additionally, lower oil import costs could stimulate resurgence in US manufacturing, bringing with it more jobs. “This is also a huge boom to US labor, across the board. It’s not just in the energy business, but you know cheap energy creates more manufacturing jobs,” Mr Adkins said, “The single biggest, most visible and immediate benefits to this ... is more jobs.”
US TRADE DEFICIT Another important aspect to consider is the US trade deficit, where oil imports play a large role. According to the research, oil imports have generated more than half of the total deficit every year since 2007. “(Decreasing oil imports is) hugely positive for the trade deficit. In the last several years, over half of our trade deficit has been energy related, and if you eliminate that, then your trade deficit gets cut in half,” Mr Adkins said. Despite adding to the total deficit, the net oil import requirement has dropped M AY / J U N E 2 0 1 2
May12-RaymondJames.indd 37
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D R I L L I N G CONTRACTOR
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4/12/2012 4:26:57 PM
Onshore Drilling
The water challenge Innovative solutions emerge to address one of hydraulic fracturing’s most critical concerns BY KATIE MAZEROV, CONTRIBUTING EDITOR
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M AY / J U N E 2 0 1 2
4/12/2012 4:29:11 PM
Onshore Drilling
A
s hydraulic fracturing enters a new phase in the current shale boom, the industry has learned a thing or two about the process, not the least of which is that it makes both economic and environmental sense to include the three R’s – reuse, recycle and reclaim – as part of the equation. It takes three million to five million gallons of water to unlock the hydrocarbons of just one unconventional shale well. That, along with the costs associated with disposal, political pressure, and regulatory changes regarding disposal of fluids, has prompted operators large and small to take a look at their water recycling and reuse strategies. In response, a variety of technologies have emerged onto the marketplace that allow producers to reuse their water, reduce transportation costs, comply with regulations and reduce their environmental footprint. Last year, Halliburton introduced a
comprehensive water management system that meets the full range of customers’ needs, including water supply and storage, transportation, recycling, reuse and disposal. Baker Hughes has two mobile services designed to provide operators with convenient water treatment and drilling waste recycling in unconventional shale formations. Innovation is coming from many sectors. “The operators themselves have pioneered approaches for water reuse that require a minimum amount of treatment,” said Keith Minnich, water sustainability manager for Calgary-based Talisman Energy. “But water treatment companies are now developing technologies that can accomplish virtually anything – even converting produced water to drinking water. Also, now that the major service companies have developed saline-tolerant additives, it is much easier to reuse produced water,” he said, noting
Water Rescue Services’ mobile, 24-ft trailers can process 20,000 bbls of water in a 24-hr period using electro-coagulation. From left are produced water, water just after the treatment and the finished product.
M AY / J U N E 2 0 1 2
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D R I L L I N G CONTRACTOR
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Onshore Drilling
Left: Ecosphere Technologies’ Ozonix EF80 Unit works in the Fayetteville Shale. Ozonix is an ozone-based oxidation process that combines ozone, hydrodynamic cavitation, acoustic cavitation and electro-oxidation to destroy bacteria and inhibit scale formation. The EF80s can process up to 80 bbls of frac water per minute. Right: Twelve Ozonix EF10 Units work to treat water at rates of up to 120 bbl/min in the Fayetteville Shale.
that saline, a product of old sea water embedded in the shale, is no longer considered an operational problem. Mr Minnich is involved in a joint industry project funded by the governments of Alberta and British Columbia to develop a methodology for the reuse of flowback water. The project is intended to provide operators, service companies and water treatment companies with a framework for evaluating what level of treatment is required for each type of fracturing fluid for a given situation. “There are different types of hydraulic fracture treatments and different fluids involved in treatments,” he explained. “Some fluids are relatively simple and simple to use; others are more complex and require more treatment.” The water treatment process for Talisman varies from play to play but has been primarily limited to simple suspended solids removal. The company has been able to reuse flowback and produced water with a minimum amount of treatment in the Marcellus play and the Montney gas field in British Columbia. “Although the access to fresh water hasn’t been a limiting factor, we are committed to a responsible and sustainable water management strategy,” Mr Minnich said, noting that the Texas drought has caused some concern over the continued availability of fresh water in the Eagle Ford.
HOW MUCH TREATMENT? Varying regulatory requirements have posed some difficulties, however. “Where we face some challenges is in the Marcellus play on what to do with the flowback water that cannot be reused. Pennsylvania does not have the same availability of injection wells as Texas, where excess flowback and produced water is commonly injected into deep wells.” Pennsylvania also has put in place regulations that require water to be treated extensively prior to surface disposal, a
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Water treatment companies are now developing technologies that can accomplish virtually anything – even converting produced water to drinking water.” Keith Minnich Talisman Energy costly undertaking. In Canada, surface discharge is not a given, and in Alberta the practice is banned no matter what level of treatment, Mr Minnich noted. “The challenge everyone is facing right now is determining what level of treatment is actually required for reuse,” he continued. “Unnecessary amounts of treatment raise the cost and make it less attractive to reuse and also generate byproducts. The alignment of what treatment is required and what technologies are available is a work in progress.” Among the entrepreneurial firms bringing high-tech solutions to the marketplace is Florida-based Ecosphere Technologies, which has developed and commercialized a technology that eliminates the need for oil and gas operators to use chemical biocides and scale inhibitors during hydraulic fracturing operations. Ecosphere’s patented Ozonix technology is an ozonebased, advanced oxidation process that combines ozone, hydrodynamic cavitation, acoustic cavitation and electro-oxidation into one process to destroy bacteria and inhibit scale formation. Mobile, 53-ft units called Ozonix EF80s can process up to 80 bbls of frac water per minute. M AY / J U N E 2 0 1 2
4/12/2012 4:29:27 PM
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May12-AD.PRECISON.indd 41
4/10/2012 12:47:23 PM
Onshore Drilling
Ecosphere’s Ozonix technology has been used by Newfield Exploration in the Woodford Play. It can be applied in oil flood operations, enhanced oil recovery and wells producing condensate. The technology also has been deployed in the Fayetteville, Eagle Ford and Permian Basin.
Through its subsidiary, Ecosphere Energy Services, the company has treated and recycled nearly 30 million bbls of flowback water, produced water and surface water used as a makeup fluid. The technology can pre-treat raw water needed for hydraulic fracturing operations and post-treat flow-back and produced water at pond sites or fixed facilities, said Ecosphere Technologies chairman and CEO Charles Vinick. “Typically, the operator brings produced or flowback water to a frac site and stores it in a reclamation pit or frac tanks,” Mr Vinick explained. “A water transfer company will then pump that water to us, along with surface waters from a nearby source.” The water is blended by a proprietary mixing manifold and then treated with the Ozonix process. Once the water has gone through the system, the effluent water is discharged into a fracturing tank or manifold to be pulled into the pumping service company’s equipment, where it is blended with sand and ready to use as a fracturing fluid. “We are treating water at the flow rate of the frac to eliminate the use of liquid chemicals,” said Robbie Cathey, CEO of Ecosphere Energy Services. “We also believe that by oxidizing organic material and precipitating salt compounds, we are improving the frac fluid’s compatibility with friction reducers, resulting in lower treating pressures.”
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Ecosphere’s Ozonix technology has been used by Newfield Exploration in the Woodford play and Southwestern Energy in the Fayetteville over the last three years, and was deployed in the Eagle Ford and Permian Basin this year. The technology, which has been tested or used in all the major plays except the Bakken, can be applied in oil flood operations, enhanced oil recovery and wells producing condensate, Mr Vinick noted. “For operators, elimination of chemicals and recycling of water are key elements of a cost-effective and environmentally safe treatment system.”
AN ELECTRIFYING PROCESS ROLCO Energy Services provides water management solutions for unconventional oil and gas producers using an electrocoagulation process that adds an electric charge to the water to convert dissolved solids such as iron, magnesium, calcium and naturally occurring radioactive materials into suspended solids that can be removed with a mechanical filter. “By changing the polarity of the water, we are allowing dissolved particles to amalgamate and join together and become a suspended solid,” said CEO and founder Perry Roland. The company, founded in 2009, has worked in the Haynesville shale play and the Piceance Basin to treat water for reuse, and plans on entering the Bakken and Eagle Ford oil plays. M AY / J U N E 2 0 1 2
4/12/2012 4:29:38 PM
Controlling WOB was once just an educated guess. The better the driller, the better the guess. Not today. Now Omron’s Intelligent Drilling System™ takes the guesswork out of controlling WOB. Our system precisely controls this important drilling parameter and changes it automatically as required. More controlled WOB means faster ROP, with less vibration on the drillstring. And that means more efficient drilling. Contact Omron today and ask about our rig automation systems. We control where it counts so your rig performs when it counts.
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May12-AD.OMRON.indd 43
4/10/2012 3:29:29 PM
Onshore Drilling
Left: ROLCO’s Flow/Pro 20 electro-coagulation system treats and recycles water on a frac pad in Colorado. Top right: Raw flowback and produced water prior to treatment by ROLCO’s electro-coagulation system (left) is compared with water that has been through the electro-coagulation process (right), prior to the polishing stage, where all remaining solids are removed for more efficient reuse at the fracturing site. Bottom right: A ROLCO electro-coagulation processing site in Colorado treats and recycles 100% of flowback and processed water from fracturing. Contaminated water is collected in a pit, then pumped into electro-coagulation systems, where it is processed on-site and recycled back to the fracturing process.
“We have figured out the key to do this successfully in the gas market, but the oil side brings some additional challenges, such as the constituents in the water,” Mr Roland said. “As operators continue to move rigs from the dry gas plays to the oil plays, our technology will follow.” To that end, ROLCO is partnering with AbTech Industries, which has developed the Smart Sponge, an oil-absorbent material that removes hydrocarbons on the front end of the electro-coagulation process so they don’t enter the clean water system. “The Smart Sponge is oleophilic, so it absorbs hydrocarbons that are in the water, but it is also hydrophobic, so it repels and doesn’t retain water,” said AbTech chief operating officer Jonathan Thatcher. “We manufacture it in a manner that retains very high flow rates through the media and results in little or no pressure loss. It can absorb one to two times its weight in hydrocarbons.” The process solidifies the hydrocarbons it removes, creating a solid that can be burned as a fuel source in waste-to-energy facilities, cement kilns or incineration operations, Mr Thatcher explained. The water being treated is a combination of fracturing flowback water and produced water. It can be treated
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repeatedly, although the process may need to be modified because the water profile will change over time. AbTech’s portable and installed units can process 10,000 bbls/day to 100,000 bbls/day of produced water. Often, there are multiple units on a fracturing site. After the de-oiling process, a number of different technologies, including electro-coagulation, can be used to treat the water for a variety of uses. “The water can be treated to remove everything except brine for reuse in fracturing operations and can also be treated for discharge, which involves further removal of the salts and chlorides, typically by a reverse osmosis (RO) process for discharge into lakes or rivers. Pre-treatment is always required because other technologies, especially RO, can’t tolerate oil and grease coming into their systems,” Mr Thatcher explained. Because a well will produce up to five times as much water as oil and gas over its life, some in the industry are eyeing water treatment systems as a potential source of water for agricultural purposes, provided all the salts are removed. “We could have a source of agricultural water that is not going to impact traditional drinking water sources such as lakes, rivers and underground aquifers,” Mr Thatcher said. M AY / J U N E 2 0 1 2
4/12/2012 4:29:45 PM
([FHOOHQW WRRO IDFH FRQWURO 1R WHPSHUDWXUH OLPLWDWLRQ 'RHV QRW LQWHUIHUH ZLWK 0:' 1R IOXLG FRPSDWLELOLW\ LVVXHV ,QFUHDVHG VOLGLQJ 523 1R ELW RU %+$ SOXJJLQJ The XRV tool greatly improves sliding ROP and tool face control during steering operations. It has been specifically designed to create minimal MWD interference while producing maximum vibration in the drillstring. This tool was engineered without any elastomeric components thus eliminating temperature limitations, fluid compatibility issues and the risk of circulation loss due to plugging of the bit or other BHA components. The XRV tool string (XRV tool and TTS drilling safety joint) have been designed for maximum ruggedness and structural flexibility making this system ideal for use inside the curve on horizontal wells and in sharp radius well sections in the lateral.
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4/9/2012 12:35:04 PM
Onshore Drilling
Above: Electro-coagulation uses electric charge to bond contaminants so they can be dropped into a settling tank. The water is then put through polishing filters before it is returned to the fracturing operation. Right: ROLCO and AbTech have developed the Smart Sponge, an oil-absorbent material that removes hydrocarbons on the front end of the electro-coagulation process. At right, Smart Sponge is installed at a fracturing site in Wyoming.
REDUCING TRUCK TRAFFIC Another young company using electro-coagulation, Water Rescue Services Holdings, has been approved by the Texas Railroad Commission to operate a mobile recycling system in the state that allows operators to reuse produced and flowback water. The firm, launched in early 2011 in Fort Worth, is also planning to move into Wyoming, Louisiana and sections of the Marcellus. Last September, the company signed a strategic alliance with Select Energy Services, an oil and gas services company, to provide a total water management system using Water Rescue’s patent-pending process. In its mobile, 24-ft trailer, Water Rescue Services can process 600 gallons of water a minute, or 20,000 bbls in a 24-hr period, said Wes Williams, president of Water Rescue Services. “We get a sample of water from the operator with a directive of the water standard they need for their type of fracturing operation, such as slick water, hybrid or crosslink gel fracs,” he said. “We get the heavy metals, such as iron and suspended solids, out easily, but our customers may want other compounds out as well.” In the electro-coagulation process, the metals surrender as the electric charge is placed on them, and the contaminants
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in the water bond together and drop into a settling tank. The water is then put through polishing filters before it is returned to the fracturing operation. Solids are compressed, de-watered and removed. “For every 100 trucks the operator would have to send to a saltwater disposal well, we use three or four, depending on the play,” Mr Williams said. “We return 95% to 98% of the water to the facility, where it can be used again and again. In one play in south Texas, we will be able to keep an estimated 12,000 trucks off the road.” The company says it has been contacted by government officials wanting to understand the process because they are receiving calls from their constituents about problems on the road. “The oil and gas industry is going through a shift,” Mr Williams said. “In the past, water was plentiful, cheap and easy. Now water is like gold, and operators need to endorse new technologies to deal with water shortages and achieve high environmental standards. The recycling business is still in an embryonic stage, but companies like ours must prove our reliability to help the industry make recycling more of a necessity than a luxury.” Ozonix is a registered term of Ecosphere Technologies
M AY / J U N E 2 0 1 2
4/12/2012 4:29:55 PM
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4/10/2012 3:25:32 PM
Onshore Drilling
Well depth extended in geothermal project using controlled pressure drilling Underbalanced runs prevent mud losses and reservoir damage, allow well to hit main fault BY ESSAM SAMMAT, STEPHEN O’SHEA, GARETH INNES, WEATHERFORD UK; JULIO KEMENYFY, DARKO PISCEVIC, GEOENERGIE BAYERN
W
Figure 1: The Kirchweidach wells have the longest open-hole sections for geothermal wells, from 1,241 meters to 1,378 meters.
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ells in the Kirchweidach geothermal project in Bavaria, Germany, and other offset wells in the area have faced problems such as severe mud losses and differential sticking in the reservoir formation. However, control pressure drilling (CPD) was successfully applied to address those challenges. The project’s objective was to erect a power plant that would produce 6 to 8 MW of electricity and supply the local town and industries with district heating using thermal energy. Two wells were planned targeting natural fractures in the Malm formation (Jurassic carbonate), including one producer and one injector. This would allow more than 90% of the produced water to be returned to the reservoir, in time making the project sustainable. M AY / J U N E 2 0 1 2
4/12/2012 4:33:23 PM
Onshore Drilling The first geothermal well was drilled using CPD equipment in the reservoir section from the beginning. The underbalanced borehole pressure was achieved by pumping various rates of nitrogen and fresh water with polymers, which can significantly reduce nonproductive time and formation damage. For the second well, CPD equipment was used only after mud losses appeared. The Malm formation is an underpressured aquifer that is often karstified, which at times resulted in severe or total fluid losses in the wells crossing it. In Kirchweidach, the top of Malm is at around 3,450 meters TVD, 400-meters thick and 130°C. As fluid losses during drilling are an indicator of success for the project, a procedure was implemented to allow drilling under these conditions to reach all targets while keeping the reservoir as clean as possible. The Kirchweidach wells have the longest open-hole sections for geothermal wells, with GT 1 at 1,276 meters, GT 2 at 1,241 meters and GT 2a at 1,378 meters. They are also the only horizontal wells drilled in this formation. At the top of Malm, the separation between GT 1 and GT 2a is 1,600 meters. Figure 1 shows the typical well design, and Figure 2 shows the structural placement of the wells.
CONTROLLED PRESSURE DRILLING Controlled pressure drilling uses a closed and pressured wellbore instead of drilling with the hole “open” to the atmosphere. A rotating control device (RCD) closes the well at surface, allowing for more precise control of the pressure profile. The RCD directs the flow of cuttings brought up by the aerated/nitrified fluid from the rig to the geothermal separator. To do this, the flowline from wellhead to separator connects to a drilling spool below the RCD. This facility also provides the option of flowing cold water over the top of the well to stay within RCD rubber element temperature specifications if necessary. The rubber seal unit rotates with and seals around the drill pipe and tool joint when drilling, making connections or tripping in or out of the hole. The three main types of CPD methods are air drilling (AD), managed pressure drilling (MPD) and underbalanced drilling (UBD). AD is geared toward increasing the rate of penetration (ROP), MPD M AY / J U N E 2 0 1 2
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reduces rig non-performance time, and UBD minimizes reservoir damage and increases productivity. Well GT 1 was drilled using two of these CPD methods as it varied temporarily from at-balance to underbalance conditions using nitrified fresh water, with the intention to avoid continuous influx to surface. Accordingly, the drilling method could justifiably be termed CPD, MPD or UBD. For this article, the
four runs undertaken will be referred to as UBD Runs 1, 2, 3 and 4 even though the well was not strictly continuously in underbalance conditions.
PLANNING WELL CLASSIFICATION IADC’s well classification system for underbalanced operations and managed pressure drilling (MPD) describes a well
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Onshore Drilling Overall risk Level 3
Geothermal and non-hydrocarbon production. Maximum shutin pressures less than UBD equipment operating pressure rating. Catastrophic failure has immediate serious consequences. Application category Underbalanced Operations. Performing operations with returns to surface using an equivalent mud weight that is maintained below the open-hole pore pressure.
B
Fluid system 4 (Gasified liquid)
Fluid medium with a gas entrained in a liquid phase.
Table 1: Well GT 1 was planned as a 3-B-4 under the IADC Well Classification System for Underbalanced Operations and Managed Pressure Drilling. The well’s open-hole section was drilled in two phases using a total of four UBD runs. Well trajectory
Minimum required velocity
Horizontal
55 meters/min
Vertical
45 meters/min
Table 2: Minimum liquid flow velocity was an important input parameter during pre-job and rig-site modeling of multiphase flow using a simulator. It determines the cutting-carrying capacities. Table 2 shows the values for minimum holecleaning capacities for water-based mud based on experience.
using a three-digit code based on overall risk, application category and fluid system. Based on this system, GT 1 was planned as 3-B-4: • Overall risk was Level 3: geothermal and non-hydrocarbon production. Maximum shut-in pressures less than UBD equipment operating pressure rating. Catastrophic failure has immediate serious consequences. • Application category is Category B: underbalanced operations. Performing operations with returns to surface using an equivalent mud weight that is maintained below the open-hole pore pressure. • Fluid system is 4 (gasified liquid): fluid medium with a gas entrained in a liquid phase.
OBJECTIVES The objective of GT 1 was to drill the 9 ½-in. open hole to TD using CPD methods with the following criteria: • Drill the open hole with a two-phase water and nitrified fluid to maintain CPD conditions in the open hole, avoiding reservoir damage; • Avoid drilling problems such as mud losses, differential sticking and potential kicks by proper fluid control and measurement; and
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• Allow potentially faster ROP and lower total drilling days. This was a secondary objective compared with the primary objective of avoiding losses. By successfully using CPD methods, the following results may also be possible: • Drill to TD with full returns, allowing collection of geological information; • Reservoir/production evaluation and characterization while drilling; and • Gather data for drilling performance optimization and future well planning.
MODELING Pre-job and rig-site modeling of multiphase flow was done using an advanced simulator to determine the required underbalanced drilling conditions. These include the following input parameters: 1. Gas-to-liquid ratios are evaluated and selected to reduce the hydrostatic pressure within the annulus to achieve the desired bottomhole circulating pressure. 2. Minimum liquid flow velocities, which determine the cutting-carrying/ hole-cleaning capacities. By experience, the values for minimum hole-cleaning capacities for water-based mud are: • Well trajectory: minimum required velocity;
• Horizontal: 55 meters/min; and • Vertical: 45 meters/min; 3. The mud motor equivalent liquid volume (ELV) is taken into consideration. This value cannot be exceeded. 4. The gas volume fraction (GVF) in the drill pipe can affect downhole tool performance. Modeling was performed using data provided by GEOenergie Bayern and known physical constants. To function, Neotec requires a number of input values, including the specific gravity of the intended drilling fluid, composition of the injected gas, borehole trajectory and annular design. Additionally, drill string design, including tubular profiles and operating limits (pressure drop and max motor ELV), are of interest as points of increased annular friction or pressure drop, which can affect downhole fluid velocity. Estimations are substituted. Initial indications were that target formation pressure was 351 bar (5,089 psi) and formation temperature was 145°C (293°F). Reservoir pressure was thought to be 383 bar (5,555 psi) at TD. Offset wells reported partial to total loss scenarios when drilling with 1.02 to 1.05 sg (8.4 to 8.7 ppg). A primary requirement of the CPD operation was to reduce annular friction pressure, which is responsible for increases in the bottomhole pressure and the potential for fluid loss. A solution was to establish a high nitrogen injection rate with a moderate fluid injection rate. This also increases the fluid velocity, which aids hole cleaning. When working in a very narrow pressure window, the case where the well is not producing at the casing shoe is considered the worst-case scenario. Fluid injection rates were designed to lie within the capabilities of the equipment available while not exceeding reservoir pressure draw-down of 10%. Initial modeling was conducted with rates varying from nitrogen at 18 cu meters/min to 28 cu meters/min and fluid injection at 2,000 lpm to 2,600 lpm. An operation envelope was created that identified an optimal injection rate of 22.6 cu meters/min of nitrogen and 2,400 lpm of drilling fluid with a density of 1.02 sg. This produced a reservoir draw-down of 4 bar (58 psi) while remaining within operating limits of less than 18% GVF (5%) and motor ELV limits. M AY / J U N E 2 0 1 2
4/12/2012 4:33:33 PM
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Onshore Drilling
Figure 2 shows the structural placement of the GT 1, GT 2 and GT 2a wells in the Kirchweidach Geothermal Project. GT 2a had the most challenging well path as it targets a fault to the north and has inclinations of up to 97째 for a long section. CPD equipment was therefore rigged up before the expected losses zone rather than after the losses appeared in GT 2a.
However, these injection rates provide hole-cleaning velocities of 41 meters/ min in the vertical section. Experience has shown that under these conditions, adequate hole cleaning can be achieved through the scheduled pumping of highviscosity pills, reciprocating the drill string prior to connections and low ROPs. On the other hand, should the reservoir flow, vertical and horizontal fluid velocity would exceed their minimum thresholds, and hole cleaning would be vastly improved. While concentric casing and parasitic string injection methods were known to be highly effective nitrogen injection methods, drill pipe injection was chosen as it was shown to be adequate.
NITROGEN There are two methods for getting the required supply of nitrogen on the rig site. Cryogenic nitrogen is widely used in drilling operations as it is transported to the well site as a liquid, and the boiling point of liquid nitrogen is -196.1째C (-321째F) at atmospheric pressure. Cryogenic tanks are necessary for transportation and storage on location. Because the nitrogen is pumped as a liquid and the conversion from liquid volume to gas volume at standard conditions is well characterized, it is straightforward to accurately measure and con-
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trol the nitrogen delivery rate. This also comes with a guaranteed nitrogen purity of 99%, which vastly reduces corrosion effects on equipment. Membrane nitrogen involves stripping nitrogen molecules from the local atmosphere. This system has different equipment requirements to the cryogenic method, but once the sourced nitrogen is in the standpipe, it provides the exact same function. Regardless of the nitrogen source, it eliminates the possibility of downhole fires. Pure cryogenic nitrogen also prevents downhole corrosion due to the purity level. Membrane-generated nitrogen contains some oxygen, and downhole corrosion remains a concern. Awareness of corrosion effects is crucial to safe operations and equipment maintenance. Other factors need to be considered before it is decided to use cryogenic or membrane nitrogen, such as cost, availability, site layout and available space, diesel consumption, and noise control. Based on the above criteria, the plan was to drill GT 1 using cryogenic nitrogen.
DEVELOPMENT EQUIPMENT SELECTION The CPD geothermal package was designed to have an efficient and minimal on-site footprint. The Model 9000
RCD was perfectly suited for the well conditions projected with 34 bar (500 psi) operating pressure rating, and they close the annulus to the rig floor. RCDs are not well control equipment, and no CPD equipment was labeled as such. An adapter and two drilling spools were installed between the top of the blowout preventer and the base of the RCD. One of the drilling spools had outlets to connect to the 8-in. flow line and the injection of cold water across the top of the well. The purpose was to ensure heated fluids did not decrease the expected life span of the rubber sealing element. Between the wellhead and the geothermal separator, a globe valve was installed to regulate flow from the well to stem intermittent slugging from the annulus that was expected to occur. In the tophole section of the annulus, nitrogen becomes free to rapidly expand due to a decrease in hydrostatic pressure, resulting in slugging at surface. The globe valve was a simplified and recognized method of manually applying surface back pressure to control the release of this fluid. An 8-in. flow line and a geothermal separator with adjustable frame to match the shaker tank height complete the return flow system. The geothermal separator is where the nitrified drilling fluid is first exposed to open atmosphere and was designed to effectively allow the separation of nitrogen from the drilling fluid. This equipment employs the principle of centrifugal force for liquid-gas separation as in cyclone equipment. The nitrogen-free liquid then goes down to the shale shaker and back into the pits. The geothermal separator has 8-in. inlet and outlet flow lines, and the inside of the separator is lined to reduce erosion. Data acquisition equipment on-site recorded flow-out temperature and pressure. Also monitored were nitrogen injection pressure, temperature and flow rate. Nitrogen pump pressure must be high enough to entrain nitrogen in the stand pipe. All data was available and transmitted via the rig-site WITS network. Float subs were inserted to the top of the drill string to prevent the upward migration of nitrogen when the rig pumps were turned off. This increased safety, reduced wasted nitrogen and reduced time spent bleeding the drill string when making a connection. M AY / J U N E 2 0 1 2
4/12/2012 4:33:37 PM
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Onshore Drilling
Figure 4: A high nitrogen injection rate with a moderate fluid injection rate was established to reduce annular friction pressure, which is responsible for increases in the bottomhole pressure and the potential for fluid loss. An operational envelope was established at the 10 他-in. liner shoe that identified an optimal injection rate of 22.6 standard cu meters/min (800 standard cu ft/min) of nitrogen and 2,400 lpm of drilling fluid with a density of 1.02 sg.
DRILLING PROCEDURES A number of drilling procedures were drawn up aimed at increasing the preparedness of the rig crew for events that could occur and aid steps to reach TD as quickly as possible without taking shortcuts. These issues had to be addressed before operations commenced as many personnel were being exposed to closedloop and hydrostatic balance manipulation methods for the first time. This was a critical step toward ensuring personnel and equipment safety on the rig site and mitigating drilling hazards. Drilling with nitrified fluid creates scenarios that conventional drilling operators may not be familiar with. Therefore, procedures were translated into German and circulated to the relevant people. In addition to normal UBD operation procedures, rig crew were presented with the information that would allow them to react to equipment failures, well control and ESD events in which the presence of nitrogen would be a factor to consider. Another critical factor to account for was the communication between rig floor and the nitrogen injection crew. Standard rules for radio communication and reporting were established.
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OPERATIONS The GT 1 open-hole section was drilled in two phases using four UBD runs. Initially, UBD Runs 1 and 2 were drilled from the 10 他-in. liner shoe at 3,664-meters to 4,503-meters MD. A subsequent acid job and well test proved unsatisfactory, so the UBD separation and nitrogen injection packages were rigged up again. UBD Runs 3 and 4 were drilled from 4,505-meters MD to 4,937-meters MD.
UBD RUN 1 This run was conducted from 18-25 February 2011. A 3-meter rat hole was drilled beyond the 10 他-in. liner. The run initially started well with full returns and a low nitrogen rate, which kept the operation slightly overbalanced. Nitrogen injection rates were gradually increased to 14 cu meters/min and held steady at this rate as the UBD system was effective in lowering the equivalent circulating density. Although this is below the initial model predictions, this left room to increase if desired. On 23 February, it was found that LWD transmissions were very noisy, and signals were not received with a nitrogen flow rate over 12 cu meters/min. A com-
promise was made to maintain flow rates to ensure adequate data transmission from the tool to the surface. This effectively increased the ECD and ESD, and the system was not truly underbalanced at all times, but it enabled the rig to continue drilling in the given circumstances. Foaming issues became a problem on 19 February due to the reaction of the drilling fluid polymer (xantin gum) with nitrogen. The initial solution of adding a defoaming agent proved to temporarily solve the issue, but the problem persisted and the system became unmanageable. The decision was taken to completely replace the drilling fluid in the pits with fresh water without any polymer. Although this was not ideal, returns were recorded on surface, and it helped decrease the daily costs for drilling fluid. On 25 February, with ROP consistently low at 1 meter/hr, the decision was made to pull out of hole and change the bit. At this point, the bit had spent 96 hrs on bottom. An average instantaneous ROP of 11.6 meters/hr across for this run was recorded, which was decreased by the time spent drilling with the greatly deteriorated bit.
UBD RUN 2 A second UBD run was started with a new bottomhole assembly run in hole on 26 February. On this occasion, LWD signal transmission was greatly improved at nitrogen injection rates of 16 cu meters/ min. LWD data transmission was lost on 27 February at a depth of 4,219-meters MD. Neotec calculated ECD and bottomhole pressure in line with LWD output prior to end of transmission. The decision was taken to continue to drill ahead without MWD directional guidance. From here on, knowledge of bottomhole conditions was solely based on the calculated model, which until this point had tracked MWD readings with great satisfaction. For this run, increased emphasis was placed on pit volume tracking. It was in this bottomhole section that significant formation fluid gains were taken while drilling UBD as the reservoir was induced to flow to surface. Increased torque was experienced while backreaming before connections from a depth of 4,320-meters MD. TD was called at 4,503-meters MD on 2 March 2011. Due to the lack of MWD guidance, the planned hole trajectory was not properly followed. Cave systems and M AY / J U N E 2 0 1 2
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Onshore Drilling pronounced fractures along the well path explain periods of diverse drilling parameters and pit volume changes. Traditionally, cave systems add complexity to UBD jobs as they can cause both high fluid gains and losses at surface. These may have been a location of temporary cuttings storage. On flowing the reservoir when pulling out of hole and during the wiper trip, this may have been a source of cutting re-injection back into the annulus. An average instantaneous ROP of 8.5 meters/hr was recorded for this run.
and nitrogen was realigned to pump down the drill string. The presence of this concentric casing, however, was beneficial for the fact that the annular pressure drop was decreased, making it easier to lift cuttings out of the hole. At 4,540-meters MD, a short trip was performed, and the string was pulled back to 3,555-meters MD. Annular nitrogen injection was halted, and the opera-
tion resumed with just drill pipe injection. Injection rates of 2,000 lpm drilling fluid and 10 cu meters/min nitrogen remained optimal values for maintaining adequate fluid return rates to continue drilling. Return rates were typically 50% of volume pumped, which was typically calculated to be a loss of 60 cu meters/hr. The high loss rate is attributed to the acidizing job that was performed after UBD Run 2. The increase in size of fissures
UBD RUN 3 UBD Run 3 started after the stimulating and test work done in the well gave unsatisfactory results, and the decision was made to extend the well to try to reach the main fault. This time CPD was paramount to get returns while circulating as the losses were above 140 cu meters/hr, and the available supply of water was 60 cu meters/hr. Early attempts to initiate full conventional circulation failed, with the rate of fluid losses to formation too high to maintain the required surface pit volume to continue drilling. Drilling eventually commenced with the sourcing of additional water supply. On 17 April, annular injection started with a two-phase fluid of water and nitrogen being pumped between the 20-in. surface casing and 13 3/8-in. concentric casing. As this operation progressed, nitrogen injection was gradually increased as drilling fluid injection was decreased. This continued until it was possible to just pump nitrogen in the annular cavity. The rig pumps were then realigned to start pumping drilling fluid down the drill string, and rotary drilling commenced. This dual-injection method worked initially with optimal rates of 2,000 lpm of drilling fluid and 10 cu meters/min of nitrogen. A decision was made to investigate the effect of increasing annular nitrogen injection from 10 cu meters/min to 20 cu meters/min. This proved less optimal, and the nitrogen rate was returned to 10 cu meters/min. However, this had the effect of essentially super-charging the annular cavity with nitrogen. As this nitrogen rounded the concentric casing perforations, high-pressure slugging resulted in the well blowing itself dry. Concentric casing injection was halted, M AY / J U N E 2 0 1 2
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Onshore Drilling (3,793.3-meters TVD) at 17:35 on 27 April 2011. An additional concern with the rig was the drill string weight approaching the maximum pulling capability of the rig.
LESSONS LEARNED
Figure 4: The initial planned well profile for GT 1 was changed when TD was extended. The scope was originally to drill the well underbalanced through the Malm reservoir carbonates to 4,720-meters MD to evaluate and exploit the geothermal properties of the reservoir. After four underbalanced drilling runs, TD was called at 4,937-meters MD. By extending the well depth, objectives were achieved. This was enabled by the use of controlled pressure drilling techniques.
and fractures led to increased permeability. A high proportion of fluid pumped from surface was lost to the formation, with nitrogen moving to the high side of the horizontal section, where it too was mostly lost to formation. It is believed some volume of nitrogen did return to surface, but this was very minor with respect to the volume injected. However, the presence of the nitrogen was responsible for decreasing the hydrostatic head sufficiently that some formation fluid influx was induced in the open-hole section above acidized zone. Further, nitrogen prevented sticking at tight spots along the well path that developed in the later stages of UBD Run 2. At 4,670-meters MD, drill pipe injection rates were increased to 2,500 lpm and 15 cu meters/min. A bit trip was called at 4,726-meters MD. The average instantaneous ROP for UBD Run 3 was 15.3 meters/hr.
UBD RUN 4 UBD Run 4 drilling commenced with fluid and nitrogen injection rates varying
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from 2,300 lpm to 2,500 lpm and 15 to 20 cu meters/min respectively. This run was rather uneventful compared with UBD Run 3. Average ROP for the section was 9.6 meters/hr. Improved returns were viewed, and this is likely due to the eventual plugging of fractures and fissures, as well as formation of skin on borehole walls. A number of pills were pumped after TD, and this helped clean the hole of a large quantity of cuttings. The drill string became stuck while pulling out of hole, and the re-introduction of nitrogen was found to aid the recovery. Reduction of differential sticking is a long-recognized benefit of UBD and previous wells in this locality have all run into pipe stick problems at shallower depths. The temperature of returns at surface was noticeably below that experience on UBD Runs 1 and 2. This is a strong indicator that water was being produced from above the acidized zone at shallower depths. LWD data is the best source for bottomhole temperature comparisons. TD was called at 4,937-meters MD
Problems stemmed from the MWD/ LWD failure in UBD Run 2 and the decision to drill on. Several points were noted regarding the tool build, and MWD/LWD tool performance at high pump rates for UBD Runs 3 and 4 was greatly improved. Electromagnetic measurement-whiledrilling tools were cost-prohibitive but would have not suffered annular fluid composition-related interference. In the end, improved tool design was sufficient, and perfect detection was recorded at the elevated pump rates. Additionally, the mud motor was changed from 6 5/8 in. for UBD Runs 1 and 2 to 8 in. for UBD Runs 3 and 4. This also enabled a greater motor throughput, raising the ELV. While concentric casing injection was not a success in this case, its presence in the annulus for UBD Runs 3 and 4 indicated further analysis needs to be done for the concentric drilling method before applying it in the future. Without accurate flow detection rigged up on the flow line, watching pit volume gains and losses is crucial to understanding the downhole performance of the system. Foaming was not initially accounted for and provided some adverse drilling conditions. Preemptive and aggressive defoaming is essential for nitrified drilling fluid operations. In a very active system this is not always possible, but it is highly recommend. Using concentric casing carries a risk, which may not be worth the investment in rig modification as the drill pipe injection method used on GT 1 has proven successful. It is strongly advised to employ this method on future UBD wells in this region. The application of multiple float subs and NRV’s greatly reduced time spent bleeding nitrogen from the drill string once the rig pumps were shut down. The GT 1 well introduced UBD technology to the rig crew and other service companies, which inevitably caused some confusion and problems, especially when adding the language barrier between the rig crew and the UBD crew. This is expected to greatly improve in future M AY / J U N E 2 0 1 2
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Onshore Drilling operations where the rig crew has a better understanding of the equipment and techniques used during UBD operations. The knowledge that the UBD crew has acquired of the rig and the location will also aid in improving future operations.
CONCLUSION The scope of this operation was to successfully drill the GT 1 well underbalanced through the Malm reservoir carbonates to a depth of 4,720-meters MD to evaluate and exploit the geothermal properties of the reservoir. After four UBD runs, TD was called at 4,937-meters MD. The expected test results were not achieved on the first attempt, but after extending the well to its final TD of 4,937 meters, the well objectives were accomplished. The use of CPD was a key factor for the efficient drilling of the extension. UBD techniques enabled GT 1 to achieve a greater depth than any known well previously drilled in this locality. Additionally, the ability to achieve 100% returns is a vast improvement over con-
ventional techniques previously applied in the area. Total loss situations were avoided on UBD Runs 1 and 2. Ultimately, UBD permitted GT 1 to be drilled to a point where well testing could be possible with reduced formation damage due to the invasion of drilling fluid solids. While the original well path was changed, drilling the longest open-hole section in the Malm reservoir allowed it to hit all the planned targets, providing significant information about the target reservoir. Moreover, extending the well TD to 4,937-meters MD in the Malm reservoir allowed a significant achievement by hitting the main fault in the area at +/- 4,900-meters MD. Achieving this objective will greatly aid future drilling in the region as well. All of this would have not been possible without the aid of nitrified drilling fluid mitigating drilling hazards and lowering the annular hydrostatic pressure head. The injection of nitrogen into an annular space created with a concentric casing string needs to be carefully planned
and considered in the well design, otherwise it will lead to problems with the surface equipment due to irregular underbalanced conditions. The use of annular pressure and temperature sensors can greatly assist in the determination of the rate of nitrogen to be pumped during drilling and can show influx/loss zones. Although CPD was not used in the GT 2 and GT 2a wells, it was ready to be deployed and was considered as the technical solution to continue drilling if severe losses would have appeared. It is recommended to include early in the planning stages of the well design in geothermal projects in the area the use of CPD as an option to allow the reaching the well objectives in case total losses appear. This article is based on SPE/IADC 156895, “Successful Controlled Pressure Drilling Application in a Geothermal Field,” 2012 SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition, Milan, Italy, 20–21 March 2012.
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4/12/2012 4:33:59 PM
Onshore Drilling
Onshore MPD system enables lower mud weights for challenging wells Automated system incorporating rig pump diverter yields improvements in South Texas, Haynesville wells BY J. MONTILVA, J. MOTA, R. BILLA, SHELL EXPLORATION & PRODUCTION COMPANY Figure 1: Compared with a conventional well (left), drilling with casing underbalanced (right) allowed a liner to be eliminated by drilling in the 5 ½-in. liner and the 3 ½-in.-by-2 7/8-in. production casing. The new well plan also reduced the number of drilling days to 28 on the first well, compared with a typical 58 on conventional wells.
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I
n the development of onshore gas fields, Shell has encountered margins in which the difference between dynamic equivalent circulating density (ECD) and static bottomhole pressure (BHP) is the difference between lost circulation and influx. The limits imposed by those conflicting conditions create narrow mud weight windows. The reasons for the tight pore pressure and fracture gradient windows in these vertical and horizontal onshore high-pressure, high-temperature (HPHT) tight gas environments vary. Some are old fields challenged by depletion. In the case of South Texas, the main problem is losses in the production hole due to depletion. The pressure in different zones is often difficult to predict due to complex geology, further complicated by years of commingled production without knowing
what each zone has contributed. In some new shale plays, such as the Haynesville, slim-hole well plans are used, which have problems with low kick tolerance design and unexpected kicks through fractured intervals. These pose unique well control challenges to minimize nonproductive time. In all of these wells, there is the high cost associated with losing mud and/or constantly changing mud weights to prevent losses or influxes. To mitigate these potential problems, Shell has recognized the use of managed pressure drilling (MPD), which enables the use of the lowest possible mud weight to drill these challenging wells. By lowering the mud weight and manipulating the annular pressure during drilling, the risk of mud losses and/or quick sudden transitions into overpressured zones is reduced. There are some direct benefits M AY / J U N E 2 0 1 2
4/13/2012 11:08:13 AM
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4/9/2012 12:41:06 PM
Onshore Drilling
Figure 2 (left) shows an example of a connection while drilling in the 3 ½-in. production casing. The min/max window for ECD during this connection was 0.3 ppg (+/- 0.15 ppg). The steady flow of gas from the well causes backpressure to slowly rise. Figure 3 (right): The operational parameters during cementing operations for the 3 ½-in. drilled-in casing were controlled by the MPD system. The ECD remained between 16 ppg and 15.85 ppg by regulating the backpressure with the rate at which the cement was displaced in the drill pipe.
of drilling with lower mud weight, such as higher rate of penetration (ROP), lower stand pipe pressures and lower circulating temperatures. In addition, there are lower ECD and higher pump rates that improve the hole cleaning. Field trials using a fully automated MPD solution were performed by Shell in South Texas and North Louisiana Haynesville from late 2010 to mid-2011. This article describes implementation of a fully automated MPD, small rig footprint system. It incorporates a rig pump diverter (RPD) for smooth transitions from circulating to non-circulating downhole during connection while maintaining continuous rig pump circulation. In this article, results will be presented that show how drilling with lower mud weights impacted well performance. Additionally, a comparison of vertical and horizontal HPHT wells that were drilled conventionally and wells drilled using MPD show the effects of drilling with lower mud weights on ROP, downhole circulating temperature, ECD, stand pipe pressure and pump rate.
BACKGROUND Shell has operated gas fields in South Texas for more than 50 years. These 10,000-ft to 16,000-ft HPHT wells normally have initial shut-in tubing pressures approaching 10,000 psi when virgin sands are completed. Most wells have multiple low permeability pay sands, which require hydraulic fracture treatments to produce economically. Severe
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pressure depletion intermingled with high-pressure sands is often encountered. For years, casing and liner drilling with statically underbalance (SUB) mud was used to reduce losses. This worked fine in tight reservoirs because you could take advantage of the low permeability and the solubility of gas in oil-based mud to drill with the ECD profile without taking significant flow during connections. However, this does not work in higherpermeability rock that would experience flow and pressure build-up while making connections. As the desire to drill with even lower mud weights due to increasing depletion occurred, Shell turned to automated MPD to drill more permeable reservoirs with SUB mud without influx. In 2008, Shell began drilling in the North Louisiana Haynesville, which lies between 12,000-ft true vertical depth (TVD) to 15,000-ft TVD. As the play moves south, it is deeper and becomes considerably hotter. The southern Haynesville formation yields bottomhole circulating temperatures that exceed 360°F during landing and drilling the long horizontal sections. The bottomhole pressure can also exceed 11,000 psi.
UNDERBALANCED DRILLING WITH CASING The underbalanced drilling with casing approach was first applied to a slim-hole reentry program that began in 1995. These wellbores were sidetracked out of existing 5-in. or 5 1/2-in. casing, and a new string of 2 7/8-in. casing was run and
cemented. By 2000, remaining reentry candidates were difficult to drill because of the high ECDs that caused lost circulation and well control problems. Drilling with casing while underbalanced was applied to resolve these problems. The low permeability of the Vicksburg sands allowed operations with a higher underbalance than would be possible in most other applications. The learnings from the reentry program were transferred to the drilling of new wells. Drilling new wells with casing while underbalanced enabled the casing program sizes to be reduced, eliminated liners and reduced cost, resulting in savings of approximately 30% to 50%. A comparison between a conventional well plan in an offset well and a drilling with casing underbalanced well plan is shown in Figure 1. A liner was eliminated by drilling in the 5 1/2-in. liner and the 3 1/2-in.-by-2 7/8-in. production casing. The intervals were drilled conventionally halfway through the shallower formations, stopping above the problematic zones to allow for open-hole logs. After running logs, the problematic zones were drilled in. A constant 20-ft to 30-ft flare was observed while drilling the deeper high-pressure sands. The conventional well plan was typically drilled in 58 days. By drilling with casing underbalanced, that was reduced to 28 days on the first well. After that, drilling with casing using SUB mud became normal practice for South Texas wells.
M AY / J U N E 2 0 1 2
4/12/2012 4:36:52 PM
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Sliplifter
4/9/2012 12:40:21 PM
Onshore Drilling
Figure 4 (left) and figure 5 (right) illustrate typical data output when using the rig pump diverter (RPD) to make a connection during managed pressure drilling. Figure 4 tracks the setpoint pressure calculated by the hydraulics model against the actual pressure held by the chokes. Figure 5 tracks the three flow rates: rig pump rate, RPD flow rate and choke flow rate. The values are used to calculate the injection rate, which is the volume of fluid going down the hole. When the diversion begins, the injection rate decreases until the system is fully diverted, signaling that it is safe to make a connection.
EARLY MPD SYSTEMS Automated MPD was chosen to extend the application of casing drilling from the typical Vicksburg fields to the more permeable Frio reservoirs in the McAllenPharr field. Compared with other nearby fields in the Vicksburg formations, those in the Frio have substantially higher permeability. A limiting factor in the McAllen-Pharr field is the ease with which losses occur in many of the reservoir sands due to depletion (lower minimum horizontal stress). The resulting narrow pressure profile and the inaccurate pore pressure predictions had complicated Shell’s early drilling efforts with excessive lost circulation and well control events. The use of liner drilling was limited in the field because of the high level of uncertainty about the pressures and permeabilities that would be encountered. Early on it was seen that the permeability of some reservoir sands was high enough to allow the gas to flow during connections when the mud is statically underbalanced. That limited the amount by which the mud weight could be reduced and the effectiveness of liner drilling. To extend the benefits of drilling with casing, Shell sought a different way to avoid losses in the shallow depleted sands while drilling with the higher ECD needed to avoid influx in the deeper permeable reservoirs. The company had already decided to use MPD to manage similar problems in mature offshore fields, so it became a matter of adapting the technology to onshore conditions. The automated MPD system that Shell was using in the deepwater Gulf of Mexico was adapted for onshore operations. It included a choke manifold, a
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backpressure pump and a Coriolis flow meter. A high-pressure rotating control device was used to provide the drill pipe seal. After drilling the first wells, Shell started looking for ways to optimize the system. The focus was on ways to reduce the size and weight of the manifold to make it easier to handle, transport and rig-up. An important modification to the original MPD system was to eliminate the backpressure pump that was a main source of nonproductive time. The new system consisted of a modular choke manifold and a Coriolis flow meter. A rig pump was used for additional flow as needed to boost the level of the trapped pressure. A principle benefit of the modular system’s small footprint and easy handling is the amount of time required to rig-up. In one well, the MPD crew rigged up the modular system in seven hours, which was 60% faster than the time it took to rig-up the system on the previous job and 85% faster than the average two days it took to rig-up the first full MPD system used on earlier McAllen-Pharr wells. This MPD system was used during conventional drilling and drilling with casing operations. The typical plan for the 6 1/2in. production hole was to drill with drill pipe the first part from the 7 5/8-in. casing shoe (about 8,700-ft MD) down to about 10,500-ft MD, and then drill in the casing in the second part to total depth (about 11,200-ft MD). The primary objective in the first part of the 6 1/ -in. section was to drill through the depleted sections below the shoe, minimizing the mud weight. Accomplishing this objective allowed significant savings by eliminating the need for a 5 ½-in. con2
tingency liner. The objective for MPD in the second part was to minimize the ECD to avoid losses and manage the gas while drilling in the casing in the payzone, where the pore pressure was at least 1.5 ppg greater than the maximum already drilled. The system was used to manage the ECD while drilling in the 3 ½-in. casing and hold constant BHP during connections. One of the rig pumps was hooked up to the kill line to help manage the BHP and preserve the trapped backpressure by injecting mud into the annulus during connections. An example of a connection while drilling in the 3 ½-in. production casing is shown in Figure 2, which shows that the min/max window for ECD during this connection was 0.3 ppg (+/- 0.15 ppg). The slowly rising backpressure is due to the steady flow of gas from the well. One final task after drilling in the 3 ½-in. production casing was to cement the casing in place. The trick was to avoid losing returns with the heavy weight cement. The cementing operation was modeled using a constant pump rate of 3 bbl/min for the entire job. A controlled procedure using the MPD system was followed to regulate the backpressure for a fixed volume of fluid displaced into the drill pipe. That procedure carefully governed the effect that the 16.2 ppg cement had on the ECD as it filled the annulus. Careful regulation of the reduction in backpressure with the cement pump rate and close cooperation between the MPD and cementing crew resulted in successful cement jobs without losses. Figure 3 shows the plot of the operational parameters during cementing M AY / J U N E 2 0 1 2
4/13/2012 11:11:42 AM
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4/10/2012 4:24:21 PM
Onshore Drilling Figure 6 (top): The effect on performance using the different drilling methods and continued casing downsizing shows the improvement from conventional to drilling with casing with managed pressure. Performance improved with less nonproductive time and optimized rate of penetration. Figure 7 (bottom): By utilizing a simplified underbalanced drilling technique, performance was improved from 2008 to 2010 as the rate of penetration increased and drilling time decreased significantly.
operations for the 3 ½-in. drilled-in casing. The MPD system controlled the ECD between 16 ppg and 15.85 ppg by regulating the backpressure with the rate at which the cement was displaced in the drill pipe. Another application of MPD in South Texas was to use the system during liner drilling operations. MPD was used to manage the ECD in the 8 ½-in. hole section while drilling in with a 7 5/8-in. liner assembly from 9,550 ft to 10,448 ft. The objective was to drill the severely depleted formations situated below the 9 7/ 8-in. casing shoe without losses by using MPD to manage the ECD and using the drill-in liner to eliminate the need for heavy kill muds. Coarse calcium carbonate as background LCM and in sweeps was also used while drilling this interval. Part of the challenge was in the nature of the pressure prediction, because both the fracture gradient and pressure prediction were estimates that would be verified by actual drilling conditions. In addition, the use of liner drilling did not allow the use of a pressure-while-drilling (PWD) tool; therefore, control was based on the hydraulics model integrated into the control system.
NEW MPD APPROACH The previous MPD experiences were done using either a backpressure pump (BPP) or the rig pumps to help manage
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the BHP and preserve the trapped backpressure utilized during connections. A major issue with the BPP and rig pump is the ramping up and down between the rig pump and BPP or rig pump during connections. A fault in synchronization could result in backpressure spikes and lead to well control events, not to mention the big footprint of the BPP, which makes it difficult for mobilizing/rig-up and to operate. In late 2010 and early 2011, before Shell sold its South Texas assets, the company conducted a successful field trial on five wells using the MPD concept with RPD technology for making connections. The main feature of this new concept is that the RPD was designed to eliminate the need to shut down rig pumps during connections. By diverting the flow from the standpipe side to the annular side of the well, the automated choke can precisely keep BHP under control, eliminating borehole breathing effect during connections. During the field trial period for all of the South Texas wells, Halliburton’s MPD package was used. It consisted of an automated choke skid, Coriolis meter skid, RPD manifold, data acquisition system (DAS) and the necessary pipe packages. A total of five trial wells were identified as good candidates to apply the MPD
concept with the RPD method for making a connection. The first trial well was PFWU 59 in the Pharr field. The drilling objectives were considered to have been fully met. It was possible to drill the depleted sands with no losses and no well control situations. It was also possible to run 2 7/8-in. casing and cement it place using MPD technology. The biggest gain from this trial was the degree of comfort and receptiveness of the MPD/RPD technology by field personnel, which was a main driver to continue the trial. Figures 4 and 5 show the typical data output using the RPD to make a connection during MPD. Figure 4 tracks the setpoint pressure calculated by the hydraulics mode. Figure 5 details the three flow rates tracked during each connection sequence: rig pump rate, RPD flow rate and choke flow rate. The software then uses these values to calculate the injection rate, which is the volume of fluid going down the hole. When the diversion begins, the injection rate decreases until the system is fully diverted and it is safe to make a connection. The four candidates were Slick 225, Slick 227, Slick 228 and Slick 229. All these wells are in the Slick Ranch Field. Using the MPD concept allows for reduction in mud weights compared with conventional drilling and consequentially reduces the ECD. This reduces the risk of M AY / J U N E 2 0 1 2
4/12/2012 4:37:01 PM
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4/9/2012 12:42:21 PM
Onshore Drilling
Figure 8 (top) provides an example of a connection made while drilling conventionally while Figure 9 (bottom) shows a connection for a well drilled using the MPD automated system with a rig pump diverter.
losses during drilling and improves ROP. Using the MPD with RPD techniques significantly improved rate of penetration by up to 93% compared with offset wells, which were drilled conventionally. Overall, the average number of drilling days for the section was reduced from seven days per well using conventional drilling to 3.24 days using MPD system with RPD technique. Figure 6 shows the overall effect on performance (days/1,000 ft) using conventional drilling, drilling with casing with SUB, and drilling with casing with MPD. These techniques allowed the continued casing downsizing and the effect of improved time because of nonproductive time reduction and ROP optimization.
SIMPLIFIED UNDERBALANCE TECHNIQUE In North Louisiana, horizontal wells targeting the Haynesville shale have been drilled conventionally using a simplified underbalanced technique. A rotating control device and the gas buster are used while drilling the curve through the Bossier and Haynesville shales because
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of the high risk of encountering gas kicks in these sections. While drilling, the flow from the well is diverted through the rig choke line with one open choke to the gas buster, and the flow is returned to the shale shakers before reaching the estimated depth of a potential kick. With the flow routed through one fully open choke, the friction loss through the choke creates about 100 psi of surface backpressure (SBP). Any fluctuation in this pressure provides an additional indicator of increased flow from the well for kick detection. If a gas kick enters the wellbore, the increased friction through the choke will increase the choke gauge pressure and will therefore indicate that a kick is in progress. If this pressure increase occurs, it will give indication of a kick prior to either the flow sensor on the outlet of the gas buster or the pit volume increase occurs. When a kick is believed to be in progress, the driller will pick up off bottom to prepare to shut in the blowout preventers (BOP). The sequence of events should be essentially the same as a normal shut-in, except the BOP is closed before stopping the pump. The kick is then circulated out using the driller’s method. Experience has indicated that kicks come from trapped gas in fractures and are limited in total volume. This procedure is designed to restrict and control the kick coming into the well rather than stopping it. The kick is “strung out” in the wellbore by maintaining flow and can be managed at surface within the fluid-handling ability of the surface equipment. This approach also allows drilling the lateral section with a lower mud weight. As a result, the ROP increases and drilling time has been reduced significantly (Figure 7).
MPD IN NORTH LOUISIANA HAYNESVILLE Based on the positive results obtained using underbalanced mitigating well control events, decreasing mud weight and increasing ROP, a field trial implementation of MPD using RPD during connections was undertaken in the North Louisiana Haynesville. The main objectives were to: • Improve kick detection without compromising the rig choke (keeping it as a backup for well control);
• Cut the mud weight lower than the conventional historical values; • Increase the ROP; and • Reduce the time associated with handling well events in the production hole. The main components of the automated MPD system used in this project were the same as those used in South Texas: • Automated choke system; • RPD; • DAS; • Rotating control device; •Atmospheric mud gas separator; and • Piping for both high- and low-pressure lines for use upstream and downstream of the MPD chokes. There were two important modifications to improve the system. The first one was the inclusion of a high closing ratio valve to tie in the RPD upstream of the stand pipe. The benefit of this new valve is that the isolation of the stand pipe during the connection is done automatically from the drill floor. In the MPD system used in South Texas, this isolation was done closing the manual standpipe valve. The second modification was to take the mud returns through the mud cross, installing a “T” with a second HCR valve. Depending on which HCR valve was close /open, the mud returns could be circulated either through the MPD choke or the rig choke. The benefit of this modification is that, in a kick event, after the well is shut in, the kick could be circulated either through the rig choke or the MPD choke. One advantage of the MPD system is that it allows continuous monitoring and evaluation of real-time drilling data via time- and depth-based plots. This enabled a 24-hr manned, trained crew to detect pressure abnormalities in the drill string by monitoring the stand pipe pressure and at the annular side by monitoring auto-choke behavior, presure-whiledrilling data, drill gas, connection gas, trip gas and bottomhole temperature. The MPD crew also monitored rig tank levels, losses and gains. Besides their continuous monitoring of drilling data, the MPD crew also set limits on what data should not exceed or go below and set alarms around those limits. This early kick detection system is able to identify abnormal conditions with the use of Coriolis meters while drilling or circulating. It was developed to allow rapid response to any unpredicted change in the mud flow or pressure. M AY / J U N E 2 0 1 2
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Onshore Drilling During the course of drilling the selected wells, the MPD crew was the first to notice drilling and pressure abnormalities and immediately bring it to the attention of Shell’s foreman and toolpusher. Two kicks were detected while drilling the curve in the other two MPD wells: • The automated MPD system detected the first influx while drilling the curve at 13,210-ft MD in the second MPD well. The MPD supervisor reported the kick to the driller and Shell foreman. The well was shut in to 280-psi casing pressure. Choke was opened; pressure was bled off. Gas and bottoms up were circulated before resuming drilling. The well was checked for flow, but no flow was detected. • The second kick was also detected when drilling the curve at 13,434-ft MD in the third MPD well. After an increase in flow was detected, the well was shut in, and a pit gain of 12 bbls was reported. The well was monitored for 30 min until pressures stabilized, with the recorded shut-in drill pipe pressure and shut-in casing pressure as 350 and 800 psi, respectively. The gas influx was circu-
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lated out through the rig choke, and a 5- to 15-ft flare was observed. After the influx was circulated out, the system was lined up and diverted back through the MPD system. An oil-based drilling fluid was used to drill the production section, and mud weights ranged from 12.8 ppg to 15.0 ppg. A brief summary of the mud weight strategy is below: • Conventional well: The curve was drilled conventionally using a typical mud weight of 14.4 ppg, but it was necessary to increase it to 15 ppg while drilling the lateral. This change impacted the initial mud weight selected to be used in the first two MPD wells, and a higher initial mud weight was used instead. • MPD well No 1: The curve was drilled conventionally using a mud weight of 14.5 ppg, and the mud weight was decreased to 14.0 ppg at the end of the curve. The lateral section was then drilled using the automated MPD system, decreasing the mud weight in stages to 13.8 ppg at about 15,000-ft MD. No surface backpressure was required while
drilling, and an equivalent mud weight (EMW) of 14.4 ppg was maintained at the shoe during connections. • MPD well No 2: The curve and the lateral section were drilled using the automated MPD system. Although lower mud weights were used in this well (14 ppg for the curve and 13.6–13.4 ppg for the lateral), no SBP was required during drilling either. The same EMW of 14.4 ppg at the casing shoe was maintained during connections. • MPD well No 3: The automated MPD system was used in both the curve and lateral sections. A mud weight of 13.6 ppg was used to drill the curve, and it was decreased up to 12.8 ppg to drill the lateral section. Surface backpressure was required while drilling and during connections to maintain a constant BHP when drilling with 12.8 ppg static mud weight. PWD is not commonly run because of factors such as additional cost and higher risk of having a “lost in hole” when drilling problematic zones. PWD was used during this field trial to measure if a constant BHP could be maintained during
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Onshore Drilling
Figures 10-13 (from left): Figure 10 compares the mud weight in and PWD data versus measured depth for the conventional well and the three MPD wells. Mud weight was decreased progressively for each of the MPD wells. For the same four wells, Figure 11 plots the mud weight in and pump rate versus MD. It illustrates a correlation between lower mud weights and higher pump rates. Figure 12 shows the average ROP vs MD for the wells while Figure 13 shows bottomhole temperature vs MD. The graphs show that lower mud weights and higher pump rates generate higher ROPs and lower bottomhole temperatures. Lower temperatures help mitigate the risk of downhole tool failures in high-temperature environments, such as in the Haynesville Shale.
connections using the automated MPD system with RPD. Two different connections are discussed below: one during conventional drilling and the other while implementing MPD with the RPD. Figure 8 illustrates a connection made while drilling conventionally. Tracks 1 and 2 indicate that a connection is being made. Track 3 shows that the mud weight in is 15 ppg, and it corresponds to a PWD EMW of approximately 16.1 ppg. When making the connection, the PWD EMW drops to 15.09 ppg; therefore, the pressure fluctuation generated once the pumps are off corresponds to 1.0 ppg. Minimum and average annular pumps off EMW are lining up on top of the 15.09 ppg, indicating the minimum pressures that occurred during the pumps-off cycle and the static mud weight were the same during the connection. The maximum annular pumps off EMW is about 16 ppg, which is capturing the maximum pressure that occurred during the pumps-off period. Figure 9 shows a connection for the third well drilled using the MPD automated system with RPD. The applied SBP was about 500 psi in this case. The mud weight in was 13.5 ppg, and the target equivalent BHP at the control depth was 14.4 ppg. The lateral section was being
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drilled at this point, and the heel of the curve was the control depth. Three variables are on top of one another almost all the time during both drilling and connection: target equivalent BHP at control depth, actual calculated equivalent BHP at control depth and PWD EMW. Because the PWD sensor was closer to the bit, the TVD does not change much and the frictional pressure losses do not start to increase considerably at this depth. The established limit for the SBP was 900 psi. Because a lower mud weight was used for this well, the model indicated that to compensate for surge and swab, the SBP could exceed the 900 psi while drilling the lateral. A decision was made not to enable the surge and swab mitigation option to try to maintain the SBP within the upper limits. As a result, in the last track, the pressure fluctuations generated were about 0.2 to 0.3 ppg for about 2 to 3 min, which was not a problem in this case because the difference between the equivalent BHP created by these pressure fluctuations and the shoe strength was considerably high. This was captured as a lesson learned, and it will be improved in future MPD wells. Figure 10 shows the mud weight in and PWD data versus measured depth for the conventional well and the three
MPD wells. The graph illustrates the mud weight strategy described previously. The mud weight was decreased progressively from Well 1 to Well 3 while the wells were drilled, and the automated MPD system proved an effective and safe tool to drill the curve and the lateral sections. The PWD data is also shown for the four wells, and it can be observed that the equivalent BHP was decreased from 15.4 to 14.2 ppg in the curve and from 16.0 to 16.4 ppg to 14.3 ppg in the lateral section. The PWD data has more variations for the first two MPD wells because no SBP was required to maintain the target BHP while drilling. For the third well, these pressure fluctuations are minimized because a lower mud weight was used and surface backpressure was required during drilling and connections. Figure 11 shows the mud weight in and pump rate (gpm) data versus MD for the conventional well and the three MPD wells. There is a correlation between lower mud weights and higher pump rates. With lower mud weights, the stand pipe pressure is also lower because the pump is lifting a lighter mud column. This lower standpipe pressure provides room to increase the flow rate. Figure 12 shows the average ROP versus MD for the four wells. The combinaM AY / J U N E 2 0 1 2
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Onshore Drilling tion of lower mud weight (less solids in the mud) and higher pump rates (better hydraulics) generates higher ROP. The ROP increased mainly while drilling the lateral, but this still resulted in a reduction of drilling days. Two key factors contributed to this: Different mud weights were used for the various wells at different depths, and significant directional work was required (sliding) while drilling the curves of the MPD wells. After 16,000-ft MD, the average ROP for the conventional well was about 10 to 20 ft/hr. This average ROP increases up to 50 to 80 ft/hr when looking at the three MPD wells. Higher pump rates also provide the benefit of better hole-cleaning that allows less solids to be kept in the hole that could help to generate less torque and drag and better transmission of weight to the bit. Figure 13 shows the bottomhole temperature versus MD for the four wells. The combination of lower mud weights (lower friction) and higher pump rates (cooling effect) generates lower bot-
tomhole temperatures. When drilling in high-temperature environments, such as the Haynesville shale, lower bottomhole temperatures could help to mitigate the risk of downhole tools failure, so it could potentially avoid tripping to replace damaged tools. At 16,626 ft, there was a decrease in the bottomhole temperature of the well 17-2H (solid red line). The reason was that the hole was circulated for a period of 9.5 hrs. After the circulation period, the bottomhole temperature of the well started increasing consistently. There was a MWD failure in the conventional well at 15,764 ft. It correlates with a high temperature spike of 331°F. It is the most probable root cause of the MWD failure. It took 63.5 hrs to get back to drilling. The curve was drilled faster in the conventional well compared with the other three wells. This is due to additional directional work required (more sliding) to drill these curves, which is mainly influenced by geology. The lateral section was drilled in about 12.2 days in the conventional well. The three lateral sections
of the MPD wells were drilled in 4.7, 5.7 and 6.3 days, respectively. This results in a reduction of 62%, 53% and 48% for each well, having an average reduction of 54% for the drilling days.
CONCLUSION Shell used different technologies onshore South Texas and North Louisiana Haynesville to optimize operations where conventional drilling would be too expensive and unsafe. A fully automated MPD system allowed a smooth transition from circulating to non-circulating downhole during connection while maintaining continuous rig pump circulation. This article is based on IADC/SPE 156909, “Onshore US MPD Use by an Operator,” presented at the 2012 SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition in Milan, Italy, 20–21 March 2012. References and additional images for this article are available online at www. DrillingContractor.org.
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M AY / J U N E 2 0 1 2
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D R I L L I N G CONTRACTOR
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Offshore Activities & Outlook
Global deepwater exploration sustains strong rig activity Emerging East African markets add to strength of Golden Triangle BY JERRY GREENBERG, CONTRIBUTING EDITOR
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Offshore Activities & Outlook
T
wo years have passed since the twin Montara and Macondo blowouts. While Macondo obviously disrupted US Gulf of Mexico drilling in all water depths, deepwater exploration and rig activity remained robust elsewhere. Today, Gulf of Mexico drilling is steadily improving, as operators, contractors and regulators come to grips with post-Macondo realities. Elsewhere, driven by healthy commodity prices and by numerous deepwater and ultra-deepwater discoveries, including in new or relatively new areas such as East Africa and the Mediterranean, the global deepwater drilling scene is more than satisfying for operators, contractors. There also have been new discoveries near established areas, such as southern Angola. Petrobras, now the center of the universe for deepwater drilling, seemingly announces a new discovery weekly.
GULF OF MEXICO REANIMATION One of the more established regions, the US Gulf of Mexico, is steadily returning to pre-Macondo levels of deepwater and ultra-deepwater drilling activity. Rig activity is anticipated to reach pre-Macondo levels by the end of this year and continue growing as more rigs are scheduled to arrive during 2013. Further, operators now have a better idea what the US Bureau of Safety and Environmental Enforcement (BSEE) and the Bureau of Ocean Energy Management (BOEM) require to approve plans for exploration and drilling permits. Other events that could portend increased drilling activity are a recent successful Western Gulf OCS lease sale and a deepwater maritime boundary agreement with Mexico. “By the end of this year, we expect activity in the deepwater (US Gulf) to be similar to the pre-Macondo level,” said Tom
Transocean’s Deepwater Millennium is performing an accelerated well testing program that includes installing observation gauges and conducting several drill stem tests for Anadarko’s natural gas wells offshore Mozambique. Photo courtesy of Anadarko Petroleum
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D R I L L I N G CONTRACTOR
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Offshore Activities & Outlook
Photos courtesy of Noble Corp
Left: The Noble Globetrotter I is undergoing customer acceptance testing before beginning a 10-year contract with Shell. Right: The Noble Jim Day, a dynamically positioned semisubmersible rated to drill in up to 12,000 ft of water, will begin working for Shell under a three-year contract in January 2013.
Kellock, senior manager, research, for IHS Petrodata. “We are looking at a net gain of about 12 rigs this year, and it’s possible there could be more next year. “The increase is basically rebuilding what we had before (Macondo),” he continued. “We are not looking for a huge increase over the pre-Macondo level. This is not a sudden surge of new activity.” “A few more (rigs) are scheduled for delivery in 2013 that already have drilling contracts to work in the Gulf,” said Cinnamon Odell, analyst, rigs, for IHS Petrodata. “There are more (deepwater rigs) that are scheduled to be delivered next year that do not yet have contracts that are potential candidates to work here.” On the other hand, she noted, not every operator will have contracted a rig to work exclusively for them. “While there still is a lot of demand and still more room in the region for more floaters, some of the demand might be filled by subletting rigs already in the area,” Ms Odell said. Virtually all deepwater activity ceased post-Macondo. However, sublet activity recently began increasing, especially for leases that are nearing their expiration, she added. “Rig-sharing contracts, which have been more popular in other parts of the world, are definitely gaining popularity in the Gulf,” Ms Odell said. “Ensco signed a rig-sharing contract among three operators, Anadarko, Apache and Noble Energy, for its newbuild Ensco 8505 semisubmersible.” Ensco also has rig-sharing contracts for its Ensco 8500 semisubmersible with Anadarko and Eni, and for the Ensco 8501 with Nexen and Noble Energy.
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The US Gulf rig market has morphed into a shelf market and a deep- and ultra-deepwater market. The mid-water market, generally below 3,000 ft of water, is virtually non-existent. All three mid-water depth semisubmersibles remaining in the Gulf are cold-stacked. Mid-water semisubmersibles in the past have mobilized to other regions, including Europe, Australia, Southeast Asia and India, Ms Odell said. According to figures from BOEM, 23 drillships and semisubmersibles were drilling in the deepwater and ultra-deepwater Gulf in water depths up to about 8,100 ft. Table 1 illustrates deepwater drilling activity as of 26 March for water depths of 1,000 ft and greater.* * Editor’s note: BSEE and BOEM, the agencies succeeding the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), which itself superseded the US Minerals Management Service, offer slightly different definitions for “deepwater.” Table 1 in this article, whose source is BOEM, cites 1,000 ft as the cut-off, the same criterion used by BSEE in its deepwater production summary by year. However, in BSEE’s GOM well permit web page, 500 ft is the limit. 500 ft was also the cut-off used by the Department of Interior when it issued its deepwater drilling moratorium in 2010. Ironically, following Macondo, IADC proposed 1,000 ft as the defining depth. Please see the QR codes at the end of this article for links to the cited pages.
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Offshore Activities & Outlook Operator
Rig Name
Lease Prospect
Water Depth (ft)
Petrobras America Inc.
ENSCO DS-5
Cascade
Shell
DEEPWATER NAUTILUS
Chevron
DISCOVERER INSPIRATION
Saint Malo
7,040
Chevron
DISCOVERER CLEAR LEADER
Jack
6,960
BP
DEVELOPMENT DRILLER II
Atlantis
6,834
LLOG
NOBLE AMOS RUNNER
Noble Energy
ENSCO 8501
BP
SEADRILL WEST SIRIUS
Kaskida
6,031
Cobalt International
ENSCO 8503
Ligurian
5,837
Anadarko
DISCOVERER AMERICAS
Heidelberg
5,260
Chevron
DISCOVERER INDIA
BIG FOOT
5,187
BHP Billiton
GSF C.R. LUIGS
Shenzi
4,337
Chevron
DISCOVERER DEEP SEAS
Tahiti 2
4,292
BHP Billiton
DEVELOPMENT DRILLER I
Shenzi
4,270
Shell
NOBLE DANNY ADKINS
Vito
4,004
Shell
NOBLE DRILLER
Europa
3,797
Anadarko
ENSCO 8500
Nansen
3,681
Nexen Petroleum
ENSCO 8502
Kakuna
3,600
BP
DISCOVERER ENTERPRISE
Nile
3,535
Shell
NOBLE JIM DAY
Serrano
3,400
Statoil
MAERSK DEVELOPER
Kilchurn
3,146
Shell
NOBLE JIM THOMPSON
Llano
2,514
ExxonMobil
DIAMOND OCEAN VICTORY
Zinc
1,458
8,143 7,157
6,427 Bob
6,060
Source: BOEM
Table 1: Gulf of Mexico deepwater drilling activity as of 26 March 2012.
DRILLING PERMIT APPROVAL TIMES According to BSEE, offshore permitting is nearly at preMacondo levels. The agency said 61 deepwater new well drilling permits were granted in the 12 months ending 27 February 2012, just six fewer than from February 2009 to February 2010 before the Macondo explosion. This analysis, however, overlooks the fact that the approximately 18 months leading up to the disaster was a time of severe downturn for the industry because of the Great Recession. For example, the number of total well permits (shallow and deep) issued for the Gulf of Mexico during the sluggish 2009 was 294.
By the end of this year, we expect activity in the deepwater (US Gulf) to be similar to the pre-Macondo level.” Tom Kellock IHS Petrodata
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For bustling 2007, the count was more than twice that – 618. During 2008, as the economy began staggering, 541 permits were approved. These numbers obviously also encompass shallow-water drilling (see Editor’s Note for conflicting definitions). And for shallow water, rate of permit approval falters. BSEE’s website states that, as of 12 April, “122 shallow-water well permits have been issued since the implementation of new safety and environmental standards on June 8, 2010.” BSEE says six of those were pending, and eight had been returned to the operator for more information. Granted, soft natural gas, the principal target in shallow water, may well have retarded permits in those water depths. Still, given current commodity prices and the strong offshore activity apparent elsewhere, comparing today’s permit level with the number issued during the depths of the greatest recession in two generations creates a poor analogy. BSEE also says that it is reducing time for approvals and has cut average number of days to approve a new well drilling permit by about one-third. The result, however, remains well above than before Macondo. BSEE said that, in 2009, the Minerals Management Service averaged 46 days to approve a new well deepwater permit. From March 2011 to September 2011, those figures more than doubled, with BSEE averaging 97 days to approve a new well deepwater permit. However, BSEE said that, M AY / J U N E 2 0 1 2
4/12/2012 4:41:09 PM
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Offshore Activities & Outlook Year
High Deepwater Rig Dayrate
2002
$222,750
2003
$225,000
2004
$230,000
2005
$318,500
2006
$475,000
2007
$528,000
2008
$629,000
2009
$629,000
2010
$650,000
2011
$703,000
2012
$703,000
DAYRATES UP FOR DEEPWATER AND ULTRA-DEEPWATER RIGS
Source: IHS Petrodata
Table 2: Dayrates for deepwater rigs have risen steadily over the past decade.
Photo courtesy of Noble Corp
The Noble Max Smith will relocate from the US Gulf to Brazil to work for Shell. The rig was working for PEMEX offshore Mexico prior to its current contract.
from September 2011 to mid-March 2012, approval times for new-well deepwater permits averaged 62 days. BSEE director James Watson defended the agency’s performance in written testimony on 7 March before an Appropriations Committee Subcommittee. His testimony regarding the agency’s
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federal fiscal year 2013 budget request, said “the permitting environment is completely different” than before the Macondo blowout. “Comparing the pace of permitting pre- and postDeepwater Horizon does not consider the current reality that applications must now meet a suite of new requirements that receive extremely close scrutiny by the bureau’s engineers.” People who believe that the pace of permitting should automatically be the same as before the Deepwater Horizon accident “are ignoring the lessons of that disaster,” Mr Watson said.
Dayrates for semisubmersibles and drillships in the Gulf generally range from the high $300,000s to the low- to mid$500,000s, but there are indications that drilling contractors could see significantly increased dayrates when these contracts expire and new agreements are put into place. An example of dayrates, according to contractor fleet status reports, is $530,000 for the Noble Jim Day semisubmersible,under contract to Shell from January 2013 through January 2016. The rig, which is rated to operate in up to 12,000 ft of water, will drill several wells at similar rates prior to returning to Shell. Another Noble semisubmersible, the Noble Driller rated to drill in up to 5,000 ft of water, is contracted to Shell from late July 2011 through early June 2013 for $375,000/day while the 6,000-ft rated Noble Jim Thompson is contracted to Shell for $362,000 from April 2011 to early December 2014. And the Noble Globetrotter I, a newbuild deepwater drillship, is contracted to Shell for 10 years beginning from April 2012 to March 2022 at an initial rate of $422,000. Ensco also has an active semisubmersible and drillship fleet in the Gulf, with dayrates ranging from the $290,000s to the mid-$500,000 range. Three of the company’s five semisubmersibles contracted to work in the Gulf are receiving above $400,000/day, including one unit being paid about $545,000/day. Its most recent delivery, ENSCO 8505, was contracted for about $474,000/day under a rig-sharing agreement. Additionally, the ENSCO 8506, expected to be delivered this summer, will mobilize to the US Gulf for a contract with Anadarko at about $530,000/day. The contract expires in June 2015. The company’s lone drillship in the region, the ENSCO DS-5, is contracted to Petrobras America at a rate of about $430,000/ day through July 2016. The rig also is eligible for bonuses up to 17%. Transocean has 10 drillships and four semisubmersibles in the Gulf, with most dayrates falling in the range noted earlier. However, the company has a few dayrates that significantly exceed that range. The Deepwater Champion, delivered last year, is contracted to ExxonMobil and recently drilled a discovery well in the Black Sea. Its dayrate was reported by Transocean as $690,000/day while operating in the Black Sea, although there were reports that the rate was about $703,000/ day. The rig will mobilize to the Gulf this spring and command a dayrate of $640,000 until the end of its contract in September 2015. Another Transocean drillship, Deepwater Expedition, was contracted to BHP Billiton and Petronas Carigali for work offshore Malaysia at a rate of $650,000/day. However, that contract was terminated, and the rig now is contracted to M AY / J U N E 2 0 1 2
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Offshore Activities & Outlook an undisclosed operator and location for $640,000/day from November 2012 for two years. The agreement also has three one-year extension options at $695,000/day. The Deepwater Expedition was built in 1999 and is rated for operations in up to 8,500 ft of water. While there are only a handful of rigs being paid above $600,000 daily, examples of rigs contracting for dayrates approaching $700,000 could portend good news for drilling contractors as deepwater and ultra-deepwater rigs become scarcer, despite several deepwater drillships still under construction and available. For example, Noble Drilling currently has three ultra-deepwater drillships for delivery in 2013 and 2014 that currently are available. Ensco also has one ultra-deepwater drillship set for delivery in the second half of 2013. And Rowan Companies, with it first three ultra-deepwater drillships under construction for delivery during 2014 and 2015, could be a recipient of increasing dayrates. The above dayrates are not only good news for Gulf of Mexico drilling contractors but for rigs contractors operating in virtually every deepwater basin around the world. Table 2 illustrates the dayrate gains made globally during the past 10 years.
U S, MEXICO MARITIME BOUNDARY AGREEMENT COULD SPUR MORE DRILLING Last February, the US and Mexico signed an agreement on the exploration and development of oil and natural gas resources along the ultra-deepwater maritime boundary. The Transboundary Agreement removes uncertainties regarding development of about 1.5 million acres of the US OCS that is estimated to hold up to 172 million bbl of oil and 304 bcf of natural gas. It also opens up resources in the so-called Western Gap that were off-limits to both countries under a previous treaty that imposed a moratorium along the boundary through 2014. The agreement establishes a framework for US operators and PEMEX to either jointly or individually develop the transboundary’s reservoirs on their respective side while protecting national interests and resources.
Discoveries continue to be made, and appraisals turn out positive in most cases, so (Brazil is) still an exciting area in terms of ongoing and increasing activity.” Tom Kellock IHS Petrodata DEEPWATER AREAS AROUND THE WORLD While the US Gulf is an important deepwater region, it’s not the only. There are still the other two points in the Golden Triangle – Brazil and West Africa – as well as several emerging deepwater markets such as Tanzania and Mozambique in East Africa.
BRAZIL It seems that Petrobras and other operators exploring deep waters offshore Brazil announce a new discovery every week. “Discoveries continue to be made, and appraisals turn out positive in most cases, so it’s still an exciting area in terms of ongoing and increasing activity,” Mr Kellock said. Between 23 February and 20 March, Petrobras announced at least three new discoveries, in water depths of 7,050 ft, 9,148 ft and 6,650 ft. In anticipation of continued exploration successes, the company recently completed negotiations with Sete Brasil and Ocean Rig to contract as many as 28 new deepwater drillships and semisubmersibles to be built in Brazil, with a required local content ranging from 55% to 65%. Petrobras said the rigs would be used to meet the demands of its long-term drilling programs, primarily in pre-salt wells. It’s not yet clear who would manage and operate the rigs as Sete Brasil operates primarily as a financing entity for the rigs. The company was established
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Offshore Activities & Outlook Lars Nydahl Jorgensen, head of exploration for Maersk Oil, said the Azul-1 well in Block 23 was the “first deepwater well targeting pre-salt reservoirs in the Kwanza Basin. Preliminary interpretation of a drill stem test indicated a potential flow capacity over 3,000 bbl/day of oil. Maersk plans additional evaluation of the find, including more exploration drilling.” The discovery well was drilled during summer 2011 with Diamond Offshore’s Ocean Valiant, which has moved to a HESS contract offshore Equatorial Guinea. Cobalt International’s pre-salt discovery with the Cameia-1 well in 5,518 ft of water in Block 21 off Angola flowed 5,010 bbl of oil and 14.3 mcf/d of associated gas during a drill stem test. James Farnsworth, Cobalt’s chief exploration officer, said, “Based upon our analysis of the test data, if not limited by the test equipment on the rig, we believe the well would have the potential to produce in excess of 20,000 bbl of oil per day. In addition, we have yet to drill our deeper targets at Cameia, which, if successful, will provide additional upside potential.” The operator planned to drill the Cameia-2 appraisal well with Diamond Offshore’s Ocean Confidence, which was expected to take 100 to 120 days, followed by an evaluation period.
EAST AFRICA
Photo courtesy of Statoil/Heine Melkevik
The drillship Ocean Rig Poseidon is drilling at Statoil’s Zafarani location offshore Tanzania.
in 2010 by Petrobras, seven Brazilian finance investors including banks, and the four largest Brazilian pension funds. The ambitious construction schedule calls for rig deliveries within 48 to 90 months. The project also includes construction of new shipyards in Brazil, which is said to be the primary reason for building the rigs in Brazil. The initial announcement of the rig newbuilding program was made about two years ago; tenders were made, but Petrobras said the dayrates and costs were too high at the time. The new rigs to be built under the latest program are in addition to the rigs that Petrobras has under contract now, plus several newbuilds that the operator is contracting. But it’s unlikely that the 28 rigs will satisfy Petrobras’ requirements. “It wouldn’t surprise me if Petrobras needed additional rigs” after the 28 newbuilds are delivered, and to fill the gap until these rigs are delivered, said Julian Gunther, senior specialist, rigs, for IHS Petrodata. Just how busy Petrobras could be is illustrated in a recent contract for subsea trees from FMC Technologies. The initial call-off includes 78 trees and related equipment while the total scope of supply could include delivery of up to 130 trees. The equipment will be engineered and manufactured at FMC’s facilities in Rio de Janeiro, resulting in 70% local content. Deliveries are scheduled to commence in 2014.
Mozambique and Tanzania have become very active following announcements of several large gas discoveries. Statoil announced that it and partner ExxonMobil had proven up to 5 Tcf of natural gas in its Zafarani well in Block 2 offshore Tanzania in about 8,470 ft of water with Ocean Rig Poseidon, which will move to a well on the Lavani prospect in the same block. BG Group announced a fourth gas discovery from its Jodari-1 well in Block 1 off Tanzania, with gross recoverable reserves in the range of 2.5-4.4 tcf of gas. Mean total gross recoverable gas is estimated to approach about 7 tcf of gas. The well was drilled by the Deepsea Metro I, which will also drill the Mzia-1 well in Block 1. Offshore Mozambique, Eni has a huge natural gas find with its Mamba prospect in Area 4, estimated to hold at least 40 Tcf of gas as a result of its recent Mamba North East 1 well in about 6,060 ft of water that increased the resource base by about 10 Tcf. The earlier Mamba North 1 well encountered a potential of 7.5 Tcf of gas. Eni plans to drill four more wells this year. Anadarko also has had enormous success with its series of natural gas discoveries and appraisal wells offshore Mozambique and is planning an LNG facility to monetize the gas. The discovery wells and appraisals are being drilled by the Belford Dolphin drillship while Transocean’s Deepwater Millennium drillship is conducting drill stem and other tests. The wells so far have been drilled in water depths ranging from about 4,800 ft to 5,400 ft. Scan to view status of Gulf of Mexico well permits by BSEE
WEST AFRICA “There are two very exciting discoveries in the Kwanza Basin of Angola with two deepwater pre-salt discoveries where there has been virtually no deepwater drilling until very recently,” Mr Kellock said.
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Scan to view BSEE deepwater production summary by year
M AY / J U N E 2 0 1 2
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Offshore Activities & Outlook
Navigating safe waters Industry takes proactive approach to safety while anticipating GOM ramp-up BY KATIE MAZEROV, CONTRIBUTING EDITOR
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Offshore Activities & Outlook
B
ooming markets in West Africa, Brazil and areas of Asia Pacific are putting a bullish spin on the overall offshore outlook, with rising utilization and dayrates in all sectors, including shallow- and mid-water, deepwater and ultra-deepwater. But all eyes are on the Gulf of Mexico (GOM), where a wait-and-see attitude prevails as a host of new regulations and compliance measures â&#x20AC;&#x201C; with more anticipated -- take hold as deepwater activity begins to ramp back up following an exodus of rigs from the region in the wake of the moratorium. November 2011 marked the deadline for operators to implement and contractors to demonstrate capability to perform their work to meet the sweeping safety and environmental manage-
ment system (SEMS), a 13-section program mandated by the US Bureau of Safety and Environmental Enforcement (BSEE) that addresses all aspects of safety management, including training, hazards analysis, incident investigation, and emergency response and control. The regulation, requiring operators to establish SEMS, is based on API Recommended Practice (RP) 75, or SEMP, first written in 1993. But until November 2010, compliance with RP 75 was voluntary. The regulation requires operators to certify that their drilling contractors and other contractors have acceptable safety management and are capable of doing the work they are contracted to perform.
Diamond Offshoreâ&#x20AC;&#x2122;s sixth-generation Ocean Courage was delivered in 2009 and is working offshore Brazil. In the last 18 months, Diamond has moved several rigs out of the Gulf of Mexico; however, the company indicates that rigs will return to the Gulf by the end of this year.
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Offshore Activities & Outlook
The Ocean Valor, a sixth-generation ultra-deepwater semisubmersible, can drill wells to a depth of 40,000 ft in water depths up to 10,000 ft. The Diamond Offshore rig was delivered from Singapore in 2009 and is working offshore Brazil. Diamond has remained active in all the major deepwater regions following the Gulf of Mexico moratorium.
“Most major operators and drilling contractors have, for years, been running SEMS based on the principles of RP 75, which is good,” said Charlie Williams, executive director of the Center for Offshore Safety (COS). “There are some companies that did not have systems in place or had systems that needed improvement.” Launched in March 2011, the center’s mission is focused on the GOM, specifically deepwater, but it is also developing tools that will be used for the entire US Outer Continental Shelf. “The idea for the center came out of the API Upstream Committee and actually predated the Presidential Commission report that was issued post-Macondo,” Mr Williams said. “Until now, our work has been focused on developing a SEMS toolkit to assist people in complying with workplace safety rules.” But there are three key elements to the center’s overall purpose. The first involves auditing, building audit tools for SEMS, developing third-party auditor training programs and auditor certification, and auditing the auditors to ensure they are compliant with the SEMS requirements. The second is to develop good practices and tools that can help people build more effective SEMS. To that end, the COS is
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facilitating ongoing industry workshops, the first one on leadership. “This is important because one of the key drivers to developing a strong safety culture and building an effective SEMS is to demonstrate leadership and commitment in site visits,” Mr Williams said. “The people on the rigs must see company leaders embrace the program. You can have a great SEMS system, but people must be motivated to use it every day, all day long. It’s a constant journey of awareness.” A second workshop focused on ways to measure the effectiveness of SEMS, including measures to help detect incidents in advance or identify weaknesses in the system. Teams of industry professionals, formed at the initial workshops, are continuing to meet. The third element involves collecting data and measurements on incidents and good practices that can be used to gauge the overall health of the industry, information that can be shared within the industry and with BSEE. This will include data from audits to derive learning and help determine what needs to be improved. “The COS wants to bring people in the industry together to M AY / J U N E 2 0 1 2
4/12/2012 4:43:27 PM
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Offshore Activities & Outlook
Left: Diamond Offshore’s Ocean Victory semisubmersible continues operations in the US Gulf of Mexico for several major operators. It is Diamond’s lone semi operating in the US Gulf, where industry is pointing to a ramp-up of deepwater activity. Right: The fifth-generation ultra-deepwater Ocean Confidence is contracted for work offshore West Africa.
share information and lessons and determine if there are gaps to making the systems better,” Mr Williams said.
POSITIVE INDUSTRY RESPONSE Response to the COS has been positive, with most of the work thus far achieved by volunteers. The agency’s Board of Governors includes 22 representatives from all sectors of the industry. The intent is to get everyone to join, starting with companies involved in deepwater. “As we develop and expand, we’ll start signing up others,” Mr Williams said. Global interest has also been significant. “This is really a sys-
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tem about managing and delivering safety that can be applied anywhere in the world,” he stated. But uncertainty lingers as the regulations have not been finalized. “There are still questions on what the new BSEE rules will be, especially for blowout preventers,” said Moe Plaisance, vice president of contracts and marketing for Diamond Offshore Drilling and a member of the COS Board of Governors. “BSEE has also announced it is coming out with some additional regulations, so this issue has not been fully defined.” From Mr Plaisance’s perspective, SEMS has gotten off to good start and has not been onerous in terms of compliance. “We’ve
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May12-AD.EXPRO.indd 85
4/9/2012 12:45:34 PM
Offshore Activities & Outlook
The ultra-deepwater semisubmersible ENSCO 8505 heads for the US Gulf of Mexico, where it is contracted to Anadarko, Apache and Noble Energy. Ensco has five deepwater rigs and 11 jackups already working in the GOM.
had a very robust safety management system in place for many years at Diamond, and we have been able to get with our operators and bridge our system with theirs, which is what SEMS is designed to do,” Mr Plaisance said. “Our Global Excellence Management System (GEMS) is very compatible with SEMS.” He also believes that while SEMS has been an awakening for smaller operators, it has not been burdensome for the majority of companies that have had safety management systems in place for many years. What SEMS addresses is the human side of the safety issue, which is the most important factor, Mr Plaisance maintains. “It is still critical to have people trained to know how to respond to an event than try and overdo mechanical issues,” he noted. “The key point to realize is that the industry is moving ahead and putting our problems behind us in an exemplary manner.” Diamond has moved several rigs out of the GOM over the past 18 months. Whereas the company had 10 rigs operating in the region two years ago, it has only one now – the Ocean Victory, which is doing intervention and abandonment work in 1,500-ft water depths in the central GOM, Mr Plaisance said. The company had moved some rigs to the robust Brazil market prior to the moratorium; the rest were shifted after the slowdown and remain under contract with international customers.
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“We’ll see rigs start to come back by the end of the year and into the following year,” he predicted.
DAYRATES RISING Meanwhile, Diamond is active in all the major deepwater regions. “We’re very upbeat about the market with crude oil prices where they are now,” he continued. “The current wide differential between West Texas Crude and Brent is an indicator that markets are going to improve. Utilization is 100% of what we want to market.” Dayrates are rising through the spectrum of floating rigs, with ultra-deepwater prices from the mid-$500,000s to over $600,000, he said. Deepwater West Africa is a huge potential growth market, as evidenced by discoveries in Angola, along with continuing activity in the traditional West African countries, Mr Plaisance added. But East Africa is also on the rise, particularly with the success companies have had in Mozambique and Tanzania. “That’s been an area that, years ago, the industry wrote off as not productive. But we’ve found opportunities in the deeper waters,” he said. Diamond has one rig in Angola, one in Equatorial Guinea and one in Egypt, all big floating rigs. In North Africa, recent gas discoveries in Egypt, Israel and M AY / J U N E 2 0 1 2
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Offshore Activities & Outlook as operators gain confidence in the permitting process,” said David Hensel, Ensco vice president, North and South America. “Operators are now getting permits far enough in advance to effectively plan ongoing operations and avoid breaks in drilling programs. We have also seen increased demand, as evidenced by our contracts for ENSCO 8505 and ENSCO 8506,” he said. Earlier this year, the ENSCO 8506 entered a two and a half-year contract with Anadarko in the GOM, at a dayrate of $530,000 plus cost adjustments. Delivery is scheduled for the third quarter this year, with deployment anticipated for fourth quarter 2012. The ENSCO 8505 and 8506 rigs are the two final rigs in the ENSCO 8500 Series that began operations in the GOM in 2009, drilling the significant Lucius discovery for Anadarko. The rigs can be modified to drill and complete wells in water depths up to 10,000 ft.
FOCUS ON INTEGRITY
Although KCA DEUTAG does not have operations in deepwater or the US Gulf of Mexico, the company is taking a proactive approach to implement lessons learned from Macondo in offshore markets where it operates. Above, the company’s Beryl Alpha platform rig operates in the North Sea.
Cyprus are indicative of significant natural gas finds, which would provide opportunities for those countries to gain cheap domestic fuel for their industries and economies. Significant events in South America include discoveries by Brazilian independent OGX and ongoing development of the pre-salts by Petrobras. Diamond has 14 rigs in Brazil, the company’s largest area of operation. “Oil discoveries in French Guyana, along northern coast of the continent, analog with those in Ghana in West Africa,” Mr Plaisance said.
CONFIDENCE IN GOM PERMITTING “We’re seeing demand increasing in oil markets in the traditional North Sea region, particularly for mid-water, harshweather rigs,” he added. “There is also strong activity in Indonesia, Malaysia and Australia.” Diamond is increasing its ultra-deepwater capacity with three new drillships being built in Korea, as well as its deepwater capacity with the Ocean Onyx, which is currently in the AmFELS shipyard in Brownsville, Texas. Ensco has two rigs scheduled for deployment in deepwater GOM this year, including the ENSCO 8505 that is being outfitted in Corpus Christi and will begin working in the second quarter under a contract with Anadarko Petroleum, Apache Deepwater and Noble Energy. The initial contract term is for two years or two rotations per operator, whichever is longer, at a dayrate of $475,000 plus cost adjustments, the company announced last year. Ensco has five deepwater rigs and 11 jackups already working in the GOM, as well as four jackups working for PEMEX in the Mexican Gulf. “Deepwater activity in the GOM continues to strengthen
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Beyond the GOM safety regulations, the offshore industry as a whole has taken time out to revise, rethink and improve processes, rather than respond to countries or regions putting regulatory mandates in place, said Rodrigo Rendon, head of business development for international drilling contractor KCA DEUTAG. The company, which does not operate in deepwater or the GOM, is taking a serious and proactive approach in implementing the lessons learned from Macondo in its offshore markets in the Caspian Sea, Sakhalin Island in Russia, Azerbaijan, West Africa (Gabon, Angola and Nigeria), Mexico, the North Sea and Southeast Asia. “Whether we call it SEMS or whatever name, as an industry, there is a lot of focus on operational and technical integrity,” he said. “The most deliberate action we have taken is the creation of a senior vice president of operations position, one level below the board, that is ultimately responsible for this area,” he continued. “Under that position are technical authorities who have the last say on whether an operation goes forward or not and who will dictate operational procedures.” The company has also revised all its well control procedures and issued new well control guidelines and rules in the form of cards that are distributed to people on rigs, providing pragmatic directives on what to do in the event of an incident, he said. After hitting a low point a year ago, the shallow drilling market is fairly healthy in terms of dayrates and utilization, both of which are increasing. Mr Rendon attributes the uptick to stable oil prices that are giving operators confidence to undertake exploration and sanction projects going to development phases. “Our jackups are fully utilized with a good backlog of contracts. For traditional jackups, we are seeing rates above $100,000 per day,” he said. “Utilization is growing in Asia Pacific and Africa. West Africa continues to be a very good market, and now East Africa is beginning to gather some attention in all sectors – land, shallow and deepwater.” The company also has a healthy tender barge business, with two units coming off contract this year. Last year, KCA DEUTAG acquired Singapore-based Global Tender Barges, which significantly bolstered the company’s mobile offshore drilling unit division, Mr Rendon noted. The company is also engineering a design for a semisubmersible tender assist. ENSCO 8500 Series is a registered term of Ensco plc.
M AY / J U N E 2 0 1 2
4/12/2012 4:44:02 PM
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4/9/2012 12:48:40 PM
Offshore Activities & Outlook
Dashboard concept aims to facilitate diagnostics, decision-making on BOPs High-level ‘traffic light’ status would allow users to know when critical functions are impaired BY JIM MCKAY, ALLEN PERE, BP; CLAYTON SIMMONS, MIKE DOTY, NATIONAL OILWELL VARCO; TONY HOGG, ENSCO; GAVIN STARLING, ROCK OILFIELD GROUP Figure 1: Traditional MUX BOP control system diagnostics are geared toward maintenance and troubleshooting more than operational decision-making. A BOP dashboard concept is being studied that would improve communications among operations personnel, contractors and the OEM to assess BOP health issues.
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A
s every motorist knows, a vehicle’s dashboard is an important interface that alerts the driver of real-time changes regarding certain car engine “health” metrics and alerts the driver that the engine may need to be serviced. While not a diagnostic tool in and of itself, the dashboard serves to alert the driver that a performance or health issue may exist. Blowout preventer (BOP) equipment is designed to secure the well, and a BOP’s health is critical to ensuring that it works as designed. A real-time BOP dashboard can improve communication between operations personnel, rig contractor subsea engineers and the original equipment manufacturer (OEM) to assess potential BOP health issues. This article describes a development process for a BOP dashboard and dis-
cusses the potential benefits, challenges and lessons learned associated with implementing a BOP monitoring system. Traditional multiplex (MUX) BOP control system diagnostics (Figure 1) are designed by OEMs for use by personnel proficient in BOP control systems, such as a rig contractor’s subsea engineer. Control system diagnostics are generally geared toward maintenance and troubleshooting system problems more than operational decision-making. Traditionally, the BOP diagnostic data is solely available at the rig-based engineering work station (EWS), also known as the event logger. Historically BOP data is not exchanged to shore from the offshore event logger. The industry could benefit from having BOP control system integrity or BOP health presented in a manner that allows operations people M AY / J U N E 2 0 1 2
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Offshore Activities & Outlook (offshore and onshore) to participate in communication with BOP experts to assess any risk associated with the BOP and the BOP control system.
THE CONCEPT The BOP dashboard (Figure 2) aims to simplify complex BOP diagnostics in an easy-to-understand format that facilitates a joint assessment of the issue. In early 2011, BP, Ensco and National Oilwell Varco (NOV) collaborated on a project to consider preliminary development of a BOP dashboard that takes existing alarms, analog data and events from the BOP EWS and translates them into a high-level “traffic light” status. The traffic light logic is based on levels of system redundancy that allow the user to understand when critical functions are impaired. The first phase of the project focuses on the electrical components of the control system, with further extension to the hydraulic components in the subsequent phases of the project. Although the initial
dashboard would rely solely on the NOV eHawk platform, the end product could be a BOP monitoring dashboard incorporated into a mud-logging network. When integrated with the common mud-logging database, the BOP data could be interconnected with other realtime well construction systems, such as digital BOP pressure-testing technology. If a BOP health issue should arise, the OEM web platform can provide additional layers of detail beyond the dashboard. These additional layers should provide the user the same screens that are already available in the offshore BOP diagnostic system. Such a system can also be designed to allow near real-time archiving of raw BOP data on an onshore computer and can produce a BOP health report. Although this system is not designed for or intended to be used for continuous monitoring, the end user can view the dashboard at any time, and reports summarizing alarm and event information can be sent automatically to select users.
Thus, this system could be a useful tool for well-site leaders (including the company man), offshore installation managers or shore-based operations teams. For example, operations teams could use this system to review applicable BOP health attributes prior to each daily rig call.
SOFTWARE, HARDWARE DEVELOPMENT AND INSTALLATION In this project, the EWS must be configured to allow for data export to the eHawk server. Although historically SQL data was used, NOV determined that the interoperability standard for automation (OPC) provided advantages for configuration. OPC has the ability to queue data and push an initial state for BOP positions and outstanding alarms. This is important when data transfer is lost or upon initial installation of the BOP monitoring system. OPC simplified the configuration by not requiring manual entry of outstanding alarms and initial positions into the eHawk database.
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Offshore Activities & Outlook
Testing: Pressure 12/2/2010
Read Back Pressure to Element Health Y B
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Figure 2: Several companies have looked at developing a BOP dashboard that aims to simplify complex BOP diagnostics. The dashboard would take existing alarms, analog data and events from the BOP engineering work station and translate them into high-level traffic light status. The traffic light logic is based on levels of system redundancy that allow the user to understand when critical functions are impaired.
Figure 3 shows a simplified system diagram of the connection between the EWS, the eHawk server and the relevant Sitecomm server. For the installation, NOV had to update the OEM drawings to show the new connection from the EWS and the eHawk server. The BOP control system had to be recertified from American Bureau of Shipping to reflect this change.
‘TRAFFIC LIGHT’ DEVELOPMENT The OEM holds the unique system knowledge required for traffic light logic development. For example, the OEM can provide guidance on the meaning of alarms and system redundancy. The operator and rig contractor can define the levels of risk that would be associated with each level of traffic light. Originally three automated tiers of colors were envisioned to provide the health status of the BOP. “Red” status would mean no functionality, “yellow” status would mean functional but no redundancy, and “green” status would be fully functional and with redundancy. As the BOP owner, the rig contractor
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may wish to retain the ability to manually change the traffic light severity due to the potential for false-positive or falsenegative traffic lights. For example, it is possible that due to interdependencies between alarms, a minor alarm could also trigger a more severe alarm. In those instances, the dashboard traffic lights can be manually changed from a more severe status to a less severe status. The manual override can be done for a specific alarm, and the related traffic lights will be identified by an “F” indicating the traffic light was forced to a more or less severe status. To manually force or clear any alarm, the user is forced to enter a description that details the reason for the force. In addition to a management of change process, this information allows for future review and oversight. The forcing of alarms, not traffic lights, allows subsequent alarms to change a traffic light status with an “F” to an increased severity level. In addition, the user can scroll over a traffic light to view the outstanding alarms and to identify those alarms that were forced.
Different parts of the control system may have different levels of redundancy. In this project, at a minimum, redundancy for a specific BOP function is required for the traffic light to be green. An example of redundancy is the use of dual pods (yellow and blue). An example of dual redundancy would be communications to the pods. Each pod receives redundant communications, and the pods themselves are redundant; hence each pod receives a spare communication link to the surface control system. For the BOP system, if the component is shared by the pod, then redundancy is required. If the component is specific to the pod, then redundancy is not required. The current traffic light logic development used in this project omitted alarms related to the hydraulic system data (Phase II) or minor alarms (e.g., stuck push button alarms).
DASHBOARD GUI DEVELOPMENT When developing the graphical user interface (GUI) for the dashboard, the target users were assumed to include both experienced subsea engineers and those on an operations team with only a rudimentary knowledge of the BOP control system. Starting in the top left of the dashboard and working to the bottom right, the following design requirements were built in the dashboard for this project: • Top left – The last test date for auditing purposes will be manually entered and recorded. • Upper left – Leaks and hydraulic issues will be detected with logic (Phase II development) and reported with a traffic light status. • Lower left – Emergency systems status will be based on the solenoid valve health. • Bottom left – Event log data will capture raw commands in a table with volumes, times for the activation and the location of the command. • Bottom left – Outstanding alarms will capture raw alarm data, the time of the first alarm, the number of alarms in the last 24 hours, time of the last alarm acknowledgement and location of the last alarm acknowledgement. • Bottom left – MUX fiber will report multiplex fiber health based on existing alarms. • Bottom left – Surface alarms and M AY / J U N E 2 0 1 2
4/13/2012 11:15:54 AM
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Offshore Activities & Outlook BP Mud Logging Dual SiteCom and Dweb Servers
MWD/LWD
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NOV eHawk
MONITORING AND DECISION-MAKING
Copper to Fibre Convertor
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EWS
Drillers PLC
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BLUE SUBSEA ELECTRONICS ASSEMBLY
YELLOW SUBSEA ELECTRONICS ASSEMBLY
Figure 3: The engineering work station, or event logger, had to be configured to allow for data export to the eHawk server. This figure shows a simplified system diagram of the connection between the EWS, the eHawk server and the relevant Sitecomm server.
subsea alarms will report all alarms and sort them based on the location of the equipment. This will allow the user to understand if the BOP stack should be pulled in the event of a yellow health status on a specific BOP function. These are envisioned as all-inclusive alarm traffic lights regardless of redundancy or alarm severity. This will also allow the user to understand if a minor alarm has been triggered. • Middle left – Read back pressures will report the analog pressure for each specific function closing pressure. For
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• Right – Chronology log will display the positions and the overall health of the system over a 24-hr period. If the user is not constantly monitoring the BOP dashboard, they can look back at a high level to understand if the BOP was functioned or if there was a BOP health issue.
example, this will allow the user to understand if the closing pressure was increased to obtain a seal. • Middle – BOP function health separated by yellow and blue pods. Each major BOP function will have a displayed traffic light health indicator for each pod. The active pod will be indicated by a traffic light that is 50% larger than the non-active pod. • Middle – BOP positions will be viewable by colored circles and blocks that animate physical position of the rams, annulars and subsea BOP valves.
The real-time BOP dashboard will only be used as a communication tool by facilitating conversation between operations teams on BOP health issues. The primary diagnostic system will remain the original rig-based OEM EWS. The workflow process (Figure 4) requires that the EWS be used to confirm the dashboard before making any decisions. One item that the project considered in the workflow process was the need to avoid uncontrolled distribution of data to individuals that may not fully understand the significance of various alarms. Not all alarms are equally important, and this distinction must be addressed when working with the dashboard. Part of the pilot intent is to develop a decision tree protocol (Figure 5) where operations teams can make standard operation decisions. This will help eliminate the potential for subjective BOP health resolutions. Ideally, all BOP health scenarios would be mapped with a decision tree; however, it is more realistic to assume that some alarms will not fully reflect the true health of the BOP. Once an alarm is triggered, the rig crew will need to confirm the BOP health issue by troubleshooting the issue. For example, if a MUX fiber signal triggers an alarm indicating fiber degradation, the crew will be able to perform a decibel loss test to confirm the issue. For this version of the console, the decision protocol was set at a level to allow operations teams to determine the health status and remedial action. By allowing the user to manually change the health rating, the user can override the automated traffic light logic. In time, as the diagnostic system and traffic light logic is accepted by the operations teams, the ability to manually override the BOP health status may be eliminated. For example, a future operations decision tree could have a defined scenario that requires the BOP to be pulled if a blind shear ram solenoid valve becomes inoperable. M AY / J U N E 2 0 1 2
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Offshore Activities & Outlook
Figure 4: The primary BOP diagnostic system will remain the rig-based OEM EWS, with the real-time BOP dashboard used as a communication tool for facilitating conversations between operations teams on BOP health issues. The workflow process requires that the EWS be used to confirm the dashboard before making any decisions.
Health Status is Yellow
Is the Fault and Traffic Light Status Correct?
Yes
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Manually Change the Health from Yellow to Green
Has Dual Redundancy Been Lost on a Critical Function?
Yes
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Dual Redundancy Criteria: - Two independant methods of communicating to the Pods - Ability to activate the function from each Pod
Short List of Critical Emergency System Functions: 1) Blind Shear Ram 2) Casing Shear Ram 3) Riser Unlatch 4) Riser Latch – Vent 5) EHBS / AMF
Not Functional F
Forced Health Status (Green, Yellow, or Red)
Figure 5: A possible operations decision tree for the pilot shows where operations teams can make standard operational decisions. This would eliminate the potential for subjective BOP health resolutions. Ideally, all BOP health scenarios would be mapped with a decision tree.
PILOT PROGRAM The milestones for the pilot program will be: 1. Sending alarm and event data back to shore.
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2. Developing a working dashboard. 3. Potentially using the dashboard for decision-making and learning from that experience. As stated previously, Phase I of the
technology will focus strictly on the MUX electrical system; however, Phase II will include hydraulic diagnostics. Digital security processes and hardware are long lead items that require M AY / J U N E 2 0 1 2
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careful planning for the first installation. An installation plan cannot be finalized until rig surveys are complete. The monitoring system can only be installed between wells when the BOP is on surface. The major challenge and learning in this pilot program will be when the rig contractor and operator disagree on the BOP health status or the proposed remedial action of a BOP health issue. As this technology is adopted, it is anticipated that these situations will be addressed through agreed upon policies and procedures or decision trees.
THE WAY FORWARD The hydraulic system will be addressed in Phase II by creating high-level traffic lights for leak detection and pressure vessel health. Leak detection methods include mix pump cycles, hydraulic fluid usage and flow measurements. In addition, each BOP function uses a specific volume that can be measured and compared with a previous baseline for leak detection. Advancing the diagnostics with better sensors or algorithms will further develop the BOP dashboard. Ram position sensors, tool joint position sensors, BOP cameras and additional BOP wellbore pressures are examples of potential sensor upgrades. The BOP dashboard data can eventually be integrated with the digital BOP pressure testing. This will allow the rams that were functioned to be identified for the pressure-testing data. Numerous key performance indicators (KPI’s) also can be calculated as more real-time data is gathered. For example, the number of cycles on a solenoid valve or the frequency of successful annular pressure tests can be captured. These KPI’s and other collected data might eventually be shared amongst the industry through existing organizations, such as Offshore Reliability Data. This collective industry data can provide more robust fault tree analysis that could potentially provide real-time probability of “failure on demand” when certain functionality is lost.
DRILLING CONTRACTOR PERSPECTIVE As the “big crew change” begins, more and more of the highly experienced subsea engineers are transferring to shoreM AY / J U N E 2 0 1 2
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based, or auditor-type, positions, challenging the industry to develop competent replacements. A well setup dashboard, supported by an agreed detailed decision tree, will allow these shore-based experts to better assist the rig-based subsea engineers to diagnose any problems, to discuss the issues with their client counterparts and to decide the most sensible path forward. The BOP dashboard will not reduce the need for development and training of the rig-based subsea engineers. The BOP dashboard can only report the “health” of the system. It cannot, by itself, do anything to maintain its condition; this has to come from the allocation of sufficient time and resources, between each well, to properly maintain and test all of the subsystems. This equipment can only be maintained and operated to the standards to which it was designed and manufactured (API 16D 2nd Ed.), regardless of the ease of monitoring afforded by the BOP dashboard. Improvements in BOP and BOP control system designs by the OEMs will be important factors in realizing future reliability enhancements.
OEM PERSPECTIVE Transferring the most up-to-date and accurate information back to the OEM allows the company to design more reliable equipment, as well as provide appropriate support to the customer. In the past, this was done over the phone, by email or required travel to the rig. Using this tool, OEMs can look at BOP information in near real time and better assist in decisions regarding the safe and proper operation of the equipment.
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SUMMARY A BOP dashboard that simplifies existing diagnostics and allows for remote monitoring of the subsea BOP control system will improve communication of BOP health. Future deployments of the BOP dashboard could serve as a common platform across rig fleets that allow standardization of BOP diagnostic data and aids in operational decision making. This article is based on IADC/SPE 151182, “Blowout Preventer (BOP) Health Monitoring,” presented at the 2012 IADC/SPE Drilling Conference and Exhibition, San Diego, Calif., 6–8 March 2012.
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Offshore Activities & Outlook BACKGROUND The operator’s affiliate in the UK North Sea, Mobil North Sea, is the operator for the Beryl, Ness, Nevis, Buckland and Skene fields, which constitutes the Beryl field. Other co-venturers in the development include Centrica, Hess, Shell and OMV. The field is approximately 200 miles northeast of Aberdeen. Production from the Beryl field started from the Beryl Alpha platform in 1976, and the Beryl Bravo platform started production in 1984. Subsea developments include Ness, Nevis North and Nevis South, where wells are tied back to the Beryl Alpha platform and date back as far back as 1996. Three newer subsea fields were developed starting in 2001, including Buckland, Skene and Lewis 1, which is an extension of the Nevis South Development. The water depth is approximately 360 ft (Figure 1). In 2007, the North Sea Beryl Drilling Campaign was temporarily suspended to reevaluate the drill-well inventory. In 2010, a semisubmersible was contracted for a five-well redevelopment campaign, which consisted of two workover operations and three abandonment and sidetracks. The operations involved reentry of wells having horizontal spool trees and vertical trees. All drilling operations required reuse of the existing wellhead, slot recoveries requiring cut and pull of casing, and whipstock sidetracks.
MOORING AND HEAVY LIFT CONSIDERATIONS The mooring design for any location is subject to many factors, which change over the life of a field. All mooring design loads are defined by the metocean conditions defined for a given area. In the North Sea, the metocean criteria used as a design basis for mooring designs have evolved, resulting in more conservative environmental criteria at locations such as the Beryl field. This is not necessarily due to actual worsening weather conditions. Rather, the quality and accuracy of metocean data, hindcasting methods and the numerical models used to develop the design criteria have all improved. Further, the assessments have become site-specific to fields within the North Sea, and the databases continue to grow with new data. As a result, the metocean data quality and analysis has improved, and the
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mooring designs will be affected. For the Beryl field, this has resulted in current mooring designs being assessed using more stringent metocean criteria than used for prior campaigns. An expanding footprint of subsea infrastructure creates a further challenge to maintain sufficient vertical clearance of mooring lines from the subsea infrastructure. For an older field, where new wells may not have been drilled in a long time, routing of subsea flowlines, equipment replacement and general field maintenance may cause the footprint of the subsea infrastructure to grow. In the absence of an active drilling campaign, the ability of a mobile offshore drilling unit (MODU) to position over the modified infrastructure and maintain adequate clearances to the infrastructure may not have been fully evaluated. For mooring lines that span over subsea infrastructure, it is common to establish a minimum tension requirement to maintain the required vertical clearance. However, with more stringent metocean criteria as the assessment basis, along with a growing subsea infrastructure footprint, specifying a high minimum tension to protect flowlines may not result in appropriate mooring analysis results. A mitigation that can be employed is use of subsea buoyancy of the mooring lines to provide sufficient vertical clearance. While subsea buoyancy provides a solution to the vertical clearance issue, the addition of mooring hardware in the mooring line creates another potential issue. Loss of subsea buoyancy in conjunction with a mooring line failure creates further failure scenarios that should be considered. For the Beryl North Sea mooring design, the following general approach was applied: • The design standard for vertical clearance required by API RP2SK requires a minimum of 10 meters vertical clearance from all subsea infrastructure. The local production affiliate, after extensive review and risk assessment, required 20 meters vertical clearance to protect their infrastructure, so this clearance criteria was used for the campaign. Although API RP2SK provides explicit design criteria, it also states, “to determine clearance criteria, many factors should be considered, such as environment, water depth, and risk of injury, asset and environmental damage, etc.
Conservative criteria should be established based on these considerations (API 2005).” Thus, the clearance criteria used by the North Sea team was consistent with this expectation. • Subsea buoyancy (buoy) was added to mooring lines where a minimum tension in excess of 100 kips was required to ensure adequate vertical clearance from subsea infrastructure. Based on mooring analysis in worst-case metocean conditions, it was determined that it was not feasible to maintain line tension in excess of 100 kips in all environmental conditions. • Minimum tension specifications for a location were determined assuming that no mooring lines have subsea buoyancy. This is a conservative assumption to ensure the buoyancy is not completely relied upon to protect infrastructure and a loss of subsea buoyancy alone does not result in a mooring line clashing with infrastructure. However, in the event of metocean conditions where the minimum line tensions cannot be maintained on the leeward lines, the infrastructure is still protected by the buoyed mooring line. It was not possible to design for mooring line tensions below the minimum tension specifications concurrent with complete loss of buoyancy. • Multiple smaller buoys were used instead of one large buoy per mooring line. Loss of a single smaller buoy would not result in complete loss of vertical clearance to the subsea infrastructure. • Buoys were periodically inspected with vessels and a remotely operated vehicle (ROV) to confirm buoy location and to confirm the mooring hardware was not unacceptably worn or damaged. Throughout drilling operations, the primary hazard to the integrity of the production flowlines and gas lift lines within the immediate area of the wells being drilled was the potential for dropped objects – either through the moon pool or over side crane work. Strictly applied, previously established operating procedures governed the movement of any MODU lift over water. The MODU was in continuous contact with the Beryl Alpha platform, allowing all subsea lines to be shut-in immediately prior to any heavy lift. Emergency shutdown (ESD) could be initiated if required via an open communication link between the MODU and the Beryl platform control room during dropped-object exposure M AY / J U N E 2 0 1 2
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Offshore Activities & Outlook
Figure 2: Welded components of a subsea wellhead system have inherent flaws from the fusion process. A fatigue screening analysis can quickly estimate the fatigue performance of the wellhead and casing system using simplified assumptions.
periods. There was also a provision for backup communication links and clear instructions to shut down operations should the communication links be lost during deployment/recovery of the heavy lift. The platform control room operator also had clear instructions to initiate a field ESD on instruction from the MODU. Furthermore, designated heavy lift handling areas were assessed for each location. Vertical clearances of mooring lines to subsea assets were assessed in the mooring analysis for these rig positions, and as often, minimum vertical clearances are observed while at the heavy lift standby location.
WELLHEAD CONNECTOR AND WELD FATIGUE ASSESSMENT METHODOLOGY Offshore drilling and workover operations impose fatigue in the subsea wellhead and casing system when the system experiences cyclic stresses induced by the motions of the MODU and riser. In shallow water, a shorter riser makes the
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fatigue load transmission to the wellhead and casing more severe; therefore, shallow-water operations under harsh environments, such as those in North Sea sites, generate more severe fatigue than operations in deeper waters under mild environments. Over the well life, fatigue accumulates in the system from the riser-connected operations. The accumulation can lead to a fatigue crack, which could propagate and lead to loss of integrity of the component. The interactions between the floating vessel, riser, wellhead stack (lower marine riser package), BOP, tree, and low- and high-pressure housings), casings and soils are modeled to evaluate the fatigue at fatigue-critical locations, both above and below the mudline. Examples of fatigue-critical locations (hot spots) are: • Connector between the subsea tree and the wellhead; • Weld at the bottom of the low-pressure housing connecting to the structural casing (typically 36- or 30- in. outer diameter, OD); • Weld at the bottom of the high-pressure housing connecting to the surface casing (typically 22- or 20-in. OD) or wellhead extension joint; • Structural casing connectors and connector welds in the first one or two joints of structural casing; and • Surface casing connectors and connector welds in the first one or two joints of surface casing. The fatigue assessment methodology applied to analyze the fatigue life of the subsea trees, wellheads and casing connectors and welds is discussed below.
VESSEL MOTION ANALYSIS First, a dynamic stationkeeping analysis is conducted to obtain the resulting motions of the vessel’s center of gravity as it is acted upon by the wind, wave and current environment. Vessel motions are dependent on vessel characteristics and whether the vessel is moored or dynamically positioned. In either case, the vessel heading with respect to the wave direction is defined, and its wave motion response amplitude operators (RAOs) are calculated for use in stationkeeping and riser analysis. For the riser analysis and well system fatigue analysis, the calculated vessel wave motion RAOs are translated to the top of the riser.
RISER ANALYSIS A global riser analysis includes the vessel motions, actions of waves and currents, tensioning system, slip joints, riser joints, and wellhead stack; structural and inner casing strings below the mudline and soils is then performed. Depending on the mud weight and environmental conditions, minimum riser tension analysis is performed to determine required slip joint tensions and corresponding static and dynamic global loads (moment, axial and shear forces) along the riser system. In the global riser analysis, tubulars and other components are modeled using beam elements of equivalent weight and stiffness with non-linear spring constraints along the structural casing to model the mechanical behavior of the soils. Static P-Y curves are used to model the soil behavior for the strength analysis, and cyclic P-Y curves are used to model the soil behavior for the fatigue analysis. Although the global riser analysis may be carried out either in the frequency or time domains, the frequency domain analysis is preferred for ease and efficiency. In the frequency domain approach, it is assumed that the wave frequency response can be represented by a narrow-banded Gaussian process with Rayleigh distributed peaks. The resultant loads are obtained from this global riser analysis and include: • Mean bending moment, tension and shear loads; • Root mean square (RMS) shear and RMS bending moment (standard deviation); and • Zero crossing periods (Tz) of the shear load and bending moment.
WELLHEAD AND CASING SYSTEM ANALYSIS A wellhead and casing system analysis is performed to determine the response of the wellhead stack and casing system to the loads imposed by the riser, which were obtained from the global riser analysis. All components in the wellhead and casing system are modeled as concentric pipe-in-pipe (PIP) elements in a finite element package with appropriate geometric and material properties. The soil and casing interaction is modeled with non-linear spring elements using site-specific cyclic P-Y curves for the soil. M AY / J U N E 2 0 1 2
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Offshore Activities & Outlook The analysis simulates the casing and wellhead installation and cementing sequence to capture the locked-in stress state in the system, followed by the internal and hydraulic pressurization. This is followed by applying the fatigue loads obtained from the global riser analysis at the top of the PIP model for each sea state. For each sea state, component sectional force and bending moment ranges are obtained at the cross-sections containing the hot spots (reference cross-sections). Following this, nominal or reference stress ranges for the fatigue-critical sections are calculated for each sea state by using the corresponding cross-section geometric properties. The section properties used to calculate the reference stress and stress ranges must be consistent with those used in calculating the stress concentration factor (SCF) for the hot spot.
log N = log A – m* log ∆σ Where: N = number of cycles to failure A = S-N curve constant m = negative inverse slope of S-N curve ∆σ = applied stress range When a frequency domain approach is used to obtain the dynamic response of the riser at a given reference section,
the fatigue damage can be expressed in a close form. Conservatively, bending moment and shear are assumed to be in phase and the shorter Tz from either the bending moment or shear is used to calculate the number of cycles for estimating the fatigue damage. The fatigue assessment is based on the cumulative damage model (Miner’s rule), which is equally applicable to welded and mechanical connectors,
SCF ANALYSIS Stress concentrations exist at geometric transitions and misalignments of well system components, welds and casing connectors. The SCFs are calculated using detailed finite element analysis for fatigue-critical locations assuming isotropic linear elastic material properties. The SCF at a given location is defined as the slope of the maximum local stress as a function of reference/nominal stress applied at the reference section. The reference stress ranges are then transformed to the local hot spot stress ranges using the following relation: Hot Spot Stress (Range) = SCF * Reference Stress (Range) The hot spot reference stress ranges for each sea state (weather bin), and its annual probability of occurrence are critical inputs to the subsequent fatigue analysis.
FATIGUE DAMAGE ASSESSMENT To evaluate fatigue resistance, the material fatigue capacity is defined in terms of S-N curves. Component testing can provide fatigue resistance data, and this approach is widely used for welded components. For large machined components, testing is typically not pursued for practical and economic reasons. Instead, the strain model can be used based on data generated with small-scale tensile specimens that characterize the monotonic and cyclic properties of the parent material. The S-N curve is defined as: M AY / J U N E 2 0 1 2
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Offshore Activities & Outlook agation of these flaws. On the other hand, in machined components, most of the fatigue life is related to initiating a crack since the parent material generally contains only structurally insignificant flaws. For a machined component, such as a tree connector or casing connector, overall fatigue life corresponding to a through thickness crack can be higher than that calculated using the parent material S-N curve, if the S-N curve corresponds to the initiation of a stable crack (Figure 2). In this case, additional life for crack propagation to an unstable size can be calculated using a fracture mechanics approach.
LIMITATIONS OF FATIGUE ANALYSIS
Figure 3: A digital inclinometer is mounted on a base plate of a blowout preventer stack, which is wired to a remotely operated vehicle for continuous surface read-out. The inclinometer monitors any minute movements.
provided their corresponding fatigue resistances are properly characterized. In this model, fatigue damage at a location from various sea states or sequential drilling and workover operations (riser connected days) are additive. The methodology can be applied to two levels of fatigue assessment: fatigue screening and detailed fatigue analysis.
FATIGUE SCREENING ANALYSIS The fatigue screening analysis is intended for obtaining quick estimation of the fatigue performance of the wellhead and casing system using simplified and conservative assumptions. The analysis assumes that an assumed environment (e.g., the 95% non-exceedance environment) occurs 100% of the time, and fatigue damage accumulates at one point on the circumference of a component. If the estimated fatigue life meets design requirements, the fatigue assessment is considered complete and detailed fatigue analysis is not required.
DETAILED FATIGUE ANALYSIS The detailed analysis is more rigorous with more realistic assumptions than the screening level analysis. The detailed analysis considers seasonal and directional variation in metocean criteria. Sitespecific seasonal and directional fatigue
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weather bins with associated probabilities of occurrence are developed. The fatigue damage is calculated at discrete locations around the circumference of a component for each of the seasonal and directional weather bins. The cumulative fatigue damage at each circumferential location is then calculated by summing the product of the unweighted damage at that location with the probability of occurrence of each weather bin for which the riser is connected. That is in the detailed fatigue analysis, the reference stress range, zero crossing period, the probability of occurrence of each of the fatigue weather bins, the riser connected days in each season, and the riser disconnect criteria are all used to calculate the cumulative fatigue damage at a number of circumferential location for each of the fatigue critical areas. Furthermore, the rate at which fatigue damage accumulates at each of the critical locations depending on the season of operations may be calculated.
CRACK PROPAGATION LIFE FOR MACHINED CONNECTORS Welded components usually have inherent flaws left from the fusion process. Therefore, the predicted fatigue life is predominantly related to prop-
For a reentry campaign, the analysis must consider both anticipated fatigue damage for the proposed work and the fatigue damage accumulated from prior campaigns. There is usually no opportunity to perform physical testing on the materials and welding procedures used for the original installation. Therefore, conservative assumptions may need to be made related to the specifications of the parent material and welds in the absence of the physical testing to verify the S-N curve characteristics. When high fatigue loading is anticipated, a preloaded wellhead system can minimize the fatigue effects on the wellhead and surface casing by rigidly locking the high-pressure housing to the low-pressure housing. Some conventional wellhead systems are not preloaded, and the required tensile load to lock the high-pressure housing to the low-pressure housing is passively applied by the weight of the surface casing string. The location of the top of the surface casing cement can also impact the fatigue assessment results. If the top of cement is not well documented, a conservative assumption for the location of the top of cement should be used in the fatigue assessment. For a reentry campaign, preloading the wellhead or remedial cementing are not feasible options. Thus, the type of system wellhead installed and details of the surface cement job (cement volume and ROV observations during the job) are important considerations in the overall assessment. In a risk assessment for a reentry or M AY / J U N E 2 0 1 2
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Offshore Activities & Outlook workover operation, failure is usually defined as a loss of containment or structural collapse of the well system. In practice, the fatigue analysis does not provide a quantifiable relationship between the calculated fatigue safety factor and the probability of loss of containment or structural failure of the component. The S-N curves used to evaluate fatigue resistance are associated with different definitions of failure (crack initiation for parent material and through thickness crack for welds) that are not directly related to loss of containment or structural failure. Additionally, the S-N curves used are typically the “mean minus two standard deviation” curve, based on regression analysis of test data. In BS 7608, “Fatigue design and assessment of steel structures,” it is suggested that a normal distribution may be assumed in calculating the probability of failure associated with a particular value of fatigue safety factor. However, BS 7608 does not provide a basis for the use of the recommended normal distribution assumption.
The engineering analysis also needs to be balanced with proven industry experience. The planned riser connected days for all wells in the North Sea Beryl campaign were within the North Sea experience envelope for the respective wellhead systems. This was also considered when evaluating the risk potential of each reentry.
SUBSEA SLOT RECOVERY Slot recovery operations from floating rigs presents several unique challenges over land or fixed platform operations. Performing precise casing-cutting operations from a heaving rig can cause damage to either the wellhead or the bottomhole assemblies being used. The subsea wellhead must be reused, and extensive effort is required to ensure protection of the wellhead and all seal areas. Subsea well reentries involve recovery of items that are very close to the full bore of the BOP, including subsea test tree assemblies, casing hangers and seal assemblies. Some assemblies may have been designed for the original installa-
tion, and recovery or reuse of these components many years after initial installation may not have been considered in the engineering design. Furthermore, casing recovery will inherently cause metal debris to be introduced into the wellbore, which may introduce risk of damage to BOP or wellhead seal areas. These considerations are discussed in further detail below.
WELLHEAD PRESERVATION/SEAL RECOVERY In the North Sea, the combined effect of high seas and shallow water depth (360 ft) makes vertical motion control of the drill string especially challenging. A typical passive heave compensator (common in older-generation rigs) will provide sufficient heave compensation while drilling (i.e., while “down weight” is being applied to the drill string). However, a drill string that is suspended above a wellhead will not be compensated. This can be problematic when pulling and setting seal assemblies or performing any work at the wellhead or BOP. Attempting to work in
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Offshore Activities & Outlook excessive sea states could result in permanent damage of the wellbore. Defining maximum sea states and rig heave is a critical consideration for each operation. Seal assemblies vary in design but generally are designed to serve three functions: provide a primary pressure barrier in the casing hanger annulus and lock to the casing hanger and the wellhead. Locking mechanisms vary in type, and the issues outlined in this article are not associated with every wellhead system. Some older-style wellhead systems have locking mechanisms for which recovery of the seal assembly years after installation was not envisaged. A locking ring expands in a profile beyond the nominal inner diameter (ID) of the wellhead to provide a path for the required reactive force between the hanger and seal assembly. The lock ring (when engaged) is larger than the fullbore ID of both the wellhead and BOP. To pass through the BOP upon recovery, the lock ring must retract to its original shape. For wells in the Beryl North Sea campaign, recovery of seal assemblies involves pulling seal assemblies 15 years after initial installation and after exposure to high temperatures and production loads. The ring does not retain any of its original properties and likely cannot be pulled back through the same bore ID that it could on the original installation. Leaving the lock ring in the wellhead introduces a risk of damage to internal seal areas when recovering casing hangers and will prevent access to set bore protectors and seal assemblies. Conventional fishing tools are not designed to recover lock rings while inside the wellhead. If the lock ring cannot be recovered by conventional means, an extensive evaluation and risk assessment of the well barriers needs to be made before unlatching the BOP connector and recovering the lock ring with an ROV. Recovery of a lock ring with an ROV may not be avoidable and should be considered as a highprobability scenario before starting any subsea reentry campaign. Risk mitigation is well-specific, and no generic rules can be followed to state when it is safe to remove the BOP. Additional barriers may be required before this can safely be done.
CASING RECOVERY Recovery of casing by cutting and pulling is a proven method of performing a
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slot recovery. When cutting casing from a MODU, the rig motion must not be transmitted to the casing-cutter assembly. Excessive cutter motion will cause damage to the cutter and prevent a sufficient quality cut to be made to recover the casing. Utilizing a marine swivel (landed off at the wellhead) is a simple and commonly used method to prevent rig motion from being transmitted down the drill string. The marine swivel is normally landed off on a casing hanger. When problems are encountered retrieving casing, the casing string may be cut in smaller sections to maximize the tension applied at the cut point. When this is done, the casing hanger that was normally used to support the marine swivel may have been removed from the wellbore. In the absence of a marine swivel, it will be necessary to use a cut-and-pull spear, where a grapple is engaged inside the casing stub, and tension is applied to the top of the casing stub, preventing transmission of rig motion of the casing cutter. When this situation was encountered in the North Sea campaign, a conventional mud motor was placed between the grapple and the casing cutter to cut the casing. For subsea slot recovery work, it is highly likely that multiple cut-and-pull runs will be required. Jarring is generally limited as extensive jarring could cause damage to the subsea wellhead. The preference is to cut into smaller sections and recover the casing with minimal force. Furthermore, heavier and stronger drill strings that provide high overpull capacity are generally not shearable with conventional blind shear rams. When recovering casing in smaller sections, the minimum casing cut length will be determined by the length between the grapple and the casing cutter.
WHIPSTOCK SIDETRACKS Whipstock sidetracks have routinely been used to establish a sidetrack from a wellbore for subsequent drilling operations. The primary difference between a whipstock deployment for a subsea well compared with a surface or fixed platform is the motion of the drill string. Prior to running the whipstock, a drift assembly simulating the length, stiffness and configuration of the whipstock assembly is run to verify the whipstock is capable of being run to the planned
depth. A significant difference between the whipstock and drift assembly is the shear bolt attaching the whipstock to the milling assembly. Rig motion, especially when the drill string is in slips, can cause cyclic loading on the shear bolt. This effect will not be fully evaluated by the drift assembly. Consideration must be made for acceptable environmental conditions for running the whipstock; otherwise, the whipstock may be lost in the wellbore. If a hydraulic anchor is being used, the surge/swab pressure introduced by rig motion may also interfere with the setting procedure. Single-trip whipstock assemblies, which allow both running the whipstock and milling a window with a single assembly, may be the quickest method of establishing a sidetrack. However, relative to a multiple-trip system, these assemblies are generally longer and stiffer because of the additional casing mills in the assembly. Consideration should be made for localized doglegs at the wellhead area when determining which system should be used. Factors include wellhead inclination, taper of casing cross overs below the wellhead and changes in geometry through the BOP and wellhead. Furthermore, the differential angle between the flex joint and wellhead should be minimized and closely monitored while running the whipstock through the BOP and wellhead. Prior to running the whipstock, the rig may need to be repositioned to achieve the lowest flex joint differential angle. Milling of a window that will enable passage of all drilling assemblies requires precise control of weight on bit (WOB). Generally, low and consistent WOB is required to mill casing windows. In conditions where high rig heave is being encountered, a passive heave compensator may not be capable of providing the required WOB control. As with running whipstocks, environmental limitations should be considered for milling operations. Excessive WOB can result in an excessive dogleg, making the window unusable. Metal swarf created by casing milling is likely to accumulate at the BOP area due to the larger ID of the BOP and riser, and in the cavities in the BOP area capable of capturing debris. A riser boost line can enhance hole cleaning, but the boost M AY / J U N E 2 0 1 2
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Offshore Activities & Outlook line is commonly above the BOP and would not sufficiently boost the flow rate across the BOP. A combination of fullbore jetting assemblies with magnets and junk baskets below the jet sub can remove the excess metal debris. If the jet sub is larger than the internal diameter of the wellhead profile below, a drill pipe hang-off tool designed for the wellhead profile can be run below the jet sub to prevent risk of damage to the jet sub and wellhead.
LESSONS LEARNED The Beryl North Sea campaign was successfully completed in 2011. All of the concepts outlined here were factored into the well designs and operations for all three wells drilled in this campaign. The geological objective of each reentry was achieved. Key lessons learned and observations throughout the campaign included: • All mooring patterns were designed for the stringent vertical clearance requirements jointly set by the drilling team and the production affiliate and were subject to extensive risk assessment. Use of subsea buoyancy was effective to ensure adequate vertical clearance to protect infrastructure at all times. Extensive simultaneous operations procedures were also strictly followed for all heavy lift operations; • A detailed wellhead fatigue analysis was completed for the locations. Primary attention was for wells with horizontal trees, as the detailed analysis showed that the connector between the tree and wellhead had the shortest predicted fatigue life. The horizontal spool trees have an inherent elevated exposure to fatigue. Both the abandonment and subsequent completion operations must be performed with the tree connected. The only opportunity to reduce the fatigue damage was to remove the tree for sidetrack drilling operations. The scope of work in this campaign involved predominately abandonment and completion activity so the potential to reduce the fatigue damage to the subsea tree was minimal; • The translation of rig motion to the riser, BOP and wellhead was monitored through use of an ROV-deployed digital inclinometer. The inclinometer is capable of monitoring any minute movement with a high degree of accuracy (+/- 0.05°).
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Conventional bull’s-eye readings can be subjective and cannot be used accurately to quantify dynamic changes in inclination (Figure 3); • A whipstock was lost in hole while running an extended-length ramp whipstock on a single-trip assembly. The combination of a 1.5° wellhead inclination, a steeply tapered 10 3/4 in. x 9 5/8-in. crossover directly below the casing hanger and a moderate rig heave contributed to the unplanned shear of the whipstock shear bolt. The whipstock was being run very slowly, and at no time could excessive down weight be observed on any rig weight indicator. The whipstock was fished from the well on the first attempt using a customdesigned box tap that was shipped with the whipstock on load-out. For the subsequent run and for all subsequent work with whipstocks, a two-trip assembly was used. This reduced the length and effective stiffness of the assembly. No further problems were encountered deploying whipstocks; • Outer lock rings on all casing seal assemblies were not recoverable by conventional methods. Prior to pulling the seal assemblies, a drift assembly was run to confirm fullbore drift through the riser and BOP. An annular preventer was then closed, and the BOP was drifted again after 15 min to verify the preventer was fully open. The seal assembly was then retrieved with the same annular closed to assess trapped pressure in the annulus. After confirming the well was static, the annular preventer was opened and left to relax for one hour prior to pulling the seal assembly through it. Despite all risk-mitigation measures, the outer lock rings could not be recovered, as they did not return to their original shape – the OD of expanded lock ring was larger than the minimum ID of the BOP. This outcome was anticipated based on an engineering review of the wellhead system, and the appropriate risk assessments were performed during the well-planning phase for this outcome. These procedures were followed to verify the well barriers, unlatch the BOP and recover the lock rings with an ROV; • Use of drill pipe-conveyed cameras were effectively used to evaluate the condition of the wellheads. Although the lack of drill string compensation resulted in poor video quality, sufficient still photos could be taken to effectively evaluate
the condition of the wellhead and assess the condition of seal assembly lock rings when lost in hole; and • After all casing-cutting and whipstock milling operations, the 18 3/4-in. BOP bore was jetted using a 16-in. OD jet sub with a pocketed string magnet that captured debris within pockets on the tool itself. A “junk basket” was used at the bottom of the assembly to catch any debris that fell below the magnets. Between each well, the BOPs were thoroughly stripped down and inspected due to the potential for damage caused by the metal debris. No swarf was observed at the BOP upon recovery to surface, and there was no wear or damage to the BOP, confirming the jetting was effective. Despite extensive up-front planning, a subsea well reentry will always have higher potential for nonproductive time and equipment issues than a new well. However, the reentry can always be performed just as safely. Problems encountered may not be the result of current operations but could be inherited from prior operations (drilling or production). The keys to success for a reentry program are to develop a realistic well plan that does not rely on a “success-based” outcome for each well operation and that provides relevant well data at each operational step to help make informed decisions on forward plans. The well plan also needs to give clear operating limits for when to continue and when to cease operations. Reentries involve reuse, refurbishment and preservation of a certain component of the original wellbore. If that component is compromised, either from previous or current well operations, the most economic decision may be to cease the operation. Effective preservation of the original wellbore components can safely extend the service life of the entire operating asset. This article is based on IADC/SPE 151202, “Regeneration of First-Generation Subsea Fields: The Challenges of New Wells in Old Infrastructure,” presented at the 2012 IADC/ SPE Drilling Conference and Exhibition, San Diego, Calif., 6–8 March 2012. References, author acknowledgements and additional images for this article are available online at www.DrillingContractor.org.
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4/12/2012 4:50:01 PM
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Completions: Sand Control
Refining the grip on nature’s fine grains Complementary tools, approaches enhance tried-and-true sand control methods BY JOANNE LIOU, EDITORIAL COORDINATOR
D
rawing on proven methods and technologies, the latest developments in the realm of sand control strategically capitalize on and enhance what is known to work. The challenge to control unconsolidated sand in the reservoir is met with a portfolio of evolving solutions that are producing better, faster and cheaper results. Mindful of risks and costs, the industry cautiously approaches sand control, managing complexity while reducing nonproductive time (NPT). “The current thinking in deepwater is selecting the casedhole completion technique and the processes that not only provides the best, fastest completions but also one that provides the least amount of risks because the daily costs of operating in deepwater for some of these rigs range from $500,000 to a million dollars per day offshore,” Bryan Stamm, technology manager of Schlumberger sand management services, said. “It’s not often that the new technologies are actually the gamechangers, but it’s properly managing the packaging of the existing technologies.” A recurring approach shared across the industry is to evaluate the utilization and application of existing technologies, then combine them with complementary elements and tried-and-true methods to produce even better results. Operators are asking service companies to provide methods that not only control sand production but also maximize productivity and increase recovery. “Our customers are asking us to look at lower completions from a productivity perspective, not just as widgets,” Suzanne
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Stewart, Baker Hughes’ product line director for sand control and lower completions, explained. “Our philosophy is to look at the payzone and provide direct connections and enhance when we can in order to maximize the conductivity and to optimize production. That way, we are offering solutions and applications, not just providing widgets.” The market and need for sand control is omnipresent from the North Sea to West Africa to onshore North America, and it continues to grow as trends point to developing significant fields. In this article, sand control experts from Schlumberger, Baker Hughes and Weatherford International share their approaches and recent developments.
SCHLUMBERGER Proper evaluation and management of sand control methods have led to some of Schlumberger’s latest developments for open-hole and cased-hole completions. Offshore, particularly in deepwater wells, standalone screens or gravel packs are typically used in open hole, while frac-pack treatments are the
Right: Using fiber-optic technology, Baker Hughes has developed a real-time compaction monitoring system to monitor deformations of the well. The system provides realtime data and can monitor downhole conditions to detect any issues before they become a problem. M AY / J U N E 2 0 1 2
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Completions: Sand Control
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Completions: Sand Control
Images courtesy of M-I SWACO, a Schlumberger company
Top Left: M-I SWACO’s BREAKDOWN HD breaker system helps remove some of the more difficult polymer components of the filter cake. Top Right: M-I SWACO’s WELL SCAVENGER is a vacuum debris removal tool that provides reverse circulation at the end of the workstring. Bottom: The WELL PATROLLER tool acts as a downhole filter during the displacement operation, removing residual debris and validating well cleanliness.
most common cased-hole sandface completions technique. In both open-hole and cased-hole environments, how to effectively execute sand control with high efficiency and low NPT is the ultimate goal. With multizone applications, the goal is to effectively balance the reward of installation efficiency with the risk of NPT. An area that has seen development in new technology is wellbore displacement and cleanup. “The chemistries, hydraulics and tools have always been available, but the combination of the three is seldom looked at as a complete system,” Mr Stamm said. In proper wellbore cleanup, cleanliness is not intuitive to the drilling engineer, but it is of paramount importance to a completion engineer for both making sure the formation is not damaged, as well as making sure debris is removed from the wellbore. Debris could cause NPT associated with completion hardware. M-I SWACO’s WELL PATROLLER and WELL SCAVENGER tools have been effective in removing debris in cased-hole completions and illustrate well cleanliness at surface. The former acts as a downhole filter during the displacement operation, removing any residual debris and validating on surface how
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well the displacement performed. The latter is a vacuum debris removal tool that provides reverse circulation at the end of the workstring to enhance debris removal, especially around sensitive areas or equipment, such as open perforations, formation isolation valves or temporary plugs. Captured debris is recovered at surface. Sand control is part of the bigger picture, and drilling engineers are as important to the productivity of the well as engineers responsible for the completion design. “The highest value that we’ve seen is when there is an integrated team working for a common goal, not just individual objectives, such as ‘let’s just drill the well without any regard for completion,’ or ‘let’s complete the well without any regard for how it was drilled,’” Mr Stamm said. In open-hole completions, breaker technology is a key aspect of managing the transition from the drilling phase through the completion phase and into the production phase. “But the filter cake treatment goes in combination with the fluid with which you drill in the first place,” Charles Svoboda, director of wellbore productivity, business development at M-I SWACO, a Schlumberger company, explained. “The breaker technology and the reservoir drill-in fluids have to be specifically designed M AY / J U N E 2 0 1 2
4/12/2012 5:17:03 PM
Completions: Sand Control together with the common objective of successfully drilling the well, completing it and then successfully producing from the well.” In a 2011 case study offshore the east coast of Trinidad, the company’s BREAKDOWN HD breaker system enabled filter cake removal in a high-permeability open-hole gravel pack (OHGP) completion. The idea was to remove the filter cake in a gentle manner and not be too aggressive by compromising the filter cake integrity before the completion process was finished. The system allows users to get to higher densities and work in divalent chemistry – a calcium-based brine, Mr Svoboda explained. “The composition of BREAKDOWN HD helps us remove some of the more difficult polymer components of the filter cake that are sometimes used.” Starch polymers, for example, break down easily with an enzyme treatment, but other fluid loss control and viscosifying polymers are more troublesome. In the Serrette project in Trinidad, the wells had open-hole production intervals varying from 150 ft to 500 ft and contained high-permeability rock ranging from 1 to 3.5 Darcy. The reservoir drill-in fluid was engineered to limit fluid invasion and formation damage; however, there were indications of a high probability of severe production-restricting screen and gravelpack plugging, making the placement of the filter cake removal treatment necessary during the placement of the OHGP. To minimize interaction between filter-cake removal chemicals and the OHGP fluid, the breaker system was implemented
to minimize interaction with the divalent brine system, retain adequate breaking power to remove the filter cake and maximize productivity. The final mixing and pumping process proceeded without issues or NPT. “It’s an extension to where we’ve been,” Mr Svoboda said. “We’re now able to work in higher densities. We’re able to remove filter cakes that before hadn’t been removed by previous technologies.”
BAKER HUGHES Fiber-optic technology is no stranger to the industry, but its use for well and reservoir surveillance has evolved in the past decade. Baker Hughes and a major operator have collaborated to develop a technology to monitor the deformation of well tubulars and casing, which has expanded to monitoring sand screens. The real-time compaction monitoring system enables the monitoring of the compaction-related deformations of the well. “Multiple fiber-optics string sensors give operators the ability to gain real-time information, allowing them to make changes,” Ms Stewart said. “The biggest benefit is that the system can monitor downhole conditions and then adjust to rectify a problem before it becomes a failure.” The operator deployed the system for the first time with a downhole fiber-optic wet connect in the Gulf of Mexico (GOM) in November 2011. The system was applied to a cased-hole frac pack and was run on a 3 1/2-in. fiber-optic screen, inside 7 5/8-in.
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Completions: Sand Control
Top: Baker Hughes’ GeoFORM Shaped Memory Polymer Sand Control System is engineered to potentially replace gravel packs in open-hole completions. Field trials are being conducted in Europe, offshore US and Southeast Asia. Right: Baker Hughes introduced the industry’s first downhole fiber-optic wet connect in November 2011. The system is able to run the upper completion and connect, allowing the fibers to meet downhole.
casing. Because the application was developed with a downhole fiber-optic wet connect, “we could run the upper completion and connect, so the fibers meet downhole,” Ms Stewart explained. The fiber-optics string engages sensors at the sand face, which allows operators to continuously monitor the reservoir with fiber optics in real time. The technology uses Bragg gratings, which is a short segment on optical fiber that reflects particular wavelengths of light and transmits all others, she continued. “Each grating is essentially a strain gauge, and when strain is applied to the sensing fiber, the fiber is helically wrapped around the completion to be monitored, such as casing or sand screen, and the individual gratings in the fiber stretch or contract. This strain causes a shift in the wavelength of light reflected and produces strain measurements along the length of the fiber containing the Bragg gratings.” Bragg gratings can offer an advantage over traditional electronic gauges in harsh environments because it can withstand vibration and heat, making it more reliable. One of the newest sand control systems, GeoFORM, is based on shape memory polymer (SMP) technology. It has been engineered to potentially replace gravel packs in open-hole completions. SMPs, introduced by Baker Hughes in 2011, resemble the material used in automobile bumpers. If there is a dent in the bumper, the repair usually involves applying heat to the area to make the dent pop out to its original form.
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“SMPs have the ability to effectively remember the shape in which they were originally formed,” Ms Stewart explained. “We take the SMP, compact it to a smaller size, and then we effectively freeze it in that condition and run it in hole and allow it to go back to its original shape.” A pipe with an SMP is run in the open hole, where it can regain its original size and effectively fill the annulus. SMPs replicate a filtration system like a gravel pack without having to pump gravel. Baker Hughes has undertaken seven SMP field trials to date in areas including Europe, offshore US and Southeast Asia, Ms Stewart said.
WEATHERFORD Conceiving the downhole production enhancement business unit, Weatherford combined chemical sand control with its water conformance technology in March. “Sand production and water production go hand in hand,” Ron van Petegem, product line director of downhole production enhancement for Weatherford, said. “There are many reservoirs out there that really don’t produce any sand. The rock may have even failed already, but when water production breaks through the capillary, pressures change. You may lose other cementation from clays and then comes the sand.” Weatherford’s new approach looks at sand and water performances in tandem. Although the two are not necessarily complementary, they also are not mutually exclusive. SandAid, originally field-tested in Romania and introduced M AY / J U N E 2 0 1 2
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Completions: Sand Control
Top: Weatherford’s SandAid treatment uses zeta potential altering chemistry to create an ionic attraction between particles and prevents them from migrating while allowing for adaptation to changes in formation stresses. Bottom left and right: The magnified views illustrate untreated (left) and treated (right) sand grains/fines. When SandAid is pumped into the reservoir, the positively charged chemistry is attracted to the negatively charged sand, which leads to SandAid adsorbing the particle. The solution is formulated so that only a certain amount is adsorbed by the rock.
to the market in June 2009 in the GOM, is one of Weatherford’s latest technologies and is still evolving in its makeup and application. The treatment incorporates Weatherford’s patented zeta potential altering chemistry, which in itself is not new to industry, but to modify the zeta potential for the purpose of sand control and increasing the maximum sand free rate is.
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The modification creates an ionic attraction between particles and prevents these particles from migrating while allowing for adaptation to changes in formation stresses. “Sandstone is anionic, negatively charged, and SandAid is mostly catanionic, so when SandAid is pumped into the reservoir, the positively charged SandAid and the negatively charged sand are attracted M AY / J U N E 2 0 1 2
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Completions: Sand Control
The chemistry of Weatherford’s SandAid technology is based on modifying the zeta potential of anionic particles. When formation stresses change because of reservoir depletion, its chemistry adapts to the changing conditions and re-agglomerates. to each other, and SandAid adsorbs to the partile,” Mr van Petegem said. The technology is typically deployed by bullheading it down the production tubing or coiled tubing; many operators prefer to bullhead the treatment down the production tubing because of the ease of placement, Mr van Petegem said. The typical treatment consists of a brine pre-flush, followed by the SandAid treatment and a brine post-flush. “We mix on the fly, and it’s an extremely simple process,” he explained. “It also means that in almost all cases, the fluids that we pump into the well are Newtonian, and as such rate diversion becomes simple and reliable, treatments are typically pumped at matrix rates just under frac pressure.” Part of rate diversion implies that higher-permeability zones will receive more treatment than lower-permeability ones. It is essential that the chemicals do not over-treat part of the matrix, and more SandAid solution applied does not mean a thicker coating but translate into a deeper treatment, according to Weatherford. The philosophy of the design takes into consideration the minimum amount of treatment needed for lowest-permeability of the target zone. “That’s one of the key reasons for our success,” Mr van Petegem said. “Thus, during a normal treatment, the high-permeability rock will receive a deeper treatment than the low-permeability rock.” SandAid chemistry is formulated so that only a certain amount is adsorbed to the rock. Weatherford has applied the technology to more than 200 zones worldwide offshore and on land. In one of its first applications in the GOM, the company teamed up with an independent operator in mid-2009, and through June 2011, the treated
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GOM well produced at up to three times its previous maximum sand-free rate. Prior to the treatment when the well’s performance initially declined, a number of sand control options were considered. A workover with gravel-pack or frac-pack installation was deemed too costly and not fit to the existing completion configuration. SandAid technology was selected because the treatment could be mixed with seawater and bullheaded down the production tubing and because it would not reduce permeability. Within 24 hours of application, the well was put on production, and as of April, was still producing sand free. “Today we have a good, reasonably well-defined operating envelope,” Mr van Petegem stated, “but as we do more jobs, we continue to learn and expand our operating envelope.” Taking a preemptive approach to sand control, the deployment of the technology is being rerouted. Weatherford is pursuing a concept called rock strength conservation, where sand control technologies are being applied to prevent failure instead of waiting for the rock to fail. Working with a major operator and through internal testing, indications are that by applying the SandAid technology prior to water breakthrough, deeper reservoir depletion may be possible without sand production. “Essentially all sand control methods that we have today are reactive,” Mr van Petegem stated. “We may choose to install sand control systems proactively, but in essence, they do not really start operating until after the rock fails and sand becomes mobile.” The proactive approach is a departure from the conventional sand control philosophy and would attempt to conserve and possibly prevent sand production in the first place, Weatherford believes, making it impervious to the change that is typically caused when water production starts. Weatherford plans to do field trials for this reservoir conservation concept by mid- to end-2012 and has seen interest from operators in West Africa and the GOM. In a separate development, Weatherford is working with operators to pump the SandAid chemistry from a floating, production, storage and offloading (FPSO) vessel through a flowline back into the well. “The considerations there are the cleanliness of the flowline itself because flowlines build up debris,” Mr van Petegem said. Weatherford is working with an operator to find the best way to clean the flowlines from the FPSO down to the well. “This could potentially allow failed deepwater wells without an intervention vessel do a sand control treatment remotely through flowline,” he added.
CONCLUSION Methods of bringing unconsolidated formation sand under control are not confined to the completion phase but also affect the drilling and production phases. The industry’s approach to sand control and traditional methods are evolving to maximize proven technologies to produce the most desirable and profitable results. “Baker Hughes does not have an allegiance to any one particular technology,” Ms Stewart stated, “which allows us to truly evaluate the payzone and to provide the best solution.” WELL PATROLLER, WELL SCAVENGER and BREAKDOWN HD are marks of Schlumberger. GeoFORM is a trademark of Baker Hughes. SandAid is a trademark of Weatherford.
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Regional Focus: Asia Pacific
Stable market pushes Asia Pacific rig demand Energy-hungry countries in the region drive deepwater exploration frontier, robust jackup sector BY JEREMY CRESSWELL, CONTRIBUTING EDITOR
The Ensco 104 jackup has a long history working for Apache in Australia. Ensco currently has 11 jackups and one new 8500-class utlra-deepwater semi in the Asia Pacific region. “The market is strongest for higher-spec jackups – a lot of operators are choosing to contract higher-spec rigs even if they don’t need all the heavy-duty capabilities,” said Jan van Bohemen, Ensco.
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sia Pacific is a dynamic yet relatively stable drilling market, having successfully weathered the impact of negative global economic pressures since the 2008 credit crunch. The quest for new hydrocarbons continues both offshore and onshore, powered by a growing focus on deepwater and the accelerating quest for coal-bed methane resources and early steps prospecting for shale gas. The region remains robust as a center for rig construction, with Singapore defending its role as the rig-building capital of the world; for how many more years depends on China’s success in capturing newbuild orders. This review focuses on the offshore scene, and covers Southeast Asia through Australasia, an area where jackups have ruled; however, the population of semisubmersibles and drillships is rising.. According to RS Platou’s rig demand tracking service, the early 2012 “Pacific Rim” jackup count was 77 units with 45 in Southeast Asia, 30 in China, one in
Australia and one in “other.” Turning to floaters – mostly semisubmersibles – the February total was 32, of which 16 were working the Southeast Asia sector, eight were in Australian waters. A further eight are dotted around this vast region. They comprise the eclectic mix of locally owned and Western MODUs. Platou records that Southeast Asia demand for jackups climbed 25% in 2011 and that the increased demand was mostly met by modern units. “It is interesting to note that the increased demand in (the Middle East) and the Pacific Rim was mostly met by modern-built jackups. We also expect future jackup demand to expand in these regions as they have represented a large and growing part of shallow-water oil and gas discoveries over the last years,” said Simon Crellin, Singapore-based Asia director of petroleum services at Deloitte (UK). He considers the region’s offshore drilling scene to have two distinct sub-regions – Southeast Asia and Australasia. M AY / J U N E 2 0 1 2
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Regional Focus: Asia Pacific
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SOUTHEAST ASIA Mr Crellin defines Southeast Asia as that vast swathe of countries defined by Myanmar in the West to PNG in the East, including East Timor. He notes that more than 12,000 exploration and appraisal wells have been drilled in Southeast Asia. “Analysis that I’ve done recently indicates that, typically, around 180 to 250 new wells have been spudded annually over the past five years,” Mr Crellin said. “Essentially one is talking about the offshore market; the onshore market is hard to track anyway. Regardless of rig availability and the financial crises since 2008, the actual drilling level has been fairly consistent. “That results typically in around 15 to 30 new discoveries per annum over that same time period 2007 to 2011. By new discoveries I mean green field, not stepout appraisals of producing fields that have identified additional reserves in a known structure.” This relative stability is important as it provides a fairly consistent hopper of discoveries for future development, which therefore offers relative stability in terms of development drilling requirements, though it is E&A activity that drives the region’s MODU market. Mr Crellin says the Southeast Asia fleet composition – balance between jackups and semisubmersibles/drillships – has also been relatively steady in past years, although the gradually accelerating deepwater push is changing that. “Typically we’re talking about jackups for less than 150-meter water depth; semisubmersibles to 3,000 meters. To 3,700 meters (and beyond), drillships are generally required. Much of the South China Sea is relatively shallow, which is why jackups dominate the region’s offshore rig market. “Interestingly, if you look at rig rates over the last seven-year period, the rates in Southeast Asia have on average been higher than the world average. This is because the demand for jackups within the region is quite high as the majority of
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Regional Focus: Asia Pacific the wells are drilled with this type of rig. In 2011, the average price of a jackup was about $120,000 per day compared with the world average of $110,000. “At any one time there are probably around 60 active jackups in the region and between 30 and 50 drilling at any one time; probably a few en route plus a few undergoing maintenance. “The number of semisubs and drillships (in Southeast Asia) is much small-
er. The number of semis active last year was about 22, of which eight were drilling deepwater wells. There were even fewer drillships ... about eight ... and they have mostly been working off Indonesia and deepwater Malaysia.”
AUSTRALASIA Turning to Australasia, the latest annual average has been about 100 exploration spuds a year, somewhat
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down compared with the past few years. “There’s a rough split 50:50 between onshore and offshore activity,” Mr Crellin said. “That’s excluding coal seam methane as hundreds of wells are drilled a year, but this activity is much harder to track. They can spud a well one day and be complete a couple of days later.” Offshore, the main focus remains Western Australia and especially the North West Shelf. “It dominates and has done for a long time. By that I mean the Browse Basin, North and South Carnarvon Basins and so forth. In contrast, the Bass Strait is a much more mature area. Much of the activity in that area is around development and extending field life rather than new exploration. “In terms of material impact on drilling statistics, it’s the North West Shelf as that’s where the greatest offshore exploration potential exists, including moving into deepwater waters for gas.” Mr Crellin notes that there has been a dip in federal drilling commitments on a year-by-year basis. This peaked in 2007 and has been tailing down since. “Around 100 commitment wells were drilled in 2007 in federal waters. The count dropped to 50 in 2008, remained much the same in 2009, while 2010 was even worse ... more like 40 wells. However, this does not mean doom and gloom. What that really means is that a lot of the blocks that companies were interested in were licensed, and reasonably successful exploration was carried out offshore North West Shelf.” There is a bank of offshore discoveries, but the challenge is to develop those reserves and whether operators can get ambitious LNG projects off the ground. According to Mr Crellin, that’s a very important issue as success or failure with LNG projects determines everything else to do with offshore activity.
FROM SHALE GAS THREAT TO HUNGRY CHINA There is a spectre on LNG’s horizon. It’s called shale gas; it has been a gamechanger in the US, and China is nursing bold ambitions with targets set. The success of shale gas means that the US is no longer a net importer of gas; indeed it may become a major exporter. Mr Crellin argues that shale gas presents a future potential threat to LNG projects in Asia Pacific and elsewhere. M AY / J U N E 2 0 1 2
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Regional Focus: Asia Pacific â&#x20AC;&#x153;It is almost turning markets on their head. If youâ&#x20AC;&#x2122;re an oil company with significant investment tied up in exploration and development activity with a view to bringing more LNG on-stream within the next five to 10 years, there is obviously now much more uncertainty for projects, especially in Australia because of the high cost base associated with development. â&#x20AC;&#x153;There is now an interesting question mark over the competitiveness of projects all over the world and not just AsiaPacific. A lot of E&P companies are now taking a serious look at unconventionals and have been building positions for the future. â&#x20AC;&#x153;Meanwhile, majors like ExxonMobil, Eni and others are investing in acreage positions in Australian CBM blocks, and their long-term objective is to commercialize that CBM gas as LNG, such as in Queensland.â&#x20AC;? Notwithstanding, Mr Crellin said the push for new conventional reserves continues and deepwater is an increasingly important place to hunt. â&#x20AC;&#x153;Clearly exploration is moving into deepwater; it has to,â&#x20AC;? he said. â&#x20AC;&#x153;But typically a deepwater well in Indonesia now costs $100 million. Thatâ&#x20AC;&#x2122;s a big outlay on what is high-risk exploration. But thatâ&#x20AC;&#x2122;s the way it is in frontier basins when youâ&#x20AC;&#x2122;re testing new plays. Thatâ&#x20AC;&#x2122;s a pretty high-stakes exploration game, and only certain companies can afford it. The push to find new reserves and replace production means that the demand for deepwater rigs is looking good.â&#x20AC;? Focusing on China, the worldâ&#x20AC;&#x2122;s most populous nation has over the past 10 to 15 years been making a big push into the rest of Southeast Asia and is an aggressive acquirer of reserves. â&#x20AC;&#x153;Whether Indonesia, Australia or countries like Myanmar, the Chinese NOCs have been building acreage positions through licensing and acquisitions. â&#x20AC;&#x153;The demand from China will continue to grow as will its influence in the region as its voracious demand for energy goes on rising. Therefore, the NOCs will be increasingly important and influential in terms of the pace of exploration, development and subsequent production.â&#x20AC;?
PETRONAS â&#x20AC;&#x201C; A MAJOR PLAYER Rosli Hamzah, head of well delivery exploration for Petronas Carigali, is M AY / J U N E 2 0 1 2
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due to speak at the forthcoming IADC/ SPE Asia Pacific Drilling Technology Conference, July 9-11 in Tianjin, China. â&#x20AC;&#x153;Iâ&#x20AC;&#x2122;ve been asked to talk on deepwater drilling challenges. Basically we have the technology, but in terms of resources there are shortages of people and drilling rigs,â&#x20AC;? he said. â&#x20AC;&#x153;The main challenge is the lack of suitable rigs as most of the deepwater/ ultra-deepwater units have been pulled
away to Brazil by Petrobras. More will become available from 2013 onwards, but in the interim, there is a shortage of such vessels. â&#x20AC;&#x153;There are issues to do with postMacondo requirements. Quite a number of the current fleet are not eligible to work for supermajors in terms of BOP certification. And there are supply chain shortages because of the fast-expanding amount of work in deepwater.â&#x20AC;?
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Regional Focus: Asia Pacific Mr Hamzah also warns that original equipment manufacturers (OEMs) are not necessarily up to scratch. “We think that OEMs themselves are not performing up to our expectation, again because of the pressure on resources.” Meanwhile, Petronas does have suitable deepwater drilling tonnage to work with. According to Mr Hamzah, about half the company’s deepwater effort is concentrated in home waters while the balance is elsewhere in the world. As for conventional shallow-water drilling, about 70% of the effort is local versus 30% rest of world. The company drilled three deepwater wells in Asia Pacific last year, compared with 21 conventional spuds. As for the current year, the tally is two deepwater wells in home waters, with possibly a third to come. Mr Hamzah expects that 18 shallow-water wells will be drilled. Mr Hamzah, who previously drove Petronas’ deepwater program, believes Malaysia is on the way to becoming the leading center of deepwater activity for Asia Pacific. Indeed, production from deepwater fields is expected to account for 30% to 40% of Malaysia’s total oil production by 2020.
Deepwater resources, most of which are offshore Sabah in eastern Malaysia, account for 65% of all undiscovered oil and 43% of undiscovered gas in the country. Winning that prize will require a considerable exploration, appraisal and development effort, not just by Petronas but also other players such as alreadysuccessful ConocoPhillips and Shell.
ENSCO Among the largest providers of jackups in Asia Pacific is Ensco, which currently has 11 jackups, plus one of its new 8500-class ultra-deepwater semis in the region. The rigs are working in Australia, Brunei, Indonesia, Malaysia, Thailand and Vietnam. The drilling market outlook is bright, as confirmed by Jan van Bohemen, Ensco senior director – marketing, Eastern Hemisphere. With a steady stream of quality discoveries, coupled with healthy oil prices and regional demand for gas, this is an attractive hunting ground, particularly for jackups. “In the jackup market, dayrates have been increasing over the last six months, and we expect them to further increase over the near future,” Mr van Bohemen said. “The market is strongest for higher-
spec jackups – a lot of operators are choosing to contract higher-spec rigs even if they don’t need all the heavy-duty capabilities. “We also see the floater market growing further, with all majors present in the deepwater and ultra-deepwater market. “We view Asia Pacific as a growth market, and we’re well positioned with independents, majors and national oil companies such as PTTEP, Pertamina, and Petronas Carigali, to take advantage of that knowledge and grow. “ENSCO 8504, one of our newbuild semi-submersibles, has been working for Total in the emerging basin of Brunei. This is one of our best startups ever with a downtime percentage of 2.4%, which is exceptionally low for a newbuild floater.” Among the jackups Mr van Bohemen is keen to highlight ENSCO 104, which has a long history working for Apache, and ENSCO 109. “We’ve been working for them in Australia for more than 10 years. Australia has very strong environmental and operational legislation following the Montara incident. ENSCO 109 was chosen to repair the client’s wells, a technically challenging exercise.”
Asia Pacific drilling market by the numbers • It’s estimated that Southeast Asian demand for jackups climbed in 2011.
25%
• In 2011, the average price of a jackup in Southeast Asia was about $120,000/day compared with the world average of $110,000. • There’s a rough split Australasia.
50:50 between onshore and offshore activity in
100
commitment wells were drilled in 2007 in federal • Approximately in 2008, remained much waters in Australasia. The count dropped to the same in 2009, while 2010 was close to 40 wells.
50
• Production from deepwater fields is expected to account for 40% of Malaysia’s total oil production by 2020.
11
30%
to
one of its new 8500-class ultra-
jackups, plus • Ensco currently has deepwater semis, working in the Asia Pacific.
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Regional Focus: Asia Pacific
Legal trends shape Asia Pacific contracts ‘Gross negligence,’ liability caps, regulatory changes among risk management considerations
BY DENYS HICKEY AND ROBIN ACWORTH, INCE & CO SINGAPORE To manage risk when operating in the Asia Pacific region, issues that should be considered include enforceability, liability caps, endeavours obligations and dispute resolutions, according to experts at the international law firm of Ince & Co. The authors presented their findings last year at the IADC Critical Issues Asia Pacific Conference in Kuala Lumpur, Malaysia.
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A
s with any other region, in the Asia Pacific there are a variety of issues that the negotiator of a drilling or associated service contract must deal with in order to manage the risk to which its employer will be exposed when the contract is performed. This article discusses some of the particular risks that commonly arise in the Asia Pacific region.
EXCLUSION OF GROSS NEGLIGENCE AND WILLFUL MISCONDUCT The oil and gas industry has seen an increasing use of expressions such as “gross negligence” and “willful misconduct” in associated contracts. Such terms are usually found in exclusion clauses, where a party seeks to exclude liability for acts constituting “gross negligence” and/or “willful misconduct” or to carve
out such acts from the scope of an exclusion or indemnity.
GROSS NEGLIGENCE Under English law, difficulties arise where an exclusion is expressed to extend to “gross negligence” because the term is not defined clearly under English common law (as opposed to criminal law, which employs the term in relation to manslaughter). However, increasing use of the term has led to its general acceptance as meaning something more than simply “negligence.” In the leading case of The Hellespont Ardent (1997), the court stated that, “‘Gross negligence is clearly intended to represent something more fundamental than failure to exercise proper skill and/ or care constituting negligence” and that the concept is “capable of embracing not only conduct undertaken with actual M AY / J U N E 2 0 1 2
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Regional Focus: Asia Pacific appreciation of the risks involved but also serious disregard of, or indifference to, an obvious risk. However, the court added that it “does not involve necessarily any subjective mental element or appreciation of risk.”
WILLFUL MISCONDUCT The English Court has considered the meaning of “willful misconduct” in several cases, including TNT Global v Denfleet International Ltd (2007) where it was held that for “willful misconduct” to be shown, the actor must have either (a) intended to do something that he knew to be wrong or (b) have acted recklessly in the sense that he was aware that loss could result from his act and yet did not care whether loss would result.
tive intentions of the parties at the time they contracted. Following the recent US Supreme Court decision in Rainy Sky SA v Kookmin Bank (2011), “If there are two possible constructions, the court is entitled to prefer the construction which is consistent with business common sense and to reject the other.” Any ambiguity in the clause will be construed against the party seeking to rely on it.
Care must also be taken to ensure that the wording of the clause is sufficiently wide to cover all the eventualities for which it is intended to apply. The wording can be so broad as to not require any causal nexus between the injury and the contract work. For this reason, wordings such as “as a result of,” “arising out of” or “in connection with” are often used.
ENFORCEABILITY English law does not prevent parties from seeking to exclude liability for “gross negligence” as a matter of policy. Likewise, unlike some US states that have enacted specific legislation against the exclusion of liability for damages arising from “willful misconduct,” English law does not provide a general rule concerning the enforceability of such clauses. In either case, however, as with any exclusion of liability for acts that may be regarded as negligent, very clear words will be required, and any ambiguity in such a clause will be construed strictly against the party seeking to rely on it. In the interests of certainty, parties contracting under English law (and the laws of most other common law jurisdictions, including Australia, Singapore and Malaysia) should generally be discouraged from using the terms “gross negligence” and/or “willful misconduct.” If they are used, they should be defined as clearly as possible in the contract.
LIABILITY CAPS As with the exclusion of “gross negligence” and “willful misconduct,” provided they are properly worded, liability caps can help to contain risk by limiting a party’s exposure to a particular level, such as the limit of that party’s insurances, in connection with the contract. As with all attempts to exclude or limit liability, care should be taken to ensure that the clause is clearly worded. Under English law, the words of a contract will be given their natural and ordinary meaning in order to ascertain the objecM AY / J U N E 2 0 1 2
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Regional Focus: Asia Pacific It is important to consider whether the clause applies both in relation to performance and non-performance of the work. It is also necessary to consider whether the clause will apply to both contractual and non-contractual liabilities (e.g., negligence) and to consider the class of persons to which it is intended to apply (e.g., just the party concerned or also its affiliates and subcontractors).
EUROPEAN UNION
If a contract imposes an obligation on a party to bring about a particular objective, that obligation will be absolute, unless it is qualified, and a failure to discharge it will constitute a breach of contract. Accordingly, it is increasingly common for parties to qualify certain obligations and, when using some standard form contracts, the parties may do so without considering the potential implications on their contractual obligations. The most common qualifications used are “best endeavours,” “reasonable endeavours” and “all reasonable endeavours.”
An “all reasonable endeavours” obligation is perhaps the most ambiguous of the three common endeavours obligations. Until recently, the main authority on its interpretation was the Rhodia case in which Mr Flaux commented that “it may well be that an obligation to use all reasonable endeavours equates with using best endeavours.” The obligation has since been distinguished from an obligation to make “best endeavours.” However, in CPC Group Limited v Qatari Diar Real Estate Investment Co (2010), judge Justice Vos said, “It seems to me … that the obligation to use ‘all reasonable endeavours’ does not always require the obligor to sacrifice his commercial interests.”
On 27 October 2011, the European Commission proposed new regulations on the safety of offshore oil and gas activities, which are intended to apply across the European Union to reduce the risk of major incidents. If adopted, they will apply to all offshore oil and gas activity within the waters of EU Member States, including their exclusive economic zones and continental shelves. Although they will not apply strictly to the operations of EU-registered operators outside the EU, the regulation currently states, “Licensees, operators and major contractors based in the Union shall endeavour to conduct their offshore oil and gas operations when outside the Union in accordance with the principles set out in this Regulation.” The regulations propose new rules in a number of areas focusing on safety and the environment and, if they are adopted, they could apply to new exploration and production operations as early as 2013. Operators of installations that are already producing could be required to make those installations comply as soon as 2014.
BEST ENDEAVOURS
PRACTICAL GUIDELINES
AUSTRALIA
A “best endeavours” obligation is the most onerous of the three common endeavours obligations. Nevertheless, it is not an absolute obligation or guarantee. While it may require expenditure on behalf of the obligor, it does allow the obligor to maintain some, albeit very limited, regard for its own commercial interests and will not require action resulting in its financial ruin. Following the case of IBM United Kingdom v Rockware Glass Ltd (1980), an obligor must take all steps that “a prudent, determined and reasonable person, acting in its own interests and desiring to achieve that result, would take.”
The degree of uncertainty as to what an endeavours clause may actually require in any given case can be addressed to some extent through precise drafting. One approach may be to consider what steps the relevant party should take to achieve a particular obligation and make express provision for it in the contract. This can be done, for example, by specifying which activities the obligor is required to carry out to discharge its obligation, by limiting the amount of time and/or expense that may be required or by stating the extent to which it is required to protect its own interests. Since questions will often arise as to whether any real endeavours have been taken by the obligor, the parties may also wish to incorporate a provision whereby the obligor must inform the obligee of its progress in meeting the objective.
The Australian government’s review of oil pollution legislation was initiated in response to the spill from the blowout of PTTEP’s Montara well on 21 August 2009. This resulted in the Montara Commission of Inquiry Report 2010. Many recommendations of this report have been implemented at a federal level through amendments to the Offshore Petroleum and Greenhouse Gas Storage Act 2006 and associated regulations, some of which came into force on 1 January 2012. These changes include the creation of the National Offshore Petroleum Safety and Environmental Management Authority, which has responsibility for administration and regulation of occupational health and safety, well integrity, environmental management and day-today operations in the Commonwealth offshore areas outside the three-mile limits of Australian state waters. Some states have opted in to this arrangement while others, such as the Department of Mines and Petroleum in Western Australia, have opted out, resulting in a complicated regulatory situation, with state-level regulations
ENDEAVOURS OBLIGATIONS
REASONABLE ENDEAVOURS An obligation to use “reasonable endeavours” will generally impose less stringent obligations than a “best endeavours” obligation. In UBH (Mechanical Services) Ltd v Standard life Assurance Co (1986), it was held that it simply means “an honest try” and that any sort of practical, financial or other commercial disadvantage associated with the obligation might justify a party’s failure to take positive action.
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In Rhodia International Holdings Ltd v Huntsman International LLC (2007) Julian Flaux QC added that although there may be a number of reasonable courses that could be taken in a given situation to achieve a particular aim, an obligation to use reasonable endeavours probably requires only a party to take one reasonable course, not all of them.
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ALL REASONABLE ENDEAVOURS
REGULATORY ISSUES In response to the Macondo incident and the Montara blowout, a number of national and international regulators have taken the opportunity to review their regulatory regimes.
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Regional Focus: Asia Pacific applying alongside the federal regime in some states but not others.
NEW ZEALAND In November 2011, New Zealand reelected its National Party. Despite pressure from opposition parties to put a moratorium on deep-sea drilling, the National Party looks likely to proceed. There appears to be some agreement from politicians across the board, however, that New Zealand is not adequately prepared to deal with significant oil spills in its waters. Even before the Rena spill, there was considerable opposition by New Zealand’s Environment and Conservation Organisation to deep-sea drilling in the waters off New Zealand’s coastline, particularly outside its territorial waters (12 miles offshore), where there is no legislation controlling oil and gas activity. Accordingly, it is likely that some degree of regulatory reform will occur that will affect drilling in New Zealand’s waters.
EFFECT OF REGULATORY CHANGES ON CONTRACTS In the event that regulatory changes occur during the period of a contract, different and potentially greater regulatory burdens can be placed on the parties – for instance, by requiring equipment to meet different standards. This may increase the cost to the parties of performing their obligations. In any case, it should be made clear to what regulatory standards the parties are required to comply and what happens in the event of regulatory changes.
DISPUTE RESOLUTION The dispute resolution clause of a contract is something that is commonly left to the end, and parties often agree to such a clause without really putting their minds to its potential effects. In Asia Pacific, as elsewhere, differences between the laws and procedures in particular countries and the availability of a variety of venues for dispute resolution means that the decision should not be taken lightly.
JURISDICTION The local courts in the Asia Pacific region can vary markedly, and this can have profound effects on the outcome of disputes. A local court near a drilling location, for instance, is likely to have a different level of experience and potentially a very different view, in relation to a complex energy dispute than a court or tribunal in the UK, Australia or Singapore. Arbitration is particularly popular in the oil and gas sector in this region because the parties can appoint a tribunal with potentially greater experience of the particular type of dispute than the courts in the region. Singapore in particular has become a popular choice of venue for arbitrations and is generally seen as providing an efficient, independent and fair environment. This article is based on a presentation at the 2011 IADC Critical Issues Asia Pacific Conference and Exhibition, Kuala Lumpur, Malaysia, 23–24 November 2011.
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Contracts & Risk Management
Drilling contracts evolve with industry expansion, legislative, judicial trends Implications of Macondo will drive continued drilling contract changes as industry pushes to new frontiers BY CARY A. MOOMJIAN JR., CAM OILSERV ADVISORS
D
uring the course of this authorâ&#x20AC;&#x2122;s 35-year drilling industry career, he has seen drilling contracts evolve from relatively simple documents to lengthy, complex contractual arrangements. Recent trends in contracting and important new legal precedents resulting from the Macondo well incident are expected to add more complexity to drilling contracts over the next few years.
IN THE BEGINNING
In the early days of drilling, a verbal contract was often sealed by a handshake. Standard contracts didnâ&#x20AC;&#x2122;t come along until the 1940s.
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In summer 1859, Edwin Drake tried to dig a mine shaft to capture oil under some promising seeps in Pennsylvania. When mining techniques were unsuccessful, he improvised a drilling technique using a steam-powered cable tool rig that enabled him to strike oil at 69 ft. Colonel Drake did not need a drilling contract as he was both the operator and the driller. When the oil and M AY / J U N E 2 0 1 2
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Contracts & Risk Management gas industry emerged, most operators drilled their own wells using in-house equipment and personnel. This trend continued long after the contract drilling industry matured. In 1940, the predecessor to IADC was founded as the American Association of Oilwell Drilling Contractors (AAODC). According to a presentation at the 1941 AAODC annual meeting, more than 2,000 drilling contractors were operating in the US and owned about 75% of the available 4,000 rotary and 2,800 cable rigs. This was the era of the “mom and pop” drillers. Further, the AAODC reported that more than 10% of the pioneer drillers also were producers. An article in the May 1945 issue of DRILLING CONTRACTOR titled “Insurance – A Necessity for Drilling Contractors” illustrates the naiveté that prevailed. Another article from 1945 commented on the fact that lawsuits between producers and contractors were infrequent, noting that “this is doubly significant when considered with the frequency of occasions where the drilling is well under way and sometimes completed before the contract is signed.” Interest in contracts seemingly intensified during the late 1940s. At the 1949 AAODC annual meeting, a paper titled “Contractor’s View on Revising Drilling Contract Forms” was presented along with an operator’s response. The response agreed with the contractor’s comment that “some of the drilling contracts enforced today are on patchwork forms.” It also endorsed the observation that “a house-that-Jack-built contract should not be recommended to the industry as a fair expression of the contractual relationship between company and contractor, and certainly should not be used as a yardstick to determine risks and responsibilities in a contractual relationship involving the expenditure of thousands of dollars.” This was supplemented by a statement that an agreement to drill a well should “be as complete, plain and unambiguous as we can make it” because “a drilling contract should express the full agreement of the parties.” A report on contractual liability was presented by an AAODC special committee in 1949 articulating seven basic principles to “be adopted in the writing of drilling contracts” by member companies “if found to be fair and equitable.” An article from 1950 titled “Comments on the Drilling Contract” emphasized
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Scan to see a sample of the archive Drilling Contractor articles cited here.
the “importance of knowing terms of contract in advance” and “checking the terms of the drilling contract.” Twelve years after the AAODC was established, it issued the first standard drilling contract. Prior to this issuance, contracting practices were sporadic. In many cases, a verbal contract was often sealed by a handshake, according to pioneer driller and originator of the IADC Daily Drilling Report, Earle Hellums. Early contracts were rudimentary, with a focus on basic commercial terms regarding scope of work, rates and the equipment and personnel to be furnished by the contractor. It was not until the late 1940s and early 1950s that DRILLING CONTRACTOR magazine discussed the emerging concept of including “hold harmless” provisions in drilling contracts. The original AAODC standard drilling contract was rather rudimentary and apparently was not universally embraced at first. A 1955 DC article contained the following passage: “The need for a standard form of drilling contract has long been recognized as very desirable. Whether or not it can be achieved is something I am not prepared to say.” The weak market for drilling rigs in the early 1960s created an environment in which contractors were compelled to accept unfavorable contracts. In a 1961 article, William Clements, then president of Southeastern Drilling Corp who later became Texas governor, commented: “To a large degree, contractors are responsible for the ills of the oilwell drilling industry. We have created some of our problems by our own actions. We have abetted the establishment of others by bowing down to undesirable contractual clauses and practices.”
STANDARD CONTRACTS Over the years, IADC has developed a suite of model drilling contracts. The original AAODC standard contract was split into US land model contracts for daywork and footage operations in February 1986. The first international daywork land model contract was issued in July 1983 and was followed by the
introduction of a US land turnkey contract in February 1988 and an international daywork offshore contract in February 1989. The US offshore daywork model contract was issued several years prior to the international daywork offshore model contract. A US offshore turnkey model contract was issued in February 1989, revised in October 1995 and withdrawn in August 2005 due to a dearth of sales. Although widely utilized for US land operations, IADC model contract forms are infrequently used in offshore or international operations. More often, they are seen as examples of contract language that enables the contracting parties to gauge commercial and legal risk exposures by comparing provisions of a proposed contract to IADC model forms. Other organizations, such as the Canadian Association of Oilwell Drilling Contracts, the API and LOGIC (a nonprofit subsidiary of Oil & Gas UK) have issued their own model contract forms. Further, most oil and gas companies have developed their own cadre of drilling contract forms. The contracts proposed by majors and large independents frequently are subject to qualification by contractors that tender for the work, resulting in negotiated contracts. However, most national oil companies will not deviate from their pro-forma contracts. This creates a “take it or leave it” situation. Many contractors consider such nonnegotiable contracts to be problematic, primarily because they often contain onerous provisions and frequently are ambiguous in important areas, such as allocation of risk for pollution liability or reservoir damage. Contracts of this nature can create significant risk exposures. A risk exposure generally can be mitigated only by insuring or contractually transferring the risk. If insurance is not commercially available and the risk cannot be shifted contractually, then management must decide whether the risk can be reduced operationally and determine whether the contract exposure fits within a company’s risk tolerance profile. Drilling contractors often develop their own pro-forma contracts. Such contracts may serve as the starting point for negotiations with an operator. Although sparingly used, they often serve as a comparative guideline. Many drilling contractors M AY / J U N E 2 0 1 2
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Contracts & Risk Management also have developed a contract checklist or contract guidelines. Several supermajors have attempted to create a global master contract for drilling operations, often with input from contractors, but these efforts never seemed to gain traction. Although there have been various attempts to increase standardization of drilling contracts over the years, the reality is that most international and offshore operators prefer their individual contract forms and are unwilling to utilize standard forms. It is unlikely that standard contract forms will become the norm for offshore or international drilling. To indicate the extent to which various types of standard contracts are used, Table 1 discloses 2010 and 2011 sales of IADC model contracts.
CONTRACT EVOLUTION The early drilling industry was largely US-centric, and expansion into other countries has created many new contractual issues. Additional terms developed for international contracts include provisions regarding currency of payment, exchange rate fluctuation, taxation, customs duties, compliance with local laws and, more recently, ethics and business conduct. International contracts often include risk allocation provisions addressing expropriation, nationalization, deprivation and confiscation of the contractor’s rig and equipment. Dispute resolution provisions are of greater import and complexity in international contracts as the parties focus on both the designation of the law that governs the contract and the provisions addressing the nature and location of dispute resolution proceedings. As the offshore industry developed, drilling contracts were revised and supplemented to address aspects of the marine environment. Contract provisions relating to responsibility for transport of personnel and materials between shore and the rig, were added, as were terms addressing responsibility for providing vessels to mobilize, move and demobilize the rig, and revised “sound location” provisions applicable to a marine environment. Risk allocation provisions addressing responsibility for subsea and mooring equipment loss or damage, marine pollution and wreck removal also were developed. As drilling contracts evolved, the length and complexity of the associated
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documentation increased. Today, a longterm contract for a deepwater rig in international operations is likely to be 200 to 300 pages.
EVENTS IMPACTING CONTRACTING PRACTICES Drilling contracts have also been impacted by events and developments involving technological, operational, strategic, legislative, regulatory and judicial activities. The advent of the top drive resulted in revised provisions addressing rig time to service the equipment. Contract terms also have been developed in response to directional and horizontal drilling, addressing excessive wear on the contractor’s drill string as well as liability provisions allocating risk for downhole motor and directional tool loss or damage. The progression into deepwater prompted provisions addressing rates applicable for rig time consumed while tripping the lower marine package and allocating responsibility for payment during suspension of operations necessitated when evading hurricanes in the US Gulf. The advent of dual-activity capability beget special drilling contract terms addressing use (or non-use) of the specialized equipment, partial downtime and patent infringement. Operational events influence drilling contract terms as well. The Piper Alpha platform explosion, Hurricanes Ivan, Katrina and Ike, and Macondo have all caused contractors and operators to refocus on drilling contract terms in general and the risk allocation provisions in particular. Strategic initiatives have impacted drilling contracts on a transitory basis. Perhaps the most significant example is Shell’s Drilling in the Nineties program, which attempted to have drilling contractors serve as a general contractor and “bundle” the ancillary well services. Unveiled during a keynote speech at the 1990 IADC/SPE Drilling Conference, Shell’s initiative was heralded as a means of “revolutionizing” the manner in which operators and drilling contractors would drill wells. Contracts frequently have been modified to address legislative or regulatory requirements relating to pollution and disposition of waste. In the US Gulf, the Oil Pollution Act of 1990 prompted con-
tractual revisions addressing the operator’s responsibility for provision of a Certificate of Financial Responsibility while the Clean Water Act, Resource Conservation and Recovery Act, Refuse Act and the Rivers and Harbors Act caused contracting parties to further delineate responsibility for pollution abatement and cleanup, fines, environmental damage and disposition of waste. Court decisions have impacted drilling contracts in several respects, often on a limited basis. In many cases, the decisions have impacted wording of contractual indemnity provisions. Rulings in litigation involving US admiralty and maritime law have established that a party may lawfully agree to indemnify another party even in the event of negligence or other culpability by means of traditional “knock-for-knock” oilfield indemnities, where each party generally assumes liability for its own personnel, equipment and property, including the operator’s well-related risks, without regard to cause. To quote the US Court of Appeals for the Fifth Circuit decision in Theroit v. Bay Drilling Corp., 783 F.2d 527, 540 (5th Cir. 1986), such provisions generally are enforceable if they are “specific and conspicuous.”
INDEMNITY PROVISIONS Indemnity provisions are among the most controversial aspects of drilling contracts and have frequently been impacted by legislative enactments and judicial rulings. Courts frequently have recognized and supported the fundamental principles underlying indemnity agreements. They are intended to allocate risks between the contracting parties for purposes of permitting the parties themselves to decide which of them should bear specified risks and minimizing legal disputes. This avoids unnecessary and costly duplication of insurance coverages and permits each party to assess its risk exposure under the contract. To achieve this objective, liability and indemnity provisions generally should be absolute and unqualified (“without regard to cause”). While such risk allocation provisions eliminate determinations of fault, certain limitations upon reciprocal “knock-forknock” indemnity provisions are commonplace. Examples of provisions that limit the general protection accorded to contractors include terms commonM AY / J U N E 2 0 1 2
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Contracts & Risk Management 2010 Forms Sold
2011 Forms Sold
Daywork Drilling Contract – US Land
3,600
4,208
Footage Drilling Contract – US Land
1,450
1,370
Model Turnkey Contract
910
680
Offshore Daywork Drilling Contract – US
20
0*
International Daywork Drilling Contract – Land
0
70
International Daywork Drilling Contract – Offshore
170
110
Model IADC Contract
*Sales suspended pending revision
Table 1: The 2010 and 2011 sales of IADC model contracts indicate the extent to which various types of standard contracts are used.
Macondo is expected to impact all manner of contracts associated with drilling operations, including contracts with oilfield equipment manufacturers and service companies.
ly included in dayrate contracts that require the contractor to redrill a lost or damaged well at a reduced rate or absorb a stated limited amount of subsurface pollution liability in the event of a specified degree of contractor negligence. Conversely, the general protection accorded to operators for damage or loss of the drilling rig is normally qualified by provisions that place specified liability on the operator for in-hole and subsea equipment loss/damage or rig damage resulting from an unsound location. Some operator drilling contract forms modify or negate the general risk allocation provisions if a party otherwise entitled to indemnification has committed gross negligence or willful misconduct. Most drilling contractors respond
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by proposing to delete the “carve out” for gross negligence or willful misconduct. If unsuccessful, contractors often seek to “cap” their liability at a specified dollar amount, propose narrow definitions of gross negligence and willful misconduct, and limit the applicability of the overriding provisions to gross negligence or willful misconduct of personnel at or above a stated level of supervisory authority. A fundamental purpose of contractual risk allocation is to create a clear line of demarcation so each party will be able to evaluate its risk exposure. Absolute, indemnity provisions eliminate the need for determinations of fault, negligence or the like. Accordingly, the author and many other practitioners believe the preferred means of contracting involves
utilization of unqualified indemnity provisions in drilling contracts and often counsel clients to reject risk allocation provisions with carve-outs or overrides that potentially create unlimited “bet the company” exposures. There is an ongoing debate as to whether an absolute, unqualified indemnity will be enforceable in the event the recipient of the indemnity has been grossly negligent. As yet, the issue has not definitively been resolved in many jurisdictions. The determination will be dependent on facts, circumstances, specific contract verbiage and, perhaps most importantly, the governing law. Since the decision may be based on public policy, the applicable policy under the governing law may be determinative. Public policy, whether based on judicial or legislative pronouncements, can vary considerably between jurisdictions. As an example, the adjacent states of Texas and Louisiana seemingly have opposite views as most practitioners believe that an indemnity can be enforceable in the event of gross negligence under Texas law but would be unenforceable under Louisiana law and statutes. A decision issued in April 2011 by the US District Court for the Southern District of Texas in Energy XXI, GOM, LLC v. New Tech Engineering, L.P., 2011 U.S. Dist. LEXIS 41223 (US DC Southern District of Texas), addressed the issue of whether an indemnity under a master service agreement governed by US maritime law would be enforceable in the event of gross negligence. In considering the issue, the opinion stated: • There is more support for the position that, under maritime law, an indemnification clause purporting to exempt a party from liability for its own gross negligence is invalid than for the position that such clauses are an appropriate means of risk shifting. Somewhat to the chagrin of many in the offshore industry, the decision concluded “that the indemnity provision in this case, to the extent it encompasses claims for gross negligence, is unenforceable.” The Energy XXI decision is of questionable precedential value since it was interlocutory in nature and focused on the wording of a specific indemnity provision. Certification to the Fifth Circuit Court of Appeal has been requested. M AY / J U N E 2 0 1 2
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Contracts & Risk Management IMPACT OF MACONDO The 20 April 2010 Macondo blowout caused substantial human, economic and environmental losses. Although the costs relating to Macondo are ongoing, it is clear that the resulting expenses, losses, liabilities and damages will amount to tens of billions of dollars. The event has already impacted drilling contract terms and surely will add complexity to drilling contracts over the next few years. In general, the post-Macondo industry maintains the traditional “knock-forknock” risk allocation principle, and the operator assumes the well-related risks, including costs and expenses in relation to pollution abatement, clean-up and liability, perhaps with a limited carve-out under circumstances involving a specified degree of contractor negligence. In the aftermath of Macondo, with the renewed focus on contractual provisions addressing liability for pollution emanating from the well, operators are attempting to whittle away at the traditional risk allocation by proposing to qualify the general indemnity relating to subsea pollution so as to exclude coverage for punitive damages, fines or penalties attributed to the contractor. Post-Macondo contracting also has witnessed an increase in proposals by operators to negate indemnity coverage in the event of the indemnitee’s gross negligence or willful misconduct. Contractors obviously are resisting such fundamental changes to customary risk allocation. Further, Macondo has and will impact other aspects of contractual risk allocation. In many cases, contractors are proposing to change terms to address postMacondo concerns. Such changes include expansion of the indemnified parties to include service companies, equipment manufacturers and other parties that have received an indemnity from the contractor, provisions stating that a material breach of contract shall not impact the contractual risk allocations, as well as proposed terms addressing an obligation to fund defense of claims subject to indemnity and recovery of costs incurred to enforce the contractual indemnities. Recent drilling contracts for work in the US Gulf of Mexico often address new post-Macondo regulatory requirements relating to BOP certification and testing. Provisions obligating the contractor to act in accordance with Safety and Environmental Management System M AY / J U N E 2 0 1 2
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(SEMS) requirements are also frequently proposed by operators, along with more stringent terms addressing maintenance, testing and certification of BOP, rig crew training, etc. Another impact of Macondo relates to the offshore drilling moratoria that were imposed by the US government following the oil spill. Post-Macondo, operators frequently propose to modify contractual force majeure clauses so as to include
moratoria, stop orders, refusal to issue drilling permits and similar government actions in the definition of force majeure events. Conversely, contractors frequently propose to include delays and suspensions of operations caused by such activities in the list of events that are subject to the standby rate. Insurance provisions have been impacted by Macondo as well, especially since BP claimed entitlement to cov-
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Contracts & Risk Management erage as an additional insured under the drilling contractor’s liability policies. Post-Macondo, the parties have focused on drilling contract provisions relating to additional assured endorsements and waivers of subrogation. Macondo has impacted the wording of insurance policies and certificates of insurance in several respects. Macondo may also signal the demise of the traditional takeover clause in drilling contracts. A typical takeover clause provides that the operator is entitled to takeover and operate the contractor’s rig in specified circumstances, which often include unsatisfactory or unsafe performance. Such provisions have been included in the vast majority of drilling contracts, although they are virtually never invoked. Post-Macondo, operators and their legal advisors have viewed such provisions as problematic since they may impact risk allocation before and after a takeover and could raise questions as to why an operator did not exercise the right to take over operations when it knew or should have known that the drilling contractor was acting in a negligent manner or operating unsafely. Elimination of the takeover clause may be the only contractual impact of Macondo that likely would be embraced by both contractors and operators.
FUTURE TRENDS Undoubtedly, drilling contract terms will continue to be impacted by operational, strategic, judicial, legislative and regulatory events, the most significant of which will likely be driven by implications of Macondo. Although the initial impact of Macondo primarily has been in relation to contracts for deepwater drilling in the US Gulf of Mexico, it is anticipated that Macondo will ultimately impact contracts for shallow-water and onshore drilling in the US and elsewhere. Macondo already has prompted new regulatory requirements and will surely result in additional legislative/regulatory pronouncements. The Report to the President by the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling that was released on 14 September 2011, includes many pages of recommendations for proposed new administrative actions and regulatory enactments. Although the extent to which the recommendations will be implemented or enacted remains to be determined, it is
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clear that future US Gulf of Mexico drilling contracts have and will be impacted by changes in the regulatory regime. Among the provisions that have and will be impacted are terms addressing change in laws and regulations, payment for rig time consumed for new BOP testing and certification requirements (including time required to pull and run the BOPE and perform remedial work), and payment for rig time consumed during rig inspections. Although the current focus is largely US-centric, it is anticipated that other countries also will enact new regulatory requirements that will impact contract terms. Drilling contracts also will be impacted by the results of the litigation relating to Macondo. The plethora of pending litigation involves liability claims filed against the principal parties (the operator, driller and cementing contractor) by a myriad of parties, including individuals, corporations and governmental entities, various claims and counterclaims between the principal parties and a maritime limitation of liability proceeding brought by the rig owner. The results of this pending litigation – especially as respects the interpretation and application of the provisions of the drilling and other associated contracts in general and the enforceability of indemnities in contracts governed by US maritime law in particular – are likely to influence contract terms in several respects and could even cause contractors to relocate their rigs to other jurisdictions. Resolution of the litigation will be a protracted process that will likely span many years. A 26 January 2012 order ruling on partial summary judgment cross-motions in the BP/Transocean Macondo litigation involving interpretation and enforceability of the drilling contract indemnity provisions determined that: • BP generally is required to indemnify Transocean for third-party claims resulting from subsea pollution, even if resulting from gross negligence or strict liability; • The indemnity does not apply to punitive damages assessed against Transocean; • The indemnity does not apply to penalties assessed against Transocean under the Clean Water Act but does apply to penalties assessed under the Oil
Pollution Act of 1990 (which expressly permits contractual indemnification); • The court deferred ruling on whether Transocean’s alleged material breach of contract would invalidate the indemnities that benefit Transocean; and • BP was not obligated to fund Transocean’s expenses to defend thirdparty claims at that time. On 31 January 2012, an order was issued in relation to partial summary judgment cross-motions in the BP/ Halliburton Macondo litigation involving the interpretation and enforceability of the cementing contract indemnity provisions. That order generally followed the above determinations in the BP/ Transocean litigation and held that fraud could void an indemnity clause on public policy grounds given that it necessarily includes intentional wrongdoing. It should be noted that the foregoing rulings were issued by the US District Court for the Eastern District of Louisiana in the context of partial summary judgment cross-motions and relate to contracts governed by US general maritime law. The most significant aspect of the rulings – that oilfield indemnities are enforceable even in the event of gross negligence (when so expressed) – is contrary to the April 2001 decision by the US District Court for the Southern District of Texas in the Energy XXI litigation. We thus have two District Courts within the Fifth Circuit that are dynamically opposed in respect of their determinations as to whether an oilfield indemnity that expresses an intent to be applicable in the event of gross negligence will be enforceable as a matter of public policy under US general maritime law. Moreover, the ruling in the BP/ Halliburton litigation seemingly indicates that the court would not enforce an oilfield indemnity governed by US general maritime law in the event of willful misconduct or other intentional wrongdoing. These are important rulings that are likely to be subject to further clarification at trial, on appeal or in other pending or future litigation. Although the interlocutory summary judgment rulings in respect of the drilling contract indemnity provisions are of particular import, the author of this article is of the opinion that there are certain significant aspects of the governing contractual verbiage that may prove to be outcome determinative that were not addressed in the M AY / J U N E 2 0 1 2
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Contracts & Risk Management motions, the associated briefs or the court’s order. The results of the ongoing litigation relating to Macondo undoubtedly will impact the indemnity provisions of future drilling and oil service contracts, especially as respects operations in the US Gulf of Mexico. While the litigation is expected to provide clarity regarding the extent to which the parties may or may not be able to lawfully allocate various liabilities, risks and exposures, the rulings also are expected to raise many questions for practitioners, producers, contractors, insurance underwriters and the courts to address over the ensuing years. Future drilling contracts also are expected to be impacted by various operational, strategic, legislative, regulatory and judicial developments. As an example, the latest evolution in rig design technology that entails provision of dual BOP stacks on deepwater rigs is likely to engender changes in contractual terms. Moreover, new US and foreign regulations are likely to increase liability and
fines for oil pollution, clean-up and abatement. Such new regulations may impact future drilling contract terms addressing the respective parties’ obligations and the allocations of risk. It should be noted that the impact of Macondo is likely to extend beyond drilling contracts. As an example, the terms of post-Macondo joint operating agreements between E&P companies will probably shift additional liability to the designated operator. Operators that have been compelled to bear more risk than non-operating participants may attempt to modify future drilling and service contracts in order to transfer some or all of that risk. Indeed, Macondo is expected to impact all manner of contracts associated with drilling operations, including contracts with oilfield equipment manufacturers and service companies.
CONCLUSIONS Since the advent of the drilling industry over a century ago, drilling contracts have evolved to become increasingly
more complex. This largely reflects the growth and development of the industry, expansion internationally and offshore, technical innovations, as well as operational, strategic, legislative and judicial developments. Moreover, Macondo has and will impact drilling operations and related contracts. The future is uncertain and the only certainty is that drilling industry practices, technology, equipment, regulatory requirements and contracts will continue to evolve and change. This article is based on IADC/SPE 151442, “Drilling Contract Historical Development and Future Trends Post-Macondo: Reflections on a 35 Year Industry Career,” presented at the 2012 IADC/SPE Drilling Conference and Exhibition, San Diego, Calif., 6–8 March 2012. Scan to read the full article containing additional contract examples and court ruling discussions.
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Drilling Optimization
Drilling optimization culture built on real-time data, communication Cycle of continuous feedback, improvement drives strategy for better performance in Brazil’s Santos Basin
BY AUGUSTO BORELLA HOUGAZ, DANILO S. GOZZI, ISAO FUJISHIMA, KLAUS L. VELLO, PETROBRAS; SANDRO ALVES, IAN THOMSON, RAUL KRASUK, FRANK BUZZERIO, BAKER HUGHES Figure 1: To meet the challenges of Brazil’s deepwater drilling environment, a real-time drilling optimization team was established. One key was to use real-time data and downhole drilling parameters to drive a continuous feedback cycle.
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I
n recent years, deepwater drilling operations have become more challenging, with new exploratory frontiers and the rise of rig rates demanding firstclass drilling optimization technology and services. In Brazil, deepwater well construction activities have increased significantly since the first major pre-salt discovery in the Santos Basin in 2006. In this highly demanding and challenging drilling scenario, building a drilling optimization culture based on the synergy and integration between a major deepwater operator and a leading service company has proven to be fundamental
for achieving better drilling results and superior performance. The creation of a multidisciplinary drilling optimization group, integrated with the operator’s drilling team in 2008, and the introduction of a highly specialized downhole drilling dynamics measurement-while-drilling (MWD) tool changed the drilling optimization concept in Brazil. This concept pioneered the remote (off-the-rig) downhole drilling parameters surveillance in deepwater operations. This article presents the fundamentals of this real-time remote and rig-site M AY / J U N E 2 0 1 2
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Drilling Optimization drilling optimization concept, with focus on the integration between the operator and the service company; the operational aspects with regards to appropriate communication protocols; and decisionmaking processes, highlighting the performance improvement achieved.
BACKGROUND Demand for first-class drilling optimization technology and services is growing fast. In Brazil, a novel real-time optimization drilling service was implemented in 2008 in the Santos Basin. Through its implementation and execution, it became clear the importance of knowing not only where (wellbore placement) and what (formation evaluation) you are drilling but also how you are drilling, which is mainly driven by the integration between operator and service company. After three years, it was clearly observed that the higher the integration between service company and operator in a proactive and collaborative environment, the higher the drilling performance. Today in the deepwater Santos Basin pre-salt environment, the real-time optimization drilling service is part of the drilling program in almost every well, from the top-hole section (typically 26-in. hole) to the reservoir section. The ability to gather and interpret reliable downhole MWD data in exploration or new development wells is crucial to help with the early detection and identification of unexpected drilling behavior, allowing better judgment of actions to be taken because it switches from perception- and experience-based decisions to ones supported by real-time data. This can save rig time and mitigate catastrophic failures.
The contact during service optimization and real-time monitoring is accomplished daily and directly between the teams, both in the office and on the rig site. This constant interaction between responsible personnel, including the manager of the well, design engineers and geologists (office and crew operator), coupled with the rig team, makes all difference in the outcome of the operation. The project is always aiming to continu-
ously improve performance while monitoring and adjusting drilling parameters in real time when necessary. It also operates with the objective to capture lessons learned to feed future projects. To accomplish effective remote and rig-site real-time drilling optimization, the use of a highly specialized downhole drilling dynamics MWD tool is key as it records and transmits dynamics realtime data (stick slip, whirl, etc) and down-
REAL-TIME DRILLING OPTIMIZATION TEAM In 2008, a culture of real-time optimization was started in Brazilâ&#x20AC;&#x2122;s Santos Basin with a multidisciplinary optimization team. The service companiesâ&#x20AC;&#x2122; real-time drilling optimization team was formed to provide quality real-time drilling services and support the operatorâ&#x20AC;&#x2122;s decision-making process. To accomplish this objective, the team was conceptually designed to incorporate members with diverse backgrounds, such as directional drilling, MWD engineers, mud logging, geosciences, geology, bit runners, etc. M AY / J U N E 2 0 1 2
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Drilling Optimization
Figure 2: The engineered optimization process is based on the continuous improvement cycle. The four main steps build on one another, and application involves teamwork and close cooperation between the operator and drilling service companies.
hole drilling parameters (WOB, torque, etc), which allow a better judgment of the downhole conditions while drilling. This in turn allows better support for adjusting and changing the surface drilling parameters to optimize operations in a continuous feedback cycle (Figure 1). In general terms, the main objectives for the drilling optimization service are: • Drill safe and fast; • Twenty-four hour real-time monitoring service; • Technically support operator decision-making process; • Visualize downhole data in real time; • Optimize overall performance while drilling; • Minimize and control the vibration levels; • Monitor the wellbore quality; • Improve and accelerate learning curve; and • Document best practices and achievements. The service has to allow decision-making process improvements in two directions: • Make decisions based on measurable facts and critically analyzed data instead of perception or experience, which is not always comparable; and • Make decisions in the real-time, 24/7 drilling optimization service for an extended period allows the building of a local database of local best practices and operator/service company common understanding.
IMPROVE /ACCELERATE LESSONS LEARNED PROCESS
Figure 3: The steps from the continuous improvement cycle are broken down into subcomponents to ensure that nothing is overlooked during optimization.
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Improving and accelerating the lessons learned process is always required, but it becomes mandatory when the activity level multiplies the rig count by an order of magnitude and operating costs are rising significantly. Capturing documented lessons learned and disseminating knowledge are critical components in this working environment. Drilling process improvements include many different actions; some are related to new methods, technologies, drilling practices and new concepts. Performing something new or innovative presents challenges and risks, which need to be properly addressed by providing accurate downhole data in real time that allow appropriate risk evaluation and mitigation actions.
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Drilling Optimization ENGINEERED OPTIMIZATION PROCESS WITH CONTINUOUS IMPROVEMENT CYCLE The engineered optimization process has been used for decades in various applications and is based on the continuous improvement cycle (Figure 2). In this application, the process involved teamwork and close cooperation between the operator and the drilling service companies. The key components are: 1. Plan – Establish objectives for the well, reasons for optimization and prewell planning. 2. Execute the drilling phase by implementing the optimization plan. 3. Analyze post-well analysis, reviewing the actual performance. 4. Capture lessons learned. Each step is broken down into subcomponents, building on one another to develop a thorough understanding of the application and drilling environment while ensuring nothing is overlooked (Figure 3). The emphasis of this cooperative program is on detailed engineering of every step, using the process to work
smarter and more efficiently. The engineered optimization process relies heavily on knowledge management and on the application of drilling best practices and procedures, which require highly competent application engineering. The “capture” requirement of the “continuous improvement cycle” was used by the service company to ensure that past mistakes were avoided and good past performance was repeated.
CASE STUDY 1 STARTING REMOTE OPTIMIZATION CONCEPT IN DEEPWATER OPERATIONS The first step was to analyze and understand the previous scenario, including drilling operations problems and challenges, as well as the technology and drilling parameters used, drilling practices and the interaction between all those factors. The most appropriate technology and drilling practices were then presented and discussed. The drilling of development wells in
the Santos Basin had opportunities for optimization and recurring problems that could be solved and/or minimized with changes in the bottomhole assembly (BHA) configuration, and especially with the control and management of downhole data. The real-time drilling optimization service was implemented in a development horizontal well in the Santos Basin in late 2008. At that time, the interaction was among the well manager, the drilling optimization engineer and the rig team. After the excellent results of the first well, a sequence of development wells in different Santos Basin fields were drilled using the same service concept. For each new well drilled, the results showed improvements, not only in cost reduction but in communication between the teams.
DEVELOPMENT WELLS PREVIOUS SCENARIO Before the implementation of the optimization service, the main problems and observations reported were:
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Drilling Optimization 8 ½-in. section – Two trajectories (one directional and one horizontal), medium interbedded formation: • Low penetration rate; • High temperature (approximately 195ºC); • Presence of risk to stick by differential pressure; • Sticking events related to mechanical issues; o Backreaming to minimize stuck events risk. • Drilling parameters not optimized (approximately 100 rpm / 10-30 Klbf), using surface data; • Recurrent directional and MWD or logging while drilling tool failures; o Insufficient dogleg severity; and o Reported high vibration levels and high temperatures as causes. • Additional runs leading to greater drilling time and higher costs; • Changes in the parameters, with significant focus on attempts to reduce vibration levels; • Shock sub placement; • Unsuccessful attempts to sidetrack the well with rotary steerable systems (RSS); • Exceeded buckling load while drilling in slide mode with motor; • Low drill bit depth-of-cut control (DOC) and toolface control problems; • Use of motor with adjustable kickoff sub (AKO) without directional needs, compromising the borehole quality; and • Bits used were heavy for the specific formation drilled.
OPTIMIZATION PROPOSALS After thorough analyses, including peer reviews with the operator, a plan of action with appropriate proposals was elaborated. Covering new technologies and real-time drilling optimization service previously established, discussed between the operator and service company, the initial goal was focused on solving or minimizing recurring problems but always striving for continuous improvement by working directly with the well manager. The main points of the proposals were: • Optimize BHA design and configuration to drill the section in a single run; • PDC bit designed for the application; o Diamond volume management; o Appropriate cutter selection to address formation abrasiveness; o DOC for improved toolface control;
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o Lateral movement mitigator to minimize vibration levels and lateral impacts; and o Secondary stability features. • Equivalent circulating density (ECD) and borehole cleaning real-time monitoring; • Early detection of stuck-pipe tendency; • Perform the sidetrack with drilling BHA, reducing a trip to do it; • High-temperature procedures implementation to minimize the potential for BHA electronics components failure; and • Use of highly specialized downhole drilling mechanics and dynamics diagnostics MWD tool with 24-hr real-time monitoring service to provide support for all drilling operations with fast response to take action.
RESULTS During the first drilling optimization service performed in the Santos Basin, it was observed that drilling performance improved whenever the integration between operator and service company worked. Results obtained at the end of the study were highly positive, going beyond the expected and planned project, being repeated in the following development wells. Relevant points of this achievement are: • Drilling performance more than doubled with adjusted downhole drilling parameters in real time; • Operation time and costs significantly reduced; • Minimized vibrations levels (observed only low to moderate); • Minimized sticking events, identifying nonproductive time and taking action with fast response; • No failures caused for vibration or high temperature; and • Teamwork guaranteed by integration between well manager, geologist, drilling optimization engineer and rig team.
RESERVOIR DATA ACQUISITION To expand the success achieved in the development wells, the real-time drilling optimization service was implemented in highly demanding reservoir data acquisition (RDA) and development deepwater wells in the Santos Basin. In a new pre-salt scenario in carbonate reservoirs in the Santos Basin, an opportunity for improvement was observed
on the new drilling optimization culture based on the synergy and integration between the operator and service company. The key to success was the direct integration between the operator’s design engineer team, which is responsible for RDA/development well projects, and the service company’s support teams. A direct communication channel between design and drilling optimization engineers – which was already established in the first pre-salt well drilled with this concept – enabled the constant feed and support for the project execution. The result was a significant improvement for each drilled well, supported by an accelerated lessons learned process, updating procedures, and reducing time, risks and operations costs. The following examples are divided by drilling sections – 26 in., 14 ¾ in. and 8 ½ in., not by chronological improvements.
PREVIOUS SCENARIO Before implementation of the integrated real-time drilling optimization service, the main reported problems and/or observations for RDA/development wells were:
26-IN. SECTION Issues in the post-salt section were: • Relatively low penetration rate; • Drilling parameters that were not optimized; • Lack of remote access to drilling surface data (flow rate, torque, rpm); • No downhole drilling data/measurements; • High tricone bit revolutions due to high motor and surface RPM; • Reduced bit life – trip for bit hours/ revolutions; • Lack of smooth and steady WOB; and • Formation-induced deviation tendency.
14 ¾-IN. SECTION Issues in the evaporitic section were: • Bit changes/more runs; • Salt formation mobility problems and doubts; • Low penetration rate; • WOB control instability; • Doubts about salt drilling response for directional issues; • Drilling parameters not accurately optimized; • Lack of downhole drilling data/measurements; M AY / J U N E 2 0 1 2
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Drilling Optimization • Common sense between drilling dynamics changes and undefined salt interfaces variations; • Excessive time spent on connection operations; • Stop criteria undefined (total section depth); and • Identified optimization opportunities to reduce time and costs.
8 ½-IN. SECTION Issues in the pre-salt section were: • Low penetration rates; • Rock mechanic characteristics variations; • Use of the same drilling system (impregnated bit and turbine); no different system used for comparison; • Common sense between drilling dynamics changes and undefined pre-salt lithology variations; • More runs to change the bit based on extremely low penetration rates; • WOB control instability; • Lack of accurately optimized drilling parameters; and • Identified optimization opportunities
to reduce time and costs.
OPTIMIZATION PROPOSALS 26-IN. SECTION • Use of motor low speed (LS) to minimize bit revolutions and optimize the tricone bit life and run; • Use of automated motor-assisted vertical system for drilling in vertical mode and minimize any inclination increment tendencies; • Use of highly specialized downhole drilling mechanics and dynamics diagnostics MWD tool with 24-hr real-time monitoring service to provide support for all drilling operation; and • Direct communication channel between design engineers, well manager, geologist and drilling optimization engineers.
14 ¾-IN. SECTION • Use of RSS and PDC bit; • DOC control to guarantee better dynamics conditions and drilling optimization possibilities;
• Better borehole quality; • Drilling dynamics stability minimizing vibration effects; • Use of highly specialized downhole drilling mechanics and dynamics diagnostics MWD tool with 24-hr real-time monitoring service to provide support for all drilling operations; and • Direct communication channel between design engineers, well manager, geologist and drilling optimization engineers.
8 ½-IN. SECTION • Use of motor LS automated drilling system to minimize vibration levels and prioritize high WOB application; • Use of PDC bit with motor, seeking better performance and data to improve PDC bit design for this new scenario; • DOC control to guarantee better dynamics conditions and drilling optimization possibilities; o Better borehole quality; and o Drilling dynamics stability minimizing vibration effects. • Use of modular stabilizers to improve
Fisher Offshore are an authorised master distributor and service centre for Ingersoll-Rand lifting equipment and spare parts We also have a large rental fleet of lifting equipment including winches, hoists, marine cranes and tooling. • Man Rider Winches • Utility Winches • Small portable hoists • BOP Handling Systems Hoists • Genuine Spare Parts • Inspection, repair, maintenance and testing facilities on site • Maintenance programmes offered Fisher Offshore North Meadows Oldmeldrum Aberdeenshire AB51 0GQ Tel: + 44 (0) 1651 873932 Fax: + 44 (0) 1651 873939 advertising@fisheroffshore.com
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A James Fisher Group Company
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Drilling Optimization BHA configuration; • Prioritize high WOB and low drill string rotation; • Use of highly specialized downhole drilling mechanics and dynamics diagnostics MWD tool with 24-hr real-time monitoring service to provide support for all drilling operations; and • Direct communication channel between design engineers, well manager, geologist and drilling optimization engineers.
RESULTS 26-IN. SECTION The last real-time drilling optimization service implemented in the Santos Basin was for this section, changing paradigms on drilling parameters and dynamics response. The significant results of the integrated real-time drilling optimization service on post-salt formation were: • Reduced operation time and costs, minimizing risks by 24/7 monitoring service; • Optimized drilling parameters; • Paradigm changes, ROP improved by an average of 100% to 200%; • Monitored drilling dynamics, gathering knowledge about post-salt lithology variations; • Understanding of “how we are drilling” with downhole data, improving the lessons learned cycle related to procedures and projects; • Downhole WOB always applied near
to bit, specified limit to optimize ROP; • Improve WOB application control with downhole WOB real-time data, optimizing ROP, reducing vibration levels and minimizing bit structure damage risks; • Torque response monitored by downhole data, supporting any decision based on bit structure indications; • Improve bit life with total rpm to TD reduction; • Downhole data supporting the lithology change identifications, helping to identify the evaporitic section; and • Use of motor LS with the steerable function (could be the better option to ensure vertical drilling as planned).
14 ¾-IN. SECTION The real-time drilling optimization service was implemented for the evaporitic section, mainly looking for optimization, fixing directional monitoring issues and providing support for stuck events related to salt mobility. The significant results of the integrated real-time drilling optimization service on the evaporitic section were: • Reduced operation time and costs, minimizing risks by 24/7 monitoring service; • Drilling parameters optimized; • ROP improved an average of 75% to 125%; • Drilling dynamics monitored, gathering knowledge about the evaporitic section (lithology variations); • Understanding of “how we are drill-
ing” with downhole data, improving the lessons learned cycle related to procedures and projects; • Downhole WOB always applied near to bit, specified limit to optimize ROP; • Started the use of auto-drill technology to optimize downhole WOB application; • Optimization of auto-drill application, minimizing damping effect and improving WOB control; • Auto-drill applications were optimized, resulting in ROP improvement, vibration reduction and minimizing of bit structure damage risks; • Lithology changes were monitored by downhole drilling parameters, as torque responses, helping to identify evaporitic section variations; • Stuck events minimized by applying backreaming procedures and mud weight control improvements; • Directional drilling performed with success, supported by directional monitoring service; and • Clear criteria for section’s end was established based on downhole drilling parameters.
8 ½-IN. SECTION • ROP improved using impregnated bit; • PDC bit runs supported improvements for bit design; • Impregnated bit runs showed better results than PDC runs in the initial tests; • Downhole data supported future
Drilling optimization by the numbers • Real-time drilling optimization service integration in the section improved ROP by an average of
100%
to
200%
• Integrating real-time drilling optimization service in the 14 improved ROP by an average of • Since
26-in.
75% to 125%.
hole .
¾-in. section
2008, more than 200 hours of real-time drilling optimization
operations have been conducted in Brazil, with more than
meters
183,000
drilled in deepwater wells, mostly in the Santos Basin and in
exploratory wells.
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Drilling Optimization plans and decisions seeking performance improvement; â&#x20AC;˘ Drilling dynamics were monitored, knowledge was gathered about the presalt formation (lithology variations); â&#x20AC;˘ Auto-drill application was optimized, resulting in ROP improvement, reduction in vibration levels and minimizing of bit structure damage risks; and â&#x20AC;˘ Need for more improvements with high technology to get significant results.
CONCLUSIONS The partnership established between operator and service company in the wells drilled in the Santos Basin became a strategy to improve and contribute to the successful results obtained in drilling operations since 2008. All decisions were made jointly. This created a specific communications pattern, and the mutual confidence grew with each new work accomplished. After the first service, a culture of continuous learning was started, allowing continuous improvement for future projects. Since 2008, more than 200 hours of
real-time drilling optimization operations have been conducted in Brazil, with more than 183,000 meters drilled in deepwater wells, mostly in the Santos Basin and in exploratory wells. The keys for this success are: â&#x20AC;˘ Create a strong teamwork culture between the operator and the service company to achieve an â&#x20AC;&#x153;integrated realtime drilling optimization serviceâ&#x20AC;?; â&#x20AC;˘ Keeping an open mind to new ideas, and discussions and always looking for a holistic view; â&#x20AC;˘ Working closely with all personnel/ areas involved on the operation to ensure continuous global performance improvement; and â&#x20AC;˘ Use of a highly specialized downhole drilling dynamics MWD tool/drilling optimization service to ensure: o Better drilling dynamics control; o Real-time downhole parameters change responses, helping to guide actions both for drilling and geologist teams (drilling dynamics issues); o Better borehole quality and conditions control (ECD, pressure);
o Better directional trajectory control and identification of any abnormal events using bending moment and bending toolface data (local high DLS, spiraling tendencies). This mainly supported the directional drillers on the rig site; o WOB transfer and cutting bit structure monitoring; o Vibration downhole diagnostics (near the bit) ensured more precision for downhole parameter adjustments to minimize vibration levels; o Drilling horizontally as smoothly and efficiently as you would vertically; and o Creating the longest wells economically and efficiently, knowing exactly where and how you are drilling. This article is based on IADC/SPE 151186, â&#x20AC;&#x153;Upgrading the Real-Time Drilling Optimization Culture in Brazilâ&#x20AC;&#x2122;s Challenging Deepwater Operations: The Utilization of a Remote and Rigsite Multidisciplinary Collaborative Concept,â&#x20AC;? presented at the 2012 IADC/SPE Drilling Conference and Exhibition, San Diego, Calif., 6â&#x20AC;&#x201C;8 March 2012.
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Since 1979 Custom Safety Products, Inc. has been supplying the petroleum industry with our award winning Safety Pad IIFR. As improving safety throughout the workplace is our priority, we have continued to develop new solutions and designs that answer the demands of a changing industry and the Health, Safety & Environmental expectations of operators and companies. We are proud to introduce new products and solutions in response to customer requests, including our new non-studded traction mat: Safety Pad IIIFR. This new non-skid design provides an exceptionally high traction surface while continuing to have all the qualities of our original Safety Pad IIFR. We also have available CS-150 for increased traction & protection in setback areas. In our continued pursuit of solutions, we are also pleased to announce our strategic alliance with Advanced Mat Systems, Inc. based in Alberta, Canada. This alliance combines the expertise of two leading businesses and product designs allowing us to provide industries with a greater selection of traction & anti-fatigue mats, including the Arctic Pad family of Heated traction & anti-fatigue pads. The Arctic Pad family is designed to reduce injuries in colder climates when the risk of ice & snow accumulation increases the potential for slip-fall type accidents. For over 30 years, more than 700 companies and 7,000 drilling rigs worldwide have benefited from our proven and original family of traction mats. You can be assured that by using Custom Safety Products, Inc., you are improving safety and eliminating injuries.
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Education & Training
Houston programs provide industry edge BY JOANNE LIOU AND KATHERINE SCOTT, EDITORIAL COORDINATORS
I
n the mecca of the oil and gas industry, Houston-area college and university programs are giving students a leg up into the industry, from field services to petroleum engineering. As the industry continues to expand, these institutions recognize the demand and opportunity to provide an educational background that leads to a career in the realm of oil and gas. Companies have actively recruited graduates of Lone Star Collegeâ&#x20AC;&#x2122;s drilling
program, which began in January 2011. In one semester (16 weeks), students, including veterans and professionals of other industries, can graduate with a marketable skills award certificate, which makes them a top candidate for local service companies. The engineering technology program is part of the Lone Star Energy & Manufacturing Institute. One of only a few programs in the US, the undergraduate petroleum engineering program at the University of Houston has received support from industry and has worked with companies to provide students with internships through their
college career. The program, which began in fall 2009, was developed in response to the industryâ&#x20AC;&#x2122;s need for more engineers. The new undergraduate program combines the fundamentals of petroleum engineering and geoscience with economics, energy law and business. Scan to watch two exclusive videos about the programs offered at Lone Star College and the University of Houston.
Students in the petroleum field service technology program participate in a lab at Lone Star College in Cypress, Texas. The hands-on program includes lectures in petroleum technology and instrumentation. In about 16 weeks, students can earn a marketable skills award certificate, which makes them a top candidate when they enter the job market.
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Education & Training Students in the undergraduate petroleum engineering program at the University of Houston take various lab courses to gain an understanding of petroleum engineering. Industry contributes to the program by hiring students as interns, providing professionals to teach classes and making donations to support the program.
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Lloyd’s Register and ModuSpec are trading names of the Lloyd’s Register Group of entities. Services are provided by members of the Lloyd’s Register Group. For further details please see our web site: www.lr.org/entities
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IADC Connection
Editorial
FROM THE PRESIDENT
Sparking performance improvement
“T
Stephen Colville, IADC president
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he ear of the leader must ring with the voices of the people.” – Woodrow Wilson
During my first days as president of IADC, I’ve been doing a lot of listening. I’m listening to land drilling contractors. I’m listening to deepwater and shallow-water drilling contractors. I’m listening to producers and equipment suppliers. As IADC staff undertakes the strategic review to outline the future direction of this association, we must have really heard and fully understood our members’ concerns. We need to know what they need IADC to focus on over the next five years. Although that review is only just beginning to take shape, one fact has become clear: IADC is not in the trade association business; we’re in the performance improvement business, and we are the spark that makes it happen. IADC exists to catalyze members’ efforts to improve personal and company performance. A key part of how we will do this is around competencies. For example, we’re exploring the development of KSA’s (knowledge, skills and abilities) for drilling positions; a workshop was held earlier this year at a NASA facility in Houston to examine the project scope. We’re also continuing significant efforts with WellCAP to ensure it is focused on critical skills. A revised Drilling Supervisory Level curriculum has been completed, and more program enhancements are under way. IADC’s various committees make up another vital compo-
nent of how we drive change and improvement in the industry. We will be reviewing the structure and processes of existing committees to make sure that critical topics are on the agenda and that committee functions are facilitating expeditious decision-making. Further enabling the participation of members from different geographical areas around the world is another key goal. IADC is a global organization, and our committees must be driven by a diverse membership. In addition, IADC will look at potentially creating new committees, standing or ad hoc, to more fully address topics of high importance, such as process safety. The maintenance of critical equipment is another area that may benefit from more concentrated efforts. In particular, the ability to capture and share real-time in-field equipment performance data is emerging as a critical challenge for better performance. Doubtlessly, these ideas and IADC’s work scope will evolve as our strategic review progresses. However, it is clear that our members want us to be far more proactive, and we intend to meet that challenge. The flip side of that is, our members must be willing to do the same. As the old saying goes, “The world is run by the people who show up.” IADC relies totally on the willingness of our members with key knowledge, experience and skills to get fully involved and help drive personal and company performance improvement. I am looking forward to meeting as many of you as I can, and working with and for you all.
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IADC Connection
News Cuttings
Well Control Committee leaders Maness, Andersson honored Brian Maness, Diamond Offshore Drilling, and Goran Andersson, Chevron, were honored on 7 March for their service to the IADC Well Control Committee. Mr Maness, longtime committee member and chairman for the past three years, led the committee during a time of signifi- Brian Maness (left) and Goran Andersson cant changes, uniting were recognized for their leadership of drilling contractor, the IADC Well Control Committee on 7 operator and train- March. ing provider members around a goal to strengthen well control training and WellCAP. Mr Andersson served as the committee’s co-chairman and spearheaded the Curriculum Subcommittee’s two-year review and revision of the WellCAP Drilling Supervisory Level curriculum (See a profile article of Mr Andersson, Page 166). Dr Brenda Kelly, IADC senior director – program development and staff liaison to the Well Control Committee, said, “Our industry has benefitted greatly from Mr Maness’ and Mr Andersson’s leadership. During their tenure, important WellCAP program enhancements were achieved.” Dan Munoz, Transocean, succeeds Mr Maness as the committee’s chairman for 2012 to 2014. William “Bill” Rau of Chevron and Paul Sonnemann of SideKick will serve as co-chairs.
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IADC attends launch of Petronas in-house competence program IADC operations assistant – Asia operations Chit Hlaing attended the launch of Petronas Carigali’s Capability Development Journey on 9 March in Kuala Lumpur, Malaysia. Mr Hlaing distributed IADC textbooks during a handover ceremony. Capability Development Journey is an in-house structured competence development program created by Petronas Carigali’s Drilling Division to support and guide engineers. The program covers the fundamentals of exploration and production, petroleum engineering, drilling courses, WellCAP-accredited well control courses and HSE-related courses. Upon passing all courses, a final exam determines the type of job for which the engineer is most suited. The handover ceremony was held between the Drilling Division and various service companies.
IADC calls for sharing of safety alerts Since 1998, the IADC Safety Alert Program has been recognized worldwide as one of the industry’s best tools for sharing best practices and lessons learned from incidents in oil and gas operations. The intent of the safety alert program is to share such learnings with industry partners to assist in providing a safe workplace for all oil and gas employees. Recently there has been a decreased number of alerts and best practices shared with IADC. If your company has an alert that focuses on best practices or lessons learned, please share with the wider industry by sending the alert to safety.alerts@iadc.org.
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News Cuttings Shayegi awarded for IADC service Steve Kropla, IADC group VP operations and accreditation, presents a service recognition award to Shell’s Sara Shayegi, who just ended her term as chairperson of the IADC Underbalanced Operations & Managed Pressure Drilling Committee, on 20 March at the 2012 SPE/IADC MPD & UBO Conference in Milan, Italy. Ms Shayegi continues to serve as co-chairperson of the MPD Subcommittee.
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IADC Connection
Karish recognized for committee leadership IADC recognized John Karish, director safety, health environment for Ensco, at the IADC Health, Safety, Environment and Training Conference on 7 February in Houston. Mr Karish served as chairman of the IADC Health, Safety and Environment Committee for the 2009 to 2011 terms. “John has devoted significant time over the past three years to serving the HSE Committee, which aims to provide a forum for the industry to exchange best practices and promote activities that enhance HSE performance. John’s leadership and dedication to helping the industry at large is greatly appreciated,” said Joe Hurt, IADC regional VP North America and lead staff land HSE issues. Mr Karish has been succeeded by Tony Johnson, senior corporate QHSE manager, Transocean, who will serve as committee chairman from 2012 through 2013.
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IADC Connection
Wirelines
INDUSTRY URGES SUSPENSION OF NATIONAL OCEAN POLICY IADC, NOIA and IPAA are urging the National Ocean Council (NOC) to suspend implementation of the National Ocean Policy (NOP), pointing to major weaknesses in the draft implementation plan and a myriad of unanswered questions. In a letter sent to NOC last month, industry groups said their chief concern lies with the anticipated use of coastal and marine spatial planning (CMSP), which could pose additional obstacles to access for oil and natural gas resources on the US Outer Continental Shelf (OCS). Its use could mean that the requirements of “expeditious development” directed by the OCS Lands Act will be limited, leading to potentially serious conflicts. “It would be very shortsighted to make CMSP decisions without the benefit of new data,” the groups stated. At a minimum, new geological and geophysical data should be obtained.
If the administration decides to move forward with implementation, a pilot project in one region should be undertaken. This would ensure a greater likelihood of meaningful stakeholder involvement and fewer unintended consequences.
OSHA HCS HARMONIZED WITH UN STANDARDS On 26 March 2012, OSHA issued a final rule aligning its Hazard Communication Standard (HCS) with the United Nations’ Globally Harmonized Systems of Classification and Labeling of Chemicals. HCS requires chemical manufacturers and importers to evaluate the hazards of the chemicals they produce or import, as well as prepare labels and material safety data sheets to convey the hazards and associated protective measures to users of the chemicals. The modifications include: • Revised criteria for classification of chemical hazards; • Revised labeling provisions, including requirements for the use of standardized
signal words, pictograms, hazard statements and precautionary statements; • A specified format for safety data sheets, revisions to definitions of terms used in the standard; and • Requirements for employee training on labels and safety data sheets. The rule becomes effective on 25 May 2012.
USCG ISSUES RULE ON BALLAST WATER DISCHARGE On 23 March 2012, the US Coast Guard issued a final rule establishing a standard for the allowable concentration of living organisms in ballast water discharged in US waters. The regulations were developed to aid in controlling the introduction and spread of non-indigenous species from ships’ ballast water. The Coast Guard also amended its regulations for the associated engineering equipment by establishing an approval process for ballast water management systems, which should not come about until 2015.
IADC Lifting & Mechanical Handling Conference & Exhibition
http://www.iadc.org/conferences/ Lifting_Handling_2012 For more information contact IADC at +1 713 292 1945, email: conferences@iadc.org.
18-19 July 2012 Hilton Lafayette Hotel • Lafayette, LA
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Industry Events Calendar *all extensions below refer to +1-713-292-1945
MAY 2012 IADC Well Control Committee Meeting. 16 May. Omni Houston Hotel Westside, Houston, TX. Contact Holly Shock, ext. 205. IADC 2nd Annual Land Contractors Operations Forum. 16 May. Omni Houston Hotel Westside, Houston, TX. IADC Ethics Committee Meeting. 23 May. IADC, Houston, TX. Contact Holly Shock, ext. 205.
JUNE 2012 IADC UBO & MPD Committee Meeting. 4-6 June. Radisson Blue Park Hotel, Lysaker, Norway. Contact Holly Shock, ext. 205. IADC Well Servicing Committee Meeting. 6 June. IADC, Houston, TX. Contact Holly Shock, ext. 205.
IADC Connection
JULY 2012 IADC Maintenance Committee Meeting. 11 July. Location TBD. Contact Holly Shock, ext. 205. IADC Training Committee Meeting. 25 July. Ensco plc, Houston, TX. Contact Holly Shock, ext. 205.
IADC HSE Committee Meeting. 26 July. Ensco IADC Advanced Rig Technology Workshop. plc, Houston, TX. Contact Holly Shock, ext. 205. 12 June. Hotel ARTS Barcelona, Spain. Contact 17-18 Apr Holly Shock, ext. 205. IADC ART Committee Meeting. 31 July. IADC, Houston, TX. Contact Holly Shock, ext. 205. IADC Well Control Committee Meeting. 15 August. Location TBD. Contact Holly Shock, ext. 205.
25-26 Apr
2012 IADC Conference Calendar IADC Drilling Onshore Conference & Exhibition Silver Sponsors: NOV Tuboscope, NOV Grant Prideco, Pason Systems USA,
17 May
Omni Houston Hotel Westside, Houston
23-24 May
JW Marriott Bucharest Grand Hotel Bucharest
7-8 Jun
Mayflower Renaissance Hotel, Washington, D.C.
13-14 Jun
ARTS Hotel, Barcelona
9 -11 Jul
Renaissance Tianjin Lakeview Hotel Tianjin, China
Silver Sponsor: Offshore Operators Committee; Endorsed by : American Petroleum Institute, Offshore Operators Committee
18-19 Jul
Hilton Lafayette Hotel, Lafayette
IADC Critical Issues India Conference & Exhibition
27-28 Aug
InterContinental The Lalit Mumbai Hotel, India
26-27 Sep
Moevenpick Hotel, Amsterdam
KCA DEUTAG Drilling Ltd; Event Sponsors : J.D. Neuhaus LP, M.D. Cowan Inc.
IADC Critical Issues Continental Europe Conference & Exhibition Diamond Sponsor: Grup Servicii Petroliere SA; Platinum Sponsors: Halliburton, OMV Petrom SA, Weatherford; Gold Sponsor: Schlumberger; Silver Sponsors: ICPE ACTEL, CONFIND SRL Romania, S.C. Rompetrol S.A., Rompetrol Well Services S.A., Tenaris; Event Sponsors: KCA DEUTAG Drilling GmbH, TM Drill Romania-SC Fora Sonde SA
IADC International Tax Seminar Silver Sponsor: Ernst & Young LLP; Event Sponsors: Miller & Chevalier, Fulbright & Jaworski LLP, Deloitte Tax LLP, KPMG LLP; Brochure Sponsor: M Squared & Associates Pty, Ltd
IADC World Drilling 2012 Conference & Exhibition Grand Opening Reception Sponsor: Repsol; Platinum Sponsor: Ensco plc, National Oilwell Varco, VAM Drilling; Gold Sponsors: Shell, Transocean; Silver Sponsors: Grey Wolf Oilfield Services Limited, Helmerich & Payne IDC, KCA DEUTAG Drilling GmbH, Weatherford; Event Sponsor: Noble Drilling (Netherlands) BV; Brochure Sponsor: DNV Software
IADC/SPE Asia Pacific Drilling Technology Conference
IADC Drilling HSE Europe 2012 Conference & Exhibition Gold Sponsor: Ensco plc; Silver Sponsor: Hercules Offshore; Event Sponsor: Enablon, KCA DEUTAG Drilling GmbH; Brochure Sponsor: DNV Software
Revised: 2012-04-10
IADC Lifting & Mechanical Handling Conference & Exhibition
The complete 2012 conference lineup is available online at www.iadc.org/events. For more information: Unless otherwise noted, call IADC headquarters in Houston at +1-713-292-1945 (fax, +1-713-292 -1946), our Netherlands office at +31 24 6752252 (fax, 16-17 +31 24 Oct 3600759), or email conferences@iadc.org. M AY / J U N E 2 0 1 2
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Departments
HSE&T Corner
Security programs must incorporate terrorism prevention, crisis management BY JIM THATCHER, ENCANA
H
istory has shown we cannot prevent terrorist acts from occurring. However, we can minimize the destruction and loss of life by instituting safeguards and precautionary policies. With the increased risk of terrorism around the world, physical protection of the facility has become the focal point of achieving an acceptable level of “safeness” within the confines of the facility, as well as how to keep the employees safe while performing their daily tasks. A well-planned security program encompasses many efforts, paying special attention to: • Screening and background checks; • Preventing unauthorized entry and controlling access; • Actively and effectively safeguarding and protecting sensitive materials; • Developing access restrictions and controlling movement within the facility; • Continuously evaluating and monitoring personnel and sensitive areas; • Developing education programs in information security; and • Applying security techniques, devices, procedures and policies. The first step in constructing a security program is to conduct a threat/vulnerability assessment. One common and recommended assessment tool for all processes that could be hazardous is a process security assessment (PSA). Its purpose is the prevention and mitigation of a hazard caused by intentional or criminal acts. The oil and gas industry should incorporate elements into a company security management system, such as: • Threat assessment and vulnerability surveys and checklists; • A written security policy; • Collaboration with corporate or division departments and with local law enforcement agencies, local emergency planning committees and federal law enforcement agencies; • Security incident-reporting system; • Employee training in security awareness; and
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Most companies already have emergency action plans that include evacuation information for several types of anticipated emergencies. To strengthen those plans, terrorist releases should be incorporated as well.
• Emergency response and crisis management. The following industrial security checklist can be considered a working tool or guide to developing a comprehensive program. The checklist contains broad questions that can be used to evaluate current plans.
NOTIFICATION Does the plan identify potential terrorist releases as emergencies that may affect the workplace? • Evaluate the workplace and nearby areas to identify potential terrorist tarM AY / J U N E 2 0 1 2
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IADC HOUSTON CHAPTER 2012 nd
2
Annual Oilfield Charity Shoot
Held at American Shooting Centers on March 9, 2012
Supporting the Oilfield Christian Fellowship and Oil Patch Chaplains
Gold Sponsors
Axon Energy Products Wilson (a Schlumberger Company)
Silver Sponsors
Atlas Tubular, LP Atwood Oceanics Blake International USA Rigs, LLC Boots & Coots Cummins Inc. Derrick Equipment Co. H&P IDC Integrated Drilling Equipment McKenzie Compressed Air Solutions Pason Systems USA Pioneer Drilling Company ScanDrill Inc. Wayne Enterprises, Inc.
Departments
HSE&T Corner
gets or situations that could be used to create a hazardous emergency release.
• Identify equipment that might be critical during a terrorist release.
Does the plan identify how employees can activate the response system, or how other employees would be alerted if a terrorist release were detected?
Would you ever isolate an area within the workplace or use the entire workplace as a shelter?
• Identify how an employee can activate the response system and how other employees will be alerted about a terrorist release. Does the plan identify how outside organizations will be notified if a terrorist release is detected? • Identify how designated employees will warn individuals outside the workplace that a terrorist release is detected.
SHUTDOWN AND ISOLATION Is there any critical equipment that must be shut down during a terrorist release?
• Describe any additional steps employees must take if they will be expected to isolate an area or the entire workplace as a shelter during a terrorist release.
EVACUATING, SHELTERING AND ACCOUNTING FOR EMPLOYEES Does your plan identify any additional/different evacuation routes, exits and shelter locations that would be needed?
Do your evacuation and sheltering plans for terrorist releases require you to assign any additional emergency response roles to your employees?
• Illustrate shelter locations and additional routes and exits necessary on the map/floor plan of your facility.
• Employees who are expected to identify terrorist releases and unusual circumstances preceding them must be trained to perform this role.
Does the plan identify how you will account for employees who are evacuated or sheltered?
Providing Training in: Well Control Marine Stability & Licensing Behavior-based Safety Leadership 800.492.9355 intertek.com/high-risk-industry-consulting-training
D R I L L I N G CONTRACTOR
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Does the plan identify how employees will be alerted when it is safe to re-enter the workplace or to leave a shelter location? • Identify who is responsible for making the determination that the workplace is safe to re-enter, how the responsible individual will make the determination that the workplace is safe to reenter and how employees will be alerted.
Intertek Consulting & Training is the largest and most widely recognized global provider of customized training for the petroleum and other high-risk industries.
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• Identify who is responsible to account for employees evacuated or sheltered during a terrorist release.
Does your plan describe the training each employee must receive to be able to evacuate or retreat to a shelter location or to perform a response role during a terrorist release? •Identify any additional training employees will need to carry out your planned procedures.
EQUIPMENT Will you need additional equipment during evacuation, sheltering, critical equipment shutdown or workplace isolation resulting from a terrorist release? • Identify additional emergency equipment employees may need during a terrorist release, who can use the additional emergency equipment and emergency equipment that will be maintained in shelter areas. To address these considerations, additional information is available from online resources such as OSHA’s Emergency Response webpage at www. osha.slc.gov/SLTC/emergencyresponse/ index.html.
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Well control school is for well control training. Don't send your crews there to learn maths!
THE ROUGHNECKS GUIDE TO DRILLING CALCULATIONS ... more than just a calculations course ... is yours one of them? Find out more at
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Departments
People, Companies & Products
FMC to supply Petrobras with subsea equipment FMC Technologies recently signed a four-year agreement with Petrobras for the supply of pre-salt subsea equipment. FMC’s total scope of supply could include the delivery of up to 130 subsea trees, subsea multiplex controls and related tools and equipment. The tree systems are for use offshore Brazil in water depths up to 8,200 ft (2,500 meters). The equipment will be engineered at FMC’s South American Technology Center and manufactured at the company’s subsea facility, both located in Rio de Janeiro. The subsea trees will achieve 70%
Brazilian local content, and deliveries are scheduled to commence in 2014.
Gazprom awards Expro three PVT contracts in Iraq
Transocean’s global training center in Macaé opens
Expro has secured three contracts in Iraq. The trio of contract awards adds to a recent contract with Eni. Expro will undertake analysis of more than 100 pressure, volume and temperature (PVT) studies in a contract award with Gazprom in the Badra field close to the Iranian border. Two further contract awards with large operators in the south of Iraq involve further PVT sampling studies and laboratory work. Expro will utilize its Iraqi capabilities, as well as its fluids analysis center and analytical data services teams in the UK, to conduct more than 200 PVT studies.
Transocean’s training center has opened in Macaé, Brazil, in the city’s busiest industrial center. The facility provides the latest in technology and teachings. The company plans to install a cyber-based drilling simulator to train drillers who work on the latest-generations of offshore rigs. Estimated demand this year is more than 200 classes for personnel from Brazil and other Transocean locations worldwide. For the first time in Brazil, Transocean personnel can take drilling and crane operations competency assessment classes, D-CAP and C-CAP, using simulators onshore, in addition to offshore assessments.
Baker Hughes facility targets unconventional resources The Baker Hughes Dhahran Research and Technology Center recently opened in Saudi Arabia with a focus on research and development of new technologies to unlock the potential of unconventional resources. The technology and research center is a partnership between Baker Hughes and Saudi Aramco. The center brings together the competencies of Baker Hughes engineers and scientists of Saudi Arabia and King Fahd University of Petroleum and Minerals to develop application-specific solutions. With rock and fluids laboratories, the center provides equipment to understand the science and technology in developing unconventional resources.
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FMC will provide Petrobras with up to 130 subsea trees and related tools and equipment for use in water depths up to 8,200 ft.
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Murchison Drilling Schools expands in Houston Murchison Drilling Schools (MDS) has opened a Houston training center (HTC). MDS offers weekly IADC and IWCF well control courses, a five-day practical drilling technology course, a five-day advanced drilling technology course and a floater operation transitions course. Additionally, Willie Lyon has been promoted to vice president and manager of the HTC. E.B. Clapp has joined MDS as manager of well control at the HTC. Tim Arnold has been promoted to manager of training at the Albuquerque training center, and Bill Murchison Jr. has been promoted to president of MDS.
Andy Hendricks joins Patterson-UTI as COO William Andrew “Andy” Hendricks Jr joined Patterson-UTI Energy as chief operating officer in April. Mr Hendricks served since 2010 as president of Schlumberger, drilling and measurements division. It is expected that Mr Hendricks will assume the position of president and CEO upon Doug Wall’s retirement this year.
Stephen Oswald joins Capital Safety as CEO Stephen Oswald joined Capital Safety in March as its new CEO. For the last 15 years, Mr Oswald had held various executive roles at United Technologies Corp (UTC), most recently serving as the integration leader for UTC’s acquisition of GE Security.
Burleson appointed director at Cudd Energy Services Larry Burleson has been appointed director of business development for corporate services at Cudd Energy Services. Mr Burleson will provide leadership in building a global clientele for the company’s integrated solutions. He joins Cudd Energy from Weir Seaboard, where he was vice president of sales.
Dokubo to lead GL Noble Denton’s new Nigerian base GL Noble Denton has opened its first base in West Africa with operations in Lagos, Nigeria. The company’s Nigerian operations will provide services and software solutions to aid international and local oil companies in developing and operating safer and more efficient assets in West Africa. Tekena Dokubo has joined the company to lead GL Noble Denton’s presence in Nigeria. Mr Dokubo brings experience in business development in West Africa’s oil and gas sector. M AY / J U N E 2 0 1 2
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unconventional wisdom SPE Annual Technical Conference and Exhibition » 8–10 October 2012 Henry B. Gonzalez Convention Center » San Antonio, Texas, USA
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Departments
People, Companies & Products
Vantage Drilling acquires Dragonquest drillship
Daewoo Shipbuilding & Marine Engineering Co in Okpo, South Korea.
Vantage Drilling has signed a definitive agreement to acquire the rights and obligations under the construction contract for the ultra-deepwater drillship Dragonquest from Valencia Drilling. Dragonquest was constructed at
Schlumberger to acquire modeling software company Schlumberger has entered an agreement with Altor Fund II to acquire SPT Group, which specializes in dynamic
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P RO D U C T S
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Exxon MZST licensed to Weatherford subsidiary ExxonMobil Upstream Research Co (URC) has licensed its Multi-Zone Stimulation Technology (MZST) well treatment process to a subsidiary of Weatherford International. The MZST process can be used to stimulate multiple zones in a single operation, yielding improved well economics. The MZST process can be beneficial for hydraulic fracturing operations in tight gas, shale gas and coal bed methane wells that target multiple reservoir zones, thick reservoir sections or long reservoir intervals where multiple stimulation treatments are required. “The MZST process is a proven tech-
nology for rapidly completing wells in tight reservoirs such as shale gas,” URC president Sara Ortwein said. “This technology will play a key role in improving the economics of developing this unconventional resource.” The MZST process will enable Weatherford to optimize its stimulation operations by combining the deployment of perforating and hydraulic fracturing equipment simultaneously in the wellbore to enable “single-trip” multi-zone stimulations. The technology increases the number of zones that can be fractured per day compared to traditional fracturing and stimulation operations.
Halliburton’s Q10 pump meets shale fracturing demands
ture environments. The lubricant was developed for wireline operations, including cased-hole logging, pipe recovery service, production loggings and reservoir analysis.
Halliburton has rolled out the first production unit of its new Q10 pumping trailer. The redesigned Q10 pump enhances performance while reducing pumping assets at the well site. The Q10 units target shale fracturing applications. Performance specifications include a maximum pressure rating of 20,000 lbs/sq in., a range of rates between 2.7 and 18.9 bbl/min, and a power rating of 2,000 hydraulic horsepower.
ConocoPhillips’ Wireline Lubricant designed for HPHT ConocoPhillips recently launched a new wireline lubricant designed to maintain a seal and prevent the escape of wellbore fluids during wireline operations. Wireline Lubricant is a specialized, clear formulation designed specifically for high-pressure, high-tempera-
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modeling. The company provides software and consulting services for multiphase flow and reservoir engineering. “The dynamic modeling and reservoir optimization software of SPT Group will complement the existing Schlumberger production software portfolio,” Tony Bowman, president, Schlumberger Information Solutions, said.
Schlumberger’s LWD service supports formation evaluation Schlumberger recently introduced the MicroScope high-resolution resistivity and imaging-while-drilling service. On a single collar, the logging-while-drilling service provides high-resolution laterolog resistivity and full borehole images in conductive mud environments. The service has been successful in more than 150 jobs and addresses challenges in unconventional shale plays, carbonate and clastic reservoirs.
Scan to watch a video interview from the 2012 IADC/ SPE Drilling Conference about MicroScope.
Gloves reduce hand fatigue, enable safer work To safeguard oftenforgotten impact and pinch points in highimpact situations, Mechanix Wear’s M-Pact EXP-2, being released in May, has an extended, embossed vinyl cuff designed to dull potential impact to the outer wrist. The anatomically designed palm pads reduce hand fatigue when the grip is engaged, enabling faster, safer and cleaner work with more power and control.
Mud mixers feature high-efficiency gearboxes Chemineer mixers offer performance, efficiency and reliability in mud-mixer applications. The Chemineer mixers feature highefficiency gearboxes designed for agitator service and have configurations to meet application requirements that are unique to mud-mixing applications.
Scan to view these products online and for links to company websites.
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Card Directory UNITED STATES
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Don’t miss out on our next issue! Key topics in July/August include: Innovating While Drilling (IWD)* including HPHT advances, drilling fluids and bits Regional Focus: Europe, including North Sea Lifting & Mechanical Handling Drilling Bit Technology
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Completions: Intelligent Well Systems
SPECIAL READERSHIP SURVEY! How many readers read and remembered your ad? Find out with our bonus reader survey. Select ads only. Contact sales rep for details. Scheduled bonus distribution IADC Lifting & Mechanical Handling Conference & Exhibition 18-19 July, Lafayette, Louisiana Offshore Northern Seas 2012 28-31 Aug, Stavanger, Norway
eNews from DrillingContractor.org delivers original news and features, as well as information from key industry players, updates on IADC activities, exclusive reports from IADC conferences, reader surveys and more to members of the drilling & completion industry 22 times per year.
D R I L L I N G CONTRACTOR Print and online advertising opportunities are available. Complete information is available on www.DrillingContractor.org.163
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ABB Marine Solutions ................................ 91 ADIPEC 2012 ............................................ 164 Aker Solutions ........................................... 89 American Block ........................................ 67 Amerimex Motor & Controls, Inc............. 11 Arnco Technology Trust ......................... 141 Atwood Oceanics .................................. 163 Auriga Training ........................................ 159 Baker Hughes Incorporated .................... 29 Balmoral .................................................... 77 Bandera Drilling Company, Inc ............ 163 Bentec ..................................................... 135 Big 6 Drilling Company .......................... 163 Blohm + Voss Repair GmbH..................... 61 Burgess Manufacturing ............................ 59 Cameron ................................................... 87 Cansco Dubai ........................................... 73 Columbia Industries LLC ........................ 139 Command Energy Services ................... 143 Cudd Well Control .................................... 63 Cummins, Inc ............................................ 93 Custom Safety Products ......................... 147 Derrick Corporation.................................. 33 Dragon Products, Ltd ................................ 65 Drillmec SPA .............................................. 31 Emerson Process Management .............. 83 Expro Group .............................................. 85 Fike Corporation ..................................... 117 Fisher Offshore ........................................ 145 FMC Technologies .................................... 75 Forum Energy Technologies .................. 109 Freudenberg Oil & Gas ............................ 95
G&J Land & Marine Food Distributors, Inc...................................... 84 Gardner Denver .......................................... 5 GE Transportation ..................................... 79 Goodyear Engineered Products ........... 105 Greene’s Energy Group ........................... 47 Haggard ID Wiper, Inc ............................. 69 Halliburton ........................................... 22-23 Hannon Offshore Drilling Equipment..... 103 Hardbanding Solutions........................... 122 Harris CapRock Communications ........ 167 Hempel A/S ............................................. 119 Herrenknecht Vertical .............................. 34 Honghua America LLC ........................... 151 Huisman Equipment BV ............................ 51 Integrated Drive Systems ......................... 37 IADC Houston Chapter 2012 2nd Annual Oilfield Charity Shoot..... 157 IADC Lifting & Mechanical Handling Conference & Exhibition .................... 154 International Registries, Inc ................... 147 Intertek Consulting & Training ............... 158 Italvibras USA, Inc ................................... 113 Jet-Lube, Inc ........................................... 115 Keen Energy Services .............................. 25 Keppel FELS ............................................. 107 Knight Oil Tools........................................ 137 McCoy Drilling & Completions .............. 145 Mechanix Wear ...................................... 131 Meco Marine .......................................... 121 ModuSpec ............................................... 149 MTU............................................................. 13 NanoSteel ................................................ 123
Ad Index
National Oilwellll V Varco ......................... 8 8, 17 Newmar Ltd ............................................. 153 Noble Drilling Corporation ..................... 163 Oilfield Motor & Control, Inc .................... 57 Omron........................................................ 43 PETEX - The University of Texas at Austin ................................................. 15 Precision Drilling Corporation .................. 41 Rangeland Energy Services .................. 133 Riteco Supply, Inc................................... 149 Schlumberger ......................................... 168 Schramm, Inc.......................................... 127 SPE Annual Technical Conference and Exhibition ..................................... 161 Superior Drillpipe ........................................ 6 Tesco.......................................................... 21 Texas Classic Productions ..................... 152 Timken ....................................................... 53 Travelers .................................................. 125 TSC Drill Pipe .............................................. 99 TTS Drilling Solutions .................................. 45 Vallourec & Mannesmann USA Corporation ............................................. 7 VAM Drilling............................................... 27 Variable Bore Rams, Inc .......................... 55 Verenium Corporation ............................. 36 Ward Leonard Electric Company, Inc .. 129 Weatherford ............................................ 2, 3 Well Control School .................................. 97 Westex ..................................................... 101 White Star Pump Company ..................... 49 Wild Well Control, Inc ............................... 19
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M AY / J U N E 2 0 1 2
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Departments
Perspectives Goran Andersson, Chevron: Experiential training is the way forward BY KATHERINE SCOTT, EDITORIAL COORDINATOR
A
s a new generation enters the industry work force, Chevron’s Goran Andersson strongly believes it is imperative to establish an industry path toward more interactive training methods. This vision includes developing more robust team-based training that incorporates group decision making and advanced simulation exercises. “You want to touch, feel and be involved in the training; that’s how we learn, especially the younger generation. That’s the direction we’re moving. … I think we will see a tremendous increase in that type of training over the next couple of years,” said Mr Andersson, who served as team lead for Chevron’s Drilling and Completion (D&C) Training Center from 2009 to early 2012. With a background in civil engineering, Mr Andersson entered the energy industry in 1980 as a drilling supervisor trainee with Shell. That experience was followed by offshore and onshore operations at Statoil and WEST Engineering before he joined Chevron in 1998. He was drawn by the company’s safety values. “Chevron has some very good visions on safety. … I could see (my similar) ambitions existed within (the company).” As team lead of Chevron’s D&C training center, Mr Andersson helped the training facility to add additional courses to the existing well control training, including risk and uncertainty management, leadership workshops, unscheduled event prevention, and drilling well on paper facilitation for drilling teams. Looking at the state of the industry, Mr Andersson acknowledges that it is important for the next generation of training to become more experiential; shifting away from typical classroom media. All too often a person’s experience is measured in years instead of quality experiences. By incorporating simulator and team-based training into the curricula, it gives trainees a chance to visualize through quality simulation experiences. “I think the days of PowerPoint slides are gone. … Through interactive and virtual courseware, we will see an increased sense of ownership of one’s own learning, leading to better results,” he said. Mr Andersson has researched the approach to training adopted by other high-performance industries, such as military and civilian aviation and the nuclear power industries. They foster a continuous proficiency program that is documented and ensures competency and perpetual growth at all levels. “It never ends. Training is a continuous process that is a part of everyday operations. The training itself is also continuously evolving to keep up with new technologies and associated training challenges.” Conversely, he said the oilfield tends to lean on experience and legacy classroom training delivered very infrequently. There are a wide range of opinions and know-how that are personality-based versus process-based, which leads to a lack of standardization. “Here, the oilfield has much to learn,” says Mr Andersson. Customizing training to a student is also critical to getting better results. “An engineer does not necessarily need the same
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Goran Andersson has a passion for world-class training. He helped make significant enhancements to the WellCAP curriculum through IADC’s WellCAP Curriculum Subcommittee. Scan to watch an exclusive video interview with Goran Andersson. training as a wellsite supervisor. It’s a matter of delivering the right training to the right people at the right time.” In addition to his work with Chevron, Mr Andersson served as co-chairman for the IADC Well Control Committee and chairman of the IADC WellCAP Curriculum Subcommittee from 2009 until early this year. During his time with the committee, he led the group to make significant enhancements to the WellCAP curriculum, starting with the Supervisory Level Course. In addition, he has been working on an internal program that promises to address knowledge and skill decay in between the current two year IADC certification cycle. “I think one of our biggest steps forward is that we increased the simulator training requirement to a minimum of 30% of the IADC WellCAP curriculum, thereby providing more interactive and experiential learning delivered through modern media that includes distributed simulation and interactive courseware that can be consumed anywhere in the world.” Although Mr Andersson recently rotated out of his training center leadership position into a new post as drilling operations manager for Poland, he remains ever passionate about the need for world-class training and emphasizes its value in this global industry. “We need to clearly understand that one dollar invested in quality training yields a significant ROI. A single error does not just affect that company; it can affect the world market. The need for training should not be sparked by a single event but rather should be a foundational part of a company’s strategy to continuously develop our workforce,” he said. Further, he hopes to see service companies become more integrated into the operator’s well control prevention efforts. Although most drilling service providers do a great deal of internal training, he believes more can be done to incorporate them into well control during the drilling process. “They are an extremely important part of the team,” he stressed. If industry continues to place increased focus and investment in training, Mr Andersson believes that it will dramatically reduce the negative effects of the Big Crew Change. “People tend to focus on training costs rather than results. In the long run, I believe it is more cost-effective, efficient and safer to always do it right the first time, at a possibly slightly slower pace.” M AY / J U N E 2 0 1 2
4/12/2012 4:01:06 PM
Connections made simple. Finally, a global communications provider that makes it easier to connect all the right people in the right places. Choosing communications solutions and services from Harris CapRock gives you simple access to the best satellite, wireless and terrestrial technologies. But more than that, our reliable, high-performance communication services keep you connected, giving you the means to improve the daily operations of your exploration and production assets, to enhance the HSE impact of your business and to improve crew morale by keeping your remote workers connected. That’s what’s possible when you choose the world’s leader in voice, video and data services for your remote oil and gas operations. No matter where on Earth your operations take you, we’ll make the connections, we’ll make them powerful and we’ll make them simple. At Harris CapRock, that’s our commitment to you.
www.harriscaprock.com/energy-dc © 2012 Harris CapRock Communications, Inc. All rights reserved.
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RELIABILIT Y NEVER REACHED SO FAR™
4/9/2012 1:08:00 PM
PowerDrive Archer
PowerDrive Archer and Measurable Impact are marks of Schlumberger. © 2012 Schlumberger. 11-DR-0475
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“The PowerDrive Archer tool is a definite game-changing technology that will dramatically improve drilling efficiencies.” —William “Bill” Lloyd, Cirque Resources, VP Operations, North America
PowerDrive Archer is the RSS that delivers high build rate well profiles previously only possible with motors—yet with the ROP and wellbore quality of a fully rotating RSS.
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4/9/2012 1:40:09 PM
Offshore Activities & Outlook
Reentry campaign gives first-round subsea fields second chance to produce Redrilling wells to extend field life requires detailed analyses of present and prior operations BY SEAN STRIGHT, NELSON TEARS, GREGORY KING, EXXONMOBIL DEVELOPMENT COMPANY; VIKAS SRIVASTAVA, DAVID W. SMITH, EXXONMOBIL UPSTREAM RESEARCH COMPANY Figure 1: The Beryl field, about 200 miles northeast of Aberdeen, began production in 1976 from the Beryl Alpha platform. In 2010, a semisubmerisble was contracted for a five-well redevelopment campaign for two workover operations and three abandonment and sidetracks, which involved reentry of the wells that had horizontal and vertical trees.
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A
large number of subsea production wells have been drilled, but to date, there has been limited industry experience of redrilling subsea wells even though redrills have become routine in platform and surface wellhead applications. The focus of this article is to highlight the key aspects of redrilling a subsea production well to extend field life. The article will describe how the unique challenges of redrilling three subsea wells were overcome in old and declining fields where the original wells were designed and drilled with limited consideration for redevelopment of the fields through reuse of existing wells. The article will define the problems of and describe the solutions to: • The mooring and blowout preventer (BOP) handling constraints in the crowd-
ed subsea infrastructure of a subsea field development; • The riser and wellhead analysis for redrilling a well through a subsea tree and the operational practices required to maintain tree and wellbore integrity; • The analysis of the additional loads put on a subsea well through the extended period of riser and BOP loading; and • The casing exit and redrill constraints unique to operations from a semisubmersible; casing recovery operations, the management of window milling debris in a subsea BOP system. There has been limited industry experience of subsea production well redrills, and significant lessons learned will be shared. They will be of wider application as the number of subsea wells increase along with the requirement to maximize recovery and extend field life. M AY / J U N E 2 0 1 2
4/13/2012 11:16:46 AM