2014 02 by Asad Ullah Khan

JOURNAL OF PETROLEUM TECHNOLOGY • www.spe.org/jpt

FEBRUARY 2014

F E B R UA RY 2 0 1 4 • VO LU M E 6 6 , N U M B E R 2

Carbon Dioxide’s Unconventional Possibilities

DRILLING TECHNOLOGY OFFSHORE FACILITIES WELL TESTING NANOTECHNOLOGY JOURNAL OF PETROLEUM TECHNOLOGY

FEATURES

Electric-Powered Subsea Systems Largest, Most Complex Subsea Development Digitizing E&P Managing SEMS Audits

Feb14_JPT_Cover.indd 1

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Vx Spectra SURFACE MULTIPHASE FLOWMETER

Full-spectrum, single-point measurement for the most accurate production fow rates. Only the Vx Spectra fowmeter captures the complete spectrum of gamma energy levels at high frequency from a single point in the venturi throat, ensuring accurate, repeatable fow rate measurements independent of fow regime. Tested for robustness and accuracy at third-party reference facilities, the fowmeter acquired more than 400 fow loop test points in a variety of fuids, fow regimes, and pressures, with results confrming excellent metrological performance. Find out more at

slb.com/VxSpectra Vx Spectra is a mark of Schlumberger. ÂŠ 2014 Schlumberger. 13-TS-0206

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Volume 66 • Number 2

20 G uest Editorial • Digitizing E&P: Accelerating the Pace of Change The oil and gas industry is a major driver of high-performance computing development, particularly for upstream seismic processing and permanent field monitoring. But exploration and production still lags behind other industries in the use of digitization.

38 M ore Carbon Dioxide Means More Oil

Research into whether CO2 can be used to coax billions more barrels of oil from unconventional formations is beginning to show promise.

52 C arbon Dioxide May Offer An Unconventional EOR Option Tests showing increased recoveries in the Bakken formation using CO2 could have significant implications for the upstream oil and gas industry.

58 P ioneering Subsea Gas Compression Offshore Norway Cover: A long line of pipes gathers

the flow from wells in a portion of the GLSAU field where CO2 injections are used to enhance production. The field, now owned by Kinder Morgan, has added deeper wells, allowing it to produce from the residual oil zone (ROZ) as well as the main pay zone. Photo courtesy of Melzer Consulting.

Performance Indices

Regional Update

Company News

President’s Column

Comments

Technology Applications

Technology Update

Young Technology Showcase

Techbits

128

SPE News

130

People

131

Professional Services

135

Advertisers’ Index

136

SPE Events

ContentsFeb14.indd 1

The world’s first full-scale subsea gas compression system is the final stages of construction and is on schedule to be installed in the Åsgard gas field offshore Norway by year’s end.

66 D eveloping Long-Distance Power-Distribution Systems Over the next decade, the number of electrically powered subsea systems in operation around the world will increase as companies adopt new technologies to produce oil and gas offshore more efficiently.

72 M anagement • Managing SEMS Audits: Past, Present, and Future Oil and gas companies are adapting to new safety regulations governing operations in the US Gulf of Mexico.

127 Drilling Conference Covers Depth and Breadth of Industry A preview of the 2014 IADC/SPE Drilling Conference and Exhibition in Fort Worth, Texas.

An Official Publication of the Society of Petroleum Engineers.

1/17/14 11:09 AM

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Rhino RHE DUAL-REAMER RATHOLE ELIMINATION SYSTEM

TECHNOLOGY

76 Drilling Technology Mike Weatherl, SPE, Drilling Adviser, Hess

77 ECD-Management Strategy Solves Lost Circulation Issues 82 Annular-Pressure Losses While Casing Drilling 86 Managed-Pressure Drilling—A Solution for Challenging Wells in Vietnam

90 Re-Engineering and Upgrade of a Semiautomated 3,000-hp Drilling Rig

94 Offshore Facilities Ian G. Ball, SPE, Technology Advisor and Project Manager, Intecsea

95 Deepwater Floating Production Systems in Harsh Environments Offshore Norway

98 Turret-Mooring-System Experience and Enhancements in the Atlantic Frontier

101 Offshore Dry-Docking of FPSOs

i-DRILL system design ensures reamer placement does not interfere with RSS directional capabilities.

104 Well Testing Angel G. Guzmán-Garcia, SPE, Independent Energy Consultant

105 Integrated Well-Test Strategy in Unconventional Tight Gas Reservoirs 108 New Techniques in Interpretation of Closure Pressure in the Montney Formation

112 Pressure-Transient Testing of Low-Permeability Multiple-Fracture Horizontal Wells

116 Nanotechnology Niall Fleming, SPE, Leading Adviser for Well Productivity and Stimulation, Statoil

117 Application of a Nanofluid for Asphaltene Inhibition in Colombia 120 Nanotechnology Applications for Challenges in Egypt 123 High-Performance Water-Based Drilling Fluids Offshore Cameroon

Dual-reamer system enlarges rathole, avoids a run, and saves 16 hours on a deepwater rig. Rhino RHE rathole elimination system enlarged 178 ft of rathole while drilling a deepwater well in the Gulf of Mexico, saving 16 hours of rig time. The Rhino RHE system’s dual-reamer process uses a hydraulically actuated reamer positioned above the MLWD tools to open the pilot hole and an on-demand reamer located near the bit to enlarge the rathole. The dual-reamer system eliminated a dedicated rathole cleanout run. Read the case study at

slb.com/RhinoRHE The complete SPE technical papers featured in this issue are available free to SPE members for two months at www.spe.org/jpt.

ContentsFeb14.indd 3

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Quality

Sustainability

Innovation

Mineração Curimbaba is a proppant manufacturer that is focused on quality from raw material identification and classification in the mines through out the process, including the most thorough SQ standards for sampling and documentation in the industry. The final product is used in oil and gas well stimulations worldwide. The guideline for testing and test procedures is the ISO 13503-2 standard measurement of properties of proppants used in hydraulic measu fracturing and gravel-packing operations. Mineração Curimbaba has been ISO certified since 2004. Curimbaba Proppants are distributed all over the world through Sintex International and Sintex North America. Curimbaba has a global reputation for the quality products, leading innovation and technology.

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www.spe.org/jpt

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ONE STOP FOR EVERYTHING JPT Get all your online JPT content in one place.

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Editorial Policy: SPE encourages open and objective discussion of technical and professional subjects pertinent to the interests of the Society in its publications. Society publications shall contain no judgmental remarks or opinions as to the technical competence, personal character, or motivations of any individual, company, or group. Any material which, in the publisher’s opinion, does not meet the standards for objectivity, pertinence, and professional tone will be returned to the contributor with a request for revision before publication. SPE accepts advertising (print and electronic) for goods and services that, in the publisher’s judgment, address the technical or professional interests of its readers. SPE reserves the right to refuse to publish any advertising it considers to be unacceptable.

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ContentsFeb14.indd 5

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SPE Bookstore

PERFORMANCE INDICES world crude oil production+ ‡ THOUSAND BOPD

T TI

OP E C

2013 APR

MAY

JUN

JUL

AUG

SEP

Algeria

1510

1520

1412

Angola

1855

1890

1770

1790

1770

1810

516

522

524

531

537

535

Iran

3200

Iraq

3175

3075

3100

3275

2825

Kuwait*

2650

Libya

1450

1420

1130

1000

590

360

Nigeria

2400

2420

2270

2400

2370

2420

Qatar

1200

Saudi Arabia*

9440

9640

9840

10040

10240

10140

UAE

2820

Venezuela

2300

32516

32647

32314

32551

32472

31672

2013 APR

MAY

JUN

JUL

AUG

SEP

Ecuador

TOTAL

Print and Digital Versions Available

THOUSAND BOPD Non-OPEC

Reservoir Surveillance

Argentina

532

541

539

545

542

546

Jitendra Kikani

Australia

344

338

356

363

356

354

Generating economic producing opportunities in a new or existing feld is key to the success of an oil and gas company, and reservoir surveillance is an important part of that process. This book will help the reader understand the broad spectrum of issues to consider for surveillance and provide tools, techniques, and templates to adapt to specifc needs. The theory behind some of the equipment as well as data analytics is illustrated with examples. It is essential reading for reservoir, production, and operations engineers and earth scientists. In addition, the theoretical concepts discussed will help students gain fuency in this integrated subject.

Contents • • • • • • • • • •

Planning Value of Information Well and Production Systems Subsurface Measurement Principles Measurement Equipment and Procedures Data Assessment and Quality Control Data Analytics Special Techniques Unconventional Reservoirs Case Studies

Visit our online bookstore at www.spe.org/go/books

Azerbaijan

860

870

905

890

800

890

Brazil

1923

1993

2101

1974

2011

2148

Canada

3237

3036

3156

3317

3470

3679

China

4174

4244

4043

4075

4107

Colombia

1007

1013

974

1020

1031

995

Denmark

183

181

169

177

162

157

Egypt

543

541

540

538

536

534

Eq. Guinea

248

250

Gabon

238

237

245

246

247

India

773

776

778

766

767

Indonesia Kazakhstan Malaysia

860

856

834

811

808

795

1580

1458

1555

1586

1466

1545

506

511

522

509

508

535

Mexico

2557

2548

2559

2522

2554

2563

Norway

1395

1567

1563

1386

1648

1546

Oman

910

920

948

931

947

958

Russia

10002

10018

9955

10052

10064

10082

Sudan

115

248

336

301

277

312

Syria UK USA Vietnam Yemen Other

827

864

783

790

629

735

7332

7298

7242

7513

7532

7794

359

348

332

325

322

131

133

128

110

2437

2429

2448

2432

2440

2384

Total

43276

43171

43348

43752

43528

44264

Total World

75792

75818

75662

76303

76000

75936

JPT • FEBRUARY 2014

Perf_Indices_Feb.indd 6

1/16/14 7:27 AM

MULTI-STAGE COMPLETIONS

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Society of Petroleum Engineers

TR AINING COURSES

PERFORMANCE INDICES

Setting the standard for technical excellence.

Henry Hub Gulf Coast Natural Gas Spot Price*‡ 5 4 3 2

NOV

SEP

JUL

JUN

MAY

APR

MAR

FEB

2013 JAN

DEC

2012 NOV

AUG

USD/Mil. BTUs

world crude oil pRICES (USD/bbl)‡

Relevant.

109.49

87.86

112.96

2012 DEC

Reliable.

102.25

111.28

116.02

2013 JAN

92.02

102.56

APR

Rewarding.

94.76

111.60

AUG

108.47

FEB

94.51

102.92

MAY

106.57

95.31

MAR

95.77

107.93

JUN

106.29

107.79

OCT

Attend an SPE training course to learn new methods, techniques, and best practices to solve the technical problems you face each day. Find out more at www.spe.org/training.

93.86

NOV

Brent

Courses are available for all levels of professionals.

104.67

JUL

109.08 100.54

SEP

92.94

WTI

WORLD ROTARY RIG COUNT† R EGI O N

2013 JUN

JUL

AUG

SEP

OCT

NOV

DEC

1761

1766

1781

1760

1744

1756

1771

Canada

183

291

368

387

378

385

372

Latin America

423

418

399

404

420

411

417

Europe

138

139

143

139

136

137

126

Middle East

389

379

362

379

383

388

405

Africa

133

128

125

119

131

135

138

Asia Pacific

250

241

238

243

245

240

249

3277

3362

3416

3431

3437

3452

3478

TOTAL

world OIL SUPPLY AND DEMAND 1‡ MILLION BOPD Quarter

Get the current schedule— wherever you are. Scan here with a QR code reader.

2013 1st

2nd

3rd

4th

SUPPLY

88.86

89.91

90.65

90.25

DEMAND

89.22

89.85

91.16

91.26

INDICES KEY + Figures

do not include NGLs and oil from nonconventional sources. approximately one-half of Neutral Zone production. Includes crude oil, lease condensates, natural gas plant liquids, other hydrocarbons for refinery feedstocks, refinery 1 gains, alcohol, and liquids produced from nonconventional sources. † Source: Baker Hughes. * The US Dept. of Energy/Energy Information Administration discontinued its reporting of US Natural Gas Wellhead Prices, replacing them with Henry Hub Gulf Coast Natural Gas Spot Prices. Source: US Dept. of Energy/Energy Information Admin. ‡ Includes *

Society of Petroleum Engineers

Perf_Indices_Feb.indd 8

JPT • FEBRUARY 2014

1/16/14 7:27 AM

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REGIONAL UPDATE AFRICA

with partners Octanex (22.5%) and New Zealand Oil & Gas (12.5%).

◗◗ Gas was discovered at two separate levels in the Mronge-1 well in Block 2 offshore Tanzania. The discovery is estimated at between 2 and 3 Tcf of natural gas in place, bringing Block 2’s estimated total in-place volumes up to 17 to 20 Tcf. Statoil (65%) operates the Block 2 license on behalf of Tanzania Petroleum Development Corporation, and partners with ExxonMobil Exploration and Production Tanzania (35%).

◗◗ A new oil zone was found in the Cooper basin, South Australia, in the Patchawarra formation at the Worrior oil field. Senex and Cooper Energy flowed 700,000 scf/D of gas and 670 BOPD during production testing of the Patchawarra formation in the Worrior-8 well. Senex (70%) operates the permit with partner Cooper (30%).

EUROPE

◗◗ Oil was discovered at the Agete-1

◗◗ Oil was discovered in the 7220/7-2S well

exploration well on Block 13T in northern Kenya. The well, drilled to a total depth of 1929 m, encountered 330 ft of net oil pay in good-quality sandstone reservoirs. Tullow Oil (50%) is the operator with partner Africa Oil (50%).

at the Skavl prospect in the Barents Sea about 240 km northwest of Hammerfest. The well has a proved 72-ft gas column and a proved 76-ft oil column in the Jurassic Tubåen formation, with good reservoir quality, and a 436-ft oil column in the Triassic Fruholmen formation, with poor reservoir quality. Operator Statoil estimates the prospect holds 20 to 50 million bbl of recoverable oil. Partners are Statoil (50%), Eni Norge (30%), and Petoro (20%).

ASIA ◗◗ Indonesia announced plans to offer 27 oil and gas blocks in 2014 in regular tenders and direct offers. The blocks include 20 conventional blocks, six shale gas blocks, and one coalbed methane block.

◗◗ Oil was discovered at the Malida-1 well in the G1/48 concession in the Gulf of Thailand. The well encountered 31 ft of net oil pay within the primary target between 2396 m and 2412 m measured depth. Mubadala Petroleum (60%) operates, with Tap Oil (30%) and North Gulf Petroleum (10%).

◗◗ Drilling began on the YNG 3262 infill development well in the southern Nyaung Do area of the Yenangyaung oil field in Myanmar. The well has a planned depth of 1646 m. The primary objective is to produce oil from undrained portions of the several reservoirs in this part of the Nyaung Do fault block. Goldpetrol Joint Operating Company (60%) operates the MOGE-1 block.

AUSTRALIA ◗◗ Drilling began on the Matuku-1 well in petroleum exploration permit 51906 offshore Taranaki basin, New Zealand. The well, with a planned depth of 4750 m, targets the F Sands reservoir sandstones of the Kapuni Group. Secondary targets are sandstones of the Kapuni Group D sand and Pakawau Group North Cape formation. OMV New Zealand (65%) is the operator

RegionalUpdateFeb.indd 10

◗◗ Well 16/2-20S explored the Torvastad prospect located in PL501 in the Norwegian North Sea. The well, drilled to a total depth of 2070 m, encountered a Lower Cretaceous/Upper Jurassic sequence with poor reservoir properties of approximately 78 ft above a water-bearing Upper Jurassic Draupne sandstone sequence of approximately 33 ft of excellent quality in a 46-ft gross sequence. Lundin Petroleum (40%) operates PL501 with partners Statoil (40%) and Maersk Oil Norway (20%).

MIDDLE EAST ◗◗ Gas was discovered at the Tamar Southwest (SW) exploration well offshore Israel. The well encountered approximately 355 ft of net gas pay within the targeted Miocene intervals. The well, drilled to a total depth of 5310 m in 1647 m of water, is estimated to hold gross resources between 640 and 770 Bcf of gas. Noble Energy (36%) operates Tamar SW, with Isramco Negev 2 (28.75%), Delek Drilling (15.625%), Avner Oil Exploration (15.625%), and Dor Gas Exploration (4%).

NORTH AMERICA ◗◗ Oil was discovered at an exploration well on Keathley Canyon Block 93 of the

Gila prospect in the deepwater US Gulf of Mexico. The well, drilled to a total depth of 8907 m, penetrated multiple Paleogene-aged reservoir sands. BP (80%) operates Block 93 with partner ConocoPhillips (20%).

◗◗ Oil was discovered at the Dantzler exploration well in the deepwater Gulf of Mexico. The well encountered more than 120 net ft of primarily crude oil pay in two high-quality Miocene reservoirs. The well, located in Mississippi Canyon 782, was drilled to a total depth of 5863 m in 2006 m of water. Noble Energy (45%) is the operator in partnership with entities managed by Ridgewood Energy (35%) and with W&T Energy VI (20%).

SOUTH AMERICA ◗◗ Oil was discovered at the 1-BRS-A-1205RNS well, informally known as Pitu, on the BM-POT-17 concession in the deep waters of the Potiguar basin offshore Brazil. The oil column was confirmed through log data and fluid samples during drilling. Petrobras (80%) is the operator with partner Petrogal Brasil (20%). After obtaining approval from the National Agency of Petroleum, Natural Gas, and Biofuels for a farm-out agreement, BP Energy do Brazil (40%) will become operator of the concession, with partners Petrobras (40%) and Petrogal (20%).

◗◗ Good-quality oil was found offshore Brazil in the subsalt Carioca field, which might have about 459 million BOE in recoverable reserves. A consortium, consisting of operator Petrobras (45%), with partners BG Group (30%) and a joint venture (25%) between Repsol and Sinopec, found the oil.

◗◗ Spectrum and CGG jointly launched a large 3D multiclient survey program offshore Brazil focusing on a large proportion of open acreage in the Foz do Amazonas basin. The survey, which will cover 11,220 km2, will be acquired by the Oceanic Endeavour survey vessel.

◗◗ Oil was discovered in the Leon 1 exploration well located in the Llanos basin of Colombia. The well encountered 133 ft of net oil pay within four different reservoirs. Canacol Energy (80%) is the operator with partner Petromont S.A. Sucursal Colombia (20%). JPT

JPT • FEBRUARY 2014

1/16/14 7:27 AM

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COMPANY NEWS MERGERS AND ACQUISITIONS ◗◗ BreitBurn Energy Partners will acquire additional oil and natural gas properties in the Permian Basin in Texas for around USD 282 million from CrownRock. The acquisition includes approximately 93 producing wells and over 300 potential drilling locations. Estimated average net production is 2,900 BOE/D.

◗◗ New Western Energy acquired two oil and gas leases encompassing 600 acres in Wilson County, Kansas, which have a combined production of 7.5 BOPD. The first lease consists of 440 acres with 14 existing oil wells and three water injection wells that currently produce at the rate of 5 BOPD. The second lease consists of approximately 160 acres with three existing oil wells that currently produce at the rate of 2.5 BOPD.

◗◗ Kvaerner sold its onshore construction business in North America to Matrix Service for an enterprise value of USD 80.3 million. Matrix will receive ownership of certain assets of Kvaerner North American Construction in the US and the shares in Kvaerner North American Construction in Canada.

◗◗ Centor Resources purchased a 55% working interest in shale oil resources in the Pasquia Hill region of Saskatchewan, Canada. The assets are estimated to hold more than 1.1 billion bbl of recoverable oil in leases that span 21,658 acres.

◗◗ MOL Hungarian Oil & Gas agreed to pay BASF USD 375 million for North Sea oil and gas assets. MOL will acquire 14 licenses on the UK continental shelf from BASF’s oiland-gas unit Wintershall. The transaction is expected to close in the first quarter this year.

design for Statoil with additional options for work in later phases.

◗◗ GOL Offshore signed a USD‑115‑million contract with Oil & Natural Gas Corporation for the reconstruction of BPA and BPB, two gas processing platforms off the west coast of India. GOL Offshore will provide the engineering survey, detailed design and engineering, procurement, fabrication, transportation of materials (from shore to offshore), installation, and hookup as well as commissioning.

◗◗ Total signed an exploration and

COMPANY MOVES ◗◗ The American Bureau of Shipping (ABS) will establish an office, scheduled to open in the first quarter, in Houston’s Energy Corridor. The new facility will colocate members from ABS engineering, project management, technology, and business management. In addition to classification services, the facility will offer education and training seminar rooms for local industry to use on demand.

◗◗ Saudi Aramco opened the Aramco

production-sharing agreement for deepwater Block 41 offshore Oman. The block covers almost 24,000 km2 of seabed at depths of up to 3000 m. The exploration program is expected to begin with seabed coring this year.

◗◗ Salamander Energy signed a production sharing contract (PSC) for Malaysia’s Block PM322, located in the Melaka Strait on the Malay side of the Central Sumatra basin, offshore west coast Peninsular Malaysia. The PSC is located in shallow water and covers approximately 20,000 km2. Salamander will operate the PSC with an 85% working interest.

gas in southeastern Poland with local state-controlled gas firm PGNiG. If the cooperation is successful, they might set up a joint company in which both parties would hold a 50% stake. Binding agreements are expected to be signed this year.

Research Center in Cambridge, Massachusetts—the first of three US-based research and development centers aimed at expanding Saudi Aramco’s global research network and capability. The 32,000-ft2 research center is expected to create approximately 50 scientific and research jobs.

◗◗ New Western Energy acquired an

◗◗ Safetec opened a new Competence

oil and gas lease consisting of 80 acres adjacent to its Winchester and Thomas leases in Rogers County, Oklahoma. The lease, Winchester II, has five existing oil and gas wells and one water injection well that currently produce an average of 4 BOPD.

Center in Bergen, Norway, which will provide onshore and offshore education and training for organizations. The center will provide clients with experienced trainers and advanced facilities for teaching and training in risk management, safety, and emergency management.

◗◗ Shell entered into a 3-year contract

CONTRACTS

◗◗ A subsidiary of McDermott

◗◗ Chevron will jointly explore shale

◗◗ The Cambay Joint Venture secured the Essar Rig 4 for drilling the Cambay77H well in its Cambay Tight Hydrocarbon Project in the Cambay basin in India through Essar Oilfield Services. The well is expected to be spudded in the middle of the first quarter.

with Transocean for the Polar Pioneer drilling rig to start work off the coast of Alaska beginning July of this year. The rig is expected to earn a rate of USD 620,000 per day from July to October and USD 589,000 per day the rest of the year.

◗◗ Jones Energy entered into a definitive agreement to acquire producing and undeveloped oil and gas assets in the Anadarko basin from Sabine Oil & Gas for USD 195 million. The assets consist of approximately 26,000 net acres in the Cleveland, Tonkawa, and Marmaton plays in the Texas Panhandle and western Oklahoma. The assets have proved reserves of 14.3 million BOE.

CompanyNewsFeb.indd 12

◗◗ Aker Solutions won a contract to provide engineering services, procurement, and management assistance for up to 10 years for the Johan Sverdrup oil field in the Norwegian North Sea. The first part of the contract is worth USD 106 million and consists of the front-end engineering and

International was awarded a USD200-million engineering, procurement, construction, and installation project for a customer in the Arabian Gulf. The contract includes the fabrication, transportation, and installation of offshore facilities including two production deck modules and 10 observation platforms. JPT

JPT • FEBRUARY 2014

1/16/14 7:28 AM

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EMERGING FRONTIERS

SPE BOARD OF DIRECTORS OFFICERS

Focus on Myanmar Jeff Spath, 2014 SPE President

2014 President Jeff Spath, Schlumberger 2013 President Egbert Imomoh, Afren 2015 President Helge Hove Haldorsen, Statoil Vice President Finance Janeen Judah, Chevron

In this third column on emerging geographic frontiers, I want to focus on what may be the fastest developing country in the Eastern Hemisphere—politically, demographically, and certainly from the standpoint of upstream oil and gas. Myanmar, often referred to as Burma, has been largely isolated from the global economy for roughly 50 years due to oppressive military rule and extensive human rights violations. In 2012, under newly appointed president Thein Sein, Myanmar began to reform its foreign direct investment laws about the same time the US and the European Union began suspending sanctions. E&P industry players, large and small, have been watching and waiting for just such reformations and are now being attracted by the potential for huge growth in the existing gas production and the potential of the country’s 17 sedimentary basins, largely offshore and unexplored.

Production History

Myanmar is one of the world’s oldest producers of oil; it exported its first barrel of crude in 1853. Two oilfields discovered in 1887 and 1902 are still in production. Today, the country is a net importer of crude oil as 90% of production is gas, most of which is exported to Thailand. With a current production of 21,000 B/D, primarily from only two fields, the need and attraction of foreign investment is clear. The sedimentary basins are extremely underexplored and much of the available geological data were acquired with outdated technology. Estimates of reserves therefore vary widely. In 2012, the Ministry of Energy estimated offshore Myanmar crude oil reserves at roughly 540 million bbl and natural gas reserves at 65 to 72 Tcf. Myanmar Oil and Gas Enterprise (MOGE) was created in 1963, shortly after nationalization of the oil and gas industry, in an effort to consolidate the oversight and management of the various local and global efforts to increase reserves and production. However, foreign operators were not allowed to participate in the efforts until 1988, when generic foreign investment legislation was passed. The Ministry of Energy held its first formal licensing round for onshore blocks in 2011, but due to the existing sanctions, western companies were largely absent. More recently, 30 offshore blocks were offered for licensing in June 2013, including shallow- and deepwater blocks. Participation was prolific, including most major international oil companies. In fact, according to an energy ministry source, foreign companies’ tenders will be given priority, as they have the technology and expertise required to bring the complex and costly deepwater resources to market. Significantly, the government waived the initial requirement that foreign companies partner with a Myanmar-owned firm for the deepwater blocks, which increased the participation greatly. Results of the bidding are expected in early 2014 but one thing is clear – interest in finding and developing deepwater resources is widespread and intense.

Local Talent Needed

Myanmar’s repressive military rule of the past 50 years has resulted in a seriously inadequate educational system. Some universities were closed for decades following

REGIONAL DIRECTORS AFRICA Anthony Ogunkoya, TBFF Upstream Oil and Gas Consulting CANADian Darcy Spady, Sanjel Corporation Eastern North America Bob Garland, Universal Well Services Gulf Coast North America Bryant Mueller, Halliburton Mid-Continent North America Michael Tunstall, Halliburton Middle East Fareed Abdulla, Abu Dhabi Co. Onshore Oil Opn North Sea Carlos Chalbaud, GDF Suez E&P UK Northern Asia Pacific Ron Morris, Roc Oil (Bohai)/Roc Oil (China) Rocky Mountain North America Mike Eberhard, Anadarko Petroleum Corporation Russia and the Caspian Andrey Gladkov, Modeltech South America and Caribbean Nestor Saavedra, Ecopetrol–ICP South, Central, and East Europe Maurizio Rampoldi, Eni E&P Southern Asia Pacific John Boardman, RISC Southwestern North America Peter Schrenkel, Vision Natural Resources Western North America Tom Walsh, Petrotechnical Resources of Alaska

TECHNICAL DIRECTORS Drilling and Completions David Curry, Baker Hughes Health, Safety, Security, Environment, and Social Responsibility Roland Moreau, ExxonMobil Upstream Research Company Management and Information Cindy Reece, ExxonMobil Annuitant Production and Operations Shauna Noonan, ConocoPhillips Projects, Facilities, and Construction Howard Duhon, Gibson Applied Tech PF&C Reservoir Description and Dynamics Olivier Houzè, KAPPA Engineering

AT-LARGE DIRECTORS Liu Zhenwu, China National Petroleum Corporation Mohammed Al-Qahtani, Saudi Aramco

To contact the SPE President, email president@spe.org. Search the Groups Field for “Society of Petroleum Engineers”. 14

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EMERGING FRONTIERS

student-led anti-government protests in 1988. Void of government support for advanced education, the scarcity of local engineering talent is obviously the biggest challenge facing the oil and gas industry. This is a recurring theme in all countries, emerging or mature, but nowhere is the problem more critical than in Myanmar. Since 2011, new policies and new foreign investments have enabled Myanmar to triple its investment in education. Although the Yangon Technological University (YTU) is the only university currently offering petroleum engineering education, oil and gas companies and service companies are donating resources in the form of buildings and information-technology infrastructure, and providing for guest lecturers to bring essential global industry knowledge. As a part of SPE’s newly adopted strategy, we have an obvious role to play in helping develop the resources. Efforts were initiated with the attendance of YTU’s newly appointed petroleum engineering department chair at the SPE Forum on Petroleum Engineering Education in August 2013. This Forum was designed to help petroleum engineering educators understand the issues and the resources required to fulfill future industry needs.

Flow Assurance Technical Section

SPE has formed a Technical Section to give members the opportunity to focus on flow assurance, a key area of interest for facilities engineers. This new section seeks to further the objectives of SPE in the free discussion of matters relating to flow assurance, to establish consensus on industry best practices, and to promote these practices widely. Deepen your learning and share your insights on the subject during discussions at study groups, monthly meetings, forums, and workshops. Enjoy the convenience of virtual meetings and the benefits of at least one face-to-face meeting a year. Learn more and join today at connect.spe.org/fts.

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Technology Required

Given the lack of modern technology used to initially evaluate Myanmar’s hydrocarbon resources, foreign operators licensing blocks need to be technology savvy, bringing knowledge of global state-of-the-art techniques in exploration, drilling, and development. Operators winning offshore blocks, as in any emerging play, will initially focus on acquiring seismic data using advances proven elsewhere in sensors, multi-sensor cables, and cable design enabling high-resolution near-surface imaging as well as deep reservoir characterization. The integration of newly acquired seismic data with advances in basin modeling technologies should give the necessary confidence for early exploration drilling. Exploratory drilling will also benefit from recent advances in logging while drilling. Measuring azimuthal resistivity, neutron porosity, elemental capture spectroscopy, and formation pressure in real-time as well as borehole imaging increases the likelihood of optimum well placement in basins that have little or no offset data. Onshore, the existing production from mature fields will undoubtedly benefit from technology advances and best practices gleaned from elsewhere in the world, such as the ability to analyze formation properties behind casing to reveal additional pay and the application of newly developed EOR techniques to improve recovery of existing pay.

SPE in Myanmar

One of my goals as SPE president is to increase the internationalization of SPE, extending the reach of our programs and providing the benefits of SPE membership with more local relevance, and I can’t think of a better example than Myanmar of an underdeveloped country that can greatly benefit from SPE’s presence. Myanmar has huge potential for SPE programs and services to help existing and incoming industry professionals alike and I’m pleased to say that SPE has just finalized the formation of our 214th professional section in Myanmar. The inauguration will become official with the meeting of the SPE International Board of Directors this month in Yangon. The response by industry, academia, and government has been remarkable. Myanmar is one of the world’s most geologically unexplored and talent-challenged countries, so the cooperation between SPE and the operators and service companies is a necessity; under the capable eye of Ron Morris, Northern Asia Regional Director, I have high expectations for progress. The organization of technical programs, the application of global best practices, the engagement with local governments, the collaboration with companies on university programs, and the educating of the public on our industry are but a few ways I expect to see valuable results. Each month, I post my JPT column topic on the SPE LinkedIn group for comment and conversation. I invite you all to join in this discussion and look forward to hearing your viewpoints. JPT

JPT • FEBRUARY 2014

1/16/14 12:39 PM

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COMMENTS

EDITORIAL COMMITTEE Syed Ali—Chairperson, Technical Advisor, Schlumberger Francisco J. Alhanati, Director, Exploration & Production, C-FER Technologies

Asia Pacific’s Future John Donnelly, JPT Editor Asia Pacific’s energy sector is on the brink of major change. New areas are opening to foreign investment, national oil companies are adopting more aggressive E&P strategies, and the supply/ demand balance is shifting. This month’s JPT contains a special supplement outlining these and other trends and challenges and describes what to expect in the region’s upstream sector over the next several years. One of the major changes under way in the Asia Pacific region is the sharp rise in energy consumption, which is leading to an increase in oil imports and cutting into gas available for export. Several major liquefied natural gas (LNG) projects are under construction or in the planning stages to help meet the increased demand for gas, which may eventually overtake oil as the region’s main hydrocarbon source. Nowhere is the shift in the global energy balance more evident than in China. BP’s Energy Outlook 2035, published in January, predicts that by 2035 China will be the world’s largest energy importer and alone will account for more than a fifth of global demand. Changes are forecast for India as well, with its energy production rising by 112% and its consumption by 132% over the same period. Significant policy shifts are occurring in China as well. The country’s leadership is pushing for changes in its energy sector that will better balance energy and economic growth with environmental protection. Liberalization of local fuel prices will be a financial boost for China’s major oil companies—Sinopec, China National Offshore Oil Corp. (CNPC), and PetroChina—allowing them to invest more both domestically and internationally. China’s state-owned companies are expected to continue to be aggressive at overseas mergers and acquisitions. The most recent deal was in November, when CNPC bought Petrobras’ oil and gas assets in Peru for USD 2.6 billion, reinforcing China’s growing presence in Latin America. China continues to show interest in international unconventional plays, as the Asia Pacific region’s unconventional sector remains largely untapped. Only two shale plays have produced commercial volumes of gas thus far—one in China and one in Australia—and shale gas exploration wells have been drilled only in China, Australia, and India. The US Energy Information Administration estimates significant volumes of shale gas and shale oil resources in those countries as well as in Thailand and Indonesia. Population in the Asia Pacific is forecast to rise significantly over the next 2 decades, putting additional strain on energy capabilities. Currently, about one-fifth of the region’s population still does not have access to electricity. This highlights the need for additional energy infrastructure and suggests that energy demand will only increase over the short to medium term. Although parts of Asia have exported gas, regional gas consumption is now competing to keep those supplies at home. And many of the oil fields in the area—in places such as Vietnam, Thailand, and Malaysia—are mature and in decline, which will lead to increased reliance on oil imports, primarily from the Middle East. JPT

William Bailey, Principal Reservoir Engineer, Schlumberger Ian G. Ball, Technical Director, Intecsea (UK) Ltd Luciane Bonet, Senior Reservoir Engineer, Petrobras America Inc. Robert B. Carpenter, Sr. Advisor – Cementing, Chevron Corp. Simon Chipperfield, Team Leader Central Gas Team/ Gas Exploitation, Eastern Australia Development, Santos Alex Crabtree, Senior Advisor, Hess Corporation Jose C. Cunha, Drilling Manager, Ecopetrol America Alexandre Emerick, Reservoir Engineer, Petrobras Research Center Niall Fleming, Leading Advisor Well Productivity & Stimulation, Statoil Ted Frankiewicz, Engineering Advisor, SPEC Services Emmanuel Garland, Special Advisor to the HSE Vice President, Total Reid Grigg, Senior Engineer/Section Head, Gas Flooding Processes and Flow Heterogeneities, New Mexico Petroleum Recovery Research Center Omer M. Gurpinar, Technical Director, Enhanced Oil Recovery, Schlumberger A.G. Guzman-Garcia, Engineer Advisor, ExxonMobil (retired) Robert Harrison, Global Business Leader, Reserves & Asset Evaluation, Senergy Delores J. Hinkle, Director, Corporate Reserves, Marathon Oil (retired) John Hudson, Senior Production Engineer Shell Morten Iversen, Completion Team Leader, BG Group Leonard Kalfayan, Global Production Engineering Advisor, Hess Corporation Tom Kelly, Systems Engineering, FMC Technologies Gerd Kleemeyer, Head Integrated Geophysical Services, Shell Global Solutions International BV Jesse C. Lee, Chemistry Technology Manager, Schlumberger Casey McDonough, Drilling Engineer, Chesapeake Energy Cam Matthews, Director, New Technology Ventures, C-FER Technologies Badrul H Mohamed Jan, Lecturer/Researcher, University of Malaya Lee Morgenthaler, Principal Technical Expert, Chemical Production Enhancement, Shell Alvaro F. Negrao, Senior Drilling Advisor, Woodside Energy (USA) Shauna G. Noonan, Staff Production Engineer, ConocoPhillips Karen E. Olson, Completion Expert, Southwestern Energy Michael L. Payne, Senior Advisor, BP plc Mauricio P. Rebelo, Technical Services Manager, Petrobras America Jon Ruszka, Drilling Manager, Baker Hughes (Africa Region) Martin Rylance, Senior Advisor and Engineering Manager Fracturing & Stimulation, GWO Completions Engineering Jacques B. Salies, Drilling Manager, Queiroz Galvão E&P Otto L. Santos, Sênior Consultor, Petrobras Luigi A. Saputelli, Senior Production Modeling Advisor, Hess Corporation Sally A. Thomas, Principal Engineer, Production Technology, ConocoPhillips Win Thornton, Global Projects Organization, BP plc Erik Vikane, Manager Petroleum Technology, Statoil Xiuli Wang, Vice President and Chief Technology Officer, XGas Mike Weatherl, Drilling Advisor, Hess Norge AS Rodney Wetzel, Team Lead, SandFace Completions, Chevron ETC Scott Wilson, Senior Vice President, Ryder Scott Company

To contact JPT’s editor, email jdonnelly@spe.org. 18

CommentsFeb.indd 18

Jonathan Wylde, Global Head Technology, Clariant Oil Services Pat York, Global Director, Well Engineering & Project Management, Weatherford International

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GUEST EDITORIAL

Digitizing E&P: Accelerating the Pace of Change Archana Deskus, Vice President and Chief Information Officer, Baker Hughes

Archana (Archie) Deskus is vice president and chief information (CIO) officer at Baker Hughes. She previously served as vice president and CIO for Ingersoll-Rand and has more than 2 decades of experience in the aerospace, industrial, and consumer products industries. Deskus held various positions at United Technologies for 19 years and has been executive director, infrastructure and e-business at Pratt & Whitney, and vice president and CIO at Carrier North America. She also worked as senior vice president and CIO for Timex Corp. She earned a BS degree in business administration/management information systems from Boston University and an MBA degree from Rensselaer Polytechnic Institute.

The pace of change is accelerating on a global scale, and the agent of this accelerated pace is digitization. Digitization has had a profound impact on our personal lives. It has transformed and created industries and has creatively destroyed some existing business models. Certain industries, such as finance, automotive, aerospace, communications, and media, have led the way. Others have been slower to adapt. The oil and gas industry is a major driver of high-performance computing development, particularly for upstream seismic processing and permanent field monitoring. The oil and gas industry currently has the highest refresh rate across all industry sectors that high-performance computing addresses. Yet findings from leading information technology research and advisory firms such as Gartner and AMR indicate that the exploration and production (E&P) industry is in the low quartile for digitization.

Realizing the Digital Vision

“Digital oilfield” is an umbrella term for technology-centric solutions that allow E&P companies to leverage limited resources and improve decision making to maximize production; minimize capital and operating expenses and environmental impact; ensure the safety of the people involved; and protect the integrity of associated equipment across the entire upstream process. It encompasses both tools and processes surrounding data and information management. Its success depends on capability, organizational alignment, and—ultimately—attitude. The industry has crossed many of the technology barriers to enabling the digital oilfield. Remote sensing is available for almost all facets of drilling and production operations, and the number of choices for network transmission of data continues to expand. The industry has invested heavily in knowledge management systems, real-time operations centers, and collaborative decision environments. It has become adept at moving data gathered from field devices into software applications and using it to enhance some specialized field operations. However, the industry has not yet succeeded in achieving the cross-disciplinary data transparency, information sharing, process integration, and collaboration that are essential to realizing the ultimate vision and value of the digital oilfield. Examining other industries’ paths to digitization may help us in our quest.

A Look at Aerospace

A number of parallels can be drawn between the aerospace industry and E&P, including the fact that both involve “flying in the dark”; both rely on close, long-term partnerships among operators, service companies, and equipment manufacturers to generate economic value; and both envision varying degrees of “unmanned flight” to reduce the margin of error, address safety and cost opportunities, and open additional opportunities to create value. Aerospace has benefitted from digitization for several decades. The first aspect involved integrating the supply chain. Digitization of scheduling, logistics, inventory tracking, testing, and other functions reduced costs, improved efficiencies, and

GuestEdFeb.indd 20

JPT • FEBRUARY 2014

1/17/14 11:01 AM

Mangrove ENGINEERED STIMULATION DESIGN IN THE PETREL PLATFORM

PetroChina Changqing beats previous-best horizontal well production by more than 50%. PetroChina Changqing used Mangrove* workfow in the Petrel* E&P software platform to capture the complexities of the Ordos basin. The engineered fracturing design helped improve reservoir-to-wellbore connectivity while cutting fracturing fuid consumption and pressure drawdown in half. Three months after the wells were completed, sustained production rates were 50% higher than the previous-best ofset horizontal well.

Read the case study at

www.slb.com/Mangrove *Mark of Schlumberger. ÂŠ 2014 Schlumberger. 13-ST-0101

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If knowledge is power, get ready to be supercharged.

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GUEST EDITORIAL

reduced lead and cycle times. Another area of focus was traceability and visibility of critical parts and components through all tiers and within specified time constraints. Integrating asset records, service bulletins, and safety procedures throughout the supply chain not only simplified traceability and prioritization, but also improved productivity, compliance, the ability to respond when an incident occurred, and the ability to identify where a problem originated and quickly correct it. The second aspect of aerospace digitization focused on collaboration of engine design. Traditionally, new design cycles could span a decade or longer, plus further time to prove manufacturability and drive down cost. Design took place in isolation until the new engine could perform at certain parameters, and only then did the supply chain become involved. So, an engine may meet certain design and performance criteria, yet still need further modifications to be viable for manufacturing and to meet customer price expectations. To dramatically reduce design time frames, the industry had to embrace a different approach to new product design. The new approach involved forming collaborative design networks across multiple organizations in the value chain for joint development. This was to drive greater customer value, eliminate waste, leverage a wider net of talent (specialists), and, ultimately, lead to better and faster design. Improved modeling and simulation capabilities, and tapping into a wealth of performance data from histories of in-flight equipment, also contributed to improving design capabilities and shortening lead time. Today’s engine development cycles are dramatically different from before digitization and collaboration, with significantly reduced development time frames. The third aspect of digitization focused on the life cycle of an asset. The life cycle of an aerospace asset

spans more than 25 years and is dependent upon flight hours and conditions. Managing the asset throughout its life cycle can be extremely costly, and airline operators are continually pressed to optimize flight time and reduce onground time. Historically, when an engine needed repair or overhaul, the service provider would literally tear it apart to understand the configuration before making the repair. Heavy repairs often required more than 100 days, resulting in millions of dollars in “grounded” costs for a parked asset. Today, integration of digital asset and service record maintenance, remote monitoring and diagnostics, and information mined from in-service equipment has helped to cut repair and maintenance cycle time, minimize time on ground, and provide valuable feedback for future product development. Advances in remote monitoring and diagnostic capabilities have advanced to the point that we literally have a flying data center that provides more data than we know what to do with. The key is determining what business problem we are trying to solve. With the insight provided by digitally enabled information and analytics, business models in the aerospace industry have evolved and new ones have emerged. Companies that began by selling equipment and parts moved to selling systems and then offering fleet management programs, nose-to-tail management, and power by the hour— all because the wealth of information and the ability to effectively manage it have made it possible to model the cost of operating an asset.

Great Heights to Great Depths

Many of the digitization ideas that have worked for aerospace can also be applied to E&P. For example, a cohesive, integrated supply chain can enable consistent flawless execution with the right people, the right equipment, and the right materials. Automation in the field

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can drive productivity, visibility, and knowledge capture. Cross-disciplinary, simultaneous modeling and simulation of discrete products, such as drill bits, and formulated products or systems, such as chemicals or drilling fluids, could dramatically impact the ability to test for variable conditions. For example, in addition to modeling the drill bit and simulating its rotation in a particular formation, applying mud, and simulating under various conditions could not only improve design and test time, but also deliver higher quality, higher performance, and safer products and systems. Collaboration around the interoperability of systems and components through industry standards would support system thinking. Remote monitoring and diagnostics capabilities offer the same benefits for managing the life cycle of hydrocarbon assets as for managing the lifecycle of aerospace assets. Integrated asset monitoring enables simulation and intervention for reservoir optimization. We can evaluate the impact of variables for desired outcomes, such as maximum extraction of oil, minimal water production, and maximization of net present value. Whereas the variations that exist in aircraft and flight conditions are pretty much known, unpredictability in geology and reservoir development— undeterministic characteristics—limit the ability of the E&P industry to capture meaningful information and, thus, impact the quality of decision making. However, continued advances in technology will improve our ability to capture meaningful information and enable reservoir-specific algorithmic knowledge development.

From Future to Present

Integrated operations are heavily dependent on technology and digitization. Today we can monitor, manage, and optimize specific operations remotely. End-to-end digitization will enable

remote operations from seismic to abandonment. Similarly, the ability to integrate disparate data from these operations, make it available in real time, and couple it with collaborative techniques that tap into expertise across disciplines, without geographic bounds, will make it possible to optimize production in real time. Intelligent systems with embedded knowledge learned from humans will be able to observe, evaluate, and make adjustments in advance of changing wellbore and geologic conditions. These achievements will both enable and be predicated upon moving away from silos of information and skills to collaborative, real-time optimization of the entire supply chain and the entire asset life cycle. Oilfield digitization will accelerate employee productivity. It will enable fewer people to accomplish more and better leverage their expertise. It will help close the labor and skills gaps that threaten to inhibit the oil and gas industry in reaching its full potential for value creation. While there are challenges that need to be overcome with securing data and communications, changing roles and responsibilities, and changes in workflow, E&P digitization could lead to new, and more productive, business models for the industry. The E&P industry has been on the path to digitization for a long time but has tremendous opportunities yet to be realized. Many industries that now lead in digitization were driven in their resolve by either great economic pressures or risk of industry destruction or disruption. The E&P industry faces no such immediate risk, but it is not beyond the realm of possibility. The industry stands at a crossroads. It can decide now to make investments and attitudinal changes necessary to break down barriers to digitization and accelerate progress. Or it can risk being forced by external forces to make the same, or tougher, decisions in the future. JPT

TIP No. 26

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TECHNOLOGY APPLICATIONS Chris Carpenter, JPT Technology Editor

Measurement-WhileDrilling Ranging Service

Scientific Drilling International’s MagTraC MWD Ranging system addresses difficult wellbore-placement and riskmitigation challenges. First introduced in 1998, MagTraC targets applications where uncertainty and risk are major factors in well construction, isolating the Earth’s naturally occurring magnetic field from the magnetic interference signature of a casing string, allowing the distance and direction to the target to be determined and using the raw measurement-whiledrilling data to calculate the relative position between wellbores (Fig. 1). Remote data centers ensure that there is no interruption in operations, and results are typically available 15 to 30 minutes after Scientific Drilling’s specialists receive the data, with preliminary results usually becoming available in 15 minutes. MagTraC allows

remote ranging where data can be sent without operational shutdown and provides increased safety assurance by eliminating additional survey runs or on-site personnel. Since September of 2013, MagTraC has been used in more than 450 jobs across the globe involving production recovery, fish bypass, plug and abandonment, close-proximity drilling, collision avoidance, ghost-well detection, and kickoff assurance. ◗◗For additional information, visit www.scientificdrilling.com.

Casing-Stabilizer Arm

Aker Solutions has developed a casingstabilizer arm (CSA) that eliminates the need for a person to be elevated on a derrick for tubular makeup. The CSA is designed for both offshore and onshore rigs. The stabilizing mechanism is stowed approximately 33 ft above the drilling

floor and includes an internal hydraulic cylinder that extends and closes the padded jaws operated by a radio remote control (Fig. 2). The CSA uses only three hydraulic cylinders to position and mobilize the pipe jaws: lifting, extension, and clamping cylinders. Aker’s unit also provides increased safety features that allow the device to interface with the rig’s anticollision-zone-management system. A warning and alarm system is built into the CSA along with an emergencyshutoff control. Additionally, a shear pin is installed on the unit as a safeguard for unexpected downward clash by hoisting equipment. The CSA is equipped in tubular capacities of 2⅞- to 22-in. diameter without changing jaws. Additionally, it offers wireless remote control and local manual control. ◗◗For additional information, visit www.akersolutions.com.

Infinite-Revolution Bit

Baker Hughes has introduced the Hughes Christensen IRev infinite-revolution bit that improves run life while minimizing trips and the number of bits required when drilling in hard and abrasive intervals, including sandstones or complex sections interbedded with softer shales. IRev technology features a cutting struc-

Fig. 1—Scientific Drilling International’s MagTraC MWD Ranging system.

Fig. 2—Aker Solutions’ CSA is designed for both onshore and offshore applications.

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Fig. 3—The IRev infinite-revolution bit from Baker Hughes offers increased rates of rock removal and penetration.

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TECHNOLOGY APPLICATIONS cables with the use of high-speed telemetry and video-compression techniques (Fig. 4). It has been designed for wellintegrity inspection and monitoring of downhole corrosion and mechanical damage, including those found in marginal conditions, and it successfully completed a wide run of 100 field-trial jobs in Canada before becoming commercially released in the North Sea, the Gulf of Mexico, Saudi Arabia, and Australia. The camera features improved speeds and picture quality compared with similar downhole video cameras, allowing for advanced inspection of oilfield subsurface equipment for integrity issues. The system tunes itself to a wide range of cables so that the Optis HD Electric camera works on virtually any cable length or cable type. Its modular design allows it to be run with downview, sideview, or both. Deviation and internal temperature are digitally transmitted to the surface laptop, providing essential information when viewing images. ◗◗For additional information, visit www.evcam.com.

Silicate-Based Preflush

Fig. 4—The Optis HD Electric line camera from EV.

ture that includes diamond-impregnated posts that allow an increased rate of rock removal, enabling the bit to drill in places where polycrystalline-diamondcompact bits typically cannot perform (Fig. 3). As diamonds wear away, new diamonds are exposed to enhance performance and extend bit life further. Other new features of the IRev bit include a design that enables higher torque output to deliver greater rate of penetration (ROP). Application-specific diamond grits provide optimal performance by matching technology to application. Depending on the application environment, additional features can be incorporated into the IRev bit to deliver superior performance.

TechAppsFeb.indd 26

New profiles balance workloads better to extend bit life, while improved hydraulics enables more-effective cleaning in hard sections interbedded with stickier, softer shales and siltstones. Posts can be exposed above the blades to improve aggressiveness in less-demanding applications, delivering higher ROP. ◗◗For additional information, visit www.bakerhughes.com.

Downhole Video Camera

EV has launched its Optis HD Electric line camera to the well-intervention market. The camera’s new technology allows operators to stream color video at up to 25 frames/second on monoconductor

PQ Corporation’s Metso 66 Preflush was specifically developed for the removal of oil-based drilling fluid and filter cake and is also suitable for wells drilled with water-based drilling fluid. This multifunctional silicate-based preflush is also designed to improve cement bonds as well as prevent slurry migration and fallback. Metso 66 is a blend of advanced granular sodium silicate, specialty surfactants, and other additives (Fig. 5). The soluble silica and alkali serve several beneficial roles in enhancing the performance of surfactants, such as raising pH, softening water, and reducing the interfacial tension between oil and water. The silicate ion further promotes the partition between the oil and water phases. This translates into greater removal of oil-based drilling fluid with a lower volume of flush material and a corresponding reduction in disposal volumes. Cement bonds are improved by having clean wellbore and casing surfaces that are water-wet as well as primed with soluble silica. Metso 66 is formulated to

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1/16/14 7:41 AM

Fig. 5—PQ Corporation’s Metso 66 silicate-based preflush is a blend of advanced granular sodium silicate and specialty surfactants.

be readily soluble, even in cold water. A 10 wt% solution of Metso 66 will achieve complete dissolution in 5°C water in less than 10 minutes and can be dissolved in fresh water or seawater. ◗◗For additional information, visit www.pqcorp.com.

Fig. 6—The interrogator unit from OptaSense’s SubseaDAS system.

Distributed Acoustic Sensing System

OptaSense is developing the world’s first fully marinized and qualified distributed-acoustic-sensing (DAS) system in a joint program with Shell. The OptaSense Subsea-DAS system, which will be de-

ployed in water depths up to 10,000 ft, will take proven onshore DAS technology to the offshore oil-and-gas industry, allowing highly accurate acoustic-data acquisition for the first time in this sector. The Subsea-DAS system will provide acoustic data for a wide range of subsea and

Optimizing Shales: New Lessons Learned Third Annual AAPG/STGS GTW: Eagle Ford + Adjacent Plays and Extensions February 24-26, 2014 • San Antonio, TX

This workshop focuses on prospectivity and producibility, with an emphasis on the conditions and characteristics of successful wells, and the technologies and techniques used in achieving success. The productive extent of the Eagle Ford has expanded, thanks to new information and understanding of the factors that make the formation producible in a particular prospect or location. The same is true of adjacent formations such as the Buda and the Austin Chalk, along with Cretaceous extensions of the Eagle Ford, which extend from the Eaglebine to the Tuscaloosa Marine Shale.

Topics: • Geophysics, regional geology, and Eagle Ford Extensions • Sweet spots, reservoir quality, and the Eagle Ford • Petrophysics • Geomechanical considerations • Drilling the “new” zones: Lessons learned and “Must-Know” facts

• Completions: Hydraulic fracturing, proppant selection, understanding reservoir behaviors • The right kind of frac: How can geologists help? What can engineers explain? • Decline curves: Seeking and finding answers

www.aapg.org/gtw/2014/houston/index.cfm

Geosciences Technology Workshops 2014

JPT • FEBRUARY 2014

TechAppsFeb.indd 27

1/16/14 7:41 AM

Are you reAdy to explore the frontiers of knowledge?

TECHNOLOGY APPLICATIONS

Fig. 7—Schlumberger’s Vx Spectra surface multiphase flowmeter.

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deepwater applications, including pipeline surveillance and leak detection, geo positioning, in-well monitoring, subseaassembly-condition monitoring, and per manent reservoir monitoring. The multi application device will include functional and technical parameters configurable in software, thereby avoiding different hardware for settings or functions. The marinization process will require the re-engineering of OptaSense’s existing DAS interrogator unit to reduce its size to fit into a pressure canister (Fig. 6). The modi fied optoelectronics will be tested to ensure that they meet the stringent temperature, vibration, shock, and electrical certifica tions required of subsea equipment. The Subsea-DAS unit is anticipated to be ready for demonstration by mid-2014. ◗◗For additional information, visit www.optasense.com.

Surface Multiphase Flowmeter

subscriptions available.

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TechAppsFeb.indd 28

Schlumberger’s Vx Spectra surface multi phase flowmeter enables operators to obtain flow-rate measurements in pro duction testing and permanent monitor

ing. Vx Spectra technology delivers flow measurements in wider applications than do conventional metering systems, enabling measurements in various flow conditions from heavy oil to wet gas. The new flowmeter uses full gamma spec troscopy to provide the highest accuracy in multiphase-production measurement (Fig. 7). The flowmeter introduces two new Venturi throat sizes adapted to an extend ed range of flow rates. The Vx Spectra 19 mm monitors low-rate producing wells down to 30 B/D, and the 40-mm-Venturi version introduces a midrange multiphase meter with high flexibility to match oiland gas-production flow rates. Modular design configurations offer easy integra tion with operators’ production facilities. To confirm the metrological performance of the Vx Spectra flowmeter, extensive test ing was conducted, acquiring more than 400 test points at four industry-reference flow-loop-metering facilities. Tests were conducted with various fluids and at differ ent pressures and flow regimes. JPT ◗◗For additional information, visit www.slb.com.

JPT • FEBRUARY 2014

1/16/14 10:10 AM

18 manufacturing plants throughout North America.

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Dragon. This is why so many companies in the energy industry choose to do business with Dragon. The company’s expansive inventory and product offering includes a comprehensive line of exploration and production equipment including, tanks, trailers, pumps, and rigs and all the parts that go with them. Dragon equipment delivers exceptional durability under the harshest conditions and in a variety of applications— including well servicing, bulk storage, liquid and solids hauling and many

– Experienced personnel and committed Health, Safety and Environmental Staff

pumping solutions.

Make it happen Production Equipment

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Dragon_004_jpt.indd 1

12/11/13 9:52 AM

TECHNOLOGY UPDATE

‘Smart’ Buoy Could Turn Waves into Platform and Subsea Power Paul Watson, SPE, Ocean Power Technologies

The use of moored, oceangoing “smart” buoys that can harvest energy from waves could be an efficient and economic means of supplying electric power for various offshore oil and gas operations, including well trees, monitoring systems, and autonomous underwater vehicles (AUVs). Potentially, such technology could reduce, or in some cases eliminate, the use of diesel-powered generators on offshore facilities. The PowerBuoy (Fig. 1), developed by Ocean Power Technologies (OPT), is new to the oil industry but has been used for a number of years in the defense and utility sectors. The autonomous buoy system consists of a surface float, a spar containing a power takeoff (PTO), a battery system, and a heave plate that constrains the spar’s motions. The system is capable of delivering energy from a few

Fig. 1—The PowerBuoy converts ocean wave energy into electricity that can power various offshore oil and gas operations, including well trees, monitoring systems, and autonomous underwater vehicles.

TechUpdateFeb14.indd 30

kilowatts to several hundred kilowatts, with future evolution planned to deliver even more power. The process begins with the rising and falling of waves, and the resultant mechanical stroking is converted by a specially designed PTO to drive an electric generator. This power is transmitted to external equipment by means of an underwater power cable or directly to payloads integrated into the structure itself. Continuous power is then available with the option of larger, timed power bursts. Advanced internal control systems continuously monitor the various subsystems and the surrounding environment and optimize performance of those systems with data transmitted to shore in real time, providing health and status updates on itself and its attached payloads. With this information, the operator gains a high level of control. Depending on the model of the buoy, the system is designed to need no maintenance for up to 3 years, providing potential savings in operating and life cycle expenses compared with existing power generation alternatives. Advanced control algorithms have been developed that actively assess oncoming waves to tune the internal PTO dynamically to ensure that it extracts maximum power. In the event of especially large oncoming waves, the buoy will automatically protect itself by locking the float and PTO subsystems and continuing to supply electric power to its payloads by means of the embedded energy storage system (i.e., batteries). The power management system of the buoy manages the state of charge of the battery to ensure

efficient overall system operation and to preserve battery life.

US Navy Project Case Study

OPT established the Littoral Expeditionary Autonomous PowerBuoy (APB) (LEAP) project after being approached by the US Navy, which was trying to increase the coastal monitoring and security surveillance capability of its high-frequency (HF) radar network. To extend the offshore range of the coastal radar system, an APB-350 unit designed by OPT was deployed approximately 22 miles of the US east coast. The HF antenna was mounted on the top of the buoy to transform a monostatic shore-based network by enabling it to operate in a bistatic mode for improved performance. Among the Navy’s specifications for the LEAP project were: ◗◗ Uninterrupted power supplied to the HF radar payload and to communications systems ◗◗ Ability to remain on station in all ocean conditions ◗◗ Mechanical, electrical, and mooring systems capable of surviving defined extreme ocean conditions ◗◗ Dimensions suited to deployment by a US Coast Guard cutter vessel (transportable in a standard ISO 12m shipping container) ◗◗ Deployment for a long period ◗◗ Autonomous operation without a constant need for on-site monitoring and maintenance These requirements guided the design and testing of the APB-350 buoy

JPT • FEBRUARY 2014

1/16/14 8:17 AM

Are you leaving money in the ground? Maximize your investment with Solvay Novecare’s Tiguar® Smart Fluid derivatized guar system At Solvay Novecare, we know your number one priority is ensuring consistently high production over the life of your well. And like most investments, the lower-cost option is rarely the best or least expensive one. That’s especially true for the oil and gas shale plays when designing a fracturing fluid. Solvay Novecare’s Tiguar® derivatized guar delivers: ◗ Flexible design for cross-linked, hybrid or linear gels regardless of water quality or well temperature, enabling optimal fracture geometry design for the reservoir ◗ Cleanest guar-based gelling agents based on viscosity yield, proppant transport capacity and regained permeability ◗ Fast hydration for on-the-fly design even at low surface temperature and poor water quality ◗ Fast break down with conventional breakers ensuring quick well turnaround after fracking and faster payback

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8/12/13 12:38 PM

TECHNOLOGY UPDATE

PowerBuoy

Junction Box

Fig. 2—The diagram shows how the PowerBuoy can be used to provide a security cordon for offshore production operations, with the buoy hosting surveillance equipment.

system, including its electrical, mechanical, and mooring subsystems. The use of the HF radar on the buoy resulted in a major improvement in the resolution and tracking of vessels, with detection ranges doubled. This helped reduce spurious alarms and improve the management of the offshore monitoring and security surveillance. Beyond its communications ability, the robustness of the buoy was tested, including mechanical, electrical, and mooring components. The structure successfully withstood Hurricane Irene, which passed just west of the deployment site. The buoy remained on station despite 29.5-ft significant wave height generated by the storm over 48 hours. However, more notable was that the system remained fully operational throughout to provide power to the payload. A post-hurricane inspection of the structure and mooring revealed no damage. This highlights the technology’s capabilities that could be transferrable to the extreme conditions of the offshore energy sector, such as deepwater and ultradeepwater environments. In the program’s next phase, starting in July 2013, a passive acoustic moni-

TechUpdateFeb14.indd 32

tor for subsea vessel tracking was added to the system.

Oil and Gas Applications

OPT has developed a range of potential applications for the oil and gas industry, including: ◗◗ AUV garages that perform permanent infield monitoring or inspection of assets ◗◗ The control of electric trees for field injection of CO2 and water ◗◗ Environmental monitoring before and after the deployment of offshore drilling and production assets ◗◗ Real-time, on-site field monitoring and sensing systems for 4D reservoir analysis and preseismic and post-seismic deployment surveys ◗◗ Security cordons for offshore developments, in which the buoy serves as a host for surveillance equipment that can track vessels and aircraft and potentially provide early threat warnings (Fig. 2)

◗◗ Temporary navigational markers for surface and submerged structures ◗◗ Diesel power replacement, using the larger PowerBuoy 40 (PB40) system Three of these applications— AUV garages, the control of electric trees, and diesel power replacement— align particularly with current needs in offshore operations.

Prepositioned AUV Networks

Applying the technology as a persistent power source for prepositioned AUV systems alongside AUV garages could enable fast and cost-effective power delivery. Used in this way, the buoy system can hold an advantage over ship-centric AUV systems, especially with the wide areas covered by typical oil and gas fields and the increasingly remote locations being developed. AUV performance is hampered by the vehicle’s need to resurface for recharging, for mission programming, and for uploading post-mission data. Doing so is particularly difficult in sea states higher than 2. Using an AUV garage removes these limitations by providing an in-situ charging

JPT • FEBRUARY 2014

1/16/14 8:17 AM

point and enabling two-way communication between the device and its control point without the need to resurface. Thus, the operator can address minor maintenance issues quickly from the desktop, requiring fewer staff members, and more time is available for addressing major problems that may arise, reducing the risk of production outages. The technology provides ample power for AUV functions and could be scaled up to support larger work vehicles. The system is equipped with a number of on-board communication capabilities, including satellite (Iridium), HF, and Wi-Fi. The stable spar buoy can also accommodate the specialized antennas required to support high-bandwidth systems such as the very small aperture terminal systems used in the Gulf of Mexico.

Electric Tree Power and Control

Electric trees offer the potential for improved control system response and increased reliability compared with similar hydraulically controlled systems. Using the buoy as a power source and control hub potentially avoids a complex and costly subsea umbilical installation. Currently, electric wellheads obtain power through connections with remote surface infrastructure. Use of the buoy system potentially can lower power delivery cost while maintaining equivalent reliability and safety levels. To use the buoy system, it must have sufficient power and a margin of safety to provide safe and reliable operation of the electric tree. The tree is mainly a lowpower system that operates on a fraction of the power used by a subsea pump. The subsea control module has no moving parts, and intermittent bursts of high power are needed to operate valves. Changing the power source to the tree does not increase safety concerns. Nonetheless, because the buoy is on the surface, there is some added risk compared with that of a submerged cable. However, up-to-date navigational aids mounted on the buoy and its marked location on marine charts mitigate that risk. The buoy continuously transmits a “health check” status to operators to alert

JPT • FEBRUARY 2014

TechUpdateFeb14.indd 33

them of incidents or failures. The buoy is designed to include a high-integrity shutdown mechanism. To ensure that a communications failure does not lead to a buoy power failure, the buoy has a failsafe closure signal that will be transmitted to the tree if a reset signal is not received from the control center within every 4-hour period.

Diesel Power Replacement

Diesel generators are the most common source of electrical power in the offshore operations market, but their use comes at a price for the fuel and its delivery to the facility. To meet the needs of an unstaffed platform with PowerBuoy technology requires the PB40 system. The system, which delivers 40 kW of power and can be scaled up to deliver 80kW, is being prepared for a trial off the north coast of Spain as part of the Waveport project funded through European Commission’s FP-7 research and development program. The buoy system can connect to a platform’s uninterruptable power sup-

ply by means of an underwater cable to supply power that will support diesel generators and thereby significantly reduce operational costs. The resulting dual power source ◗◗ Greatly reduces diesel generator use and fuel consumption, extending generator life. ◗◗ Reduces maintenance and the associated staff needs, transportation, and operational downtime. ◗◗ Increases the redundancy and enhances the safety of the power system. ◗◗ Reduces the environmental impact of platform operations. As the technology evolves, larger systems being planned could further reduce or eliminate diesel generator use and reduce capital and operating expense, which could especially benefit marginal production facilities. JPT

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1/16/14 8:17 AM

YOUNG TECHNOLOGY SHOWCASE

Fiber Optic Feed-Through Packer Technology Assists Multizone Fracturing and Production Monitoring Fiber optic pressure and temperature (P/T) sensing technology for multizone fracturing and production monitoring is enabled by a new feed-through (FT) technology that integrates the optical fiber within the multiple elastomer elements of a compact, swellable openhole packer system to achieve competent zonal isolation. It is important that a continuous length of optical fiber be installed across the multiple zones isolated by the swellable packer system. Splicing the fiber is problematic because the process is time c4onsuming, and the splice point degrades faster than uncut fiber. Over time, the splice presents a weak point that can limit system life. This is compounded in long, multizone completions that may require as many as 40 isolation points along the well. Weatherford’s Fraxsis FT technology facilitates deployment of continuous lengths of optical fiber across multiple zones as part of a modular pack-

er system made up of short (24-in.) swellable elastomer sections that provide high-pressure zonal isolation. The FT technology is also a key enabler in the development of a faster, spoolable fiber deployment capability. Fiber optic monitoring of a fracture stimulation and the resulting production across every stage of the completion provides engineers with the information to improve stimulation and completion design, and optimize production over the life of the well. The FT technology enables fiber-optic monitoring using a proven packer technology that achieves high-pressure zonal isolation with a much shorter inflatable element, which reduces packer stiffness and makes the system easier to run.

Technical Details

The FT packer design is based on a modular approach that uses single or multiple swellable elastomer elements to create isolation points for the comple-

Fig. 1—Fiber optic feed through enables data collection in multizone completions when using a modular packer system made up of 24-in.-long elements.

YoungTechFeb.indd 34

Editor’s note: If you have a new technology introduced fewer than 2 years ago and would like to highlight it in Young Technology Showcase, please contact JPT Editor John Donnelly at jdonnelly@spe.org.

tion (Fig. 1). Each element incorporates a proprietary metal backup system to achieve a higher pressure rating with less than half the length of a conventional swellable packer. The metal backup system expands concurrently with the elastomer to prevent extrusion of the rubber element and form a higher pressure seal. Depending on the completion’s pressure requirements, 24-in. elastomer sections are added to the packer system to achieve 1,500 psi (one element), 3,000 psi (two), and higher-pressure specifications. As a result, the technology allows a packer only 7 ft long to seal up to 5,000 psi with the same hole-conformance of traditional swellable packers. The base module is a 24-in. packer element with exposed back-up rings. Specifications for the initial 6.25-in. hole-size packer include a 4.5-in.-OD mandrel, 5.65-in.-OD element, and 5.75‑in.-OD gauge. A 5.5-in. open hole size is planned. The new FT technology feeds two ¼-in. fiber lines through the packer elements: one for temperature sensing throughout the well, and one with integrated pressure gauges to provide pressure measurements along the wellbore.

JPT • FEBRUARY 2014

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Feed-through deployment of the optical fibers is achieved by incising two precise ¼-in.-wide slots approximately ½-in. deep and opposed 180° along the length of the element. The fibers are inserted in these grooves. The cutting process produces an extruded strip of rubber that is approximately the same size as the slot. After the FT slot is incised, the extrusion is retained and replaced in the groove prior to wellsite delivery of the packer. The incision has a rounded profile to help hold the replaced extrusion in place.

Running Process

In the running process, the tool is made up with the string in the same manner as conventional swellable packers. The pre-cut rubber extrusions are removed from the FT slots in the element and the two fiber cables are inserted. The extrusions are replaced and pressed into the slot using a rubber extrusion insertion tool (REIT). The REIT hand tool sets the rubber extrusion in place so that it covers the fiber cables and integrates them within the element. Sets of C-rings that are integral to the metal back-up technology are installed at either end of the element to further secure the fiber FT. Grooves in the C-rings ensure that the clamps provide the optimal pressure against the fibers as they exit the element. Full integration and sealing of the fibers within the elastomer is further enhanced when the elastomer swells and pushes against the formation. Installation time is always a concern with the deployment of downhole monitoring systems. The FT installation requires less than 15 minutes per packer.

Pressure Rating (psi)

Continuous Lines

Elastomer Length

Overall Length

1,500

2¼ in.

24 in.

30 in.

3,000

2¼ in.

48 in.

57 in.

5,000

2¼ in.

72 in.

83 in.

7,000

2¼ in.

144 in.

166 in.

Element Segments

Fig 2—The modular Fraxsis FT swellable packer system was tested in one-, two-, and three-element configurations.

modified V3 ISO 14310 cased-hole standards to achieve a less-than-1% pressure loss over a 15-minute period. The modular system was tested in one-, two-, and three-element configurations. Tests proved that a maximum 7,000 psi can be achieved with a six- element assembly that has a combined elastomer length of 144 in. and an overall assembly length of 166 in. (Fig. 2). Test results showed that the FT process of incising and replacing the rubber extrusion avoided any communication along the fiber FT channel. There was

no leak path and the FT incision healed competently when the extrusion was replaced and swelling took place. The trials occurred during a standard 3-week period for swell-testing procedures.

Field Deployment

The success of the tests proved the tool was ready for field application and it is currently pending initial commercial deployment. Plans include manufacture of a 5.5-in. openhole tool, and completion of the development of a spoolable fiber system enabled by the FT capability. JPT

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Testing

Successful testing of the FT packer system was completed in October 2013. The testing process applied the same standards used for conventional openhole packer designs. An oil-actuated, H4WON elastomer with a maximum 300° bottomhole temperature was used in the initial tests. Pressure was applied alternately to each end of the assembly according to

JPT • FEBRUARY 2014

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www.hardbandingsolutions.com hbs250@hardbandingsolutions.com

1/16/14 12:51 PM

TECHBITS

First SPE Workshop-Webinar Held on Waterflooding The Technical Aspects of Waterflooding workshop held 23 October in Long Beach, California, was the first SPE event to involve both live participants and members participating around the world through a real-time video feed. The workshop drew more than 70 participants from various companies and organizations, including Occidental, Signal Hill Petroleum, Berry Petroleum, Santa Maria Energy, Termo, Spec Services, the California State Lands Commission, SPE board members, and students from the University of Southern California and California State University of Long Beach. The workshop was held by the SPE Los Angeles Section and the oneday live webinar by SPE. Following are highlights from the workshop. When Water and Oil Mix Abbas Firoozabadi Water and oil sometimes mix due to formation of certain structures known as emulsions, small droplets of water in oil or small droplets of oil in water that add surfactants. Some complex molecules in oil may cause formation of emulsions without adding surfactants. Emulsions in production facilities are well known. Functionalized molecules are added in small quantities to separate oil and water. The formation of water-in-oil emulsion in the reservoir is very undesirable because of the high increase in viscosity and low recovery. Oil-in-water emulsion formation is desirable for improved oil recovery. The talk centered on mixing of oil and water when water-in-oil emulsion is formed. Extensive results from laboratory core flooding were presented to demonstrate that when water-in-oil emulsions are formed from the contact of

TechbitsFeb.indd 36

water and oil, the flow has many complexities. These include pressure decrease in the core at high injection rate and substantial pressure increase when water enters the core. To alleviate the problem and recover oil from the conditions in which water and oil mix, the best option is addition of small amounts of functionalized molecules that invert the waterin-oil emulsion to oil-in-water emulsion. Waterflood Management and Surveillance Ganesh Thakur This presentation illustrated how practical application of surveillance and monitoring principles are key to understanding reservoir performance and identifying opportunities that can improve oil production and ultimate oil recovery. Implementation of various principles recommended by industry experts were presented using examples from fields currently in production. Examples of how to process valuable information and analyze data from different perspectives were presented in a methodical way on the following bases: field, block or zone, pattern, and wells. A novel diagnostic plot, called the ABC Plot, was presented to assess well performance and identify problem wells for the field. Results from the application of these reservoir management and surveillance practices in a pilot area were shared, indicating that the nominal decline rate improved from 33% to 18% per year without any infill drilling. The change in the decline rate was primarily attributed to effective waterflood management with a methodical approach, employing an integrated multifunctional team. Although the suggested techniques can be applied to any

oil field undergoing a waterflood, they are of great value to mature waterfloods that involve significant production history. In these cases, prioritization is a key aspect to maintain focus on the opportunities that can add most value during the final period of the depletion cycle. Waterflooding Process and Design Abdus Satter Waterflooding as a process is the most widely used post-primary recovery method in the United States and contributes substantially to current production and reserves. Waterflooding consists of injecting water into a set of wells while producing from the surrounding wells. It maintains reservoir pressure and displaces oil from the injectors to the producers. Waterflood recovery efficiency=displacement efficiency within the volume swept by the water×areal sweep efficiency×vertical sweep efficiency. Displacement efficiency is affected by rock and fluid properties, and throughput (pore volume of water injected). Areal and vertical sweep efficiencies are affected by flooding pattern types, mobility ratio, reservoir heterogeneity, and throughput. Waterflood design considerations are reservoir characterization, potential flooding plans, estimation of injection and production rates, facilities design, capital investments, operating costs, and economic evaluation. Satter emphasized the following: Build integrated geoscience and engineering model using available data, simulate full-field primary performance, and forecast performance under peripheral and pattern waterflood drive. Choose peripheral and pattern development cases. Make economic analysis of

JPT • FEBRUARY 2014

1/16/14 2:25 PM

Innovation TM

the chosen cases using waterflood oil recoveries obtained, and capital investments to determine which case would be more profitable. Waterflood on a Chip Baldev S. Gill Microfluidics are used to displace one phase with another in a water-wet prefabricated microchip and the displacement can be seen under a microscope. In Gill’s example, synthetic oil was displaced with deionized water using equipment from a laboratory at the University of Alberta, Canada. In essence, this talk discussed the concept of “reservoir on chip” (ROC). The process includes several steps, from taking a core from a reservoir rock and creating a series of micro-structure images in FIB-SEM and then constructing a 3D model of the reservoir pore space. From this, a pore network is extracted and a realistic 2D pore network is developed from the crosssection of the 3D network. This network is finally etched on silicon and the ROC is developed. A video is developed that highlights when the chip is originally saturated with oil and then a blue dye is introduced with the water velocity to show the displacement efficiency as the number of pore volumes increase. Of particular interest is the entrapment of oil globules around the pore throat network, which highlight the capillary pressure influence on the pore throat size and the bypassing of oil once the water breaks through. JPT

Rheometer

Redefning the Stand-Alone Rheometer The Fann RheoVADRTM Variable Automated Digital Rheometer gives new meaning to the term “stand-alone.” The RheoVADRTM Rheometer can be used in the lab or in the feld, wherever there is a power source. An operator can record test data without a computer or network. Just plug a USB fash drive into the USB port, select a pre-programmed API test, or set up a test and touch the “Record” button. Data is captured in a standard CSV fle.

The RheoVADRTM Rheometer has an illuminated sample cup, an RTD to monitor and record sample temperatures, variable speeds from 0.01 to 999 RPM, and 12 pre-set speeds.

Available Now! Contact your local distributor or call Fann Instrument Company at 1.281.871.4482 for more information. Contact Fann Telephone: 1.281.871.4482 eMail: fannmail@fann.com Web: www.fann.com

Fann Instrument Company Houston, Texas USA

JPT • FEBRUARY 2014

TechbitsFeb.indd 37

RheoVADR 3_4 Approved.indd 1

1/10/2014 3:56:04 PM

1/16/14 1:55 PM

More Carbon Dioxide Means More Oil

But Building On That Can Get Complicated Stephen Rassenfoss, JPT Emerging Technology Senior Editor

arbon dioxide (CO2) injected into oil fields is “the gift that keeps giving.” The description comes from David Schechter, an associate professor of petroleum engineering at Texas A&M University, who is researching whether CO2 can be used to coax billions more barrels of oil from unconventional formations. In the United States, 318,000 B/D of oil production is credited to the injection of 3,443 billion ft 3 of carbon dioxide. That estimate is based on a joint study by the US Department of Energy (DOE) and the University of Wyoming, which forecast that this technique for enhancing oil production

CO2 Projects.indd 38

could nearly double by 2018. That assumes a surge in the amount of CO2 captured from industrial sources to meet the growing demand. Offshore Brazil, carbon dioxide removed from natural gas produced in the Lula field is being reinjected into that reservoir to reduce carbon emissions. It offers a rare test for learning how injecting CO2 affects the output of a young field, and Petrobras has said reinjection will be applied to other large offshore fields. A growing body of evidence indicates that below the aging giant oil reservoirs in west Texas, is a large untapped

JPT • FEBRUARY 2014

1/16/14 7:10 AM

A long line of pipes gathers the flow from wells in a portion of the GLSAU field where CO2 injections are used to enhance production. The field, now owned by Kinder Morgan, has added deeper wells, allowing it to produce from the residual oil zone (ROZ) as well as the main pay zone. Photo courtesy of Melzer Consulting.

layer known as the residual oil zone (ROZ) that could produce billions of barrels if enough CO2 is available to coax crude out of formations with low oil saturations. Some people working to find ways to reduce CO2 emissions see selling CO2 to increase oil production as one of the only currently available methods to financially justify capturing the gas blamed for global warming and store it. The growth potential is strong if a lot more carbon dioxide is available at the right price. “The biggest problem with carbon dioxide is there is not enough of it. There are far more projects than carbon dioxide,” said David Vance, a

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geologist who is a principal scientist at Arcadis. Vance moved a decade ago to Midland, Texas, to become part of a community of people there who are focused on turning what is still seen as a west Texas thing into something far larger. The nature of that vision is on display annually at the CO2 Flooding Conference and at its sister event, the EOR Carbon Management Workshop, both held during the same week in December 2013 in Midland, Texas. The pair of meetings, which go back more than a decade, is evidence of the marriage of necessity that has sprung up between those who see CO2 as a means to greater oil production and those who see oil reservoirs as the only growing option now for long-term CO2 storage. As with many things related to CO2 EOR, the relationship is complicated. Europe’s grand plan to pay to store carbon dioxide as a waste product in saline aquifers sunk with the carbon credit market, where the cost of buying the right to emit CO2 has dropped to around USD 5.50/t, far less than the cost of pumping it into a deep aquifer forever. Those using CO2 to enhance oil production will pay far more for the gas, giving them a strong motivation to ensure a valuable commodity does not escape into the atmosphere. At the Midland conference, speakers played up how CO2 EOR can be used to pay for carbon capture, utilization, and storage (CCUS). It is a positive environmental message, but convincing environmental regulators that injected carbon dioxide will remain stored in the ground permanently, is a problem to be solved. The US Environmental Protection Agency has developed a permitting process for long-term CO2 storage (Class VI), which is likely to be needed for facilities capturing CO2 to meet emission limits on the gas. To do that, they will need to prove it has been secured in an underground formation where it will remain. But operators fear large added costs and long-term liabilities if the agency requires a mass migration by those conducting CO2 EOR using a Class II permit to the new standard, said Michael Moore, executive director of the North American Carbon Capture and Storage Association and the organizer of the EOR Carbon Management Workshop. On the supply side, the US government is supporting the search for greater supplies. The US Geological Survey (USGS) is working on its first national survey of technically available natural CO2 resources, said Peter Warwick, research geologist at the USGS. It recently completed a survey of CO2 storage space in the US. What it found suggested underground capacity is not likely to limit storage. The US DOE is backing research into potential sources of manmade CO2 and supporting industrial installations to

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CO2 PROJECTS

This map shows the expected footprint of the ROZ (light blue) in the Permian Basin. This extremely slow moving, oily aquifer runs beneath and between the major San Andres oil fields in west Texas. The map is based on data from wells drilled through the zone showing hydrocarbons were present but at saturations too low for production without EOR methods. This work was funded by the Research Partnership to Secure Energy for America (RPSEA). Map courtesy of Melzer Consulting.

demonstrate that it can be captured in industrial plants. It is also backing research to increase the effectiveness of CO2 EOR. Gas supplies from industrial facilities are expected to rise from fivefold to sevenfold over the next 5 years. “CO2 is a nice business that is going along well. But, now we are starting to think about the next phase of CO2‑driven production, and we do not have the CO2 to do that,” said Chuck McConnell, executive director of the Energy and the Environment Initiative at Rice University and former assistant secretary of energy for fossil energy at the US DOE. He said, “Punching more holes in the ground is not the strategy for the next phase of the CO2 business.”

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The USD 40 Limit There is a giant supply of manmade carbon dioxide, but much of what comes out of smokestacks is mixed with other gases such as nitrogen, noxious chemicals such as mercury, and particles of soot. The cost of extracting pure CO2 from that mix using current technology typically exceeds what the oil industry is willing to pay. That challenge was summed by one long-term attendee to the CO2 conference, who said the message offered every year is “Carbon dioxide works. We need more of it. And we are not going to pay more than USD 40 a ton.” The creator of the conference, Steve Melzer, founder of Melzer Consulting, said those three themes are a given but he is seeing signs of significant change.

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CO2 PROJECTS The use of manmade (anthropogenic) CO2 is expected to increase fivefold by 2020, according to Vello Kuuskraa, president of Advanced Resources International, who presented its region-by-region analysis of CO2 use at the conference. By 2020, gas from industrial sources will nearly equal the supply from natural ones, he said. Every North American region he looked at is expected to grow rapidly in terms of CO2 use and production. The traditional center of the business remains the Permian Basin in west Texas, but that area’s dominant position in CO2 EOR is expected to erode as others grow faster. By far the largest expansion is expected on the US Gulf Coast, where low-cost US natural gas is stoking a rapid expansion of petrochemical plants capable of also producing CO2 for sale. Supply growth could allow CO2 EOR to move offshore in the US. That could start in the shallow waters of the Gulf of Mexico, where little-used natural gas lines might offer a lowcost supply route; but, the big prize is in the deep waters of the US Gulf of Mexico, Kuuskraa said. The predicted sources of supply vary by region. Industrial supplies are critical in the midcontinent, while drilling in the Rockies could increase production from CO2 fields there. If a large liquefied national gas plant is built in Alaska to export natural gas from the North Slope, the CO2 removed during chilling could be used for enhanced oil projects there. “There are distinct systems for carbon dioxide, and in all of them is a lot of expected growth,” Kuuskraa said. But, in some of those areas where he sees growth, such as offshore, there is a cost gap, he said.

Puzzles to Solve The man who started the conference is at the center of the international network of those interested in CO2 EOR. An engineer at the meeting in need of names for some market research prefaced his request to Melzer by saying, “you are the guy who knows everybody in the business.” That is a testimony to the 19 years Melzer has been at this, and to the relatively small size of this community. For now, what they are doing looks tiny compared with the boom in unconventional exploration. Those visiting Midland for the meeting could see how its landscape was being altered by new offices and equipment yards for companies racing to develop the enormous unconventional shale oil formations nearby in the Permian Basin, such as the Wolfcamp shale. “The shale guys are winning the investment dollars now,” said Doug McMurrey, vice president of marketing and business development for Kinder Morgan CO2. In the Permian Basin, CO2 EOR is competing with shale plays, such as the Wolfcamp, which appeals to investors who prefer projects that break even sooner rather than later.

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A gas separation facility at the Scurry Area Canyon Reef Operators Committee (SACROC) oilfield, where CO2 is removed for reuse and natural gas liquids are pulled out of the stream for sale. Photo courtesy of David Vance.

When oil prices are around USD 100/bbl, the Wolfcamp can offer relatively fast paybacks, despite the high cost of drilling and completing those wells. Those involved in CO2 EOR counter that a well-run project can produce oil for less per barrel than shale and return equal or better profit margins. But it takes years longer to deliver those returns and an operator with the knowledge and experience needed to manage the complex process of alternating between CO2 injection and waterflooding. While shale well production quickly declines, CO2 EOR can provide a return on investment for many years to come, McMurrey said. Tabula Rasa Partners, a young company in CO2 EOR with private equity financing, has bought CO2 reserves and is working on four CO2 flooding projects in west Texas. “We feel it is important that we have a foot in both the CO2 and the EOR worlds. What we find is there are a lot of opportunities out there,” said Tracy Evans, chief operator officer at Tabula Rasa, who previously filled a similar position at Denbury Resources, one of the largest operators in CO2 supply and EOR. Evans said CO2 EOR developers need to seek out longterm investors. And he said production generated using

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CO2 PROJECTS

Towers once used to refine oil are now used for the last stages of gas separation at Kinder Morgan’s SACROC unit. These perform the last steps of the process that separates natural gas and gas liquids from CO2, which is reinjected into the unit. Photo by Stephen Rassenfoss.

CO2 is better understood than the long-term outlook for production from shale formations. “The risk-adjusted rate of return on EOR is as attractive as shale,” Evans said. And Tabula Rasa’s goals include exploring a frontier with some significant upside—the ROZ.

Next Generation For those in carbon dioxide injection, the ROZ has been their moonshot. This zone, which is also called the transition zone, lies below the main pay zones that once held far higher concentrations of oil. The ROZ looks appealing now because it can be up to 400 ft thick and the oil found in it (20% to 40% saturation) is comparable to what is left in the main pay zones after decades of production. Operators are beginning to explore the ROZ, hoping deeper wells into the zone can extend the life of old fields. In the process, they are testing whether the ROZ extends beyond the limits of the fields.

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The Seminole San Andres Unit, operated by Hess, was redeveloped to tap the ROZ. In a presentation at the conference, Hess said it has 30 injection and production wells in the ROZ and 80 in the main pay zone. It deepened some wells to limit the cost of new drilling and injected only CO2 for 2 years in the ROZ. Results of the project were described as positive. When asked for ROZ production numbers, Chad McGehee, team lead for well servicing at Hess, said determining production by zone is difficult because CO2 travels vertically from one to another, adding that the company does not disclose such detailed production information. However, he did say that the ROZ there extends beyond the boundaries of the Seminole. That comment supports the theory that the residual oil zone exists well beyond the boundaries of the fields. Those working on ROZ research describe it as Mother Nature’s waterflood because they say the aquifer moving at approximately 1 ft every 1000 years

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ultimately swept much of the oil out of the thick reservoir, leaving behind a permeable carbonate reservoir with a low oil saturation—20 to 40%—comparable to what remains in the primary production zone above it after decades of waterflooding. If that is so, it could offer a new frontier for production between fields using CO2 EOR. The US DOE has backed a study by a team associated with the University of Texas of the Permian Basin, led by Melzer, to study the ROZ and create reservoirmodeling tools to understand it better and produce oil from it. Melzer’s current best estimate is 28 billion bbl in the ROZ beneath conventional reservoirs in the Permian— called brownfield ROZ. “If we are good at what we do, we can get one-third of it,” Melzer said. They are now working on an estimate of the total resource in the Permian, but the potential in the large areas between fields looks huge. It is difficult to pin down because no one has ever drilled a successful well in what is known as the greenfield ROZ. Melzer said that could double or triple the total resource.

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And the ROZ may well be found in other regions because the geological factors found in the Permian are found in other oil-producing regions, such as the Rockies. Given the amount of CO2 needed, they would ideally be located near large industrial sources of CO2. It is a vision that has entailed years of work mapping the ROZ from data from past projects that looked at, and often drilled through, the zone. Melzer hopes to see greenfield ROZ drilling in the next few years. As with many things to do with ROZ, it is a complicated pursuit that will depend on finding more carbon dioxide. “It will inevitably have a lot of moving parts when selling and financing a project,” Melzer said. It will require “getting engineers to speak the same language as financial people and vice versa.” “An awful lot of stuff we do relies on multiple processes and finding markets for a couple products,” he said. “If we can bridge that gap, we can see large volumes (of CO2) come into the market.” JPT

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CO2 PROJECTS

Carbon Dioxide: From Industry to Oil Fields

he lifespan of a huge, old oil field in Oklahoma is now linked to a fertilizer plant 68 miles away. Chaparral Energy is capturing 45 million ft 3/D of carbon dioxide (CO2) that had previously been vented into the atmosphere in Coffeyville, Kansas, compressing it, and sending it via a pipeline to the Burbank field in Osage County, Oklahoma. If the USD-250-million project works as planned, Chaparral will revive a field that looked to be near the end, with wells producing more than 99% water, adding a projected 80 million bbl more of oil production. This is the biggest project for the company that is filling a hole in the CO2 supply map in the middle of the United States by building a CO2 supply system based only on industrial sources for enhanced oil recovery (EOR). Chaparral’s 380-mile long system connects three fertilizer plants and an ethanol plant with fields where it has EOR projects. The goal is a longer life for marginal oil fields, said Keith Tracy, director of CO2 Midstream at Chaparral. “We have dozens of additional fields on the drawing board.”

A worker coats metal that had been left exposed for welding. Carbon dioxide is now flowing through the pipeline built by Chaparral Energy to supply an enhanced oil recovery project at the North Burbank unit in Northeastern Oklahoma.

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Those plans depend on finding more CO2. For Chaparral, and for the industry as a whole, industrial sources appear to be the most promising growth option. A nearly sevenfold expected rise in CO2 captured from industrial waste streams is expected to account for more than half of the 86% increase in US CO2 supplies over the next 5 years, according to a study by Phil DiPietro, strategic planner at the National Energy Laboratory of the US Department of Energy (DOE), and Glen Murrell, a research scientist at the Enhanced Oil Recovery Institute of the University of Wyoming. “They (Chaparral) are the company that looks like other companies will look like over time,” in CO2 EOR, said Michael Moore, who led the CO2 EOR Carbon Management Workshop and leads the trade association representing those doing conducting CO2 EOR, the North American Carbon Capture and Storage Association. The now small supply of CO2 for EOR from man-made sources—anthropogenic CO2—is expected to grow far faster than natural CO2 , which is produced in nearly pure form from wells tapping ancient volcanic sources. By 2020, the two sources are projected to be equal, but a lot of work and innovation will be required to turn that potential into a reality. The biggest source of industrial gas growth is said to be the US Gulf Coast, where there is a wave of petrochemical plant expansion aided by low US gas prices, said Vello Kuuskraa, president of Advanced Resources International, a geology and engineering services firm that makes regional CO2 EOR forecasts. The study looked at existing and planned facilities with CO2 as a byproduct along Denbury Resource’s Green Pipeline, a pipeline that runs past the many refining and petrochemical plants along the coast of Louisiana and southeast Texas. The pipeline handles both naturally produced CO2 from the Jackson dome in Mississippi and gas that is a byproduct of plants along the coast. “There is huge growth expected in the Gulf Coast,” Kuuskraa said. “That is the vision and the direction that this industry is headed.” Growth in industrial CO2 supplies is also predicted in the midcontinent area, where Chaparral began injecting gas last June into the North Burbank unit, which is where the mineral rights are held by the Osage Indian tribe in northeastern Oklahoma. Chaparral’s plan predicts that

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CO2 PROJECTS Key

Potential Natural CO2 Source Natural CO2 Source NG Processing Source Conversion Source CO2 Pipeline CO2 Pipeline planned

2.5 MMscf/d 150 MMscf/d

“There is a massive resource identified in mature oil fields that can take more CO2. The trick is more CO2 ,” Moore said. “In all cases, the next path for CO2 growth is captured CO2.”

No Easy CO2

The biggest potential industrial source of the carbon dioxide by far is coal-burning power plants. It is also one of the more expensive sources. 150 MMscf/d The price is commonly estimated at twice or more than the USD-40/ton price commonly cited as the highest ENHANCED OIL RECOVERY INSTITUTE 1,800 MMscf/d operators can afford for EOR, based on little experience. 950 MMscf/d TOTAL 3,453 MMScf/d Most of what is used for EOR now is from wells producing nearly pure CO2 , which are concentrated Key either in the US Rocky Mountains Potential Natural CO2 Source Natural CO2 Source or in the southern state NG Processing Source Conversion Source of Mississippi. CO2 Pipeline CO2 Pipeline planned Active drilling programs by 75 MMscf/d the two largest CO2 suppliers, 200 MMscf/d Denbury and Kinder-Morgan, are also expected to increase the amount from natural sources because supplies are limited 10.5 MMscf/d 700 MMscf/d for their customers and their 330 MMscf/d EOR projects. “We had some pro-rationing earlier this year (2013) in the 25 MMscf/d M f/d Permian Basin,” said Doug McMurrey, vice president of marketing and ENHANCED OIL RECOVERY INSTITUTE business development for Kinder Morgan CO2. It is drilling CO2 wells 2,200 MMscf/d to increase its already high levels of deliveries in West Texas. Kinder Morgan sells 60% of Projections of CO2 supplies show strong growth in regional pipeline supply its CO2 to customers and uses the systems, according to a study by the US Department of Energy and the Enhanced Oil Recovery Institute of the University of Wyoming. rest for its EOR operations, making it a major oil producer in Texas. And when there are curtailments, McMurrey said, Kinder Morgan’s fields are treated the same adding CO2 will push production there from 1,200 to as third-party buyers. 12,000 B/D, according to a company presentation. The CO2 EOR business was built using reserves found The company, which also develops unconventional oil reserves, projects that CO2 EOR projects companywide will and developed decades ago during the oil boom that ended in the early 1980s. The cost of bringing on a new generation of grow from 4,000 B/D now to more than 35,000 B/D in 2020. CO2 wells is forcing users to consider whether they can live Its growth requires finding industrial sources near fields where CO2 injections are likely to be effective. The economics with higher carbon dioxide prices. “All the sources are more expensive than in the past,” of CO2 EOR put a strict ceiling on how much operators McMurrey said. This is causing resistance. He said there have can afford to pay for the gas, which limits how far it can been customers who claimed to be “desperate” to find more be shipped.

390 MMscf/d

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10.5 MMscf/d

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Pipe is laid along the 68-mile line from Coffeyville, Kansas, to Osage County, Oklahoma, that is now delivering carbon dioxide for an enhanced oil recovery project by Chaparral Energy.

carbon dioxide who said they could not sign a deal when they saw the terms.

Big, Costly Supplies The biggest sources of smokestack CO2 are ones where the carbon dioxide is mixed with gases no one wants to inject in an oil field, requiring separation methods that are costly and have been little used in power plants. To show that it is possible and how much largescale operations actually cost, the US DOE has funded demonstration projects. There are proven methods for separating carbon dioxide from industrial emissions, but the cost is often an issue. One of the larger grants went to Air Products to retrofit a unit supplying hydrogen to a Valero refinery in Port Arthur, Texas, to capture CO2. After two steam/methane reforming gas modules were replaced, the unit now is able to capture 90% of the CO2 produced in the gas-separation process. During its first 6 months of production, it produced 500,000 tons of carbon dioxide, which it delivered to Denbury’s Green Pipeline. Government support covered USD 284 million of the USD 431-million cost, which included a 30-MW unit to power the operation. “This process does not make sense without

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DOE support,” said John Palamara, development manager for research and development at Air Products and Chemicals, in a presentation at the conference. In Kemper County, Mississippi, a coal-fired power plant being built by Southern Company will be equipped to capture nearly two-thirds of the CO2 , which will be used for EOR. It also will produce and sell ammonia and sulfuric acid to help offset the cost of CO2 capture. Capturing carbon dioxide means the plant would emit less of it than a natural-gas-fired plant, which would put it under the emission limits proposed by the US Environmental Protection Agency for new coal plants. But this demonstration, backed by USD 270 million from the US DOE, has become a cautionary tale. The electric utility developed and tested the technology, but budget overruns have pushed up the cost of the plant, coal mine, and pipeline to an oil field by USD 1 billion to USD 4.45 billion. Its opening date has been delayed until late 2014. When asked about the overruns in an interview posted on Southern’s website, Tom Fanning, chairman and chief executive officer at Southern, said the budgeted cost was calculated early in the engineering process and only a 6% contingency was built in. Based on the cost per kilowatt

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CO2 PROJECTS He has counted 18 projects in North America that could capture industrial and supply it for EOR. His goal is a DOE strategy backing development of methods to lower the cost of CO2 capture from industrial sources and allow operators to produce more oil per ton of CO2 injected.

CO2 Next

These compressors increase the pressure of carbon dioxide captured from a fertilizer plant in Coffeyville, Kansas, from 1 to 2000 psi before it is moved through a pipeline to a field 68 miles away.

hour of generating capacity, this plant could make sense in international markets where power costs significantly more than it does in the US, he said. Another clean coal project, the Texas Clean Energy Project, has yet to begin construction. The plant in west Texas being developed by Summit Energy Group will use nearly half the 400-MW generating capacity to capture all its CO2 and turn it to make salable commodities. It will sell some of the gas for EOR and use the rest to make urea, which is used for fertilizer. The process also removes sulfur, which the plant will use to make sulfuric acid to sell. The project is supported by USD 450 million from the US DOE plus more than USD 673 million in tax credits—plus promises from state and local governments to reduce future tax bills. As of yearend, Summit was still working on closing deals needed to begin construction, which was likely to continue in 2014, said Chris Tynan, vice president of project finance for Summit Power. Among the loose ends were final agreements with China’s Export-Import Bank and Sinopec, which are among the backers. The surge in hiring related to the rapid rise in unconventional exploration in the sparsely populated region around Midland has pushed up the price of the plant. “The boom in the Midland economy has caused labor prices to increase. We are trying to navigate that at this time,” Tynan said during the CO2 conference. Meanwhile, the US DOE is looking for ways to capture relatively clean streams of the gas that come from certain types of plants, such as those removing carbon dioxide from natural gas or makers of ammonia or ethanol. “I think there is a good opportunity there,” DiPietro said. “There are early opportunities up and down the Gulf Coast” to add new industrial CO2 sources.

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The enormous potential market for CO2 is attracting innovators with ideas about how to close the price gap. In mid-December, former US Energy Secretary Michael Chu became a board member for Inventys Thermal Technologies, a Canadian company with a method using a ceramic material that it says can capture CO2 for about USD 15 a ton. When other costs associated with compressing and delivering carbon dioxide are added, a company release said the price per ton could be from USD 40 to 50, which is near what is considered affordable for EOR. The company said it has yet to demonstrate it can do this in a large-scale test. A group of technology developers from GE Research, working on lower-cost CO2 capture methods, also was at the CO2 conference. Some companies at the conference presented ideas for using natural gas to create CO2. For these processes to be affordable, they must also produce power and sell it at a good price. One innovator on hand was Robert Zubrin, the chief executive officer of Pioneer Energy. The company was created to commercialize its Portable Enhanced Oil Recovery Technology, which turns natural gas into CO2 and hydrogen, which then can be used to generate electricity for sale on the grid. The initial target audience for its units, which will be able to produce 500 Mcf/D of CO2 , will be operators conducting field tests who now rely on tank trucks, which are expensive. For the process to be cost-competitive, Pioneer needs to be able to sell power for about USD 0.06/kW-hr, Zubrin said. Maersk has licensed another technology that, like Pioneer’s, has roots in the space program. Its Trigen system burns natural gas with pure oxygen to produce CO2 , electricity, nitrogen, and water. It can use low-quality field gas associated with oil production, which could reduce flaring. “You can get to below USD 40/ton for carbon dioxide if you can get a reasonable power price,” of from USD 0.07–0.09/kW-hr, said Pieter Kaptejin, director of technical operations at Maersk Trigen, a venture that includes Siemens. “It changes the way you do upstream.” So far, Maersk Trigen is in talks with a national oil company. A significant problem has been the complexity that comes with negotiating agreements to divvy up multiple income streams among partners. “The whole value chain creates a lot of value,” Kaptejin said. “But how do you distribute it (revenue) is the hard part.” JPT

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CO2 PROJECTS

Carbon Dioxide May Offer An Unconventional EOR Option

s the daily oil output of the Bakken and Eagle Ford formations rose toward 1 million B/D, researchers were seeking a way to push the ultimate recoveries in these formations, where producing 6% of the oil in the ground is now considered good. One line of attack on the problem is using carbon dioxide (CO2) to get more oil from tight formations where rapid production declines are the norm. In laboratories at the Energy and Environmental Research Center (EERC) at the University of North Dakota

This device measures changes in surface tension between CO2 and oil. As the CO2 pressure is increased, the oil level in the capillary tubes drops, indicating reduced surface tension. When the levels are equal, there is no surface tension. The Energy and Environmental Research Center at the University of North Dakota developed this as a lowcost way to predict the minimum miscibility pressure.

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and at Texas A&M University, experiments have shown that carbon dioxide circulated around a small sample of source rock can remove a significant amount of oil. Now, the scientists are trying to understand how it works and if those lab results can be applied in the real world. “It is incredible what CO2 can do,” said John Harju, associate director for research at the EERC, while describing the center’s research program at the annual CO2 Flooding Conference in Midland, Texas. “The really big prize is (overcoming) the innately low recovery rate in these shale plays,” said David Schechter, an associate professor of petroleum engineering at Texas A&M University who is turning his expertise in conventional enhanced oil recovery to unconventional reservoirs. While laboratory results normally show much higher recovery than field results, even a 1% improvement of recoveries in the Bakken formation could yield more than 1 billion bbl of oil, according to an EERC paper. Previous SPE papers, based on reservoir simulation work at Montana Tech of the University of Montana and the Colorado School of Mines, concluded that significant increases in ultimate oil recovery might be possible using CO2 injections. One of the biggest backers of the work in North Dakota has been Harold Hamm, the chief executive officer at Continental Resources, which pioneered unconventional liquids development and is the biggest acreage holder in the Bakken, Harju said. On the basis of early tests using CO2 and similar positive results from using chemical surfactants, Texas A&M is working to recruit support from oil companies for a joint industry project called the Enhanced Oil Recovery in Unconventional Reservoirs Joint Industry Project. Both the EERC and Texas A&M have tested samples ranging in size from Chiclets—square bits of reservoir rock about the size of the popular chewing gum—to small core samples about the size of a disposable lighter. The tests produced significant amounts of oil from samples exposed to CO2 flowing through a test chamber simulating reservoir conditions. In a lab test, the EERC was able to recover 60 to 95% of the hydrocarbon in rock samples from the middle, upper, and lower Bakken, according to a paper on the work (SPE 167200). Researchers were surprised

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How CO2 Might Free Oil From Shale

Researchers at the Energy and Environmental Research Center at the University of North Dakota created this four-step illustration to explain how CO2 might work to increase oil production from unconventional formations such as the Bakken.

Courtesy of the Energy and Environmental Research Center at the University of North Dakota.

to find that the recovery rate at reservoir pressures and temperatures was high for all three layers after 4 days of exposure. The middle Bakken reached that recovery rate faster than the tighter rock in the upper and lower Bakken. The result in the middle Bakken was not surprising because that rock is not as tight as the layers of source rock above and below it. Researchers reported oil recoveries ranging from 60 to 80% from the upper and lower Bakken after longer exposures to CO2. In a test at Texas A&M, a small sample produced 0.4 cm3 of oil, suggesting a potential recovery rate of more than 18% of the oil in the sample. Schechter said testing so far suggests the CO2 is “dragged into the matrix” of the rock. The laboratory there also found that using chemical surfactants produced similar results In conventional fields, injecting CO2 aids production in several ways: by reducing interfacial tension, which loosens the hold of the rock and oil; by lowering the viscosity of the

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oil; and by causing oil molecules to swell, forcing it out of pores in the rock. CO2 is high on the list of EOR methods to try because the options are limited. Many unconventional reservoirs, including the Bakken, are oil-wet, and that attraction between the rock and the oil means waterflooding is very unlikely to succeed, said Ed Steadman, a department director at the EERC. Researchers in North Dakota have begun working to understand how CO2 is likely to act in the Bakken formation. The expectation is that these tight reservoir rocks, where the gas must flow through constricted fracture networks, will act differently than porous conventional formations. “Testing on Bakken rock suggests CO2 ’s benefits will require significant contact time,” said Steven B. Hawthorne, a senior research manager at the EERC. Another question is: What does it take for CO2 to become miscible with oil in shale reservoirs? The conditions at which carbon dioxide is miscible with oil matter because

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CO2 PROJECTS

Production from unconventional formations now depends on fractures created by injecting a high-pressure stream of water, such as at this fracturing job in North Dakota. Researchers there are trying to understand the fracture networks can be created better in search of a way to increase production. One option would be injecting CO2. Photo courtesy of the Energy and Environmental Research Center at the University of North Dakota.

that is the point when it is most effective at getting more oil out of a reservoir. Carbon dioxide floods are engineered to reach the minimum miscibility pressure (MMP)—the level where there is no interfacial tension between the oil and CO2. At the CO2 conference, Hawthorne showed a video offering a view of how CO2 interacts with oil as the pressure rises to where it becomes miscible and beyond. The image of what went on inside a small tube simulating reservoir conditions in the Bakken showed a rising level of activity as pressure increased, suggesting the line between immiscible and miscible could be fuzzier than is suggested by precise calculations of the MMP.

In the Ground All the researchers involved say more work is needed before they can say this will work in the field. “If it contacts the rock enough, under the right conditions, this could work,” Schechter said. Two field tests using CO2 in the Elm Coulee field in Montana in 2009 and in Mountrail County in North Dakota were described by Harju as “not particularly successful.” What has been learned will be applied in two to three tests expected over the next year.

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It could be a long journey. The first two CO2 EOR tests tried injecting carbon dioxide into a field, closing off the well, and then returning it to production to see if the CO2 increased the output. These “huff ’n puff” tests were not successful, which is leading researchers to consider ways to push a stream of the gas through the rock to maximize the surface area and the duration of the CO2 contact. Researchers in North Dakota are considering injecting carbon dioxide inside the oil-rich shale layers that sandwich the middle Bakken—the layer of dolomite that has been the primary source of production there—and the Three Forks, which is also being produced. Finding an effective CO2 EOR method would only be a first step. Applying it widely in a shale play covering half of a state and several adjoining states and provinces would require enormous amounts of carbon dioxide in an area where there is not enough CO2 to flood conventional reservoirs left from the early days of oil production.

Grand Plan Filling those projected needs could alter the economic landscape of North Dakota. Because the state needs more power and has large undeveloped coal resources, one idea is to capture carbon dioxide from new coal-fired power plants.

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CO2 PROJECTS It could generate more power, enhance oil production, create a market for the coal, and emit little or no CO2. It would also make the state a technology proving ground. North Dakota has estimated it would need an additional 2,500 MW of electric-generating capacity in the future, much of it to support growing oil production, Harju said. That is double the state’s current capacity, according to the US Energy Information Administration. That plan could create demand for a less-desirable resource—lignite, which is a low-quality grade of coal that needs to be burned near to where it is mined because it is expensive to ship. Realizing this vision will require reducing the cost of removing CO2 from the exhaust gasses vented from power plants burning coal. Another option would be producing CO2 using the natural gas associated with oil production in the Bakken, much of which is now flared. Either way, the technical risks are large, but so might be the potential returns. JPT

For Further Reading SPE 167209 Long Overlooked Residual Oil Zones (ROZ’s) Are Brought to the Limelight by A Harouaka, B. Trentham, University of Texas of the Permian Basin, and S. Melzer, Melzer Consulting SPE 123176 CO2 Flooding the Elm Coulee Field by Shehbaz Shoaib, SPE, Montana Tech, and B. Todd Hoffman, SPE, DRC Consulting SPE 168915 Geologic Characterization of a Bakken Reservoir for Potential CO2 EOR by Basak Kurtoglu, Marathon Oil Company, and James A. Sorensen, Jason Energy and Environmental Research Center, et al. SPE-167200 Hydrocarbon Mobilization Mechanisms From Upper, Middle, and Lower Bakken Reservoir Rocks Exposed to CO2 by Steven B. Hawthorne and Charles D. Gorecki, Energy and Environmental Research Center, et al. SPE 168774 Hydraulic Fracture Orientation for Miscible Gas Injection EOR in Unconventional Oil Reservoirs by Tao Xu and Todd Hoffman, Colorado School of Mines

2014 SPE International Conference on

Health, Safety, and Environment 17–19 March Long Beach Convention & Entertainment Center Long Beach, California, USA www.spe.org/events/hse/2014

CO2 Projects.indd 56

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Pioneering Subsea Gas Compression Offshore Norway Trent Jacobs, JPT Technology Writer

he world’s first full-scale subsea gas compression system is in the final stages of construction and is on schedule to be installed in the Åsgard gas field offshore Norway by year’s end. Norway’s state-owned oil and gas company, Statoil, says that the project is the largest and most complex subsea development ever undertaken in both size and scope and represents a leap forward for an industry that has sought to produce hydrocarbons ever farther from

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shore for more than a century. With the ability to process and compress gas far beneath the harsh surface conditions of the Norwegian Sea, Statoil envisions a future where surface installations are not required to develop subsea fields. The concept is referred to as the subsea factory, and the company aims to install one capable of producing both oil and gas by 2020. If successful, the Åsgard subsea gas compression project will become the latest milestone in prov-

ing that the company’s ambitious objective is possible. Statoil selected Aker Solutions to design and build the system after determining that a subsea compressor station was economically favorable and had a greater technological potential compared with constructing a semisubmersible platform. By installing a compressor train on the seafloor, “you are closer to the reservoir, which means you can do more with less,” said Svenn Ivar

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In June of last year, Aker Solutions delivered the nearly 4-million‑lbm frame for Statoil’s subsea gas compression system in Norway. The frame is now installed on the seafloor approximately 124 miles offshore Norway. Image courtesy of Aker Solutions.

Fure, Aker Solution’s senior vice president of strategy and business development. “You don’t have to take the gas up to a platform and then pump it down again. That provides a lot of advantages,” he said. Fure also noted that, besides requiring less energy to achieve the same end, a subsea system requires far fewer personnel to maintain and oversee its operation. While subsea facilities do require constant monitoring, it can be done remote-

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ly and with far fewer people than necessary for a conventional platform. This provides the operator with considerable saving in regard to salaries, logistical services, helicopter transportation, catering services, and power generation. And, because no personnel work directly on the system day in and day out, the risk for injury and loss of human life is greatly reduced. Additionally, Statoil and Aker Solutions claim subsea compressors involve a simpler build and installation

process compared with that of a semisubmersible platform.

Boosting Åsgard

To be installed at a depth of approximately 850 ft and scheduled to start up early in 2015, Statoil’s USD-2.7-billion subsea gas compression system will sustain natural gas production from the Midgard and Mikkel reservoirs, two of the largest resources in the Åsgard field. The subsea template will consist of two identical compressor trains producing in parallel and will be used to recover an additional 28 billion m3 of natural gas and 14 million bbls of condensate from the field, equal to 280 million BOE. First production at the Åsgard field, 124 miles offshore Norway, began in 1999. Current production is supported by two facilities, an oil production vessel, Åsgard A, and a semisubmersible, Åsgard B, for gas production. Produced condensate is stored in a tanker, Åsgard C. The decision to move forward with gas boosting was made because Statoil projects that, within the next few years, reservoir pressure will become too low to maintain a steady rate of gas flow, yet a large volume of technically recoverable reserves remain in the field’s reservoirs. Some of the project’s equipment has already been installed on the seabed, including the manifold station that will direct the flow of gas and the enormous steel frame that will protect the compressors. Measuring 65 ft tall, almost 150 ft wide, and more than 245 ft long, the compressor frame takes up almost the same area as a soccer field. Remaining work consists of sailing out two compressor trains later this year and connecting all the pieces for the first time. “We have qualified the components. We have built the components, and now we are starting to put the components together and testing it all as a system,” said Rune Mode Ramberg, Statoil’s chief engineer of subsea technology and operations. “It is a big puzzle that is coming together.” Each train at the Åsgard system comprises approximately 10 different modules that include gas processers, coolers,

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SUBSEA PROCESSING

A worker walks under the steel frame that will house Statoil’s gas compressors expected to come on stream in 2015 and process approximately 740 MMcf/D of natural gas. The company expects the system to ensure production from one of Norway’s largest offshore fields for the next 2 decades and beyond. Photo courtesy of Statoil.

scrubbers, pumps, and compressors. As the gas leaves each wellhead, it travels through a flowline and into a manifold, where it is directed into a larger pipeline that takes the gas into the compressor trains. At that point, the liquids are separated from the gas. The dry gas is boosted using the compressor, and the liquids are pumped to Åsgard B.

Subsea Reliability

To achieve a high degree of system reliability, Statoil commissioned Aker Solutions to build not just two compressor trains, but three. The first compressor train is submerged at a test facility while it undergoes verification testing before being sent offshore. The second compressor train will also be submerged and subjected to testing. The first two trains will be installed at the field, and the third train will be kept onshore to provide Statoil with replacement modules. Ramberg describes the physical process of compressing gas subsea as not too dif-

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ferent from what happens on a platform’s topsides or at an onshore facility. “The big difference is the way the components are put together,” he said. “That is different from what you would have on a platform because (on a platform) we can modify the units instead.” The idea for a subsea system is that, while the critical components of the system are connected together, they work independently of one another, so that, if one module fails, it can be replaced without replacing the entire production train. The design life for the Åsgard compression system is 25 years, and Statoil wants the major components to operate 2 to 3 years before requiring maintenance intervention. Once operational, the compressors will increase pressure to compensate for the steady decline in natural pressure. If one of the trains fails, the other will pick up some of the slack and production can be maintained at up to 70% of the full flow rate. At the onset, only one com-

pressor train will be needed to provide the required amount of compression and boosting capacity.

New Subsea Technology

Because of their proximity to the existing facilities, the 11.5-MW subsea compressors will be powered from the existing generators aboard the field’s oil production vessel, Åsgard A. A new 880ton module with high-voltage electrical equipment has been installed onboard the vessel to run the compressor station. For future discoveries, where there may not be a nearby floating facility to host a power unit, operators likely will rely upon emerging long-distance power transmission technologies to deliver high-voltage electricity from shore-based stations. Among the technologies being put to use in a subsea environment for the first time at Åsgard is the compressor’s rotating equipment. The electrical motors that will turn the rotors are the largest ever installed subsea, and, as the natural gas

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SUBSEA PROCESSING

When the modules are brought online inside Åsgard’s compressor station, they will use approximately 40% less energy on average to operate compared with a platform and will produce approximately half the CO2 emissions. Image courtesy of Statoil.

Statoil’s subsea compression system will be installed almost 25 miles from its host platform, where it will receive more than 23 MW of electricity to power the 20 individual modules inside the system’s protective frame. Image courtesy of Statoil.

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flows into the system, it is compressed by rotor blades elevated and held in place with magnetic bearings. Before Åsgard, Ramberg said that this type of magneticlevitation technology has only been used effectively in onshore and offshore surface facilities where workers can easily access and recalibrate the machines as needed. “We are using a lot of sensors to measure the distance between the rotor and the stator to detect an imbalance in the system,” he said. “If there is an imbalance, the operators can try to avoid problems by manipulating the electromagnetic field.” The concept of producing hydrocarbons hundreds or thousands of feet beneath the water’s surface raises new questions about environmental safety. One of those questions is: How to know if gas is escaping from the system? To address concerns over hydrocarbon leaks, the subsea system at Åsgard is being equipped with environmental monitoring sensors that will use acoustics to detect the sound of gas or other liquids venting into the water. Statoil says that it is “the most sophisticated leak detection system there is.” Other integrity management systems will provide the ability to monitor the various components and their condition around the clock using a highbandwidth fiber-optic communications network to deliver large amounts of data in real time. In the event of a system shut down or failure of any kind, Statoil has an onshore support facility and contracted a specialized vessel to provide immediate support for replacement or repair operations. To reduce the number of moving parts and increase response reliability, all of the subsea compressor’s valves at Åsgard will be activated using an electrical control system instead of a hydraulically controlled system—a notable achievement in itself, according to Ramberg. “This is the first time that a subsea system like this is totally electric,” he said.

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The Åsgard subsea compression project is the culmination of more than 15

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SUBSEA PROCESSING

An artist’s impression of Statoil’s subsea factory concept. The company believes it is on course to achieve an installation of this scale by 2020. Image courtesy of Statoil.

years of subsea research and development by Statoil and its partners, beginning in 1997 with the company’s first installation of subsea pumps. As Statoil pursues the ultimate goal of installing the world’s first subsea hydrocarbon plant, Ramberg noted that the company needs time to gain the experience of operating the subsea compressor at Åsgard as it develops more complex subsea systems for the future. “We are moving step by step toward the subsea factory by increasing the capabilities of each building block,” he said. He added that some of those building blocks included inside Åsgard’s compressor trains were first qualified through

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the Shell-operated Ormen Lange pilot program, of which Statoil is a nonoperating partner. Statoil had responsibility for technical qualification of the Ormen Lange compressors. Ormen Lange is Norway’s second-largest gas field, and, like Åsgard, the field is predicted to begin losing pressure in the coming years. Shell is evaluating whether to build a tension leg platform designed to host more than 32,000 tons of equipment and materials on its topsides or to move forward with a subsea facility capable of the same compression capacity but that would weigh approximately 8,000 tons. In some respects, the Ormen Lange compression project could prove to be

more complex than the Åsgard subsea compressor project. The Ormen Lange pilot system is submerged and operating at a test facility in Nyhamna, Norway. But once a full-scale system is installed, it will be operating at a greater depth of 2,950 ft. and approximately 75 miles from its onshore power source, more than twice the distance between the Åsgard subsea compressor system and its power source. Building upon its experience with both systems, Aker Solutions is working with Statoil, Shell, and others to study the use of subsea compression on greenfield gas projects and to debottleneck existing subsea gas fields. Some of the area’s operators are expressing

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join the best interest in deploying similar systems, including offshore Australia, eastern Africa, India, and west of the Shetland Islands in the North Sea. “The Åsgard and Ormen Lange projects have attracted a lot of attention from international oil companies with similar types of issues,” Fure said. If subsea compression technology is adopted on a wider scale, Åsgard and Ormen Lange projects might prove to be the exception rather than the rule, in regard to their size and volume of gas compression. The industry, Fure said, is looking for more-compact solutions that are lighter and cheaper than the first-generation systems. “Going forward, I think we will see a few of these large projects, such as Åsgard and Ormen Lange are, and a lot the smaller and midsized ones,” he said. To miniaturize current subsea processing technology, more work will be needed to simplify the power units, remove as many parts as possible without losing efficiency, and standardize components to reduce manufacturing costs. Representative of this trend is Statoil’s next compression project at its Gullfaks field, where it plans to install two 5-MW subsea compression units. For this project, Statoil selected OneSubsea to design subsea gas boosters on the basis of technology derived from multiphase subsea pumps. For a full-scale subsea factory to become a reality, Statoil and its offshore partners must combine a suite of technologies that have been qualified through other projects and deploy a system that is fully independent of a surface structure. For areas such as the Gulf of Mexico or offshore Brazil, the systems must be built to withstand the extreme pressures of deep water. In the Arctic, the challenges will involve mitigating the very serious risks posed by ice floes and icebergs at shallower depths. For the concept to work in such an environment, companies likely will have to take the extra precaution of excavating deep pits in which to place the processing components and wellheads to avoid being scoured off the seabed by slow moving chunks of ice. Ultimately, the exact requirements for each subsea factory will be based on field economics. Regarding human resources, Statoil is using the Åsgard subsea compressor project and other ongoing subsea projects not only to qualify the components, but also to train its staff on how to maintain and operate the systems optimally. Statoil also wants to integrate more advanced subsea systems into its normal operations, which it believes will increase its personnel’s familiarity with the technology. Another issue that needs to be resolved is how to increase the capability of subsea oil separation. Subsea bulk separation of oil, gas, and water has been successfully demonstrated by a number of companies but remains a young technology. Subsea factories will require much more sophisticated processing than what is currently available. Statoil is interested in units capable of two and three stages of oil separation to be able to reintroduce clean produced water directly back into the environment without transporting it beyond the field. JPT

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SUBSEA POWER DISTRIBUTION

Developing Long-Distance Power-Distribution Systems Trent Jacobs, JPT Technology Writer

The vision of installing large subsea production facilities in remote offshore locations is today, simply not feasible. The problem is that subsea power systems are not designed to transmit high-voltage electricity to a production facility or pipeline tieback that may be under thousands of feet of water and 100 miles away from the nearest power plant. Today’s subsea power-distribution technology is largely based on alternating-current (AC) technology, which, because of its electrical characteristics, can only be efficiently transmitted across a distance of 90 miles. In most cases, however, the effective distance is much less. On average, subsea tiebacks receive power from a platform or vessel located not more than 10 miles away and, in the case of most subsea processing

systems, even closer. In an AC-supplied system, the flow of electricity alternates back and forth across the transmission line and is the form of electricity most commonly used in homes and businesses around the world. When long distances are involved, AC power distribution becomes a complicated operation and requires a great amount of attention to detail because of the physics involved with voltage regulation. The search for an alternative to conventional AC systems has revealed the need for multiple technological advancements, from pressure compensated electrical switches to highly-conductive cables able to deliver power more efficiently. About 5 years ago, “We were looking at going to farther distances with alternating current instead of direct current (DC)

In 2009, the Research Partnership to Secure Energy for America (RPSEA) and General Electric began a 4-year study to design a long-distance directcurrent-based system that could distribute power to offshore fields more than 100 miles from shore. Image courtesy of RPSEA.

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because most of the equipment we have right now is AC powered,” said James Pappas, vice president of the Research Partnership to Secure Energy for America’s (RPSEA) ultradeepwater program. He said that, after studying the issue, however, it was determined that using AC power could result in a 35% power loss in a 100-mile-long cable because of resistivity and other factors. Not long after that conclusion was reached, General Electric (GE) approached RPSEA with a concept to transfer all the power to a deepwater field with DC and then use a subsea transformer module located within the field to convert some of the power to AC. With this system, the expected power loss over 100 miles could be as low as 25%. “So, if you have AC components, it can convert power to AC for those components, and if you need DC, then it has DC components,” Pappas said. “It all sounds pretty simple until you want to put it in a package and then set it down in 10,000 ft of salt water.” To prove the concept, RPSEA and GE began a 4-year-long project in 2009 to develop the best method of transmitting DC electricity from an onshore or platform-based power plant to a deepwater field located 100 to 160 miles away. A DC solution has the potential to eliminate some of the issues technology developers are expecting to encounter in long-distance AC systems. One of the challenges involved with AC is that, as the positive and negative electrons move back and forth across a power cable, they generate an electromagnetic field. This can lead to malfunctions in electrically controlled rotating equipment, such as compressors. In contrast, the electrons in a DC

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SUBSEA POWER DISTRIBUTION

RPSEA and General Electric’s laboratory demonstration unit of an ultrareliable deepwater electricity-distribution system is a scaled-down version used for verification and testing. Photo courtesy of RPSEA.

cable move in the same direction, which eliminates the risk of creating an electromagnetic field. The simulated deepwater field used in the project was a four-well cluster supported by a number of all-electric subsea components including downhole pumps, seabed pumps, trees, compressors, and a chemical-injection system. “Then, we needed to think about all the controls that go to the well, to the manifold, and to each one of those components,” Pappas said, noting that the power demands for such a system could surpass 80 MW. “A few years down the road, if we have separation, we may be looking at reinjecting water into disposal wells or even seabed disposal if we can reliably get the water clean enough.”

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RPSEA and GE’s USD-5.8-million project concluded in November and resulted in engineering drawings and working mockup units that they believe can be scaled-up. RPSEA now wants to move forward with a full-scale prototype system that can be tested in a subsea environment.

Technology Gaps

The RPSEA and GE project answered many questions, but it also identified technology gaps that must be addressed. Among them is the lack of a proven subsea DC connector, which is needed to provide a reliable connection from a power cable into subsea machines. “One of the things we recognize is that we don’t have enough information on how connector

technology works in that subsea environment,” he said. “So we don’t know what we don’t know.” Because they are exposed to the environment, subsea connections are more vulnerable than the internal components of a subsea system and, in many cases, are the first pieces of critical equipment to fail. To overcome the lack of a reliable solution, RPSEA recently solicited bids to develop a prototype of a subsea connector that can handle high voltages and high pressure. The project’s deliverables include designing a DC wet-mate and dry-mate connector for performance and durability testing. Pappas said that, because of the complexity of what the project is trying to achieve, the DC systems under

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development are nothing like what has been designed thus far for onshore or subsea applications. Another issue yet to be resolved is how to protect a subsea system from power spikes that can occur during transient conditions such as a startup, shutdown, or an electrical fault. If not managed properly, an electrical spike can resonate through the entire system until burning out a component at the end of the line. The large number of electrical systems a spike could flow through inside a complex subsea processing system only adds to the likelihood of a failure. To counter the risk of overloading the electrical system, engineers must develop technologies that can detect and isolate faults and shutdown the subsea system if warranted in time to avoid damage from a power surge. However, not everything in a subsea system can be turned off immediately, such as a compressor, which needs time to dissipate its internal pressure before a safe shutdown is achievable. “It goes beyond the electrical components themselves,” Pappas said. “You have to have the smarts installed so that the system knows exactly what to do in any type of situation you can envision.”

This conceptual design model of a subsea DC wet-mate connector was developed by RPSEA and GE to begin validating a system that can be used to connect subsea equipment reliably to high-voltage power cables. Image courtesy of RPSEA.

is the one that failed, then it could be all for nothing and when you try to reenergize (the power system) you will have the same problem.” Rather than add sensors to the system to tell operators where the fault is, a simpler solution may be to use a remotely operated vehicle to place plugs onto the system’s external electrical connections and run tests to determine where the fault is located. To keep it simple and improve the availability of parts, Hazel said developers of next-generation subsea power dis-

tribution systems are trying to use as few mechanisms as possible. “Every time we have to put something else in, you end up creating a lot more potential problems that could outweigh any possible advantage,” he said.

Pressure Compensation

While there are drawbacks, AC is still the preferred power solution for most subsea projects and developers are looking for more ways to better enable long-distance AC systems using current technology. One of the more promising devel-

Fault Detection

The amount of time and money involved with bringing a subsea power module to the surface for repairs or maintenance increases the need for simpler, more durable designs. In some cases, companies will be able to endure isolated faults on a temporary basis without shutting in production. In other cases, a major fault or a series of faults could force a total shut in of production. According to Terence Hazel, a senior engineer at Schneider Electric who has worked on subsea power solutions and written numerous papers on the subject, faults in electrical equipment are almost certain to occur, but the trick is to know where. “If you know what has to be replaced, you put the replacement module on the boat, retrieve the faulty module and install the new one,” he said. “If you don’t know exactly what module

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A completed subsea switchgear system is ready for testing before being sent to the shipyard where it will be reassembled inside an enclosure capable of handling subsea pressure. Photo courtesy of Schneider Electric.

1/16/14 7:21 AM

SUBSEA POWER DISTRIBUTION

A computer-generated illustration of the subsea switchgear module enclosure. Image sourced from OTC paper 20468-PP.

opments in AC distribution is the Ormen Lange subsea gas compression pilot project underway in Nyhamna, Norway. The pilot system is in a 45-ft deep tank where it is being tested to verify various subsea technologies, including the AC distribution system Schneider Electric designed and built inside the subsea switchgear module. Schneider’s system is using proven technologies to distribute power to the subsea compression station. Upon completion of the pilot operation, the system will be reinstalled in the Ormen Lange field, 78 miles from its power source and at a depth of 2,950 ft. To prevent corrosion, normal air was removed from the switchgear module’s pressure vessel and replaced with dry nitrogen gas, which provides an oxygen-free environment. For depths even deeper than Ormen Lange, Hazel believes that the absence of high-voltage switchgears capable of withstanding ultradeepwater pressures will push companies into building stronger enclosures for power systems. “The downside of using that technology is that you have a higher risk of leaks,” he said. A potential, and theoretically more attractive, alternative to using pressure vessels could be to use pressure compen-

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sated equipment instead, which are typically filled with oil. The problem with that concept is that no one has figured out how to do it with subsea switchgears. “Either you make a very reliable pressure enclosure, or you find someone who can design a circuit breaker that can work in a high pressure oil filled environment,” Hazel said. “The oil majors would be very keen on somebody coming up with that idea.” However, Hazel added that the development of such a technology would have such marginal applications that it could be too costly to develop. And whether gas filled or oil filled, the switch gears and other electrical systems must be proven to be extremely reliable for subsea use.

Nanotube Power Cables

In a separate but related subsea power project, RPSEA subcontracted NanoRidge Materials, a company that specializes in developing nanomaterialenabled products, to develop a prototype of an ultrahigh-conductivity umbilical cable using carbon nanotubes as the conductive element. Originally conceived as a lightweight power solution for aircraft, carbon nanotubes have the potential to become an enabling subsea technology.

Carbon nanotubes are a single atomic layer of graphene rolled into a seamless cylinder many times stronger than steel. If compared to a copper cable of the same length and diameter, a carbon nanotube cable would be only a sixth of the weight, which means smaller and less-expensive vessels could be used to transport and install subsea power cables. “Oil and gas companies have been clamoring for a lighter cable for quite some time, and they see many applications for carbon nanotubes,” said Chris Dyke, a senior chemist at NanoRidge. “Some people are looking at this technology from a strength perspective, and others see it from a lighterweight conductor perspective.” According to RPSEA, a major driver behind the development of carbon nanotubes is that they have the potential to reduce power losses by up to 90% over long distances when compared with AC systems using copper. Delivering highvoltage electricity down a subsea cable with enough capacity to power a subsea facility at distances approaching 100 miles is not an option using copper, but that may someday be possible with nanotubes. As electricity flows through a copper wire, it builds resistance counter to the direction of energy flow, which raises the temperature and correspond-

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ingly lowers the wire’s ability to conduct electricity. Dyke said this phenomenon is known as the skin effect, where the current density is greatest near the surface and diminishes further into the conductor. “If the mechanism of carbon nanotube conductivity is channelization through many 1-nm-in-diameter conductors and we diminish or entirely overcome the skin effect, then the carbon nanotube wire can be 35 to 50% smaller in the diameter with the same power rating,” he said. Or, he added, “We can make the same diameter conductor used in current umbilicals but with decreased resistance at higher frequencies, essentially putting more power down the line.” NanoRidge initially focused on purchasing nanotube materials and extracting fibers using a polymer agent. The company found that the extracted material was a poor conductor of electricity and that it would be more feasible to produce the nanotubes themselves into the desired diameters. Now in the second year of the umbilical program, NanoRidge is yielding positive results in terms of achieving conductive parity with copper but isn’t quite there yet. “We’re at a point now where we are getting 10−5 Ω∙cm resistivity, where the copper is 10−6,” Dyke said. “The goal is to get to 10−6.” As described in a technical report by Nanoridge, to make the nanotube wire, the company uses a custom-built tube-shaped furnace arranged vertically so the end product can be drawn out of the top. A liquid carbon source, mixed with a set of chemical additives, is fed into the furnace, where it undergoes thermodynamic and chemical processes that transform the liquid into a black elastic gel, or aerogel. Inside the furnace, the aerogel is then consolidated into fibers and spun out in the form of a bare conductive cable that is wound onto a spooling system. The take-up velocity is synced to the liquid feed rate so that the product can be spooled up as it is being formed. “The idea is that this is a continuous process where we can make miles of material in a single production run,” Dyke said.

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From there, a polymer jacketing material routinely used on conventional copper wire is applied as a protective measure, after which the cable is ready for testing. In terms of cost, NanoRidge says that its technology compares very favorably with copper umbilicals but is less competitive against aluminum, which is also used in subsea power cables. In the second quarter of this year, NanoRidge plans to produce a mockup power cable and test it under 5,500 psi of pressure. After that, the next step is to produce a power umbilical capable of transmitting three levels of high-voltage electricity. Because they are made of a nonmetallic substance, carbon nanotubes are not susceptible to corrosion. Another advantage carbon nanotubes hold over copper is a longer fatigue life because of the material’s tensile strength. “If you look at the stress/strain curve of a carbon nanotube fiber, necking and strain hardening do not occur as with most metals,” Dyke said. “Also, if you compare the tensile strength of carbon nanotube fibers and copper, 6 GPa and 0.22 GPa, respectively, the carbon nanotube fiber is considerably more tenacious than copper. This allows designers to potentially reduce armoring due to the higher top tension capability,” he said. NanoRidge is also exploring the use of its nanotube cables for wireline and downhole monitoring operations. The company believes that the strength of the material and its high conductivity will allow companies to multitask, using a nanotube cable as a tool and a source of power. JPT

For Further Reading OTC 20468-PP Impact of Subsea Processing Power Distribution: Subsea Switchgear Module—A Key Enabling Component in Subsea Installations by Terence Hazel, Senior Member IEEE. et al. 13OTC-P-1410OTC Ultrahigh Conductivity Umbilicals: Polymer Nanotube Umbilicals by C. Dyke and L.M. Jacobs, Nanoridge Materials, et al.

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MANAGEMENT

Managing SEMS Audits: Past, Present, and Future Greg Gordillo and Lucas Lopez-Videla, Bureau Veritas

Safety and environmental stewardship have always been important priorities for the offshore oil and gas industry. In recent years, serious offshore incidents forced the industry to take a hard look at its processes and procedures for ensuring that every operation is conducted with the highest regard for human safety and protection of the sea, land, air, and animal life. While the majority of offshore operators and service companies implemented plans to continuously improve their corporate safety and environmental standards, offshore operators are now legally obligated to adhere to new regulations. In the US Gulf of Mexico (GOM), the US Bureau of Safety and Environmental Enforcement (BSEE) established Safety and Environmental Management Systems (SEMS) regulations, which companies operating oil and gas and sulfur leases in the Outer Continental Shelf (OCS) must meet with regularly audited safety and environmental programs.

From Recommendation to Requirement

The concept of SEMS was developed in response to the 1990 finding of the National Research Council’s Marine Board that the Bureau’s prescriptive approach to regulating offshore operations had forced the industry into a compliance mentality. Further, the Marine Board found that this compliance mentality was not conducive to effectively identifying all the potential operational risks or developing comprehensive accident mitigation. As a result, the Marine Board recommended, and the Bureau concurred, that a more systematic approach to managing offshore operations was needed.

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In response to the Marine Board findings, the American Petroleum Institute (API), in cooperation with the bureau, developed Recommended Practice (RP) 75-Development of a Safety and Environmental Management Program for Outer Continental Shelf Operations and Facilities. The API also produced a companion document, RP-14J, for identifying safety hazards on offshore production facilities. API RP-75 was published in May 1993 and, in 1994, the bureau published a notice in the Federal Register that recognized implementation of RP-75 as meeting the spirit and intent of SEMS. RP-75 was updated in 1998 to focus more on contract operations, including operations on mobile offshore drilling units. This recommended practice was updated several times in the following decade; a third edition was published in May 2004, which was reaffirmed in May 2008. The Deepwater Horizon accident in April 2010 dramatically changed the regulatory landscape, leading to BSEE’s implementation of the first mandatory SEMS rule for oil and gas operators in the OCS. Also known as the Workplace Safety Rule, it required all OCS lessees to have a well-documented SEMS program in place by 15 November, 2011. On 15 November, 2013 all operators with facilities in OCS waters of the GOM were required to have a SEMS audit. According to BSEE, 84 operators were subject to the November audit deadline, and 72 ended up completing the initial audit. The 12 operators that did not complete the audit were cited by BSEE for failure to demonstrate compliance with the SEMS requirements of the Workplace Safety Rule, 30 CFR Subpart S.

Of the 12 companies that had not satisfied the rule, five were notified by BSEE to halt operations because they failed to provide an audit plan and completed audit report. Those operators were given 3 days to reach a safe point in operations before ceasing activities. While most of the companies were conducting decommissioning activities, the elements of a SEMS program are applicable to all offshore operations. The seven additional companies submitted audit plans but had not yet completed their SEMS audit. Those companies were directed by BSEE to immediately provide a copy of their SEMS program and have the company chief executive officer certify, under penalty of perjury, that the company implemented the SEMS program. Other enforcement measures such as civil penalties could be assessed if operators did not comply with the rules. SEMS compliance calls for these programs to be monitored and, if necessary, updated annually through a comprehensive auditing process that includes submission of an audit plan, a thorough review of all aspects of the program and reporting of audit findings through a formal report to BSEE. In the first round of SEMS audits, companies had the option to conduct these audits internally with their own designated and qualified personnel. BSEE has now expanded the regulation under what is referred to as “SEMS II,” which is designed to enhance existing SEMS programs adding several additional requirements such as employee participation plans, reporting unsafe working conditions, and additional empowerment of field-level personnel with safety management decisions under

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MANAGEMENT Stop-Work Authority and Ultimate Work Authority. For conducting future SEMS audits, SEMS II also requires operators to hire an independent and third-party (I3P) audit firm that is accredited by an organization such as the Center for Offshore Safety. While the operator may use members of its own internal organization on the audit team, a representative of the third-party firm must, at a minimum, lead the audit. Operators now have a SEMS II compliance deadline of 5 June 2015. Many operators are now in the process of evaluating each audit option—a third-party audit team leader supplemented with their own personnel or an audit team fully staffed with I3P personnel—to determine which route makes the most sense for their organization. To answer this question, operators need a solid understanding of what kind of information must be gathered, analyzed, and tracked in the audit and weigh that against the resources they have available to successfully complete the audit. The goal should be not merely passing the audit, but also improving the safety and environmental management system.

Availability of Internal Resources

Operators must assess whether they have adequate personnel to dedicate to the audit process. Operators will have to coordinate with their audit service provider to ensure that the entire audit team meets the guidelines set forth by BSEE that reference COS guidelines published on their website at centerforoffshoresafety.org. The center’s qualification guidelines for third-party SEMS auditors have now been incorporated into federal law under SEMS II. These guidelines call for an audit team consisting of a team leader and two additional members. More team members may be added if the size and scope of the client asset require it. Subject matter experts may be brought in to help assess specific technical processes. While some operators— particularly majors and larger producers—may have the necessary number of experienced personnel to fulfill these

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requirements, they tend to represent a minority share of facilities in the GOM. The majority of facilities are owned and managed by smaller operators that may find it difficult to dedicate personnel to an auditing cycle. In these cases, it may be preferable to completely outsource the audit to an I3P with the necessary number of qualified personnel. Regardless of the option selected, no auditor on the team—either from inside the operator’s organization or from a third party— is allowed to have had any involvement in developing the management system within the past 2 years.

Expertise of Internal Resources

Operators must not only consider the number of personnel they have dedicated to the audit. Additional consideration must be given to the qualifications, experience, and skills of each team member such that they complement those of the I3P lead auditor. Also, the team, as a whole, must fulfill the qualification and experience requirements contained within the COS guidance documents. The original SEMS rule identified 13 program elements to be audited, including management commitment, safety and environmental information, hazards analysis, management of change, operating procedures, safe work practices, training, quality assurance of critical equipment, pre-startup reviews, emergency response and control, incident investigation, audit of management program elements, and documentation/ record keeping. At a minimum, each audit team member must meet a set of rigorous qualification requirements as defined by COS: ◗◗ Deemed qualified or competent as a safety and/or environmental management system auditor in accordance with the I3P’s documented process ◗◗ Has a minimum of 2 years of offshore or related oil and gas industry operations or safety and/or environmental management system audit experience within the previous 5 years

◗◗ Participated in at least three onsite management system audits in the past 3 years as an active member of the audit team, subject matter expert, observer, or as an active management representative ◗◗ Trained in the application of safety and/or environmental management system standards, management system auditing, and audit techniques ◗◗ Completed COS SEMS auditor training In addition to this list, the lead auditor is required to meet additional, more stringent qualification and competency criteria. If any member of the audit team fails to meet one or more of these requirements, BSEE reserves the right to reject the audit plan submitted by the I3P. If an operator decides to conduct the audit with minimal third-party involvement, they must ensure that their internal team is thoroughly equipped and well-versed in how to audit each program element. An accredited third party should not only be able to competently audit these elements, but also provide wider industry experience regarding how these elements are managed in other offshore assets. In addition, large outside auditing bodies must have auditor qualification and competence verification systems that have been in place for many years. These verification systems exist because of the auditing requirements of the International Organization for Standardization and Occupational Health and Safety Advisory Services.

Key Attributes of I3P Auditors

A third-party audit services provider should ensure that each SEMS auditor meets clearly defined prerequisites for education, work experience, training, appropriate knowledge, and skills to expertly conduct all functions of certification and auditing activity. This should be achieved through a rigorous screening and selection process that ensures auditors have the right profile of skills, knowledge, and qualifications to conduct

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audits in a consistent and thorough manner. The screening process at Bureau Veritas includes in-person interviews, technical reviews of each auditor candidate’s work history, competence reviews, verification of management system auditor training completion, and periodic witness audit monitoring.

Unbiased Identification of Potential Improvements

The primary goal of the audit process is to ensure the SEMS program keeps the operation running safely and sustainably. Therefore, the audit team must be committed to continuous improvement built on best practices. The team must be able to identify work functions that are out of date or falling behind with regard to standards requirements, and then provide detailed analysis of any system gaps. If done properly, this drives continual improvement in the asset’s operation and safety record. And if these procedural improvements are captured and shared with other assets as best practices, the operational and safety track record of the entire organization improves. While a SEMS audit team with internal members may be able to drive sustained improvement through their detailed working knowledge of the management system, there is a risk of familiarity with the system leading to an underestimation of risk or lack of perception of gaps in the management system. Too much familiarity may also lead to communication problems in employee safety, as the operator’s personnel are typically so familiar with workplace risks that concern disappears. This can lead to a failure in noticing safety or environmental hazards in the field or in a management system. A fully independent third-party audit team, that regularly conducts audits from one operator to the next, may be in a better position to identify unsafe practices and then leverage their experience from other audits to communicate possible resolutions through industry best practices. An operator’s auditing choice is also guided by changes to the regulatory process. The SEMS II regulations are still

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ManagementFeb.indd 75

relatively new, but they will be updated to reflect changes in offshore technology and processes. While these changes tend to be gradual, the auditor must be aware and up-to-date on how regulatory revisions will impact an operation, and proactively communicate possible resolutions through industry best practices. Finally, an operator must consider which auditing process will move them most efficiently from a “compliance mindset”—conducting the audit because they have to comply with regulations—to a “behavior mindset” in which all personnel perform their work with the goal of minimizing risk. This new mindset also empowers every worker to intervene when they see an unsafe work practice, without fear of reprimand from their superiors. At the end of the day, we as an industry are not meeting the intent of SEMS if we do not reduce both accidents and spills. Regardless of which auditing path they choose, operators realize the im-

portance of maintaining their SEMS programs to not only comply with regulations, but also to ensure the safety and long-term productivity of their assets. As operators have completed the first round of SEMS, it has become apparent there is a need for contractors and service companies to also undergo third-party SEMS audits. One of the primary goals of industry is to generate a standard that the industry can use where one COS SEMS audit, either on an operator or contractor, will be accepted throughout the industry and reduce the replication of audit. There is an opportunity to adopt common language and frameworks throughout the industry to drive improvements in safety management effectiveness. By carefully considering the factors presented above, every company working offshore can make the most informed auditing decision and help drive the industry toward new levels of safety and environmental sustainability. JPT

1/16/14 7:30 AM

TECHNOLOGY

Mike Weatherl, SPE, is a drilling adviser in the global services organization of Hess. He holds a degree in petroleum engineering from The University of Tulsa. Weatherl started his career as a production engineer with Chevron in New Orleans. Over the next 25 years, his career with Chevron included a variety of positions in production and drilling. Since 2004, Weatherl has worked primarily on deepwater projects, first as a drilling advisor at Chevron before moving over to Hess Corporation in November 2007. He is a board certified professional engineer in Texas and a 25-year SPE member. Weatherl has authored several papers and has served as Technical Editor for SPE Drilling & Completion. He is a member of the JPT Editorial Committee. Recommended additional reading at OnePetro: www.onepetro.org. SPE 163957 Practical DirectionalDrilling Techniques and MWD Technology in Bakken and Upper Three Forks Formation in Williston Basin North Dakota To Improve Efficiency of Drilling and Well Productivity by Guangzhi Han, Baker Hughes, et al. SPE 166456 Newtonian Fluid in Cementing Operations in Deepwater Wells: Friend or Foe? by Polina Khalilova, Schlumberger, et al. SPE/IADC 163410 Large-Bore Expandable Liner Hangers for Offshore and Deepwater Applications Reduce Cost and Increase Reliability: GOM Case History by John McCormick, Halliburton, et al. SPE/IADC 163451 A Collaborative Approach for Planning a Drilling-WithLiner Operation by Steven M. Rosenberg, Weatherford, et al.

1DTFocusFeb.indd 76

drilling technology Once again, we find ourselves in a time of extreme challenges on many fronts in the arena of well construction, with corresponding needs for technological advancements. Anyone who has been around the drilling-and-completion world during the past several years can attest to the unique environment in which we operate today. Ever-increasing drilling depths and formation temperatures and pressures are combined with depletion of mature basins and unprecedented geopolitical uncertainty. The good news is that human innovation and problem solving continue to accelerate commensurate with these challenges. In this feature, we specifically highlight the persistent need for high-performance drilling fluids. Back in the early 1980s, when I started in the business, in-house “Drilling Engineering 101” courses with a major operator defined three primary objectives for a drilling fluid: (1) hydrostatic pressure for well control, (2) delivery of hydraulic horsepower to the bit, and (3) adequate rheology for hole cleaning. Of course, these criteria must still be satisfied or the ability to deliver a given well to total depth is jeopardized. However, today there is much more to consider: wellbore strengthening in low-fracture-gradient environments, special fluid systems for narrow porepressure/fracture-gradient windows, low toxicity for safety and environmental consideration, nondamaging water-based drill-in fluids, and wide-ranging formulations for nonaqueous systems. The wealth of available SPE publications provides a fantastic resource for the vast array of drilling-fluids strategies today. With the ongoing evolution of managed-pressure drilling, companies are expanding the envelope of technical feasibility and successfully constructing wells thought to be undrillable a few years ago. Onshore US and in many other areas of the world, another revolution is taking place in the realm of directional drilling, with new tools and techniques for rotary-steerable applications, measurement/logging while drilling, and bits. These technological advancements are profoundly altering the energy outlook through horizontal and complex-directional-well design, with corresponding delivery of reserves and value. And, of course, unprecedented advancements have been made in zonal isolation, cement-slurry design, and cement-placement techniques. Starting with clearer definition of permeable zones in the planning phase, operating companies, working in partnership with third-party service providers, are demonstrating the ability to hydraulically isolate water- and hydrocarbon-bearing formations, greatly enhancing well integrity and reliability and reducing risk for the life of the well. Good news indeed for all of us. JPT

JPT • FEBRUARY 2014

1/16/14 7:45 AM

ECD-Management Strategy Solves Lost Circulation Issues

rilling horizontal infill wells in the Pierce field in the UK central North Sea is challenging because of a narrow drilling window caused by depletion in a highly fractured reservoir. Wellbore strengthening was attempted in the reservoir section of Pierce B5 although, when a pre-existing fracture further weakened by depletion was encountered, losses occurred. A detailed analysis of the losses event on Pierce B5 provided an improved understanding of the loss mechanism, resulting in a revised equivalent-circulating-density (ECD) -management strategy.

A11

Introduction

The Pierce field (Fig. 1) in the UK central North Sea is a brownfield development with 17 existing wells drilled around two complex salt diapirs. Oil production was depletion-driven for the first 7 years until pressure support was provided by three water injectors drilled around the southern salt diapir. Pierce B5 was drilled in the proximity of the southern diapir, and losses encountered in the reservoir section were severe enough that no further drilling progress could be made. Preexisting fractures further weakened by depletion were thought to be the cause of the losses. Unfortunately, from a wellplanning perspective, these fractures cannot be predicted or avoided when drilling horizontal wells. During a three-well infill campaign (Wells B5, A11, and C1), considerable losses on the first well led the operator to re-evaluate how future wells would

Fig. 1—Pierce field, showing location of Pierce B5, A11, and C1.

be drilled. The outcome of this was the development of a low-ECD-drilling-fluid system, a revised ECD- management procedure, and a much-improved losstreatment strategy. This combined strategy was applied in the field and resulted in the successful drilling of the subsequent wells.

Loss Event on Pierce B5

Because of the close proximity in the reservoir of the Pierce B5 well to a pre-

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 166134, “Case Study—ECD-Management Strategy Solves Lost-Circulation Issues in Complex Salt Diapirs/Paleocene Reservoir,” by David Murray, Shell; Mark W. Sanders, SPE, and Kirsty Houston, SPE, M-I Swaco; and Hamish Hogg and Graeme Wylie, Shell, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September–2 October. The paper has not been peer reviewed.

existing production well (Pierce B2), it was determined that the localized depletion seen at this location because of the drawdown effects of B2 would be on the order of 2,300 psi, which would result in a reduction in formation integrity. However, there was concern that the effects of depletion could be higher than that; 3,200 psi through open fractures was modeled as the worst case. Therefore, because of the potential for dynamic losses when encountering zones that have seen the lowest field depletion and to mitigate the risk of open fractures, the recommendation was made to use a fluid design incorporating wellbore-strengthening materials (WSMs). Drilling the first 2,066 ft of reservoir out of a planned total of 2,357 ft exposed the wellbore to stable ECDs

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. JPT • FEBRUARY 2014

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Fig. 2—Scanning-electron-microscope image of HF/HS-pill material in its fibrous-lattice form (left). The HF/HS-pill material in defluidized state (right).

of 12.48 lbm/gal without any induced losses, which suggested that wellbore strengthening had been effective in providing an additional drilling margin. However, at this point in the well, losses occurred both dynamically (while pumping) and statically, with initial loss rates of 200 and 65 bbl/hr, respectively. These losses occurred shortly after a connection was made and an ECD spike of 12.67 lbm/gal was observed; drilling then continued for the next hour with a decreasing trend in the drilling ECD, which was 12.38 lbm/gal when losses occurred. The ECD trend demonstrated that there was no ECD spike or warning of losses when they occurred, suggesting that drilling into an existing weakened zone or fracture was the cause of the losses. Over the next 10 days, more than 5,000 bbl of nonaqueous fluid (NAF) was lost downhole and 15 individual lost-circulation-material (LCM) treatments were performed in an attempt to halt the losses. More than 51 t of LCM was used without success before the well stabilized enough to secure the drilled footage and complete the well. Two main types of LCM treatments were used: (1) a combination of predominantly fibrous materials, ground nut shells, and metamorphized limestone (marble), designated as Pill B; and (2) a thermally activated gelling agent for NAF. It was suspected that the losses were attributable to a pre-existing fracture or fractures with a fracture width exceeding what the WSM was designed to bridge.

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Wellbore Strengthening on Pierce B5

Wellbore strengthening was chosen for B5 because of concerns about localized depletion around B5. Optimum WSM treatments were derived using algorithms for particle-size distribution and fracture sealing. Operationally, the material was added as a concentrated slurry at the rigsite at a controlled rate to keep the coarser particles in the circulating system.

Pierce A11: Low-ECD Drilling Fluid and Losses Strategy

Planning for Pierce A11 was taking place when the losses on B5 occurred. A11 was clearly a challenging well, and additional focus was drawn to the design team following the losses on B5 to accomplish the following goals: ◗◗ Decide if wellbore strengthening was necessary for the successful drilling of A11. ◗◗ Develop a strategy to reduce ECD while drilling, through the development of a low-ECD drilling fluid based on a high oil/ water ratio (OWR). ◗◗ Design a robust LCM strategy on the basis of the best products currently available for the region to cater to large fractures.

Low-ECD Drilling Fluid

The use of WSM on B5 was far from basic, so with a larger drilling window available for A11, the opportunity existed to drill the planned 7,300 ft of reservoir conventionally. The key was ECD management,

where drilling-fluid properties and drilling parameters were monitored closely to ensure the ECD was kept as low as possible. A successful system is one in which its low rheological profile (low viscosity) leads to a reduction in ECD while drilling but does not affect the drilling-fluid cuttings-carrying capacity or increase the likelihood of barite sag. The solution on the Pierce wells to achieving a low-ECD-drilling-fluid system together with high barite-sag resistance is in the OWR, coupled with an optimum organophilic-clay content. In NAFs using organophilic clay for viscosity, the concentration of organophilic clay will increase as the OWR increases in order to maintain a particular rheological requirement. This is because the organophilic clay will yield less as the OWR increases. Organophilic clay can be thought of as the backbone of an NAF for reducing the likelihood of barite sag when used in sufficiently high concentrations. The OWR range programmed for A11 was from 75:25 to 85:15. The drillingfluids engineers were encouraged to aim for the higher end of the range but allow for dilution with base oil to control solids toward the end of the section. Limits for both ECD and rate of penetration (ROP) were set to stay within the expectformation-integrity measurements; ed the ECD limit was set at 12.5 lbm/gal, and an ROP limit was set at 50 ft/hr. The offshore team was made aware of the importance of ECD management. This is higher than the possible real low value for formation-integrity measurements; however, fracture breakdown pressure will exist even with depletion. The amount of additional strength is unknown and will be lost if ECDs are too high or a fracture is encountered. The result would be the formation strength equaling the formation-integrity measurements, and losses occurring. The key to lowering the induced-losses risk, therefore, was to limit ECD as much as possible, adhere to good drilling practices, and use the lowECD drilling fluid. The decision to use the low-ECD drilling fluid (weighted with ultrafine barite) was the result of modeling predicted ECDs. LCM Strategy. The operator’s well-fluids team evaluated possible LCM treatments

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1/16/14 7:46 AM

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from incumbent fluid vendors that might enable the sealing of large fractures (>3 mm). The following LCM solutions were proposed for Pierce A11: ◗◗ High-fluid-loss/high-strength (HF/HS) pill. ◗◗ Soft-setting cement plugs with additives to prevent accidental sidetracking (reduced compressive strength). ◗◗ Specially selected synthetic fibers originally designed for cement spacers. ◗◗ Shear-thinning water-based mixed-metal-oxide fluid treatment. ◗◗ Pill A and Pill B—LCM blends including fibrous materials, ground nut shells, and marble. (Pill A represents a light treatment, and Pill B represents a heavy treatment.) The LCMs chosen for Pierce A11 were Pill A, Pill B, and the HF/HS treatment.

HF/HS Functionality

HF/HS is a one-sack inert multifiber lostcirculation pill treatment designed to be easily mixable in a variety of media and engineered to defluidize rapidly within the loss zone, leaving behind a resilient, high-solids plug in a fibrouslattice form (Fig. 2). As the filtrate is squeezed into a permeable formation and the consolidating matrix of solids increases in thickness, its resistance to differential pressure and mechanical force also increases. Pill density can be controlled either with a weighting agent such as barite or through the use of a brine base, as in Pierce, to help maximize shear strength.

Results From Pierce A11

On A11, 2,169 ft of pilot hole and 4,608 ft of main bore were drilled by use of the revised ECD-management and lowECD-drilling-fluid strategies. The ECD throughout both hole sections was maintained below the 12.5-lbm/gal ECD limit. One instance of losses occurred while drilling the pilot hole when crossing a fault with a 12.15-lbm/gal ECD, but this cured itself and no LCM treatment had to be used. No further loss events occurred,

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with both hole sections being delivered successfully as per the plan.

Pierce C1 Planning

Pierce C1 was the 17th development well drilled in the Pierce field. It consisted of a 2,850-ft horizontal reservoir section targeting the Forties Paleocene reservoir and was planned as the most northerly production well at the top of the North Pierce diapir. The available drilling window was assessed, and a low-ECD-drilling-fluid, ECD-management, and LCM strategy was planned to drill the well. ECD management would be critical, and the following lessons from A11 were introduced to C1: ◗◗ Establish optimum OWR with laboratory testing on the lowECD drilling fluid. ◗◗ Control ROP to a 50-ft/hr average value and a 70- to 80-ft/hr instantaneous value. ◗◗Limit ECD to 12.30 lbm/gal. ◗◗ Track pressure-while-drilling data and hole cleaning in real time. ◗◗ Optimize marble additions to the drilling fluid (added in case of stuck pipe). ◗◗ Establish a testing method to measure marble concentration in an NAF. ◗◗ Adopt narrow-margin drillingwindow practices (stage up pumps, reduce surge pressures). ◗◗ Provide additional wiping of the hole on connections to improve hole cleaning as per A11. ◗◗ Use a minimum of 150 rev/min when drilling the reservoir section.

Pierce C1 Execution, Losses, and Application of the HF/HS Pill To Halt Losses

Pill A was prepared and pumped and allowed to soak for 50 minutes. Attempts were made to achieve a drilling loss-free flow rate; however, even at a lower flow rate of 225 gal/min, the loss rate was 60 bbl/hr. This high loss rate at such a low pump rate was considered too high to continue drilling. The decision was made to pump an HF/HS pill. To help maximize

product shear strength, the HF/HS pill was prepared using 10-lbm/gal sodium chloride brine. This was then increased to 11.28 lbm/gal with barite. Subsequently, 20 bbl was pumped downhole with the bit 3 ft off-bottom. Circulation was then established with 24-bbl losses at 450 gal/min, which decreased quickly to loss-free status. On the basis of this positive outcome, the decision was made to drill ahead, increasing flow rate to 488 gal/min. Losses initially were as high as 60 bbl/hr but reduced to a sustainable 8 bbl/hr. For the next 2 days following the HF/HS-pill treatment, no additional LCM treatments were made to the drilling-fluid system. The 7×5½-in. liner was run and cemented successfully. Of the 188 bbl of cement pumped, 22 bbl was lost to the formation and 7 bbl of cement was circulated from above the hanger after the cement job, indicating that a complete cementation of the liner had been achieved.

Discussion

Evidence of pre-existing fractures was captured by the neutron-density-logging tool on Pierce C1 and, therefore, validates the theory that losses on B5 and, subsequently, C1 were caused by pre-existing fractures weakened by depletion. Because losses of this nature are a recent phenomenon in Pierce, this would suggest that increasing the reservoir pressure in the field, from the lows before water injection, has not improved the overall strength of the formations encompassing these fractures. On B5, the risk of losses was exacerbated further by the localized depletion from the nearby B2 well. This implies that future drilling around the Pierce diapirs may also suffer losses; however, the likelihood of predicting preexisting fractures that would be problematic is low because many faults were crossed without any issues. The HF/HS pill has been shown to be an effective LCM where losses occur in pre-existing fractures. The ability to apply a single effective treatment to cure severe losses is a huge advantage when planning depleted wells. The HF/HS pill can be recommended for loss zones similar to those in Pierce C1 or B5, in fractured and depleted sandstone reservoirs. JPT

JPT • FEBRUARY 2014

1/16/14 7:46 AM

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Annular-Pressure Losses While Casing Drilling

asing drilling is a method by which the well is drilled and cased simultaneously. The small annulus from casing drilling can create a controllable dynamic equivalent circulating density (ECD). Casing-drilling technology enables obtaining the same ECD as with conventional drilling but with a lower (optimized) flow rate and lower rheological properties and mud weight. Frictional pressure loss during casing drilling was evaluated with computational fluid dynamics (CFD). Having accurate models for ECD, including the effects of pipe rotation and eccentricity in the annulus, is essential for success in these challenging jobs.

Introduction

Casing drilling builds on experience gained from drilling liners to bottom in troublesome holes. The technique was implemented for drilling a formation sequence of highly pressured shale followed by a depleted reservoir. The major problem when drilling depleted reservoirs is the narrow operational mud-weight window. With advances in topdrive systems, retrievable bottomhole assemblies, and polycrystalline-diamond-compact bits, the technology enables completing a well by use of casing as the drillstring. An often-reported benefit of casing drilling is significantly fewer lostcirculation problems. The wellbore- plastering effect that casing drilling offers can enable drilling depleted zones while causing less formation damage. Plastering also enhances pressure con-

tainment by smearing the smaller drill cuttings into the pore spaces. The aim of this study was to simulate the casingdrilling operation through CFD modeling to evaluate the combined effect of eccentricity and pipe rotation on the velocity profile of a non-Newtonian fluid.

walls (both inner-pipe and wellbore). The pipe and the wellbore were assumed to be smooth. Also, the geometry was held uniform along the pipe (i.e., the effect of tool joints on pressure loss was neglected). The pipe section was considered to be 5 or 10 m long.

Approach

Methodology

Initially, the geometry of casing drilling was constructed for a given wellbore condition. Then, the domain was discretized such that the result would not be grid dependent. A series of cases was designed to compare the CFD model with the analytical solution and validate the discretization scheme. Then, the non-Newtonianfluid (yield-power-law model) simulation was run. Thereafter, an effort was made to analyze the effect of eccentricity and pipe rotation on the yield-power-law fluid.

Assumptions

In drilling operations, continuous fluid circulation through the annulus results in steady-state flow. In the shallow tophole section, the fluid can be treated as an incompressible fluid. The simulated laminar-flow regime verified the CFD results with the analytical solution. It was assumed that a single-phase fluid flows through the annulus and that the pipe geometry provides a uniform concentric annulus along the test section. For simplicity, the effects of drill cuttings were neglected in the simulation to be able to validate the CFD results with the analytical solution. Initially, the casing was treated as stationary (no pipe rotation) with a no-slip condition at the

This article, written by Dennis Denney, contains highlights of paper SPE 166103, “Evaluation of Annular-Pressure Losses While Casing Drilling,” by Vahid Dokhani and Mojtaba P. Shahri, SPE, University of Tulsa; Moji Karimi, SPE, Weatherford; and Saeed Salehi, SPE, University of Louisiana at Lafayette, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September–2 October. The paper has not been peer reviewed.

Analytical solutions are faster and more convenient than numerical techniques, but they lack generality in most cases. To verify the accuracy of a given numerical technique, its results can be compared with the corresponding analytical solution, if available. To verify that the velocity profile was fully developed, the required entry length of the pipe in the test section was estimated. Entry length is the pipe length at which the centerline velocity is 99% of the fully developed centerline velocity. Computational Mesh. The accuracy of the steady-state numerical solution constitutes a base case for other complicated geometries for which no analytical solution is available. Numerical-method validation was carried out by comparing CFD results (i.e., pressure gradient and velocity field) with results of a narrow-slot analytical solution, as shown in Fig. 1. The annular gap between the inner pipe and the wellbore wall was configured as a concentric geometry and as an eccentric layout. To analyze the effect of eccentricity on pressure loss, five cases were considered. Initially, an optimization process was performed to match the best meshing size with the lowest error. Several simulations were run with different mesh sizes, and the results were compared with the narrow-slot analytical solution of a non-Newtonian fluid. To capture the velocity field in the region of high shear rate (i.e., close to the wall), two inflation layers were defined within the cross-sectional area of the pipe.

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. 82

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W 2πRi Ri R

h 2πR

Fig. 1—Geometrical parameters of cylindrical (left) and narrow-slot (right) configurations for concentric pipe in a wellbore. R=wellbore radius, Ri=pipe outside radius, W=channel (annulus) width, h=channel (annulus) thickness.

TABLE 1—FLUID PROPERTIES FOR SENSITIVITY ANALYSIS

Parameters

Value

Average velocity, m/s Density, kg/m3 Viscosity model Yield stress, Pa Consistency index, kg/m⋅s Fluid-behavior index, m

A′ A

0.1 998.2 Herschel-Bulkley 1.5327 0.3745 0.5989

A′ A

Fig. 2—Meshing configurations for a radius ratio of 0.76 and (left), 0.5 (center), and 0.9 (right).

Discretization of the domain along the tangential direction was selected in the range of 200 to 300 divisions. It was confirmed that the numerical results were consistent for 5- and 10-m pipe lengths. Boundary Conditions and Fluid Properties. To simplify analysis sensitivity, it was assumed that the fluid flows in isothermal and laminar conditions. At the inlet, a constant fluid velocity equal to the bulk-fluid velocity along the pipe was specified and the boundary condition at the outlet was set to zero static pressure. To initialize the CFD analysis, the fluid properties of a yield-power-law fluid were assumed, as given in Table 1.

Verification of CFD Results

No analytical solution was available for flow of a yield-power-law fluid in an annulus section. Therefore, the authors used CFD simulation to generate the results for the cylindrical geometries. The results of the CFD solution were verified with the narrow-slot-approximation solution for a yield-power-law fluid. A sen-

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A′

ε values of 0.1

sitivity study of CFD simulation was performed by selecting different rheological values to examine the accuracy of the computation and meshing properness. Values of yield stress τy=0.833, 1.183, and 1.533 were used to quantify the error magnitude of CFD calculations. The simulation was performed for each configuration (concentric geo metry), and the results were compared with the narrow-slot analytical solution. Error values for all cases were reasonable, with the largest error <3%. The frictional-pressure-drop curves showed a similar pattern for the values of yield stress. When the yield stress increased, the frictional pressure drop increased. The meshing scheme was nearly insensitive to the values of yield stress when a good match existed between the CFD result and the analytical solution. There was a similar pattern in pressure drop for the three selected values of yield stress.

Eccentricity Effect

The governing equations become complicated as the inner pipe (casing) be-

comes offset to an unknown value. An eccentricity value ε describes how offcenter a pipe is within another pipe or the open hole. A pipe is considered concentric (0% eccentric, ε=0) if it is perfectly centered in the outer pipe or hole. The eccentricity of the inner pipe was increased to investigate the effect of eccentricity on frictional pressure loss. Five cases were studied: ε=0.1, 0.3, 0.5, 0.7, and 0.9. Note that the meshing scheme of the eccentric pipe should be repeated to discretize the wider-gap region properly. The meshing configurations shown in Fig. 2 are for a radius ratio (inner-pipe outside radius/borehole-wall radius) of 0.76 and ε values of 0.1, 0.5, and 0.9. Monitoring the velocity profile in the horizontal cross section (A–A′) reveals that the fluid velocity is higher in the wider gap and lower in the narrow region. The geometrical configuration reduced the overall effect of wall friction on the fluid domain. Therefore, it is expected that increased eccentricity would reduce the pressure drop. The effect of eccentricity on pressure loss is more dominant in the range of ε=0.2 to ε=0.8. In general, it was concluded that as eccentricity increases, the pressure drop along the annulus decreases.

Pipe-Rotation Effect

The inner pipe was rotated at 20, 30, 40, 50, and 60 rev/min by selecting the inner-pipe boundary condition as a moving wall. A velocity-ratio parameter ζ can be defined to specify the flow regimes in the annular space. The ζ for these geo metries was set between 1 and 10. That range specifies a mixed-flow regime (i.e., between axial-dominated and rotationdominated flow). A pressure-drop pattern, similar to a function of radius ratio, was recognized. Pipe rotation promoted a shear-thinning response to reduce the apparent viscosity exhibited by a yield-power-law fluid. The effect of pipe rotation on frictional pressure loss was explained by examining the velocity profile across the annular gap. For the first configuration (radius ratio=0.7), the effect of pipe rotation was distributed almost along the radial direction. The plug zone disappeared as pipe rotation was increased, which was accounted for by the shear-thinning properties of a yield-power-law fluid.

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MCCO

Simulating Field Data

The geometry of the casing-drilling operation corresponded to the second eccentric case, with a radius ratio of 0.764. The Fann-viscometer data were converted to corresponding shear-rate and -stress values by use of appropriate conversion factors. The results then were recognized as the rheological properties of a yieldpower-law fluid. Those fluid properties were used to match the CFD prediction with that of field data. The frictional pressure drop for field data was reported as 135 Pa/m, which could be obtained from ECD data. Initially, an attempt was made to obtain the pressure drop of the concentric geometry without pipe rotation. The CFD yielded a 330-Pa/m pressure drop for the given geometry. The next step was to implement the effect of pipe rotation, yielding a 178-Pa/m pressure drop. To match real data, an attempt was made to determine the geometry by use of estimated eccentricity values. The closest match of pressure-drop prediction to field data yielded a possible eccentricity value. Increasing the casing eccentricity to a value of 0.9 reduced the pressure drop. The combination of

pipe rotation and eccentricity yielded a 151‑Pa/m pressure drop. The final velocity distribution is shown in Fig. 3. The discrepancy between simulation and field data may be attributed to the following constraints: Tool joints were not included in the geometry, the walls were treated as a smooth surface, and the effect of drill cuttings on the flow regime was ignored. Note that the wellbore shape might not be circular, as envisioned in this model. Also, assuming a zero-slip condition may not be appropriate for real application. Thermal effects and fluid compressibility may contribute to overestimating pressure loss also.

Conclusions

◗◗ Including eccentricity in the simulation indicated that a general pattern can be recognized as a function of pipe eccentricity for yieldpower-law fluids. ◗◗ Increasing pipe rotation helped reduce the frictional pressure loss in the annulus. ◗◗ Comparing the results of CFD simulation with field data in a

1.48e+00 1.40e+00 1.33e+00 1.25e+00 1.18e+00 1.11e+00 1.03e+00 9.59e–01 8.85e–01 8.11e–01 7.38e–01 6.64e–01 5.90e–01 5.16e–01 4.43e–01 3.89e–01 2.95e–01 2.21e–01 1.48e–01 7.38e–02 0.00e+00

Fig. 3—Velocity-magnitude distribution across annular space by use of CFD to match the pressure drop reported in the field.

stepwise manner indicated that the casing may have been offcenter in the wellbore. ◗◗ The effect of wellbore-wall roughness should be considered to yield a more-realistic estimation of the frictional pressure loss. Several pipe joints should be included along the test section to study the effect of tool joints on pressure losses. JPT

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Managed-Pressure Drilling— A Solution for Challenging Wells in Vietnam

anaged-pressure drilling (MPD) has been used in Vietnam since 2007 to address a number of drilling and reservoir challenges. The main application of MPD has been to overcome the challenges of granite-basement, fractured and vugular carbonate, high-pressure/ high-temperature (HP/HT), and overpressured clastic reservoirs. This paper examines the procedural approaches of MPD, including constant bottomhole pressure (CBHP), equivalent-circulating-density (ECD) management, early kick detection, and pressurized-mud-cap drilling (PMCD).

MPD Techniques and Applications

The International Association of Drilling Contractors (IADC) defines MPD as “an adaptive drilling process used to precisely control the annular pressure profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly. MPD is intended to avoid continuous influx of formation fluids to the surface. Any influx incidental to the operation will be safely contained using an appropriate process.”

MPD Variants

The definition of MPD covers a wide range of variations and applications, but the most commonly used among them are the PMCD and CBHP variations (Fig. 1).

PMCD enables high rate of penetration, less flat time, and lower-cost drilling in extreme-loss situations. The goal of MPD is to control the pressure profile in a way that eliminates many of the drilling and wellbore-stability issues that are inherent to conventional drilling.

CBHP reduces NPT and enables fewer and deeper casing strings when “drilling windows” are narrow or relatively unknown.

Dual-gradient MPD enables total well depth in the right hole size in deep-well and deepwater drilling. Hydraulically speaking, it “tricks” the well into “thinking” the rig is closer.

Returns-flow-control MPD reduces risk to personnel and the environment from drilling fluids and well-control incidents. Fig. 1—Various types of MPD.

PMCD as defined by the IADC as “a variation of MPD that involves drilling with no returns to surface and where an annulus fluid column, assisted by surface pressure [made possible with the use of a rotating control device (RCD)], is maintained above a formation that is capable of accepting fluid and cuttings. A sacrificial fluid with cuttings is accepted by the [lost] circulation zone. This technique is applicable for cases of severe [lost] circulation that preclude the use of conventional wellbore construction techniques.” The PMCD variant of MPD allows conventional drilling operations until losses are experienced and has been used successfully to drill through

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 165775, “Managed-Pressure Drilling—A Solution for Drilling the Challenging and Undrillable Wells in Vietnam and Southeast Asia,” by Ben Gedge, SPE, Harpreet Kaur Dalgit Singh, Elsofron Refugio, and Bao Ta Quoc, Weatherford Asia Pacific, and Nguyen Viet Bot, PVD Well Services, prepared for the 2013 SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, 22–24 October. The paper has not been peer reviewed.

fractured and vugular carbonate for mations where circulation losses can be simultaneously sudden and severe. This allows drilling to target depth despite massive losses being encountered. The CBHP variant of MPD involves the ability to maintain a constant bottomhole pressure (BHP), especially when drillpipe connections are made and the rig mud pumps are turned off. In this instance, the MPD system exerts a backpressure value that corresponds to the frictional pressure loss. This backpressure is slowly relieved once the connection has been completed and the rig mud pumps resume operation. However, given the sophistication of current MPD-control systems, BHP not only can be kept constant but also can vary to ascertain the downhole-pressure-environment limits and allow drilling personnel to manage the annular-hydraulic-pressure profile accordingly, thereby making the drilling operation more effective and more efficient.

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. 86

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HP/HT; Overpressured Formations With Low Rates of Penetration; Formations With a Very Tight Kick/Loss Profile

For these applications, CBHP and earlykick-detection procedures are used with an RCD and autochoke system, coupled with a Coriolis meter and microprocessor. MPD enables a constant BHP to be maintained while drilling an HP/HT well, thereby reducing nonproductive time (NPT), especially across pressure ramps where kick/loss situations are common, time consuming, and expensive. Benefits associated with the system are early kick detection, better well control, and ease of circulating kicks out, allowing the well to be drilled through very tight kick/loss margins with quick adjustment to desired BHP. The dedicated choke allows maintaining BHP at a constant value or range.

PMCD Used To Drill Fractured/ Karstified Carbonate and Granite-Basement Formations With High Fluid-Loss Rates

PMCD is implemented on wells to address severe lost circulation and

DT165775.indd 87

Fig. 2â&#x20AC;&#x201D;The Moc Tinh platform.

Â ydrocarbon-influx problems when drillh ing through karstified/fractured limestones and granite basements. PMCD rig-up will allow safe drilling ahead without delay if significant losses are encountered. PMCD can help achieve well objectives (time, depth, costs, safety, and

environmental) where high loss rates lead to problems with well control, hole cleaning, and high fluid costs. Using PMCD with a low fluid weight enables ECD to be managed, fluid losses to be minimized, and rates of penetration to be increased.

1/16/14 8:23 AM

Implementation of PMCD To Manage Fluid Losses in Granite-Basement Drilling

In the past, a dependency on high brine consumption because of losses in the fractured basement for wells drilled for Hoan-Vu joint operating company resulted in very high brine and salt costs. This led to suspension of the operation because of an interruption in brine and salt supply, caused by bad weather and exhaustion of onshore supplier stocks, resulting in the total planned depth not always being achieved. Use of seawater as the drilling fluid, common in the granite basement in Vietnam, was not possible because of the slightly overpressured reservoir. The MPD system was identified as a possible solution to the brinemanagement and kick/loss-on-connection problems for several reasons: ◗◗ High loss rate when drilling the fractured granite reservoir ◗◗ Brine-supply difficulties during the northeast monsoon season ◗◗ Previous experience of drilling disruption while waiting on brine ◗◗ High mud weight to control kick/loss, leading to ECD issues while making/breaking connections The objectives of using MPD were to minimize the dependency on brine during drilling and tripping operations on the fractured granite basement and to reduce the overall amount of brine lost during these operations.

Implementation of MPD To Manage ECD in an HP/HT Overpressured Clastic Formation With Low Rate of Penetration

The Hoang Long Joint Operating Com pany in Vietnam planned to drill a second offshore appraisal well in the Te Giac Den field offshore Vietnam. In the first well, TGD-1X, hole instability was addressed by increasing mud weights, which increased losses. For the later well, TGD-2X, the major objective for using MPD was to manage BHP (remove ECD fluctuations). The MPD equipment will also allow con-

DT165775.indd 88

ducting CBHP operations on the 14½- or 14¾-in. and the 8¼-in. sections. Losses During Drilling. The use of MPD means drilling with minimal overbalance. This will reduce the chance of losses. Instability During Drilling. The use of MPD to keep BHP as close to constant as possible will reduce cyclic stresses on the formations drilled. Additionally, if splinters or cavings are observed in the cuttings, the use of MPD means that increased pressure on the wellbore can be applied instantly, thus stopping pressureinduced instability much faster than could be achieved by increasing mud weight. Drilling Summary. Use of MPD has clearly shown results that saved rig time and minimized unplanned well-control events and NPT. By use of CBHP, drilling expectations were met and exceeded in Well TGD-2X. The MPD setup with RCD and semiautochoke manifold was the most efficient way to reduce the cost of drilling the HP/HT TGD-2X well. The previous well incurred four sidetracks. The MPD choke manifold was used to enable tripping with surface pressure. The well was then stabilized by maintaining a constant BHP. A drilling summary includes the following: ◗◗ Reduction of the mud weight during drilling facilitated by the RCD was successful in reducing the losses. ◗◗ The maximum pressure seen on the RCD (choke pressure) was 300 psi during tripping in the 12¼×14¾-in. section and was 1,254 psi in the 8¼-in. section. ◗◗ The CBHP hookup was efficient for the purpose of reducing mud weight and holding the appropriate surface backpressure (choke pressure) on connections to replace the lost ECD increment when drilling.

Implementation of MPD, Early Kick Detection, and CBHP in HP/HT Well With Very Narrow Kick/Loss Tolerance

MPD was used on this project for the following reasons:

◗◗ Narrow margin between pore and fracture pressure would require CBHP control to avoid unnecessary kick/loss incidents during dynamic and static conditions. ◗◗ Using a closed-loop MPD system in a narrow pore-pressure/ fracture-gradient window would allow wellbore breathing or ballooning to be readily identified. ◗◗ Frequency of well-control incidents is higher in HP/HT wells, and the MPD manifold enables easier control of kicks. ◗◗ The MPD manifold allows kicks to be circulated at full pump rates with pipe vertical and with rotational movement.

Project Results and Conclusions

MPD was deployed on all but one of the wells drilled to date on the Moc Tinh platform (Fig. 2). The Bien Dong drilling team employed strict, well-planned, thoroughly engineered and defined HP/HT procedures and practices, successfully avoiding incidents commonly accompanying such severe HP/HT formations. Only some ballooning and minor influxes were encountered. MPD was used in the early-kick- detection mode but not in the CBHP mode.

Conclusion

Over a fairly short span of time, MPD technology has been introduced and accepted into drilling operations in Vietnam to address a range of drilling challenges, with generally good success in reducing drilling time, NPT, and cost. Some wells were previously unable to reach their targets without the use of MPD technology. The technology will grow in use in the various basins in Vietnam, as the wells become ever more challenging when more-difficult reservoirs and formations are drilled. These will include deepwater projects, which are in their infancy, but currently growing in number. JPT

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Re-Engineering and Upgrade of a Semiautomated 3,000-hp Drilling Rig

n 2011, the Kuwait Oil Company (KOC) considered enhancement of equipment specifications for deep drilling rigs to integrate state-ofthe-art technologies. UPDC Rig 776 was the first to be upgraded, and this work was handled as an integrated project by the rig contractor working closely with the field operator. With regard to the rig design, major changes were made to enhance safety, capacity, and automation of the drilling functions.

Purpose of the Upgrade

The drilling of future deep high-pressure/ high-temperature wells in Kuwait will become more challenging. New frontier areas with increased depth and formation difficulty are being targeted. To ensure that the deep drilling rigs will be able to meet these future challenges and to improve safety and operational performance, KOC has enhanced the deepdrilling-equipment specifications for their new contracts. For Rig 776, this required a major upgrade or replacement of all core rig components. ◗◗ The subbase height had to be increased to be able to incorporate a full 15,000-psi blowout-preventer (BOP) -stack rig-up. ◗◗ The topdrive system had to be upgraded to cope with higher mud-flow rates and pressures,

and a control system for the driller was to be installed. ◗◗ Mud pumps were replaced with new 2,200-hp pumps, producing up to 7,500 psi. ◗◗ The rig power system was upgraded with five new 1,855‑bhp (maximum) engines and a new selective catalytic reduction (SCR) system. ◗◗ An upgrade of the drawworks included an integrated disk brake system and installation of a semiautomated control system for the driller. ◗◗ The iron roughneck was enhanced. ◗◗ The mud system was upgraded. These improvements were aimed at enhancing safety, capacity, and automation of the drilling functions. In addition to these major changes, the rig camp was completely refurbished and the camp power generation was upgraded to silent packages.

Rig-Upgrade Works

Once Rig 776 finished drilling the last well before the upgrade, the rig was prepared for the yard work. As the rig commenced to rig down for the move to the project yard, all equipment had to be cleaned properly. The mud tanks had to undergo sand blasting before inspections could be conducted. The cleaned equipment was then moved to the project yard. The rig offices were set up

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 164019, “Re-Engineering and Upgrade of Semiautomated 3,000-hp Drilling Rig for KOC HP/HT Exploration Program in Frontier Areas—Case History of UPDC Rig 776,” by A. Al-Saleh, SPE, M.D. Al-Khaldy, SPE, A.A. Shehab, SPE, F.A. Al-Naqa, SPE, and S. Baijal, Kuwait Oil Company; M.F. Karam and S. Schmidt, United Precision Drilling; and D.C. McKinnell, SPE, Total Kuwait, prepared for the 2013 SPE Middle East Unconventional Gas Conference and Exhibition, Muscat, Oman, 28–30 January. The paper has not been peer reviewed.

in the project yard to provide extra office space. Subbase and Mast. The subbase height had to be increased by 10 ft. This was accomplished by changing out all existing subbase legs. With the new subbase height, all stairs, escape slides, piping and hoses, and the personnel elevator to the rig floor had to be modified or replaced and the V-door ramp had to be extended. In addition to increasing the height of the subbase, the entire subbase and mast underwent inspection and recertification. This required sand blasting of all components, inspection, and repainting. Any defects found had to be repaired, with parts replaced as needed. Once work on the subbase and mast was completed, a new 120-ton BOP hoist system had to be installed. The spill containment (drip pan) was replaced under the rig-floor area. On the rig floor, the existing ST-80 iron roughneck had to be replaced with a large-capacity IR10-100 roughneck. A new 20,000-lbm air tugger also was installed. Drillers Cabin. The old driller’s console was to be replaced with a modern enclosed driller’s cabin that holds joystick controls for the drawworks. This cabin incorporates touch-screen controls for all major rig functions (Fig. 1). Topdrive. The topdrive was stripped down, and all parts were inspected. The main shaft had to be upgraded from 3 in. to a new large-bore 4-in. shaft with a 7,500-psi pressure rating. Drawworks. The existing drawworks had to be completely stripped down and inspected and overhauled. The old drum shaft and drum had to be replaced. A new disk braking system was installed.

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. 90

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Fig. 1—Driller’s cabin and control system.

New semiautomated controls were installed for the driller. Mud Pumps and Discharge Piping. The three original 1,700-hp mud pumps were replaced with new 2,200-hp pumps with 7,500-psi output. These new pumps include a quick liner and piston change system. Also, an independent chargepump skid was added to the system. These new pumps can deliver more mud volume at higher pressures, as required for the new drilling program. All old 5,000-psi mud-discharge lines, mud-discharge manifold, stand-

Fig. 2—Rig 776 completed.

pipe manifold/lines, and rotary hoses had to be changed to larger-inner-diameter and higher-rated 7,500-psi lines. Mud System. The existing mud tanks were cleaned, sand blasted, inspected, and repaired as required. The mud-volume capacity was increased to 4,500 bbl with the incorporation of additional tanks. New larger 20-hp agitators were installed to improve agitation of the heavy muds (up to 20.5 lbm/gal) used in Kuwait. Also, one new shaleshaker unit was installed to provide better solids removal.

Rig Engines, SCR System, Accumulator Unit. To cope with the higher power demands of the new mud pumps and mud system, the five existing 12-cylinder engines were replaced with larger, 16-cylinder engine packs. The old SCR system was replaced with a new SCR system that integrates automated engine control in the driller’s cabin. The original nine-station accumulator was replaced with an upgraded 12-station unit. Camp Refurbishment. The entire main camp and rigsite camp underwent re-

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furbishment in the project yard. One by one, the cabins were cleaned and repaired and refurbished, as required. Several cabins were replaced with new-built cabins. 24-Hour Testing and Final Inspection. Once all work was completed, the rig entered into a 24-hour maximum-load test, which was witnessed by KOC representatives and a rig-inspection contractor. The test was set up to simulate heavy drilling conditions. To draw maximum power from the engines, all three mud pumps were pumping, the topdrive was running, and all agitators and shale shakers were running. The rig systems had to withstand this 24-hour load test without any shutdown of more than 30 minutes. The rig was then rigged down and moved to the first location in the South Burgan field (Fig. 2). During rig-up, the remaining smaller outstanding jobs were completed and a final prespud check was conducted by KOC. Once all was accepted, the rig spudded the first well on 18 January 2012.

Main Challenges and Recommendations

Yard Operations and Multiple Projects. Many challenges of this project stemmed from the fact that, concurrently, there was a second upgrade project (Rig 3) and two new rigs being built. To deal with this, three project managers with their teams were used (one for the new builds and one each for the upgrades). The upgrade teams for Rig 776 and Rig 3 worked at the yard in Kuwait, while the new rigs were built in Dubai. Rig 776 was the first rig to undergo the upgrade works, followed by Rig 3. The rigs were expected in the yard in Kuwait within a month of one another, so the available yard space had to be used efficiently. The project yard was separated into two areas to keep equipment and materials from getting mixed during the project. Materials and Logistics. Another substantial challenge was the coordination of all purchasing activity. Large quantities of equipment and parts were ordered for all four projects. This required the use of dedicated warehouse and logistics

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teams to process the ordering, tracking, and shipping of materials. A major problem was slippage in promised delivery times from various vendors, some of which resulted in delays to the project work. To overcome these problems, some equipment had to be urgently airfreighted and some had to be shared or borrowed from other rigs until the new equipment arrived in Kuwait. The main lesson from this is that the sooner the equipment is ordered, the better. Refurbishing Existing Equipment. While planning for the upgrade, all efforts were made to establish the condition of existing equipment accurately and to anticipate what work and which parts were required. But some of the equipment conditions remained unknown until the particular item was completely dismantled in the yard. On a few items, equipment conditions were found that were worse than expected, and replacement parts had to be ordered on an urgent basis. For future upgrade projects, it is recommended to negotiate with the parts vendors to provide all possible required critical parts ahead of time and then return the parts that are not needed. This will avoid waiting-for-parts project delays.

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Connecting Systems From Different Vendors. The new driller’s cabin and controls and the SCR house were made by one manufacturer, and the main rig equipment was supplied by other vendors (drawworks, topdrive, mud pumps, and main engines). Getting the equipment set up properly to ensure smooth communications between these systems was vital and had to be done with care, using service technicians from all involved manufacturers. Initial Results. After final testing and commission of the upgrade, the first deep exploratory well was drilled with the modified rig in the Kuwait South Burgan field. While drilling the first well, no major problems were experienced with the newly installed instrumentation system or other upgraded equipment. The initial well was drilled under planned time, with no lost-time injuries or environmental incidents. JPT

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TECHNOLOGY

Ian G. Ball, SPE, is technology advisor and project manager with Intecsea, focusing primarily on deepwater subsea field development and technology application. Previously, he was with Reliance Industries as senior advisor for deepwater challenges in opening the Krishna Godavari basin off the east coast of India. For most of his career, Ball was with Shell, where he specialized in deepwater subsea and floater-based field development, with assignments in Brunei, Norway, UK, and the US Gulf of Mexico. He holds a BS degree from the University of Manchester Institute of Science and Technology. Ball was cochairperson of the 2008 and 2009 SPE Annual Technical Conference and Exhibition Program Committees and serves on the JPT Editorial Committee. He is also chairperson of the Editorial Committee for Oil and Gas Facilities.

Recommended additional reading at OnePetro: www.onepetro.org. SPE 166639 An Assessment of the Impact of Water-Injection-Systems Uptime on Well and Reservoir Management on Two North Sea FPSOs by Olawale Adeola, Shell SPE 166617 Improving the Economics of Marginal Fields Through Technology Transfer From the Defense and Renewables Industry by Paul Watson, OPT, et al. SPE 166546 The Use of Multirotor Remotely Operated Aerial Vehicles as a Method of Close Visual Inspection of Live and Difficult-To-Access Assets on Offshore Platforms by Philip Buchan, Cyberhawk Innovations, et al.

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offshore facilities In recent years, an unprecedented upsurge in offshore field-development activity has been driven largely by the corresponding sustained surge in oil price on world markets. Much of this activity has been focused on deep water, where the challenges have stretched both the hardware supply chains and the availability of qualified workers close to their limits. One of the consequences of this offshore market stimulation has been a substantial increase in unit development costs to a point at which operators are increasingly seeking ways to restore a better balance in supply and demand. Hence, an increasing number of field-development decision deferments are becoming a key part of thatÂ process. One potential benefit to the industry that could be derived from a temporary slowdown in major capital expenditure would be an opportunity for increased focus on technology development and qualification in anticipation of the huge challenges ahead. The initiative, however, would have to be driven and funded largely by the operator sector, with practical vendor solutions to real, tangible problems being the prime target. Here, we take a closer look at the kind of technology developments that are already making a major contribution to our ability to move forward successfully and safely into new and harsh frontiers for oil and gas development. The chosen papers reveal the increasing importance of taking an integrated and systematic surface/subsurface approach when seeking solutions to the ever-more-complex challenges ahead. The industry has demonstrated time and again that it is not sufficient for a vendor to have put huge effort and investment into getting a new solution into its catalog of options. It is increasingly necessary to be able to show convincing and verifiable evidence that a rigorous and recognizable testing and qualification program has been followed in order to substantiate the claim that a solution is ready for field application. The final ingredient necessary to justify the technology investment is an operator capable of analyzing the qualification evidence and confident enough in its own staff to make the decision to be the first adopter of that technology offshore. Statoil has shown itself to be a shining example of such an operator in the subsea arena, but others, too, have risen to the challenge, especially where the technology is a key development enabler. I hope you enjoy reading this small selection from a large body of recent papers covering associated topics of technology-development interest. JPT

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Deepwater Floating Production Systems in Harsh Environments Offshore Norway

eepwater field developments are regarded as standard technology in several areas of the world, but in harsher environments, extreme design loads and increased fatigue loading become more challenging. In particular, risers and mooring solutions are vulnerable to loading conditions in harsh environments. Development solutions that work well in more-benign environments may not work as required in deepwater harsh environments such as those offshore Norway. Fig. 1—Aasta Hansteen location and view of selected field-development solution.

Introduction

Floating production systems in harsh environments have long been in operation, but have been limited to water depths of 400 to 500 m. Deepwater floating production systems have been in operation in benign environments such as offshore Brazil, west Africa, and the Gulf of Mexico (GOM) for almost 2 decades. After Hurricanes Katrina and Rita, the design level for the GOM has been increased, and one can argue that the GOM is no longer considered a benign environment. But tropical-storm areas such as the GOM have significantly less dynamic loading in general than harsh-environment areas such as offshore Norway. Currently, Statoil and its partners OMV and ConocoPhillips have sanctioned the gasfield development Aasta Hansteen in 1300-m water depth in the Norwegian Sea. Field developments are moving into deeper waters in some of the harshest conditions in the world.

Concept Selection: Deepwater Floating Production in Harsh Environments

Aasta Hansteen is a rich gas field located 300 km from shore. It consists of three reservoirs, and the drainage strategy is pressure depletion. Dry trees offer no benefits; therefore, the field will be developed with subsea trees, seven in total, tied back to a floating production facility. There is also a limited amount of condensate present. The plant processing capacity is higher than needed because the development opens a new area; the production facility will be used as a hub. The treated gas will be exported through a new approximately 500-km-long pipeline to Nyhamna for final processing and further export (Fig. 1), and the produced water will be cleaned and disposed of at sea. However, the small volumes of condensate caused some challenges for concept selection. Economically, the condensate

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24511, “Deepwater Floating Production Systems in Harsh Environments: A Look at a Field Development Offshore Norway and the Need for Technology Qualification,” by T.S. Meling, Statoil, prepared for the 2013 Offshore Technology Conference Brasil, Rio de Janeiro, 29–31 October. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission.

is more of a burden than a value because a solution is required for the limited production. Export through the pipeline was not feasible from a flow-assurance standpoint; and, because the closest existing facility with storage capacity is 150 km away, a separate condensate-export pipeline was not attractive either. Therefore, local storage of 25 000 m3 of condensate and offloading was required at the lowest possible cost. Because the large storage capacity provided by a ship-shaped floating production, storage, and offloading (FPSO) vessel was not required by Aasta Hansteen, alternative solutions were studied to identify the most cost-effective solution. The use of circular-shaped FPSOs is a field-proven concept in shallow water in the North Sea and the Barents Sea. The potential of a circular FPSO was also studied for the Aasta Hansteen project, and it was the preferred concept. In the interests of competition, however, alternative solutions were studied in the next screening phase, including subsea tiebacks to a floating production unit located in shallow waters. The shallow- water solutions were not competitive, but one alternative deepwater-floater concept was the spar concept. The spar is a popular deepwater concept because of its favorable motions in storm condi-

The complete paper is available for purchase at OnePetro: www.onepetro.org. JPT • FEBRUARY 2014

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tions, which is beneficial for riser solutions such as steel catenary risers (SCRs). Except for the Kikeh spar offshore Malaysia, all spars are installed in the GOM, and even though the hard tank in the spar hull can provide storage capacity, no spar hulls are used for storage. Therefore, use of a spar FPSO in the harsh environment offshore Norway would definitely require technology qualification. An important driver for the concept selection was the riser solution. Because no deepwater risers have been installed offshore Norway to date, all riser solutions would require some qualification work. On the basis of Statoil’s costly experience with gas export through roughbore flexible risers, there was a desire to avoid the flow-induced pulsations (FIPs) caused by the carcass in the flexibles. With subsea trees, there is no need for top tension risers, and then the only riser solutions that eliminate FIPs are SCRs, smooth-bore flexible risers, or a hybrid riser solution with smooth-bore jumpers. Use of a hybrid-riser solution would eliminate the water-depth challenge for the smooth-bore flexible riser because the vertical steel riser section bridges most of the water column. However, because of its complexity and costs, the hybrid-riser solution was not chosen for the Aasta Hansteen project. With the FIP challenge and the need for technology qualification for smoothbore flexible risers, the preferred riser concept was the use of SCRs. The hangoff area and the touchdown area are critical sections for the SCRs, and floater motions are critical to achieve a robust SCR concept. Model tests were carried out, and ultimately the spar FPSO was the selected hull concept because its motions gave the most robust SCR solution and it was the most cost-effective concept.

Spar FPSO and the Need for Technology Qualification for Installation in Deepwater Offshore Norway

Because the spar used in the Aasta Hansteen project would be the first spar offshore Norway—and the first ever with storage and offloading combined with the first SCRs used on the Norwegian continental shelf—the need for a technology assessment to establish a technology-qualification program was ev-

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ident. In addition, the spar will be the largest in the world, with a topside dry weight of 22 600 t, a hull dry weight of 41 000 t, and a total displacement of 165 000 t. The diameter of the hard tank is 50 m, and total length of the hull is 195 m. Both a truss-spar design and a new type of spar with a “belly” were studied, requiring different types of qualification. Model testing has already been mentioned as essential in documenting the global response. The design waves in the GOM are not far from the design waves at Aasta Hansteen, but the associated peak periods are longer and there might be wave energy at periods up to 30 seconds. Hence, the natural period in heave must be shifted toward a longer period than in the GOM to avoid any resonance problems. Heave/pitch instabilities must also be avoided. Additionally, vortex-induced motions (VIMs) are another spar characteristic that must be limited. Therefore, comprehensive model tests were carried out for both spar concepts to confirm predicted response. While strakes are commonly used to control VIMs in the GOM, the model tests revealed that the waves in the Norwegian Sea dampened the VIMs and that no strakes were needed for the truss-spar design. The effect of increased fatigue loading was also thoroughly addressed for critical sections such as the connection between the hard tank and the truss section, and the pull tubes. However, with proper structural design, these issues were managed. The storage consists of four separate compartments located below the zone at risk of ship collisions. The tanks are surrounded by cofferdams to prevent leakages. Two separate access shafts are provided for normal operation and maintenance. Offloading of the condensate to shuttle tankers will be performed by pumps submerged in welded caissons from the topside cellar deck. The design principle is that all hydrocarbon-containing systems shall be determined on the process side of the topside cellar deck. All valves, headers, and flanges in the hydrocarboncontaining systems shall be located topside to minimize risk of leakages and required operator attention in the hull. The design allows simultaneous loading and offloading. Condensate offloading will be carried out approximately once a month.

The marine operations connected to upending and topside installation are another challenge for a spar offshore Norway. The standard GOM approach of upending the hull at the field and installing the topside with a heavy-lift vessel is regarded as too risky in the harsh environment offshore Norway. Fortunately, Norway has several deep fjords providing sheltered areas for upending of the hull and installation of the topside before towing to the field. Upending and installation of the topside for Aasta Hansteen will be carried out in a fjord close to Stavanger. The Aasta Hansteen topside will be installed by mating. Mating was also used for the installation of the Kikeh topside. Thorough assessments have been carried out to ensure feasibility and robustness for the selected manner of carrying out the marine operations. The hull and topside will be fabricated in South Korea and transported by dry tow to the fjord outside Stavanger for assembly. For a thorough discussion of the mooring system used, please see the complete paper.

SCRs

Statoil has been working with qualification of SCRs for many years in order to have them available as riser solutions for its deepwater field developments. The focus has been on critical areas such as the hang-off area and the touchdown zone. Documenting sufficient fatigue life for the SCRs is very often the most challenging task, especially in the touchdown zone. Fatigue damage caused by wave loading is one contributor, but the largest uncertainty is linked to fatigue damage caused by vortex-induced vibrations (VIVs) of the risers. VIVs have been studied for many decades, but the uncertainty is still considerable. Strakes are commonly installed more or less along the entire free-spanning part of the SCRs to limit VIVs to manageable levels. Although one alternative to strakes is to use fairings, strakes were chosen in the Aasta Hansteen project to limit VIVs. At hang-off, the stresses for the SCRs will be controlled by support from the pull tubes. A riser-integrity-management system is under development by the project, including riser monitoring, to ensure that the risers respond as predicted to the various loadings. JPT

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Turret-Mooring-System Experience and Enhancements in the Atlantic Frontier

he Schiehallion floating production, storage, and offloading vessel (FPSO) is moored by a turret-mooring system (TMS) located in a water depth of 400 m in the Atlantic in very challenging environmental conditions. The Schiehallion FPSO went onstream in 1998. As part of the planned field development, the Quad 204 FPSO currently under construction will replace the producing unit in 2015. This paper compares the main features of the Schiehallion and Quad 204 TMSs, reporting the performance of key components over 15 years of operation.

Introduction

for harsh weather and continuous operations in the west Shetland area.

BP Schiehallion FPSO

The Schiehallion is at this time the world’s largest purpose-built vessel, capable of storing 950,000 bbl of oil, with a length of 245 m, a width of 45 m, and a depth of 27.25 m (Fig. 1). A simple bargetype hull was chosen, incorporating a design life of 25 years in situ, with a fatigue life of 50 years and the capacity to survive the 100-year-storm condition. A high forecastle was designed to protect the forward process area and the turret. Accommodation astern of the vessel provides full temporary refuge facilities for 80 persons. For stability performance, ballast water tanks are segregated and arranged to form a double-sided hull. Two aftmounted thrusters are implemented for heading control during offloading operations to tandem-moored shuttle tankers.

◗◗ Survival of 100-year-storm condition (intact/one line broken/ transient case) ◗◗ Four bundles of mooring lines allowing for large corridors for the risers ◗◗ Mooring stiffness independent of offset directions Fourteen anchor legs, bundled in an anchor pattern of 2×3 and 2×4 legs and using a combination of 6¼-in. studless chain (a first) and 146-mm-diameter sheathed spiral-strand steel cables, enable the criteria to be met. Suction anchors placed in a radius of 1650 m provide the required holding capacity.

Top-Mounted Internal Turret (TMIT). The fixed part of the turret is composed of a 14-m-diameter cylinder, inserted through the vessel hull and supported at the vessel’s deck level on the turret collar by a bogie-bearing system (for further details on the bogie-bearing system, Mooring System. The mooring design please see the complete paper). This sysis based on an entirely passive moor- tem allows the vessel to weathervane ing (i.e., no assistance of a dynamic- around the turret, and comprises a sepositioning system is required for ries of 20 vertical bogie assemblies and station keeping). The natural FPSO 18 radial wheels. The vertical bogies and weathervaning capacity ensures mini- the radial wheels run on bolted and secmum environmental loading on the cat- tored rails. All components can be reenary mooring arrangement. placed in situ should the need arise. The mooring system was conceived Fluid-Transfer System. The FPSO of by analytical methods validated by topside facility is designed to handle a series of model tests in a 1:80 scale in excess of 145 million bbl of oil and representing the 400-m water depth at 140 MMscf/D of gas production. The production scenario comprises five drilling the site. The criteria for the mooring design centers, with a total of 16 production wells, 12 water-injection wells, and one were as follows: gas-disposal well. The turret provides the link between This article, written by JPT Technology Editor Chris Carpenter, contains highlights the earthbound incoming and outgoing of paper SPE 166560, “From Schiehallion to Quad 204 FPSO: Turret-Mooring-System flowlines and the topside placed on the Experience and Enhancements,” by Lionel Fromage and Jean-Robert Fournier, weathervaning vessel. In addition to the SBM Offshore; Pieter Drijver, BP; and Alwyn McLeary, BP North Sea, prepared previously mentioned services, there is for the 2013 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, a requirement for individual-well test3–6 September. The paper has not been peer reviewed. ing, well control (hydraulic and electric A contract was signed in June 1995 between BP and an alliance of partners to develop an FPSO for Schiehallion. Sanction was given to the project by BP and their partners in February 1996. The harsh environment encountered in the Schiehallion field, offshore the Shetland Islands in the Atlantic Frontier area, required a new dimension of a mooring system. An internal turret was chosen to allow the vessel to freely weathervane and to transfer the fluids and services from subsea to the vessel and vice versa. The required turret dia meter to accommodate 24 risers precluded the use of a conventional slewing-ring arrangement, as was used in previously built North Sea turrets. The new Quad 204 FPSO that will replace the Schiehallion will be a doublehulled vessel 260 m in length designed

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt. 98

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Fig. 1—Schiehallion FPSO.

signals), chemical injection, and gas lift. A large, multipath swivel stack handles the transfer of these lines from within the turret-mounted manifold to the gantry structure placed on the vessel deck or vice versa. In order to allow for the initially installed 13 flowlines and two umbilicals, and the additional risers planned for the future, the turret contains 24 I-tubes. The flexible risers that transfer the fluids from the seabed to the FPSO enter the turret structure through the bottom and continue to the deck level of the vessel at the top of the turret, where the end fittings are connected to the hard piping.

Fig. 2—Quad 204 FPSO.

This allows an above-water dry connection of the flexible risers. Bend restrictors protect the riser sections below the chain table (vessel keel level). Upper-Turret Manifold and Gantry. An open manifold structure houses the shut-down and emergency-shutdown valves, the piping headers and pigging equipment, the turret equipment room, and the chain and riser installation winch. Three elevated decks, stepped in diameters from 22 to 16 m above the riser deck, are arranged to form a cone with a height of 27 m above the main deck. A three-legged pyramid gantry structure is

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fitted over the manifold. This structure carries all the piping to the vessel deck and supports a hydraulic turret crane for maintenance and a windshield structure allowing personnel to work protected in the manifold, which is equivalent in size to a 10-story building. Swivel Stack. The swivel stack is the heart of the TMIT, transferring all fluids and services from the fixed turret to the freely weathervaning vessel. It accommodates a full 360° rotation during full service life. During the design of the Schiehallion TMS, it became apparent that the required swivel stack would become extremely complex and large. Previously

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produced stacks were mounted atop the manifold, with the external housing driven from the gantry. This “normal” concept resulted in a total height of 36 m from the vessel deck for the top of the turret crane. A challenge to reduce the overall height resulted in an unusual inverted swivel stack with a number of advantages, including reduction in overall height for the turret top, reduction in gantry height and piping length, and protected access to swivels for inspection and maintenance.

BP Quad 204 FPSO

The vessel will be able to store 1,000,000 bbl of oil, with a length of 270 m, a width of 52 m, and a depth of 27.25 m (Fig. 2). Mooring System. The FPSO will be turret moored in the same location as the existing vessel through an anchor-leg system composed of four bundles of five legs laid within the same sectors as the present Schiehallion anchor-leg bundles, thereby keeping free the access corridors for the existing risers and umbilicals.

TMIT. At the turret bottom, the risers and umbilicals are routed through tubular guides (I-tubes) to, respectively, a riser support deck and an umbilical connection deck in the upper portion of the turret cylinder. Piping spool pieces connect the riser termination flanges in the turret to the piping on the decks of the manifold. From the manifold decks, the fluids are routed to the fluid swivel stack. The chain stoppers are mechanical systems that transfer the mooring load to the lower-turret fixed structure. The chain stoppers are considered to be key technology items because of the resulting mooring-load level and chain-fatigue aspect. In addition, the connector’s offshore changeout is possible without interrupting production. Bogie-Bearing System. For bogiesystem designs after the Schiehallion TMS, the bogie radial-guide wheels fulfill the function of guiding the bogies along the track and replace the former tie rods. Otherwise, the weathervaning-system materials recently used are very similar to those of Schiehallion, the system being scaled to specific requirements. The axial wheels mounted in each bogie (32-off) counteract the gravity, heave acceleration, mooring lines, and

riser loads and moments. The radial wheels (36-off) counteract the horizontal loads caused by vessel motions, wind, current, and waves. To minimize friction, both the axial and radial wheels run on roller bearings. The wheel/rail interface is greased by an automatic system fixed on the bogie in order to prevent corrosion and to reduce friction and wear. Fluid-Transfer System. Turret Manifold and Gantry. A multideck super structure (manifold), located on top of the turret, houses installation and production equipment and piping manifolds, and supports the fluid swivel stack. Access to the fixed part is achieved directly from process deck to collar deck. A gantry structure is positioned above and around the superstructure. The turret design allows for maintenance in operation, which maximizes availability over the full field design life. Swivel Stack. The swivel-stack assembly includes all individual swivel units, the swivel supports between swivel units, and all internal piping and cabling of the stack. The swivels allow the transfer of fluids, utilities, chemicals, electric power, and electrical and optical signals between the vessel, turret, and seabed equipment. The fixed portion of each swivel pipe run extends downward from the swivel-inner-shell flange connection to the turret-deck-piping flange connection. The rotating portion of each swivel pipe run extends outward from the swivel- outer-shell flange and is flange connected to the pipe runs on the overhead structure. Compared with the Schiehallion swivel stack, weighing 100 t and with a height of 12 m, the Quad 204 stack is much larger, with 14 swivel units, a height of 26 m, and a 265-t weight. The space allowed between each swivel allows for the replacement of offshore seals without disrupting operations using the other swivel paths. On Quad 204, the high-voltage swivel is located at the bottom of the stack to avoid the routing and supporting of high-voltage cables through the stack. A large-diameter unit with slip rings transferring the requested power levels was thus developed. The air swivel is located at the stack base to accommodate a large air swivel without impacting production units. JPT

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Offshore Dry-Docking of FPSOs

he large number of floating production, storage, and offloading units (FPSOs) commissioned more than a decade ago now require offshore-asset-integrity management and maintenance. The FPSOs were originally designed for continuous service for periods up to 25 years. However, although designed to strict criteria, structural and hullmaintenance shortcomings have become apparent, prompting remedial actions or extensive offshoremaintenance campaigns. An offshoredry-docking concept was developed to lift an FPSO out of the water without disconnecting it from its mooring system and leaving the flowlines connected. The stable working platform allows work access to the FPSO hull, appendages, and mooring system.

Introduction

The proposed offshore dry-docking concept lifts the FPSO out of the water by submerging the floating dry-dock vessel and moving it underneath the FPSO offshore without disconnecting the FPSO from its mooring system or flowlines, as shown in Fig. 1. The bowless concept of the dry-dock vessel with a high load-carrying capacity enables dry transportation of more-traditional semisubmersibles and other floating production units and FPSOs. The proposed offshore dry dock investigated the use of dry-transportation technology for offshore dry-docking of complete floating production units.

Fig. 1—Offshore dry-docking.

Technical Specifications

The largest heavy-transport vessel currently operating is designed to dry- transport offshore production facilities including ultraheavy semisubmersibles and FPSOs. In the past, an offshore unit would need to be wet towed from the fabricator to its production location. Scaling up the existing heavy-transport vessels was not sufficient because of the length of FPSOs, which can exceed 300 m. A bowless design is capable of transporting and offshore dry-docking FPSOs longer than 300 m, with the strength of the FPSO being the limiting factor. The design is shown in Fig. 2. With its bowless design, the total length of the Dockwise Vanguard (275 m) can be used. Its cruis-

This article, written by Dennis Denney, contains highlights of paper OTC 24330, “Offshore Dry-Docking of FPSOs: A Response to Industry Needs,” by T. Terpstra and E.A. Hellinga, Dockwise, prepared for the 2013 Offshore Technology Conference Brasil, Rio de Janeiro, 29–31 October. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission.

ing speed of 12 knots is at least twice the speed of a wet tow. Floating cargoes with a maximum draft of 16 m can be loaded (not considering cribbing or grillage). The dry-dock vessel’s bowless design and the movable casings allow use of the vessel’s entire deck to transport units. Also, there are no vessel restrictions for overhang forward and aft. The bowless design is created by placing the crew’s accommodation on the extreme starboard side of the vessel together with the lifeboats. Carrying Capacity. The capacity to drydock FPSOs is governed by the deadweight capacity of the vessel and the width and length of the FPSO. Deck-load requirements and stability are not considered critical in this case. The deadweight capacity of the Vanguard allows a payload of 117 000 t. Depending on the position of the center of gravity of the cargo, ballast water is required only for weight-offset compensation. With the FPSO overhanging the stern of the drydock vessel, it is expected that ballast

The complete paper is available for purchase at OnePetro: www.onepetro.org. JPT • FEBRUARY 2014

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Fig. 2—The Dockwise Vanguard.

water will need to be added to achieve zero trim. The allowable width to accommodate an FPSO depends on the available width between the fixed accommodation block and the variable-position buoyancy casings. This width ranges from approximately 52 m to 65 m. The support length for supporting an FPSO is 275 m. Depending on the structural capacity of the FPSO hull girder, some overhang can be allowed, enabling the dry-dock vessel to accommodate FPSOs greater than 300 m in length.

Compliance With Det Norske Veritas Heavy-Lift Notation. This dry-dock vessel is one of the first vessels to be built according to the Det Norske Veritas notation for semisubmersible heavy-lift vessels. The notation had a major influence on the design of the casings and the accommodation tower. The requirement to provide 4.5% of the submerged displacement as reserve capacity in submerged condition, and a minimum of 1.5% of the submerged displacement in each end of the vessel, resulted in additional freeboard.

Ballast System. The ballast system of the dry-dock vessel is a pump-based system selected for its potential to be adapted to ballast-water treatment. Such a system with sufficient capacity is not yet available. To achieve sufficient redundancy, the ballast system consists of a dual-ring line, serving all tanks, and dual pump rooms. The system is compliant with the latest regulations, including avoidance of crossflooding through vent lines in case of damage. All vent lines are routed to a safe zone, which will remain dry in case of damage, before venting in a central duct. To avoid pressures building up in tanks and the occurrence of water locks in the venting system, use has been made of drain tanks in the forward and aft ends of the vessel.

FPSO Limitations. The deck capacity and carrying capacity of the dry-dock vessel will not limit offshore dry-docking of FPSOs. Two aspects that limit the concept are the dimensions and mooring system of the FPSO. Dimensions. The dimensions of the deck are 275×70 m. The maximum width of the FPSO must be less than 65 m to install the safety and sea-fastening equipment. Clearance is required for maneuvering the FPSO between the casings of the dry-dock vessel and is necessary for repair work on the FPSO. A width of 60 m or less is preferred for loading, offloading, and performing repair work on the FPSO. The maximum length of an FPSO is limited by the strength of the overhang of the FPSO, the bending-moment capac-

ity, and the static and dynamic loadings on the turret from moorings, risers, and flowlines. The largest FPSOs are 370 m long. These FPSOs will have an extensive overhang on both ends of the dry-dock vessel, potentially limiting access for inspection or repair work. Mooring System. The offshore-drydock concept uses the mooring system of the FPSO to moor both ships. The most common mooring systems are internal-, external-, and spread-mooring systems. These systems are used by most of the current FPSOs. Both external and internal mooring systems are suitable for dry-docking. Spread-moored FPSOs have mooring lines in all directions, and some lines will need to be disconnected to avoid collision with the casings of the dry-dock vessel during loading and offloading operations. FPSOs with disconnectable turrets have not been assessed, and it is assumed that drydocking onshore or near shore is more economical than an offshore operation.

Offshore-Dry-Docking Operation

The offshore-dry-dock operation can be divided into four steps. During all phases, the FPSO can stay on location and the turret system can stay intact. Scenarios considered for the feasibility assessment included the possibility for contin-

Fig. 3—Loading operation of an external-turret-moored FPSO.

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ued production and the configuration of moorings and the turret. Two scenarios were assessed. ◗◗ No production—all production systems and tanks emptied and gas free ◗◗ Limited production—direct offloading into shuttle tanker, with limited use of FPSO storage tanks The following steps are for an FPSO with no production. Prepare the FPSO. Preparation consists of emptying cargo tanks and freeing gas from them and depressurizing all processing plants onboard. An underwater inspection with a remotely operated vehicle is performed before dry-docking to determine the required work and to supply information necessary for loading the FPSO (e.g., protrusions). Cargo in the tanks will be offloaded to a shuttle tanker until no oil remains in the FPSO. After offloading is completed, all tanks must be cleaned and gas free. Risers must be depressurized and flushed. Loading Operation. After both vessels have been prepared, the loading operation commences. This operation comprises approaching the FPSO, positioning the dry-dock vessel, and loading the FPSO. The loading operation is illustrated in Fig. 3. The FPSO remains on its position, and the dry-dock vessel is maneuvered by use of its thrusters and winches and by assisting tugs. After the initial load transfer is achieved and the floating assets are moving as an integrated body, initial utility and safety connections can be established. Once these connections have been established and confirmed to be in working order, the dry-dock vessel will deballast to dry-docking conditions. Dry-Docking. The dry-dock-vessel/FPSO combination will be moored by the turret of the FPSO. The bow of the FPSO will overhang the stern of the dry-dock vessel, and the bow thrusters of the drydock vessel can assist in station keeping. After positioning the cargo on deck, it will be sea fastened. Sea fastening keeps the cargo in position during the dry-docking stage. Permanent utility

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connections will be established to support the FPSO during the dry-docking period, including electrical power, water supply, waste and gray-water discharge, and cooling-water discharge. Lifesaving appliances and escape routing are installed to support both the contingent crew of the FPSO and the dry-docking labor during the dry-docking period. Logistics for the dry-docking work are put in place, including deck barges, accommodation barges, and standby safety vessels. Thereafter, the repair work can commence in favorable weather with modest movement of the dry-dock-vessel/FPSO combination. The scope of work during the dry-docking stage will include inspection, maintenance, and repairs. Discharge. After completing the drydocking work, the reverse of the loading operation can be initiated, implementing proper hold points to perform checks that would normally take place before leaving any dry dock.

Hydrodynamics of Offshore Loading and Discharge

Normal loading and discharge operations are performed in sheltered waters, resulting in limited environmental effects. Performing the same operation offshore leads to significantly higher loads and will affect workability. The main challenge during offshore loading and discharge is controlling the relative horizontal movements of the dry-dock vessel and the FPSO. Another specific hydrodynamic challenge during loading and discharge of an FPSO is to estimate the vertical movement when a very small gap exists between the FPSO and the drydock vessel.

Hazard-Identification Process and Safety Assessment

The hazard-identification study assessed the offshore dry-docking of an external-turret-moored FPSO as the base case considering no production from the FPSO and process equipment fully depressurized, but not necessarily gas free. The cargo tanks are gas free and made inert. General hot work is performed on the hull, but not the topside. Next, an internal-turret-moored FPSO was as sessed, with the same considerations as the base case. The assessment of the

spread-moored FPSO was not developed because the operating conditions were not fully defined. A variation of the base case was assessed for external- and internal-turretmoored FPSOs to account for crude oil in the FPSO cargo tanks (no hot work, or hot work only in limited areas). No production would occur at the FPSO. Most tanks would not be gas free, and some tanks could contain cargo, although some operators may not permit dry-docking of a single-bottom FPSO with cargo onboard because of the potential of an oil spill if the bottom is damaged (e.g., by the cribbing). Another case was assessed for reduced production to an attached shuttle tanker during dry-docking. Production might be shut down for a short period during the loading operation, but would be restarted directly from the production train to the shuttle-tanker export hose. The production rate would be significantly less than full production capacity. Cargo tanks would be emptied and made inert.

Conclusion

The main challenge during offshore-drydock loading and discharge is controlling the relative horizontal movements of the dry-dock vessel and the FPSO. The model test of a large semisubmersible showed positive results, providing confidence in the feasibility of the system. The mooring loads were within a realistic range for safe operation. Further model tests will be required to verify the relative movements during loading and discharge of an FPSO. The dry-dock vessel must be able to load and discharge the FPSO with a preferred significant wave height of at least 1.5 m to make it financially attractive in most cases. Areas with favorable wave characteristics would allow a maximum significant wave height of 1.0 m. Use of a dry-dock vessel for offshore dry-docking can be of benefit when the FPSO is permanently moored by an internal or external turret and all lines have sufficient slack, repairs are related to the underwater portion of the FPSO and are accessible, significant advantages exist vs. executing an underwater repair, and no dry-dock repair yard is available within a relatively short distance. JPT

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TECHNOLOGY

Angel G. GuzmánGarcia, SPE, is an independent energy consultant. He holds a PhD degree in chemical engineering from Tulane University. GuzmánGarcia spent more than 23 years with ExxonMobil, where he held a variety of positions: conducting research on the response of resistivity tools in shaly sands; investigating nuclear-magneticresonance petrophysical applications; conducting and interpreting production logging; designing fluid-sampling collection and pressure/volume/ temperature analyses; and designing, executing, and interpreting well tests in both siliciclastic and carbonate environments. He is an instructor in well testing, production logging, and petrophysics and is a member of the JPT Editorial Committee.

Recommended additional reading at OnePetro: www.onepetro.org. SPE 164349 Innovative Single-Phase Tank Technology for In-Situ Sample Validation Enhances Fluid-Sampling Technology by Francisco Galvan Sanchez, Baker Hughes SPE 164482 Inferring Interwell Connectivity in a Reservoir From Bottomhole-Pressure Fluctuations in Hydraulically Fractured Vertical Wells, Horizontal Wells, and Mixed Wellbore Conditions by Anh V. Dinh, Schlumberger, et al. SPE 166074 In-Situ Poisson’s-Ratio Determination From Interference Transient Well Tests by Mojtaba P. Shahri, The University of Tulsa, et al. IPTC 16711 Deepwater Reservoir Characterization Using Tidal Signal Extracted From Permanent Downhole Pressure Gauge by Xingru Wu, University of Oklahoma, et al.

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well testing As throngs of people crowd the car dealerships eager to buy hybrid or electric vehicles to stop using fossil fuels to drive their cars, I reminisce about the good old days when hydrocarbons ruled the world of energy. Oh, wait, that is the start of my upcoming novel! Renewable energy and nuclear power are the world’s fastest-growing energy sources, each increasing 2.5% per year. However, it is estimated that fossil fuels will continue to supply nearly 80% of world energy use through 2040. Natural gas is the fastest-growing fossil fuel, as global supplies of tight gas, shale gas, and coalbed methane increase. Rising prosperity in China and India is a major factor in the outlook for global energy demand. This is great news for our industry because it forces us to continue finding new resources to meet the world’s demands. The massive deepwater reservoirs seem to have been discovered and are, for the most part, in the field-development and production phases. The unconventional reservoirs open new possibilities. Although the term is used indiscriminately for rocks that exhibit permeability values in the nano- to microdarcy range, these unconventional reservoirs fall into various categories that must be exploited differently. Common practice is that massive fractures are required to stimulate hydrocarbon production. But, in many developed countries, the mere mention of the word “fracturing,” or “fracking,” sends shivers down the collective spine of the general population to the point that governing bodies have simply prohibited such practice. Thus, the reservoirs remain unproduced. And they will remain so unless new technologies are developed or the public is eventually educated on the benefits and safety of this procedure. In the meantime, shale gas and coalbed methane, or coal-seam gas, continue to gain acceptance in countries other than the US, where most of the initial techniques have been tested with reasonable success. Interest in exploiting these types of reservoirs has gained momentum in places such as Australia, Argentina, China, Canada, Russia, and even the Middle East. Allow me to say that this is not a comprehensive list; other countries are also opening the doors for companies to find, develop, and produce hydrocarbons from these reservoirs. During the last year, a large number of publications have dealt with testing unconventional reservoirs. Although it was difficult to select three articles from the many manuscripts, I hope that the three chosen convey the interest in these reservoirs and the clever use of well-test data to add knowledge into understanding the producibility of these reservoirs. Finally, let me remind the interested reader that many other articles on this subject are available in the OnePetro library. JPT

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Integrated Well-Test Strategy in Unconventional Tight Gas Reservoirs

ight gas reservoirs and shale gas reservoirs are economically viable hydrocarbon prospects that have proved to be successful in North America. In such reservoirs, established methods of well testing and data analysis are often impractical. This paper presents an integrated well-test program developed for a tight gas reservoir in southwestern China. The program, designed and modified from conventional methods to meet the project-delivery timeline and cost constraints, makes use of a combination of various formationevaluation techniques.

Introduction

The northwestern and central areas of the Sichuan basin have been identified as having basin-centered gas potential. In particular, there are several blocky sand intervals in the Late Triassic Xujiahe formation that contain a relatively immature, continuous gas accumulation. The tight-gas-reservoir project described in this paper is located in the central uplift area of this basin and is operated by Shell and PetroChina as a joint venture. In this tight gas block, the Xujiahe formation has a gross thickness of greater than 500 m and is found at 3000- to 4000-m drilling depth. The hydrocarbon system in the block is an overpressured section of tight gas sands that are

sourced by imbedded and surrounding shales and coals. Gas and condensate can be produced from this objective section through massive multistage hydraulicfracturing treatments. As with the exploration and development of any tight gas reservoir, the economic delivery of this project requires the integration of various well-testing methodologies to identify the economic feasibility of the reservoir. Well tests are normally conducted during various stages of the well life (Fig. 1). The objectives of well tests include the following: ◗◗ Identifying the hydrocarbonbearing horizon ◗◗ Characterizing reservoir parameters ◗◗ Obtaining initial reservoir pressure ◗◗ Characterizing well damage and the extent of the damage ◗◗ Determining well deliverability and drainage area ◗◗ Evaluating well-completion efficiency ◗◗ Evaluating reservoir heterogeneities ◗◗ Estimating recoverable reserves Unlike conventional hydrocarbon prospects, however, the formation permeability in a tight gas reservoir is extremely low, and commercial production generally requires stimulation through extensive hydraulic fracturing. The ma-

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16950, “Integrated Well-Test Strategy in Unconventional Tight Gas Reservoirs: Learning and Experiences From an Actual Field Project,” by Minquan Jin, SPE, Shell Exploration & Production; Wenxia Zhang, SPE, Shell China Exploration and Production; and Hongli Zhang, PetroChina Southwest, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26–28 March. The paper has not been peer reviewed. Copyright 2013 International Petroleum Technology Conference. Reproduced by permission.

ture and well-defined methods of well testing and data analysis, although applicable, are often impractical because of excessive test duration. Therefore, the true potential in tight gas reservoirs can be established only when well tests are combined with a well-hydraulic- fracturing program. We present an integrated well-test program developed and implemented for reservoir characterization and formation evaluation of this particular tight gas reservoir. The program makes use of a combination of various formation-evaluation techniques that include diagnostic fracture-injection tests (DFITs), perforationinflow tests (PITs), pressure-buildup (PBU) tests, rate-transient analysis, and production logging.

Major Components of the Integrated Well-Test Program

DFIT. The DFIT is also sometimes called the minifracture test. Minifracture pumping is a routine part of a hydraulic-fracturing operation. DFITs provide information for fracture design (leakoff types) and reservoir properties (initial reservoir pressure and system permeability), which is used for predicting future production. PIT. A PIT is a cost-effective technique for the evaluation of prefracture reservoir parameters. The PIT provides estimates of the reservoir pressure, flow capacity, gas-in-flow rate, and skin. PBU. A PBU is the most familiar transient well-testing technique; it has been used extensively in the industry. The primary purpose of a PBU test is to estimate system permeability, initial reservoir pressure, and fracture half-length, height, and conductivity. In most tight gas reservoirs, however, the PBU test requires very long buildup times—months are typical—and supercharging. There-

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Drilling

Prefracture Well Tests (DFIT, PIT)

Fracture

Flowback

Post-Fracture Well Tests

Fluid Sampling

Production

Production-Data Analysis

Well-Program Sequence Fig. 1—Well-test programs in various stages of well life.

fore, the PBU test is often not feasible in very tight rock.

tween the cost of the program and the amount of data potentially acquired.

Production-Data Analysis (PDA). PDA includes a series of well-test techniques such as absolute open-flow potential, decline-curve analysis, rate-transient analysis, and the production-logging test. The purpose of these well-test techniques is to determine the well deliverability (including initial well potential), well-decline behavior for expected ultimate recovery, well drainage area, reservoir properties, and well-flow profiling.

Well-Test Results, Challenges, and Solutions

Development of an Integrated Well-Test Program

The development of a tight gas reservoir generally requires extensive multistage hydraulic-fracturing jobs. Therefore, the integration of various well tests with multistage hydraulic-fracturing jobs becomes very complex, and a successful integration requires careful planning. To facilitate this integration process, we developed a decision flow chart. For a discussion of this flow chart and its application, please see the complete paper. The ultimate selection of a well-test program depends on the balance be-

Significant amounts of well-test data have been collected during the appraisal phase of this particular program. However, because of the limitation on the amount of data that can be practically presented in a single paper, we focus on the estimation of initial reservoir pressure. Initial reservoir pressure is one of the most critical reservoir parameters for estimation of the gas in place and recoverable reserves. For the purposes of comparison, we present the pressure- estimation results for the same fracture stage of a particular well by use of a PIT, a DFIT, and a PBU test. PIT Results. A PIT was conducted in this particular well in the Xu4 formation at a depth of 3262 m. The well was perforated and allowed to bleed off for a short time period and then was shut in; this was followed quickly with a relatively higher rate (approximately 1,800 B/D) for approximately 0.32 hours. The well was then shut in for approximately 2 days,

and the surface-pressure responses were recorded. An impulse plot yields an extrapolated initial reservoir pressure of 7,375 psi. In summary, we found that PITs are successful when reservoir permeability is relatively high and good communication with far-field reservoir formations is established. However, PITs are unsuccessful when matrix permeability is low. Costwise, PITs are the most favorable option. DFIT Results. A 1-day DFIT was executed successfully in the same formation of this particular well immediately following the PIT. During this test, a total of 88 bbl of water was injected into the formation, and the surface pressure was monitored for 16 hours. The DFIT data were analyzed by use of the standard software package. The recorded breakdown pressure at the surface was 8,214 psi, with an injection rate of 2 bbl/min. The maximum injection rate reached 10 bbl/min. The recorded surface maximum pressure reached 9,000 psi. The instantaneous shut-in pressure was estimated at 7,650 psi, corresponding to a bottomhole pressure of 12,286 psi. The after-closure analysis

4000

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was used to estimate an initial reservoir pressure. The estimated initial reservoir pressure in this case was approximately 7,819 psi. This number is slightly higher than the 7,375 psi estimated from the PIT. The difference, however, is reasonable and within 6%. Also, the flow in this case is still in the pseudolinear-flow regime, and the pseudoradial flow has not yet started. Therefore, the initial reservoir pressure estimated from this test may contain some uncertainty, and that could contribute to the observed difference. We observed that DFITs are successful when the formation can be broken down at the initial attempt. The success rate is approximately 70%, although operational cost is an issue. PBU-Test Results. This particular well was put under production for a short time following completion of well flowback to clear up the completion fluid. The well was subsequently shut in for a total of 70 days while waiting for tie-in to the production pipeline. The tubinghead flow pressure and temperature were monitored during this time period (Fig. 2). The data were not used for pressure-transient analysis because of the presence of multiphase fluid inside the wellbore, and the depth of fluid contact was also unknown during this time period. A pressure and fluid-density survey was conducted with a production-logging tool at the end of the shut-in period. The results indicate that the reservoir pressure at the sand surface at a depth of 3262 m was 7,234 psi. This number is lower than those for the DFIT and the PIT. However, this is probably to be expected because the wellbore pressure had not yet completely reached equilibrium with the formation. Therefore, the pressure estimation from the pressure survey is generally consistent with the results from the PIT and DFIT. We found that PBU tests are the most-expensive and -timeconsuming option and should be considered only when the well is idle, and should be coupled with a wellbore-fluid survey.

Challenges and Solutions

Not all of the well tests conducted in the field were successful. There were many challenges and issues during the conduct of the well-test program. For example, the initialization of breakdown of the reservoir formation becomes a major issue during the DFIT. In one such example, the formation failed to break down during several continuous attempts even though the bottomhole pressure reached 18,000 psi (approximately 6,000 psi above overburden pressure). Over the course of field operations, several actions were taken to mitigate this issue, including increasing the number of perforation shots and using better perforating tools, longer slugs, and acid and crosslinked gel. These and other actions did improve the success rate of subsequent DFITs. JPT

Winter Education Conference 2014

February 10-14, 2014 • Houston, Texas

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JPT • FEBRUARY 2014

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New Techniques in Interpretation of Closure Pressure in the Montney Formation

he Montney formation in Canada is one of the largest resource plays in North America. Horizontal multistaged fracturing is the best method for developing this vast resource. Before hydraulic fracturing of the wellbore, the toe stage is frequently minifractured to obtain reservoir and geomechanical properties. Various pressure-transientanalysis (PTA) -based interpretation techniques have been introduced to the industry over the last few years for the determination of closure pressure. From a theoretical viewpoint, unification of the fields of traditional PTA and minifracture interpretation has been achieved.

Introduction

Despite low natural-gas prices, the Montney-play region of northeast British Columbia remains one of the most active of such plays in North America. Operators continue to push drilling activity in the Montney, with increased liquids production within many portions of the trend. Characterization techniques and stimulation and production mechanisms continue to make economics favorable. Prefracture diagnostic testing is an approach that regulators and operators are now more commonly using in unconventional and tight formations. Industry’s current use of minifracture analysis for the determination of fracture closure and after-closure reservoir properties, how ever, still presents several challenges. The conventional approach to all minifracture analysis is the 1D Carter

(a) Carter Linear Flow, (b) Carter Linear Flow, High Permeability Low Permeability

(a) Fracture Linear Flow

(b) Formation Linear Flow

Fig. 1—Schematic of the beforeclosure linear-flow regimes (verticalwell planar view).

Fig. 2—Schematic of the after-closure linear- and radial-flow regimes (vertical-well planar view).

leakoff model, which leads directly to the concept of G time. For more than 30 years, G time (or the G-function) has played the dominant role for the determination of closure stress, but there remains ambiguity in performing minifracture analysis. Part of the problem is that the recommended plots do not rigorously identify the various flow regimes that occur during a minifracture/falloff. Minifracture analysis requires a general theory that accounts for all of the actual observed flow regimes (both before and after closure). The objective of this paper is to create and perform a consistent workflow process of four Montney diagnostic injection tests (one vertical and three horizontal wells) on the same pad, with a systematic approach highlighting the

characteristic flow-regime slopes when using the Bourdet log-log derivative plot. In brief, the Bourdet derivative function used in the PTA-based log-log derivative approach accounts for rate variation before the analyzed shut-in period. The workflow we present is also dependent upon plotting the primary-pressure derivative (PPD) in combination with the Bourdet log-log derivative plot.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 163825, “Interpretation of Closure Pressure in the Unconventional Montney Using PTA Techniques,” by Robert V. Hawkes, Pure Energy Services; Irene Anderson, Talisman Energy; R.C. Bachman, Taurus Reservoir Solutions; and A. Settari, SPE, University of Calgary, prepared for the 2013 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 4–6 February. The paper has not been peer reviewed.

Overview of Flow-Regime Identification in Minifracture Analysis

The log-log derivative plot is the preferred flow-regime-identification/diagnostic tool for PTA. It is uniquely capable of identifying all flow regimes, from early time through late time. The current paradigm for PTA is first to identify flow regimes by use of the Bourdet loglog derivative plot and then to use secondary specialized plots to complete the analysis. In contrast, the current practice in minifracture interpretation is to give equal weight to various combination plots (G-function and square root of t) and the Δt (or delta-time) log-log derivative plot. The robustness of the Bourdet

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88000 84000

Instantaneous Shut-In Pressure= End of Job=33.96 kPa/m

80000 76000 72000 68000

Pressure, kPaa

64000

Overburden=25.3 kPa/m

60000 56000 52000 48000 44000 40000 36000 32000 28000 24000 0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00 1.10 1.20 1.30 1.40 1.50 1.60 1.70 1.80 1.90 2.90 2.10

Time, hours

Fig. 3—Well 058-L: bottomhole treating pressure vs. time.

log-log derivative plot is one reason that it is one of the outstanding achievements in the field of reservoir engineering over the last 30 years. A brief overview of the more-common before- and afterclosure flow regimes appears in Figs. 1 and 2, respectively. Log-log derivative plots have truly revolutionized PTA. However, the reader needs to be aware of a number of issues when applying the technique to minifracture analysis. Generally speaking, with most of the commercially available software packages used for minifracture analysis, a default decision about how derivatives’ smoothing will be calculated for the observed pressure leakoff has already been built into the software and the degree of smoothing that is applied. The software user will have some control over how the derivative is calculated (i.e., the amount of smoothing that will take place). Therefore, it is imperative that the analyst understand the ideas behind these algorithms. For a more detailed discussion of consideration of derivatives, please see the complete paper.

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Minifracture Tests on Pad 58-L. Talisman Energy is targeting the upper and lower Montney in British Columbia. The Montney formation, for the purposes of this paper, has been divided into four groups: upper upper (UU), lower upper (LU), upper lower (UL), and lower lower (LL). There are six horizontal wells completed on the 58-L pad. One vertical wellbore has also been drilled for geological and microseismic-monitoring purposes. For the seven wellbores, four minifracture/leakoff tests were conducted. One was conducted on vertical Well D58-L (LL) and one each in horizontal Wells 058-L (UU), F58-L (UU), and E58-L (UL). Operational Procedure. All four minifracture tests were conducted in casedand-cemented wellbores within 4 days of each other. The horizontal wells were perforated near the toe of the wellbore over a 1-m interval. The minifracture test was then conducted by injecting fresh water at a final rate of 0.5 m3/min (132 gal/ min), with injected volumes ranging from

5.5 to 8.3 m3. The minifracture-falloffpressure data were collected at surface with electronic surface gauges and converted to bottomhole pressures (BHPs) on the basis of a water specific gravity of 1.0 (freshwater gradient=9.8 kPa/m) to the wells’ respective true vertical depths. The wells were shut in for approximately 3 weeks to observe the leakoff behavior. Breakdown pressures for the horizontal wells (058-L, F58-L, and E58-L) were exceptionally high (BHP gradients in excess of 34 kPa/m), with end-of-job treating pressures indicating average gradients of 33 kPa/m. On the basis of integrated density logs, the overburden gradient in this area is 25.3 kPa/m. Two of the four well tests are discussed here; for test results of the other two wells, please see the complete paper. D58-L. This is the only vertical well in our study area and was perforated over an interval of 2612.7 to 2613.7-m measured depth. An apparent pressure- dependent leakoff (PDL) signature is pronounced near a G time of 2.5. This

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early-time feature of the falloff will be described better with the Bourdet loglog plot. The Bourdet log-log derivative plot with the accompanying PPD curve shows a late-time Carter leakoff (slope of 1.5) ending at approximately 12 hours and is consistent with the G-function closure pick. The after-closure flow regime is identified as formation linear flow, as indicated by the derivative slope of 0.5 and the PPD slope of –1.5. Unfortunately, scatter in the derivative data masks the confidence of the after-closure analysis. This derivative scatter is common with surface pressure data in the late-time region of PTA, and therefore the use of subsurface pressure recorders placed as low as safely possible in the vertical section of the wellbore is recommended. The early-time derivative and PPD slopes in the first three log cycles are of special interest because a radial-flow regime is suggested by the zero slope of the derivative and the –1.0 slope on the PPD curve. This apparent radial flow is unique to this vertical well and is an interesting

RESOURCES

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observation, considering that wellbore configuration (horizontal vs. vertical) can play an important role in near-field stimulation complexity. If we choose a pressure at the end of the apparent radial flow, then we calculate a gradient of 24.0 kPa/m. This pressure is close to the vertical stress gradient, either suggesting an incorrect closure interpretation (the overburden gradient from the density logs is high) or indicating multiple fractures oriented in various planes such as horizontal parting of bedding planes. 058-L. During pumping of the toe of this horizontal well, bottomhole breakdown pressure was observed at 84 MPa with an end-of-job injection pressure of 80 MPa, or 34.0 kPa/m (see Fig. 3). The corresponding G-function plot demonstrates the classical “belly-shaped” derivative response observed. Typically, this shape of the G-function has been referred to as an indication of height recession or of transverse storage according to current practices. One motivation of this paper was to study the flow regime of this early-time belly-shaped pressure profile. The Bourdet log-log derivative plot with the PPD curve shows some earlytime complex flow behavior. The PPD curve drops rapidly and has a slope of less than –1 (an actual slope of –2.0 on the PPD curve). The rapid drop in the PPD continues until approximately 0.4 hours, when the pressure drops below the vertical stress gradient (shown as a gradient of 23.1 kPa/m). This diagnostic behavior is observed in all three horizontal minifracture wells and must reflect the significant near-wellbore tortuosity in these horizontal wells. The derivative develops into a Carter leakoff slope as identified by the slope of 1.5, indicating a closure gradient of 22.6 kPa/m. Following the 1.5 slope (fracture closure), there is an increase in slope that transitions to an after-closure flow regime of formation linear flow (slope=0.5). The late-time linear flow is also confirmed by the PPD slope of –1.5. Because formation linear flow is the dominant flow regime, a pore pressure is estimated by extrapolation of a specialized linear plot (not shown), resulting in a pore-pressure gradient of 16.1 kPa/m. The increase in the Bourdet derivative slope after closure is of particular

interest. The PPD response at the same time is increasing. In a normal static reservoir situation, the slope of the falloffpressure time data should be decreasing continuously, never increasing. The increasing Bourdet derivative and increasing PPD are considered a function of reservoir and fracture interaction during prolonged closure. After full closure of the main fracture, the PPD decreases at a slope of –1.5 (linear flow).

Comments

◗◗ The closure-pressure gradients with the G-function range from 19.1 to 21.3 kPa/m. On the basis of the Bourdet log-log method, the gradients range from 20.0 to 22.6 kPa/m. These differences might not appear significant, but it should be recognized that, using the G-function only, some analysts would have concluded that there was no closure for two of the tested wells. ◗◗ The PPD has been available to the industry since 1992, but has been overlooked in identifying flow regimes. The PPD has no superposition effects built into its calculation, and addresses concerns with erroneous superposition assumptions. The PPD function therefore has practical independent diagnostic capabilities to identify flow regimes in minifracture analysis. ◗◗ Although radial flow was not observed with these field examples, when the late-time data were extrapolated to provide an estimate of pore pressure, the pore-pressure gradients were comparable in Wells 058‑L, D58‑L, and F58-L. A slightly higher gradient was determined for the E58-L well. However, this falloff was shorter in duration. ◗◗ As shown in vertical Well D58-L, comparisons need to be made between vertical and horizontal wells in the same zone/interval whenever possible. ◗◗ It is recommended that BHP measurements be used whenever possible to help with after-closure flow-regime interpretation. JPT

JPT • FEBRUARY 2014

1/16/14 8:02 AM

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1/14/14 8:33 AM

Pressure-Transient Testing of Low-Permeability Multiple-Fracture Horizontal Wells

common well-completion configuration for shale-gas wells is a horizontal well with multiple transverse hydraulic fractures. This configuration is becoming common for tight gas reservoirs. Pressure-transient testing of this completion configuration has not been considered practical or useful because extracting completion parameters (e.g., fracture conductivity and fracture half-length) from the recorded response requires estimating the effective formation permeability. Estimating permeability directly from a buildup or drawdown test can be performed only if data from the radial-flow period, which reflects this parameter, are recorded. Unfortunately, for this completion configuration in a low-permeability reservoir, this flow period occurs only after extremely long shut-in or flowing times.

Introduction

The usual shale-gas completion is a casedand-cemented horizontal well, perforated with multiple perforation clusters. Each perforation cluster is treated with an independent fracture stimulation with a large volume of fluid and relatively low proppant concentration. The goal is to create an induced-hydraulic- fracture system, spaced along and covering the length of the horizontal well to provide a large, effective surface flow area in the reservoir. Interpreted microseismic images of these multistage-stimulation treatments indicate that, in some reservoirs, the fractures created at each perfo-

ration cluster have dominant transverse components. These dominant transverse components may or may not be interpreted to be overlain with or coupled to a more-complex system of secondary fractures. Even if the secondary system of more-complex fracturing occurs, the relative importance of this secondary fracture system and its relative contribution to the deliverability of the overall induced fracture system remain subjects of debate. It is equally difficult to establish or deny the importance of the overprint of a natural-fracture system to the flow response and performance of multiplefracture horizontal wells (MFHWs) in unconventional reservoirs. Therefore, the natural starting point for developing a useful pressuretransient-analysis method for horizontalshale-well data would be on responses from horizontal wells affected by induced transverse fractures alone. Building viable pressure-transient-data interpretation methods for this simple base-case problem was the goal of this work. This interpretation must be accomplished before considering how to solve the moregeneral cases that include inducedand natural-fracture complexity. The main issues in analyzing the pressure- transient response from an MFHW are the same as those with a vertically fractured well. 1. An estimate of permeability is required to perform a complete analysis of any data set. 2. This estimate, in general, can be obtained only from the formation radial-flow regime.

This article, written by Dennis Denney, contains highlights of paper SPE 163983, “An Approach to Practical Pressure-Transient Testing of Multiple-Fracture-Completed Horizontal Wells in Low-Permeability Reservoirs,” by Richard Volz, Elvia Pinto, and Omar Soto, SPE, BP America, and J.R. Jones, SPE, NSI Fracturing, prepared for the 2013 SPE Middle East Unconventional Gas Conference and Exhibition, Muscat, Oman, 28–30 January. The paper has not been peer reviewed.

3. This flow regime is the last transient-flow regime to occur. The main barrier to practical analysis in unconventional reservoirs is that this last transient-flow regime occurs at prohibitively long times. With typical fracture half-lengths on the order of hundreds of feet and expected permeabilities in the microdarcy-to-nanodarcy range, the time to the beginning of this final transient-flow regime (the radialflow regime) is thousands to hundreds of thousands of hours. Because the form of the flow-regime equations dictates that the first issue cannot be avoided and the essential physics of the problem defines the third issue, the formation permeability must be estimated from data obtained before the start of radial flow. The work reported here focuses on a data-analysis method that avoids the general limitation of the second issue.

Type-Curve Development

One possible shape for the pressure- transient response of an MFHW is a log-log diagnostic graph of a drawdown response generated by a numerical simulator with formation permeability of 10 nd and 10 transverse fractures with fracture half-length xf and fracture conductivity set to 800 ft and 3 md-ft, respectively. Development of the type curve is detailed in the complete paper. There are several ways to use these type curves in conjunction with flow-regime equations to analyze pressure-transient data from an MFHW. An analysis algorithm that uses the type curves developed here requires data in the fracture radial-flow regime. These data are difficult, but not impossible, to measure or capture. For the range of parameters studied in these simulations, this flow regime exists for times on the order of seconds to tens of seconds. Collecting good data this early in time

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Fig. 1 shows the data recorded before and during the test sequence. The upper part of the figure shows the pressure data from the downhole gauge, while the lower graph shows the p roductionrate data used to analyze the pressure data. Bottomhole-pressure measurements started on 7 December 2011 and ended on 10 April 2012. During this test sequence, two main sets of pressure-buildup data were collected. The first set of data was recorded for 331 hours, and the second set was recorded for 95 hours. The second pressure-buildup test was performed to determine the effect of changes to the surface recording equipment on the quality of the measured data. This second test was shortened on the basis of the interpretation of the response captured during the first pressure- buildup period. For both tests, a down-

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Pressure, psi

300 400 500 600 700 800 0

5,000

10,000

5,000

10,000

15,000

20,000

25,000

15,000

20,000

25,000

Time, hours

Rate-Normalized Pseudopressure and Derivative, (psi2/cp)/(Mscf/D)

Fig. 1—Woodford-well-test overview.

1.00×10–1

1.00×10–2

1.00×10–3

Short-test pseudopressure Short-test derivative Long-test pseudopressure Long-test derivative

1.00×10–4

1.00×10–5 0.00001

0.0001

0.001

0.01

0.1

100

1,000

Pseudotime, hours

Fig. 2—Log-log diagnostic graph of both pressure-buildup-test responses.

Rate-Normalized Pseudopressure and Derivative, (psi2/cp)/(Mscf/D)

To test the viability of these new type curves and the associated data-analysis approach, a field trial was performed in a Woodford-shale-gas well (Arkoma basin). When this well was selected, it had been on production approximately 3 years. The general plan for collecting data was as follows. 1. Shut in the well, pull the existing tubing, return the well to production, and perform a production-log test. 2. Reinstall the tubing with a bottomhole-pressure gauge system. 3. Return the well to production, and flow the well for approximately 30 days. 4. Run a downhole shut-in device approximately 7 days before the planned pressure-buildup test. 5. Activate the downhole shut-in device, and collect pressurebuildup data for 14 days.

Rate, Mscf/D

Field Example

–1,000 2,000 5,000

requires careful planning, high-quality gauges capable of high-frequency data collection, and the use of a downhole shut-in device to minimize wellborestorage effects. Also, post-processing of measured data by use of sandface-rate convolution may be required to remove wellbore-storage effects.

10–2

10–3

10–4

10–5

10–4

10–3

10–2

10–1

100

101

Pseudotime, hours

Fig. 3—Flow-regime interpretation for the field-trial pressure-buildup response.

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Behind every winner is a great nomination Nominate a colleague for outstanding work in the E&P industry. Now until 15 February, the Society of Petroleum Engineers is accepting nominations for outstanding work in the E&P industry. Visit www.spe.org/awards for more information on nominating a colleague today.

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hole shut-in device was used during the pressure-buildup periods. Fig. 2 shows a log-log graph of the appropriately transformed data from the two pressure-buildup tests. Both data sets were smoothed by use of data- and derivative-smoothing algorithms implemented in the analysis software. Data smoothing was necessary to extract the response quality and shape because the raw data contained significant noise. Subsequent retesting of this well with a wireline-deployed, high-resolution, high- recording-frequency gauge confirmed that the response shape in Fig. 2 was valid and representative. Note that the two tests yield essentially the same response shape. Also, the use of pseudotime compressed the apparent test length of the 331-hour test to less than 100 hours of pseudotime and the 95-hour test to approximately 24 hours of pseudotime. The interpretation of the test response is shown in Fig. 3, a log-log diagnostic graph of the response during the shorter test. Focusing on the derivative, the early data appear to define a constant-slope period thought to represent the fracture radial-flow regime. This period is followed by a half-slope period in the derivative that defines the fracture linear-flow regime. After a flattened transition in the derivative, another half-slope period develops that is broken into three stair-step shifts. These stair-step shifts in the half-slope are being investigated, but may be related to how the data were recorded. However, the last half-slope period represents formation linear flow. The first step of the analysis algorithm was performed in Fig. 2. Proceeding to the second step, a match of the data in Fig. 2 to the type curve for the dimensionless fracture conductivity FcD=1,000 is shown in Fig. 4. The overlay of both pressure-buildup-test data sets is matched to take advantage of the slightly better definition of the fracture radial-flow regime given by the shorter test and the extra definition of the formation linear-flow regime given by the longer test. The match shown here was obtained by placing the derivative data, defining the fracture radial-flow regime, over the corresponding part of the type curve and then sliding the data graph to the right until the measured data’s derivative matched one of the de-

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FCD=1,000, HCD=0.1 to 0.25

Rate-Normalized Pseudopressure and Derivative, (psi2/cp)/(Mscf/D)

1.00×10–3

1.00×10–1 1.00×10–4

1.00×10–2 1.00×10–5

mwD⋅HD=0.25 mwD′⋅HD=0.25 mwD⋅HD=0.2 mwD′⋅HD=0.2 mwD⋅HD=0.15 mwD′⋅HD=0.15 Short-test pseudopressure Short-test derivative Long-test pseudopressure Long-test derivative

1.00×10–3 1.00×10–6 1.00×10–4 1.00×10–7

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1.00×100

1.00×10–5 0.00001

0.0001

0.001

0.01

0.1

100

1,000

Dimensionless Time/HD

Fig. 4—Overlay match of pressure-buildup data on FcD=1,000 type curve. mwD=dimensionless pseudopressure drop.

rivative shapes on the type curve and the late-time spacing between measured pseudo pressure and derivative honored the spacing between the type-curve pseudopressure and derivative. This process was followed for type curves with an FcD=500, 750, 1,000, 1,250, 1,500, and 2,000. The best match obtained is shown in Fig. 4 for FcD=1,000. However, this match is not unique. Matches on the FcD=750 and FcD=1,250 type curves (not shown here) were of comparable quality. Accepting this match yields an estimate of FcD=1,000. On this type curve, the best match of the fracture linear-flow regime and the subsequent transition period in the derivative was made on the curve parameterized by a dimensionless effective thickness HD=0.1. Formation thickness of the Woodford shale in this well is reported to be 173 ft. Combining this with the matched HD gives an estimate for xf of 1,730 ft. This completes the second step of the analysis algorithm.

Conclusions

◗◗ A practical type curve was developed that, when combined with flow-regime equations, allows analysis of pressuretransient responses from an MFHW if the FcD characterizing the well is greater than 500. ◗◗ A field trial to test this combined analysis approach was successful. The use of downhole shut-in and high-recording-frequency gauges

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enabled capturing the very-earlytime data critical for applying the combined analysis approach. ◗◗ A modification of the original combined type-curve/flowregime analysis was applied successfully to the pressure-

buildup data collected in the Woodford field trial. For this well, the required estimate of the number of near-well fractures was derived by examining the production-log interpretation. ◗◗ The measured pressure-transient response of the Woodford is consistent with flow from nanodarcy-permeability matrix into long planar fractures created during stimulation. ◗◗ A reasonable interpretation of the data supports relatively few, but long, planar fractures that may be amalgamations of multiple clusters. If effective fracture half-lengths are as great as 1,800 ft, operators will need to reconsider stimulation and wellspacing strategies. ◗◗ Despite the ultralow permeability, all pertinent flow regimes were observed in the Woodford well after only 4 days. The resulting analysis can be used to predict long-term performance of the well. JPT

UAF DEPARTMENT OF PETROLEUM ENGINEERING The Department of Petroleum Engineering at the University of Alaska Fairbanks invites applications for a tenure-track, Assistant Professor position. The position is available beginning Fall semester 2013. An earned Ph.D. in Petroleum Engineering or closely related discipline is required. Preference will be given to candidates having a bachelor's degree in petroleum engineering. Industry work experience is desirable but not required. The successful candidate will be expected to teach undergraduate and graduate courses, supervise graduate students, build an independent research program and perform public, university and professional service. The preferred area of expertise is drilling engineering, but candidates with other specializations will also be considered. Applications will be accepted until the position is filled. Apply online at www.uakjobs.com/applicants/central?quickFind=80070 paper applications are not accepted. For further information regarding this position, please contact: Professor Shirish Patil Department of Petroleum Engineering Email: slpatil@alaska.edu Phone: (907) 474-5127 THE UNIVERSITY OF ALASKA IS AN EEO/AA EMPLOYER AND EDUCATIONAL INSTITUTION. Persons hired by UA must comply with the provisions of the Immigration Act of 1990 and are expected to possess a valid social security number. Your application for employment with the University of Alaska is subject to public disclosure under the Alaska Public Records Act. Women and minorities are encouraged to apply. Applicants needing reasonable accommodation to participate in the application and screening process should contact Human Resources (907) 474-7700.

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TECHNOLOGY

Niall Fleming, SPE, is the leading adviser for well productivity and stimulation with Statoil in Bergen, Norway. He has previously worked as a production geologist, chemist, and engineer. Fleming’s main interest is within the area of formation damage from drilling and completion fluids and from wells in production. In particular, he has recognized the potential for several different nanotechnology applications. Fleming holds a PhD degree in geology from Imperial College London. He has authored several SPE papers, is an associate editor for SPE Production & Operations, serves on the JPT Editorial Committee, and has been a member of the organizing committees for several SPE conferences and workshops.

Recommended additional reading at OnePetro: www.onepetro.org. OMC 2013-105 Nanotechnology Applications in Drilling Fluids by Katherine Price Hoelscher, M-I Swaco, et al. SPE 164461 Illuminating the Reservoir: Magnetic Nanomappers by Abdullah A. Al-Shehri, Saudi Aramco, et al. SPE 166140 Crosswell Magnetic Sensing of Superparamagnetic Nanoparticles for Subsurface Applications by Amir Reza Rahmani, The University of Texas at Austin, et al.

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nanotechnology Nanotechnology has enormous potential in the oil industry, with numerous applications currently under investigation. These include, for example, improvements in material design for enhanced resistance to corrosion or erosion, improved and enhanced oil recovery, improved understanding of reservoirs through use of nanosensors, nanocoatings that prevent the adherence of deposits, and use of nanotechnology in drilling and completion fluids along with production chemicals. The key word with regard to nanotechnology applications in the oil industry is “potential.” Realizing that potential is another matter. A survey of SPE papers published in 2013 describing nanotechnology applications that have been implemented in the field showed only two. There are, of course, numerous explanations for the apparent lack of papers describing field experiences, with the most obvious being that we are in an early-phase technology development and it will take time for new products to emerge in the marketplace. Our industry can be cautious when it comes to new technology, and this resistance to change could be another factor here. A further influence is the potentially unknown consequences of introducing nanotechnology into the environment. For example, much research is focused on the environmental effect of releasing nanoparticles and the potential health risk through inhalation along with the potentially damaging consequences of these particles entering the food chain. It will take time to work through these issues before nanotechnology can be described as mainstream. Where does the future lie for nanotechnology in the oil industry? It is too early to say, with too many unanswered questions remaining. Nevertheless, given the effect that nanotechnology has had in other disciplines (for example, medicine), it would be surprising if nanotechnology had little effect on the oil industry. The papers selected this year include two examples presenting field implementation of nanotechnology. Let’s hope that, in the future, many more papers of this type will appear in the SPE literature. JPT

JPT • FEBRUARY 2014

1/16/14 7:56 AM

Application of a Nanofluid for Asphaltene Inhibition in Colombia

his paper describes the evaluation of a nanofluid containing nanomaterials with high adsorption capacity used for asphaltene inhibition in the volatile Cupiagua Sur oil field in Colombia. Asphaltene precipitation has been identified as one of the most potentially damaging mechanisms affecting this field’s productivity. The goal of the injection of nanofluids containing nanoparticles of alumina with high surface area is to absorb the asphaltenes and carry them with the condensate, avoiding precipitation near the wellbore.

Niscota Boyaca Floreña Laguna de Tota Recetor

Complejo Pauto Piedemonte

Recetor

Yopal

Recetor Casanare Niscota Piedemonte YOPAL Recetor Tauramena Rio Chitamena

Cupiagua Aguazul Santiago De Las Atalayas

Cupiagua Sur Tauramena

Cusiana Tauramena Rio Chitamena

Introduction

The Cupiagua Sur field is located 110 km northeast of Bogota in the foothills of the Colombian Andes, close to other fields such as Floreña, Pauto, Volcanera, Recetor, Cupiagua, and Cusiana (Fig. 1). Despite the fact that Cupiagua Sur is very close to Cupiagua, this reservoir is totally independent and separate. It is a compositional volatile-oil reservoir with an average gravity of 38°API; there is no free-gas cap at initial conditions (for a discussion of asphaltene precipitation in volatile oil, please see the complete paper). The main formations are Mirador and Barco, which are quite similar in terms of petrophysical and fluid properties (average permeability is 21 md, and average porosity is 6.5%).

Fig. 1—Cupiagua Sur and other fields in the Andean foothills.

Cupiagua Sur is a prolific oil field that in 15 years of production has recovered 88 million STB/D gross out of 189 million STB/D originally in place from Mirador and Barco reservoirs in a developed area with four producer and two injector wells. The current reservoir conditions in this field are highly dependent on the way the reservoir has been produced. The first production well, CPXP1, started producing in March 1998, while the first gas-injector well went into action in January 2000; at that time one volatile well was on production. There are currently six active wells in the field.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24310, “Application and Evaluation of a Nanofluid Containing Nanoparticles for Asphaltene Inhibition in Well CPSXL4,” by R. Zabala, E. Mora, C. Cespedes, L. Guarin, H. Acuna, and O. Botero, Ecopetrol; J.E. Patino, Petroraza; and F.B. Cortes, Universidad Nacional de Colombia, prepared for the 2013 Offshore Technology Conference Brasil, Rio de Janeiro, 29–31 October. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission.

There are four producers and two gas injectors. Oil production reached its peak in March 2001 at 41,722 STB/D. The average gas production at that date was 175 MMscf/D. Today, the recovery factors are 48.2% and 29.5% in the Mirador and Barco formations, respectively. There was no production plateau in Cupiagua Sur; instead, a constant decline rate is observed. This indicates the extreme conditions under which the reservoir was depleted, as well as the sources of damage. In Cupiagua Sur wells, the increase in CO2, compositional changes, pressure drop, and the revaporization caused by gas injection are the main factors favoring asphaltene destabilization and precipitation. Periodic cleaning jobs are performed in those wells by use of a chemical blend composed of an aliphatic/aromatic mix. These stimulation jobs have been effective in increasing oil production. However, the effective life of organic stimulation is very short and the wells need to be stimulated

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again after a few months. Chemical inhibition jobs also have been performed with polymers that act like resins for the asphaltene-inhibition mechanism. The method of using nanofluids containing alumina nanoparticles is expected to effectively extend the life of organic stimulations, preventing asphaltene precipitation downhole while maintaining a sufficient residual of nanoparticles within the reservoir. With the implementation of this nanotechnology, it will be possible to compare results between this novel method and the polymer-inhibition method.

Experimental Description

Asphaltene Isolation. The first stage of the study consisted of asphaltene extraction from a sample of oil by use of traditional methodology for asphaltene flocculation (adding n-heptane). The nheptane/oil mixture was prepared in a ratio of 40:1, and then the mixture was sonicated for 2 hours at 25°C, then put through centrifugation for 2 hours to complete decantation. The precipitate was then filtered through 8-μm What-

man paper and repeatedly washed with n-heptane to obtain a clean leachate. Finally, the filter containing asphaltene cake was dried in a vacuum for 24 hours. Adsorption Test. A stock solution of 1 g of asphaltenes in 0.5 L of toluene was prepared. Different dilutions were then prepared from this stock solution in order to produce a calibration curve by use of a spectrophotometer measuring runs at a wavelength of 295 nm. To construct isotherm curves, three different dilutions were prepared with concentrations of 25, 750, and 1,500 ppm and nanoparticles were added at 0.1 mg per 10 mL of solution. The vessels containing the solutions were submitted to a magnetic stirrer for 15 minutes, and allowed to stand for 5 minutes afterward. A sample of the supernatant was then taken, and an absorbance measurement was carried out in the spectrophotometer. This cycle was repeated continuously until two consecutive equal values were achieved, indicating that the equilibrium point had been reached. The time was recorded, and a curve representing ad-

sorption vs. time for the nanomaterial was elaborated. The nanofluid was prepared using a mixture of solvents as a carrier fluid for alumina nanoparticles. This carrier fluid, or mixture of solvents, needed sufficient viscosity to maintain nanoparticles in suspension and needed low surface tension in order to maintain appropriate dispersion of the nanoparticles. The solvent mixture also required good compatibility with the nanomaterial, avoiding any further reaction that might degrade or otherwise affect the nanoparticles. Aromatic solvents were not included in the nanofluid for environmental reasons. Upon preparation of the nanofluid, effectiveness in a core plug obtained from the Cupiagua Sur field was evaluated. Coreflooding Test and Results. These tests are fundamental for evaluation of the nanoparticles’ effectiveness for asphaltene inhibition in porous media, and also for determining return permeability in porous media after each flooding-test stage. For the coreflooding procedure used in the field, please see the complete paper.

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Changes in oil effective permeability show the alteration of permeability by asphaltene precipitation. After nheptane injection, without inhibition, asphaltene precipitation creates skin damage greater than 99% if it is compared with the original permeability. After cleanout with an injection of diesel, alcohol, and xylene (DAX), the skin damage was reduced to 37% and, after application of the nanofluid containing nanoparticles for asphaltene inhibition, additional skin-damage reduction to 34% was achieved. Inhibition is proved after application of nanoparticles; the oil effective permeability is maintained for a long time after 50 pore volumes of injected oil. Additionally, the relative permeability to oil visibly increases after application of the fluid containing alumina nanoparticles.

Field Application

For reasons detailed in the complete paper, Well CPSXL4 was the first well selected for testing the new stimulation technology. Developing a New Technology With Nanoparticles To Inhibit Asphaltene Deposition. Four chemical stimulations were performed in the well. The first one was conducted in January 2004 to attack inorganic deposits; this was followed in April 2006 with an inorganic/ organic stimulation. In January 2011, a selective stimulation was performed in the Barco and Mirador formations; the instantaneous oilrate increase was 152 BOPD. The chemical stimulation using inhibition developed with nanoparticles was designed to overcome the main problems associated with the previous inhibition methods. Usually, organic stimulations are performed for periodic cleaning or for removing asphaltene deposits that precipitate in these wells. Management of pressure drop is needed in the field to avoid large pressure drawdowns that accelerate flocculation and precipitation of asphaltenes. High flow rates and high pressure drops prevent good retention of conventional inhibitors of asphaltene formation. It is expected that asphaltene inhibitors based on nanoparticles such as nanoalumina have greater affinity for

the mineral structure of the reservoir rock (stronger adsorption) and can be retained for extended periods. Stimulation and Inhibition-Job Strategy in the CPSXL4 Cupiagua Sur Well. The overall stimulation job was performed in several stages to ensure the best reservoir conditions for the inhibition treatment. A pickling job was set to clean the production tubing, and an ethylene diaminetetraacetic acid treatment was begun to dissolve carbonate scale; an organic treatment stage was intended to dissolve organic scale. The inhibition job in CPSXL4 was carried out in December 2012, pumping 220 bbl of nano fluid containing alumina nanoparticles and 411 bbl of displacing fluid to reach the desired penetration radius of 7.2 ft. As displacing fluid, the DAX mixture was used. A coiled-tubing unit was used, and a selective packer was set between the Mirador and Barco formations. The job was performed, pumping fluid at a very low rate and at pressures below the fracture gradient. After 12 hours of soaking time, the well was opened for production at controlled flow rates.

Results

A production well test was performed between each stage to verify well performance. ◗◗ The net initial incremental oil rate was 1,280 BOPD. ◗◗ A performance increase (American Petroleum Institute scale) was observed, from 40 at the beginning of the stimulation job to 41.5 at the end of the inhibition with nanoparticles. ◗◗ Nodal system analysis showed an improvement obtained in inflow performance relationship (skin reduction); also, the vertical lift performance relationship was altered because of the increase in oil production. ◗◗ The post-inhibition/poststimulation production performance has been monitored for almost 8 months; during the last 3 months of that period, production has remained a constant 300 bbl above the baseline. JPT

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High-Performance Water-Based Drilling Fluids Offshore Cameroon

istorically, invert-emulsion drilling fluids are the preferred system for drilling offshore Cameroon. However, with a regulatory environment moving toward zero discharge, associated costs are rising. Therefore, an operator planning to drill in this environment investigated high-performance water-based-mud (HPWBM) -system alternatives. HPWBM systems offer the potential advantage of offshore discharge of drilled cuttings and effluents (owing to the absence of oil contamination) and lowered waste-management costs. Experience in the field demonstrated that the selected drilling fluid met expectations by achieving the required drilling performance and high shale stabilization with zero environmental impact.

KB Field

KF Field BaF Field

Ebome Ebodje

Introduction

Drilling with an overbalanced pressure is a common operational technique used to prevent formation fluids or gas from entering the wellbore, thereby minimizing the risk of well kick and blowout. However, overbalanced drilling can cause drilling fluid to invade the formation, resulting in formation damage, differential sticking, and sloughing if the formation consists of highly reactive clay and shale. To avoid these consequences, invert-emulsion drilling fluids have always been preferable for drilling highly reactive clays and shale formations.

Fig. 1—A location map of the BaF field in the Douala basin offshore Cameroon.

The HPWBM system is formulated with a concept of total inhibition. Unlike a conventional water-based-mud system, designed chemical additives are used explicitly in the formulation to achieve desired drilling characteristics that are similar to those of invert-emulsion mud. The key features of HPWBM systems include high shale stability, clay and cuttings inhibition, rate-of- penetration (ROP) enhancement, mini-

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 163502, “High-Performance Water-Based Drilling Fluids: An Environmentally Friendly Fluid System Achieving Superior Shale Stabilization While Meeting Discharge Requirement Offshore Cameroon,” by Anuradee Witthayapanyanon, SPE, Baker Hughes; Jerome Leleux, SPE, Julien Vuillemet, Ronan Morvan, and Andre Pomian, Perenco; and Alain Denax and Ronald Bland, SPE, Baker Hughes, prepared for the 2013 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 5–7 March. The paper has not been peer reviewed.

mized bit balling and accretion, torque and drag reduction, and environmental compliance. A complementary benefit of its aqueous base is that HPWBM captures the growing need for more- environmentally-friendly drilling fluids. During the past 10 years, more-stringent regulations on drilling-waste disposal have been implemented worldwide. The industry anticipates that the zero discharge of oil-contaminated drilling wastes will soon be the global standard. By switching from invert-emulsion drilling fluids (oil-/ synthetic-based mud) to an HPWBM system, operators can achieve substantial cost savings on waste management and logistics. These savings result from the use of on-site, offshore discharge allowed by an absence of oil contamination.

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Field Background

Fig. 1 displays the location of the BaF field in the Douala basin offshore Cameroon. The operator has been drilling a number of wells in these fields, most of which were development wells. According to the operator’s drilling campaign, three offset wells were drilled with synthetic-based muds (SBMs) and five wells were drilled with HPWBMs in the BaF field. Our reference offset well (Offset Well 3) was the last SBM well, drilled in late 2005.

Operator’s Selection Criteria for HPWBM

On the basis of the historical data of the offset well, approximately 1933 t of oil-contaminated drill cuttings and 37,834 bbl of waste water were generated from drilling with SBM. With past SBM practice, the operator obtained environmental permits that allowed the discharge of untreated synthetic-based wastes from the platforms directly into the ocean. However, there is a strong anticipation that the Cameroonian government will begin placing stronger restrictions on ocean discharges of SBM and oil-contaminated cuttings. If the regulatory agency leans toward a zero-discharge limit, the operator will be liable for the transfer of oil- contaminated drill cuttings to land for any further treatment. The secondary consideration was that the operator had already used the HPWBM system for shale inhibition onshore in the Peruvian jungle and in Colombia, Cameroon, and Gabon. The system showed success in achieving high shale inhibition, preventing clay and cuttings hydration, and reducing bit balling. The operation was successful, without any hole-related problems. Therefore, when the operator planned to drill the next offshore development well in BaF field, they selected the HPWBM with a saturated NaCl system as an alternative to traditional SBM. This transition has been taking place since 2011.

HPWBM Design

The shale formation is known to act as a semipermeable (selective) membrane because the clay-rich matrix hinders the movement of some solutes. The selec-

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tivity of the shale membrane increases with decreasing shale permeability. Therefore, the design of the HPWBM formulation is aimed to form in-situ, effective sealing under downhole conditions, improving the efficiency of the semipermeable membrane. In this work, the HPWBM components contributing to shale stability were sealing polymer, aluminum complex, and NaCl brine. Because of its extremely small particle size, a nanosized polymer sealant provides a mechanical plug for shale pore throats and shale microfractures, while the aluminum complex chemically precipitates inside the pore throats and shale matrix because of the change in Fig. 2—Electric-logging image with pH or the interaction with multivalent six-arm caliper of the (left) 12¼-in.cations in the formation. A coprecipita- and (right) 8½-in.-hole sections of the tion of polymer sealant and aluminum HPWBM Well 6. complex forms a good membrane sealing that imposes a water flow from the in membrane efficiency and osmotic wellbore to the formation side. In ad- pressure differential of the HPWBM led dition, the HPWBM formulation used to a significant reduction in the pore- the NaCl brine to lower water activity of pressure transmission. One of the technical challenges inmud and increase the osmostic gradient, causing the fluid to flow from inside volving water-based muds is control of PressureAd_JPT9_12_Layout 1 8/7/12 8:27 AM Page 1 the pore to the wellbore. An increase the hydration of reactive clays. Clays

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Slugging It Out XXII

consist of negatively charged aluminosilicate layers kept together by cations. Clay hydration begins with a surface hydration (a bonding between water molecules and oxygen on clay surface) and ionic hydration (the hydration of interlayer cations with surrounding shells of water molecules). The ability to adsorb water between the layers results in strong repulsive forces and interlayer expansion (swelling). Severe clay hydration and dispersion in water-based mud can lead to poor fluid rheological properties. In the HPWBM formulation, an environmentally acceptable watersoluble clay-hydration suppressant was used in conjunction with monovalent salt (in this case NaCl) to reduce the swelling and dispersion of highly reactive clays by a cation-exchange mechanism. A similar chemical inhibition approach can also be applied to drillcuttings inhibition.

Drilling Performance Evaluation: Offset vs. HPWBM Test Wells

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Offset-Well Review. Well 3 is a J-type directional well. There were two sections (12¼-in. and 8½-in.) drilled with SBM. The 12¼-in. section drilled with 1.25-specific gravity (SG) SBM was the directional drilling, with a final inclination of 68° and an average ROP of 17.5 m/h. The following section (8½-in.) was drilled with 1.16-SG SBM, with an average ROP of 11 m/hr and a final inclination of 90°; then, the 7-in. slotted liner was run to total depth with a gas lift completion. The well’s true vertical depth was 700 m. Test Wells: HPWBM Achievements. The operator performed a 1-year campaign to evaluate the HPWBM system for offshore drilling from March 2011 to March 2012. Five wells were drilled with the HPWBM system in the BaF field. Here, the performance of HPWBM in the last three wells (6, 7, and 8) is evaluated. In these three test wells, the HPWBM system was employed in the 12¼-in.- and 8½-in.-hole sections. In Well 6, operator review indicated that the 12¼-in.-hole section drilled with the 1.35- to 1.4-SG HPWBM provides a good ROP of 14.6 m/h. The section total depth was achieved in 2 days

with no back reaming. Electric logging with a six-arm caliper (Fig. 2) shows no washout, with an average of 12¼‑in. mean internal diameter. Both casing and cementing operations were completed without any issues. Similar findings were also observed in the 8½-in. section drilled with 1.25- to 1.30-SG HPWBM. The section daily mud report of Well 7 indicated that the cuttings appeared to be very dry and remained integrated. This finding suggests superior clay- and cuttings-inhibition performance of the HPWBM. Additionally, the report indicated that a good hole condition existed when performed back to bottom. As noted in the report, the hole was circulated clean and was confirmed stable by the flow check before tripping out without any noticeable drag. At the end of Well 7, the 63 m3 of a 1.24-SG HPWBM was transfered for reuse to drill the next well (Well 8). In that well, recycled mud was reconditioned with additives, mainly to increase mud weight to 1.40 SG, and then combined with the freshly formed HPWBM in the active pit. The results show that the HPWBM still maintains desirable rheological properties. The ability to reuse or recycle the HPWBM system provides an added benefit of reducing drilling-mud cost for the operator. The operator was able to decrease the total operational cost by a range of 13 to 30% from the planned budget by use of the HPWBM system. Furthermore, because the HPWBM is an environmentally compliant fluid, the spent mud and drill cuttings can be discharged directly and do not require further drilling-waste treatment.

Conclusions

After the 1-year campaign, well recaps indicated that the HPWBM proved to be an excellent alternative to the invert- emulsion mud for the BaF field. The system delivered high drilling performance and optimum characteristics such as shale stability and clay and cuttings inhibition as well as a high ROP. The operator experienced no wellbore problems. From an environmental perspective, because of the absence of oil contamination, the system eliminated the rig costs associating with drillingwaste management. JPT

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Nanotechnology Applications for Challenges in Egypt

recise manipulation and control of matter at dimensions of 1–100 nm have transformed many industries including the oil and gas industry. Nanosensors enhance the resolution of subsurface imaging, leading to advanced field-characterization techniques. Nanotechnology could greatly enhance oil recovery by use of molecular modification and by manipulating interfacial characteristics. Egypt’s oil consumption has grown by more than 30% in the past 10 years. Hydrocarbon reserves in Egypt have increased 5%/year over the past 7 years, while the average recovery factor remains at 35%. Nanotechnology is key to solving this production/ consumption imbalance.

Introduction

Nanotechnology is the use of very small pieces of material, with dimensions between approximately 1 and 100 nm, by themselves or by manipulation to create new larger-scale materials with unique phenomena enabling novel applications. A nanometer is one-billionth of a meter—a distance equal to two to twenty atoms laid down next to each other (depending on the type of atom). Nanotechnology refers to manipulating the structure of matter on a length scale of nanometers, interpreted at different times as meaning anything from 0.1 nm (controlling the arrangement of individual atoms) to 100 nm or more. Fig. 1 compares the scale of various items referenced to a nanometer.

Pencil Tip

H2O 0.1

Glucose Molecule 1

Bacterium Virus 10

100

1000

Cancer Cell

104

Tennis Ball 105

106

107

108

Nanometers Fullerenes Antibodies

Nanoparticles

Carbon Nanotubes Fig. 1—Scale of items referenced to a nanometer.

Engineered Nanomaterials

Nanoparticles are the simplest form of structures with sizes in the nanometer range. In principle, any collection of atoms bonded together with a structural radius <100 nm can be considered a nanoparticle. The tiny nature of nanoparticles yields useful characteristics, such as increased surface area to which other materials can bond in ways that make stronger or lighter materials. At the nanoscale, size is a factor regarding how molecules react to and bond with each other. Suspensions of nanoparticles are possible because the interaction of the particle surface with the solvent is strong enough to overcome differences in density, which usually would result in a material either sinking or floating in a liquidforming nanofluid. Nanofluids for oil and gas applications are defined as any fluid used in the exploration and exploitation of oil and gas that contains at least one

This article, written by Dennis Denney, contains highlights of paper SPE 164716, “Applications of Nanotechnology in the Oil and Gas Industry: Latest Trends Worldwide and Future Challenges in Egypt,” by Abdelrahman Ibrahim El-Diasty, SPE, and Adel M. Salem Ragab, American University in Cairo and Suez University, prepared for the 2013 North Africa Technical Conference & Exhibition, Cairo, 15–17 April. The paper has not been peer reviewed.

additive with a particle size in the range of 1–100 nm. A few oilfield uses are described in the following. See the complete paper for additional uses and details.

Exploration

Nanoparticles with noticeable alterations in optical, magnetic, and electrical properties compared with their bulk counterparts are excellent tools for developing sensors and imaging-contrast agents. Hyperpolarized-silicon nanoparticles provide a tool for measuring and imaging in oil exploration. There are several programs to develop nanosensors with temperature and pressure ratings allowing use in deep wells and hostile environments. Nanosensors are deployed into the pore space by means of nanodust to acquire data on reservoir characterization, fluid-flow monitoring, and fluid-type recognition. Nanocomputerized tomography can image tight gas sands, tight shales, and tight carbonates in which the pore structure is too small to be detected with conventional computerized-tomography techniques. Fluid-Loss Control and Wellbore Stability. Several researchers are investigating the use of nanoparticles as drilling-fluid additives to reduce fluid

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cal properties that are not available in conventional materials. Oil droplet Wedge-film nanoparticle suspension

Vertex Solid Fig. 2—Nanoparticle structuring in the wedge film.

loss and enhance wellbore stability. Filter cake developed with nanoparticlebased drilling-fluid filtration is very thin, which implies high potential for reducing differential-pressure sticking and formation damage while drilling. In shale formations with nanodarcy permeability, the nanometer-sized pores prevent the filter cake from forming, which in turn allows fluid loss. Nanoparticles can be added to the drilling fluid to minimize shale permeability by physically plugging the nanometer-sized pores and shutting off water loss. Hence, nanoparticles can provide a solution in environmentally sensitive areas where oil-based muds currently are used for shale-instability problems. Torque and Drag. Because nanomaterials can form fine and very thin films, nanoparticle-based fluids can significantly reduce the frictional resistance between the pipe and the borehole wall by forming a continuous thin lubricating film at the wall/pipe interface. Also, the tiny spherical nanoparticles may create an ultrathin ball-bearing-type surface between the pipe and the borehole wall that would allow easy sliding of the drillstring along the nanoparticle-based ball-bearing-type surface. Nanoparticlebased fluids could be especially useful in reducing the torque-and-drag problems in horizontal, extended-reach, multilateral, and coiled-tubing drilling. High-Pressure/High-Temperature (HP/HT) Challenges. In HP/HT drilling operations, many drilling-fluid systems have a relatively poor heat-transfer coefficient. The cooling efficiency of traditional drilling fluids decreases because of slow heat dissipation from the surfaces of downhole tools and equipment. Hence, there is a higher probability of equip-

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ment failure caused by thermal degradation. The extremely high surface-area/ volume ratio of nanoparticles enhances the thermal conductivity of nanoparticlebased drilling fluids, providing efficient cooling of the drill bit and leading to a significant increase in the operating life cycle of a drill bit. Diamond-Nanoparticle Technology. Carbon nanomaterials have unique combinations of mechanical, structural, electrical, and thermal properties. Diamond nanoparticles have been functionalized for polycrystalline-diamond applications such as polycrystalline-diamondcompact (PDC) cutters for drill bits. Diamond nanoparticles provide unique surface characteristics to PDC cutters that allow them to integrate homogeneously into the PDC synthesis. High-Strength Nanostructured Materials. Flow-control and completion devices (e.g., fracturing balls, disks, and plugs) are used for sleeve actuation or stimulation diversion during fracturing. Traditional lightweight material for ball or plug applications is prone to early deformation. The yield strength of conventional aluminum alloys usually is less than 400 MPa. Nanotechnology can be used to enhance the mechanical properties (and other properties) through engineering the material microstructure. Controlled-electrolyticmetallic nanostructured materials are lighter than aluminum and stronger than some mild steels, but disintegrate when exposed to the appropriate fluid. The disintegration process works through electrochemical reactions that are controlled by nanoscale coatings that are part of the composite-grain structure. The nanomatrix of the material is high strength and has unique chemi-

Cement Properties. Because of the very high surface area of nanomaterials, they can be used in casing cementing to accelerate the cement-hydration process, increase the compressive strength, help control fluid loss, reduce the probability of casing collapse, and prevent gas migration, a common cementing problem in gas wells. Also, the required quantity of nanomaterials is small.

Production

Gas hydrate is an ice-like crystalline solid formed from a mixture of water and natural gas, usually methane. Hydrates can produce a gaseous-methane volume 160 times the hydrate volume. Injecting airsuspended self-heating Ni-Fe nanoparticles (50 nm) into the hydrate formation through a horizontal well has been suggested. These particles will penetrate deep into the Class I, II, and H hydrate reservoirs by passing through the cavities (86- to 95-nm diameter). Self-heating of Ni-Fe particles in a magnetic field is caused by hysteresis loss and relaxation losses. These particles provide a temperature rise up to 42°C in the formation, disturbing the thermodynamic equilibrium and causing the water cage to decompose and release methane. In this technique, the pressure of the fluids in contact with hydrate is lowered, pushing the hydrate out of its stability region, which results in its decomposition. Viscoelastic-Surfactant (VES) Stimulation. High-molecular-weight crosslinkedpolymer fluids have been used to stimulate oil and gas wells for decades. These fluids exhibit exceptional viscosity, thermal stability, proppant transportability, and fluid-leakoff control. However, a major drawback of crosslinked-polymer fluids is the amount of polymer left behind. Polymer residue can damage formation permeability and reduce fracture conductivity significantly. Nanoparticles, through chemisorption and surface-charge attraction, associate with VES micelles to stabilize fluid viscosity at high temperatures and produce a pseudofilter cake of VES fluid that reduces fluid loss significantly. When internal breakers are used to break the

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Make Every Frac Count Geoscience solutions for unconventional resources

The benefts of integrated geoscience and drilling technologies include proper positioning of frac zones within targeted reservoirs to maximize production.

Success in the exploration and development of unconventional source rock plays (shale, carbonate gas and oil, tight gas, etc.) depends largely on thorough integration of geoscience and drilling technologies. The CGG and Baker Hughes Shale Science Alliance has developed a ft-for-purpose integrated solution to successfully explore and develop unconventional resources. Our scientifc approach supports effcient well placement and optimized hydraulic fracturing by estimating rock brittleness and stress derived from seismic data that is calibrated with formation evaluation and geological data to provide predictive models for well trajectory planning and completion (frac) modeling analysis and design.

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Oil-Recovery Factor, %OOIP

Nanofluid Breakthrough

Water

Breakthrough

PV Injected Fig. 3—Waterflood performance compared with nanofluid flooding. PV=pore volume.

VES micelles, the fluid viscosity will decrease dramatically and the pseudofilter cake will break into nanometer-sized particles. Because the particles are small enough to pass through the pore throats of producing formations, they will flow back with the producing fluids and no damage will be generated.

Reservoir Characterization and Management

Nanoparticles are small enough to pass through pore throats in typical reservoirs, but they can be retained by the rock. Nanoparticles in an aqueous dispersion will assemble into structural arrays at a discontinuous phase such as oil, gas, paraffin, or polymer. The nanoparticles in this three-phase-contact region tend to form a wedge-like structure and force themselves between the discontinuous phase and the substrate. Particles in the bulk fluid exert pressure forcing the nanoparticles in the confined region forward, imparting the disjoining-pressure force. The energies that drive this mechanism are Brownian motion and electrostatic repulsion between the nanoparticles. The force imparted by a single nanoparticle is extremely weak, but when a large amount of nanoparticles exists, referred to as the particle-volume fraction, the force can be upward of 50 kPa at the vertex, as shown in Fig. 2. When this force is confined to the vertex of the dis-

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continuous phase, displacement occurs in an attempt to regain equilibrium.

Challenges in Egypt

Egypt’s domestic demand for oil is increasing rapidly. Local production has not kept up with this demand increase. Field development is considered an effective solution to meet the increasing energy demand. Nanotechnology could be key to solving this production challenge because it helps increase oil recovery while decreasing the cost of production by eliminating problems that occur throughout field operations. To increase production, Egypt has a large heavy-oil resource to develop. Also, unconventional resources have not been explored. Current technology updates must be applied to explore more fields and improve development operations. Advanced exploration methods, remote sensing, and improved-resolution seismic are needed. Nanosensors for imaging can improve exploration success by improving data gathering, recognizing shallow hazards, and avoiding dry holes. To decrease production costs, many solutions have been mentioned for the largest problems in development operations including drilling, cementing, logging, completion, and production. The use of silica nanoparticles on an Egyptian formation was studied to compare waterflooding and nanofluid flooding. Fig. 3 shows that waterflood-

ing displaced the oil to recover 36% of the original oil in place (OOIP) at the breakthrough point. Nanofluid flooding recovered 67% of OOIP at the breakthrough point. This increase shows that the nanofluid can displace oil better than the water can.

Conclusions

Potential applications of nanotechnology include the following: ◗◗ Improvement of exploration by improving data gathering, recognizing shallow hazards, and avoiding dry holes ◗◗ Providing strength and endurance through nanotechnology-enhanced materials to increase the performance and reliability in drilling, tubular goods, and rotating parts ◗◗ Improvement of elastomers that are critical to deep drilling and drilling in HP/HT environments ◗◗ Production assurance through diagnostics, monitoring/ surveillance, and management strategies ◗◗ Selective filtration and waste management for water ◗◗ Enhanced oil and gas recovery through reservoir-property modification, facility retrofitting, gas-property modification, and water injection. JPT

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CONFERENCE PREVIEW

Drilling Conference Covers Depth and Breadth of Industry Fort Worth, Texas, will be the setting for annual drilling conference sponsored by SPE and the International Association of Drilling Contractors (IADC). The conference alternates between a US location and Amsterdam. This year’s conference, set for 4–6 March at the Fort Worth Convention Center, will include one plenary and 18 technical sessions covering the depth and breadth of the drilling industry. The first day of the conference kicks off with a welcome address and an awards session. Welcome speeches will be delivered by 2014 IADC/SPE Drilling Conference Chairman Kevin Neveu, 2014 IADC Chairman Jay Minmier, and 2014 SPE President Jeff Spath. The 2014 SPE Drilling Engineering Award will be presented to Rolv Rommetveit, managing director of eDrilling Solutions, who has extensive technology development experience in the fields of well control, drilling hydraulics, managed pressure drilling, and drilling process automation. The opening keynote address will be given by Doug Suttles of Encana on the topic of “What Are the Critical Issues in Today’s Energy World?” Technical paper sessions on the first day will cover such topics as drilling dynamics, underbalanced and managed pressure drilling, drilling contracts and management, casing and riser integrity, and drill bit innovation. The second day of the conference will feature a plenary session on “Eventually That Which Is Unconventional, but Successful, Becomes the Conventional.” Panelists will discuss the growth in unconventionals production, challenges to further commercialization of resourc-

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es, technological advances, the strain on capital and talent, and public perception. The session moderator will be Kevin A. Neveu of Precision Drilling. Panelists will be Jeffery Lee Flaherty, Helmerich & Payne International Drilling Co.; Karl Blanchard, Halliburton; and Michael Power, Chevron. Technical paper topics on the second day of the conference include tubulars, cementing, directional drill-

ing, automation, and deepwater drilling. Among the technical sessions on the conference’s last day are wellbore strengthening, safety, case studies, and drilling technology. Several training courses will be held both before and after the conference. JPT For more detailed information on the conference, please go to www.spe.org/ events/dc.

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SPE NEWS

SPE SERVICE DIRECTORY SPE Online www.spe.org Awards Program Tom Whipple, twhipple@spe.org Phone: 1.972.952.9452

SPE’s Myanmar Section Created SPE now has a presence in Myanmar. Its 214th section—the Myanmar Section—was established 25 September 2013. The SPE International Board of Directors meeting this month will be held in Yangon, and the section’s inauguration will become official with that meeting. According to Jeff Spath, SPE president, in his column in this issue of JPT, the new Myanmar Section’s presence has been enthusiastically welcomed. “The response by industry, academia, and government has been remarkable,” he said.

Book Sales Phone: 1.800.456.6863 or 1.972.952.9393 books@spe.org Continuing Education/Training Courses Chiwila Mumba-Black, cmumba@spe.org Phone: 1.972.952.1114 Distinguished Lecturer Program Donna Neukum, dneukum@spe.org Phone: 1.972.952.9454 Dues, Membership Information, Address Changes, Copyright Permission Phone: 1.800.456.6863 or 1.972.952.9393 service@spe.org

MYINT

Insurance/Credit Card Programs Liane DaMommio, ldamommio@spe.org Phone: 1.972.952.1155 JPT Professional Services Evan Carthey, ecarthey@spe.org Phone: 1.713.457.6828 JPT/JPT Web Advertising Sales Craig Moritz, cmoritz@spe.org Phone: 1.713.457.6888 JPT John Donnelly, jdonnelly@spe.org Phone: 1.713.457.6816 Peer Review Stacie Hughes, shughes@spe.org Phone: 1.972.952.9343 Professional Development Services Tom Whipple, twhipple@spe.org Phone: 1.972.952.9452 Section Service Phone: 1.972.952.9451 sections@spe.org SPE Website John Donnelly, jdonnelly@spe.org Phone: 1.713.457.6816 Subscriptions Phone: 1.800.456.6863 or 1.972.952.9393 service@spe.org

Officers of the new Myanmar Section. Standing from left: Program Chairperson, Bertrand Jean Daniel Brun, manager, Total E&P; Program Chairperson, Gagan Singhal, former country general manager, Schlumberger Asia Services; Section Activities Chairperson, Sahawit S. Vorasaph, senior manager Myanmar operations, PTT Exploration and Production; Membership Chairperson, Sean Danley, senior business development manager, Halliburton; Treasurer, Ahkar Aung, legal supervisor, Daewoo E&P. Seated from left: VC-Secretary, Aung Kyaw Min, director industry and university relations, Schlumberger Logelco; Chairperson, Ahmad Lutpi Haron, country chairman, Pentronas; Student Chapter Liaison, Zaw Htet Aung, head of Petroleum Engineering Department, Yangon Technological University. Pictured separately: YP Chairperson, Sithu Moe Myint, technical manager, MRPL E&P.

R&D Competition Focuses on Industry’s “Grand Challenges” The oil and gas E&P industry faces big challenges to meet the world’s growing energy needs and the solutions are uncertain. For that reason, SPE is holding a Research and Development (R&D) Competition to encourage researchers from the basic sciences and other engineering disciplines to engage these challenges. The competition focuses on six Grand Challenges identified by the SPE R&D Committee:

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Americas Office 222 Palisades Creek Dr., Richardson, TX 75080-2040 USA Tel: +1.972.952.9393 Fax: +1.972.952.9435 Email: spedal@spe.org Asia Pacific Office Level 35, The Gardens South Tower Mid Valley City, Lingkaran Syed Putra, 59200 Kuala Lumpur, Malaysia Tel: +60.3.2182.3000 Fax: +60.3.2182.3030 Email: spekl@spe.org Canada Office Eau Claire Place II, Suite 900–521 3rd Ave SW, Calgary, AB T2P 3T3 Tel: +403.930.5454 Fax: +403.930.5470 Email: specal@spe.org Europe, Russia, Caspian, and Sub-Saharan Africa Office 1st Floor, Threeways House, 40/44 Clipstone Street London W1W 5DW UK Tel: +44.20.7299.3300 Fax: +44.20.7299.3309 Email: spelon@spe.org Houston Office 10777 Westheimer Rd., Suite 1075, Houston, TX 77042-3455 USA Tel: +1.713.779.9595 Fax: +1.713.779.4216 Email: spehou@spe.org Middle East, North Africa, and South Asia Office Office 3101/02, 31st Floor, Fortune Tower, JLT, P.O. Box 215959, Dubai, UAE Tel: +971.4.457.5800 Fax: +971.4.457.3164 Email: spedub@spe.org Moscow Office Perynovsky Per., 3 Bld. 2 Moscow, Russia, 127055 Tel: +7.495.268.04.54 Email: spemos@spe.org

JPT • FEBRUARY 2014

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◗◗Increasing recovery factors from oil and gas fields ◗◗In-situ molecular manipulation ◗◗Carbon capture, storage, and sequestration ◗◗Produced water management ◗◗Higher-resolution subsurface imaging of hydrocarbons ◗◗Minimized environmental impact The competition is open to academia, research institutes and organizations, companies, and individuals. Proposals submitted should include the following requirements: ◗◗Address one of the six Grand Challenges listed above ◗◗ Involve ideas and/or technologies not previously used in petroleum engineering ◗◗ Propose application of technology not already used commercially in the oil and gas industry

The top finalists will be invited as guests of SPE to the 2014 SPE Annual Technical Conference and Exhibition in Amsterdam on 27–29 October, where they will present their proposal in a special session to a panel of industry judges. Awards of USD 30,000 for first place, USD 20,000 for second place, and USD 10,000 for third place will be announced at the SPE President’s Luncheon on the last day of the conference. Submissions for the competition are being accepted online through 1 June 2014. Those who submit by 31 March will have the opportunity to be assigned an industry mentor to provide advice on how to improve the proposal before the final submission deadline. For more information, please go to www.spe.org/industry/ competition.php

Innovative Teaching, Faculty Recruitment Awards Given SPE has honored several university professors for their excellence in teaching and efforts to recruit faculty and students to petroleum engineering schools. The SPE Faculty Innovative Teaching Award recognizes and rewards teaching excellence in petroleum engineering and supports the attraction and retention of faculty in the discipline. The 2013 winners were ◗◗ David DiCarlo, The University of Texas at Austin, for his creative methods in relating fundamental, abstract concepts to the petroleum industry; for his traditional methods tuned to the modern student; and for his dedication to preparing students to effectively present their research in SPE paper contests and technical meetings ◗◗ Shenglai Yang, The China University of Petroleum, Beijing, China, for his passion and excellence in petroleum engineering education, specifically in creating a team teaching approach in petrophysics that has won both local and national awards and has impacted more than 5,000 students and for promoting the use and comprehension of the English language in classrooms and through the publication of Englishbased textbooks The SPE Faculty Recruitment Award recognizes petroleum engineering faculty who have developed innovative techniques to recruit doctorial students, faculty from other disciplines, and industry personnel to consider an academic career in petroleum engineering. Winners of thet 2013 award were ◗◗ Brian Evans, Curtin University, in recognition of his use of innovative methods to attract students to enroll in a PhD program and to consider a career in academia, and to attract PhD graduates back to roles in academia ◗◗ Russel Johns, Pennsylvania State University, in recognition of his use of innovative methods to attract

JPT • FEBRUARY 2014

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students with a commitment to first-class research in petroleum engineering with attention to detail in order to find practical new solutions for the current problems of the petroleum industry

Be a part of the SPE Opinion Panel Short on time? This volunteer opportunity is for you. For less than one hour of your time each month, you can help shape the future of SPE products and services. Join the SPE Opinion Panel and give feedback about the Society and its programs, as well as participate in industry and technical topic research. Getting started is easy. For more information, www.spe.org/volunteer.

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PEOPLE

JUAN A. PINZON, SPE, joined BHP Billiton (BHPB) as drilling development manager of its Global Petroleum Division. Pinzon has more than 20 years’ oil and gas industry experience and has held engineering and management positions at BP, Schlumberger, and Occidental Petroleum (OXY). He began his career with BP where he gained experience in exploration, development, and appraisal projects in Colombia, South America. He worked with Schlumberger as drilling engineering manager for North and South America for its Drilling and Measurement Division, based in Houston. Pinzon also worked for BP America, where he held drilling positions in projects in southeast Texas, south Louisiana, and Wyoming. Before joining BHPB, he worked for OXY where he worked as drilling team lead for the Permian Basin. He was awarded a Certificate of Service by the American Association of Drilling Engineers. Pinzon earned a BS in petroleum engineering from Universidad de America in Bogota, Colombia.

Member Deaths Ray Allen Barton, Medina, Texas, USA Ian Muir Cheshire, Abingdon, UK George Dausch Jr., Mandeville, Louisiana, USA Neil R. Edmunds, Calgary, Alberta, Canada Charles H. Martin, Warrenton, Oregon, USA Charles H. Ware, Palm Harbor, Florida, USA

SPE Faculty Grants and Awards

Get rewarded for a job well done! SPE-sponsored grants and awards help faculty educate the next generation of petroleum engineers and industry leaders.

Accepting 2014 applications for • SPE Faculty Innovative Teaching Award • SPE Faculty Recruitment Award • SPE New-Faculty Research Grant Deadline: 15 April

For qualification and application information, please visit www.spe.org/members/faculty.

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JPT • FEBRUARY 2014

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JPT • FEBRUARY 2014

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Unconventional resource studies Integrated reservoir description projects Detailed petrophysical analyses www.wallace-international.com Office: 972-386-4581

WELL COMPLETION TECHNOLOGY William K. (Bill) Ott, P.E. • Sand Control • Well Completion • Stimulation • Formation Damage Control • Cementing • Technical Schools • Equipment Trading • Consulting 7903 Alamar Drive Tel: 281-859-6464 Houston, TX 77095-2840 Fax: 281-855-3004 USA E-mail: info@wcthou.com

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ADVERTISERS IN THIS ISSUE AAPG Pages 27, 107

M-I SWACO Page 13

QRI Page 43

Baker Hughes Inc. Page 81

McCoy Global Page 85

Sandvik Materials Technology Page 41

Brookfield Engineering Page 75

Messe Dusseldorf Page 65

Schlumberger Pages 3, 21, Cover 2

Cameron Page 2

Mewbourne College of Earth & Energy—University of Oklahoma Page 15

Semaphore Page 73

Carbo Ceramics, Inc. Page 79 CESI Chemical Page 71 CGG Page 125 Cudd Energy Services Page 111 Dragon Products, Ltd. Page 29 FANN Page 37 FMC Technologies Page 11 Forum Energy Technologies Page 9 Friedrich Leutert GmbH & Co. KG Page 110 Halliburton Pages 23, 47, Cover 3 High Pressure Equipment Company Page 121 KAPPA Cover 4

Momentive Page 45

2 0 1 4

Sintex Page 4 Solvay Novacare Page 31

MSi Kenny Page 87 National Oilwell Varco Page 63 NCS Energy Services, Inc. Page 61 Newpark Drilling Fluids Page 19 Oil Plus Ltd. Page 99

Statoil Page 17 TAM International Page 57 TBC-Brinadd Page 67 Tejas Tubular Products Page 5 TMK IPSCO Page 51

OneSubsea Page 25

University of Alaska Fairbanks Page 115

Orr Safety Page 55

Varel International Page 97

Packers Plus Page 7

Volant Products, Inc. Page 83

Petrolink Page 89

Weatherford International Ltd. Page 91

Postle Industries Pages 33, 35 Price College of Business— University of Oklahoma Page 119

Well Control School Page 93

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SPE EVENTS WORKSHOPS

8–10 April ◗ Banff—Land Well Integrity: Current Challenges

1–3 April ◗ Utrecht—SPE Intelligent Energy Conference and Exhibition

23–26 February ◗ Phuket— Managed Pressure Drilling, Underbalanced Drilling, and Well Controls

15–17 April ◗ Dubai—Sour H2S and CO2 Rich Oil and Gas Projects: Lessons Learnt So Far and Have We Figured It All Out

1–3 April ◗ The Woodlands— SPE Unconventional Resources Conference—USA

24–25 February ◗ Muscat—SPE Mature Assets: Learning from the Past, Planning for the Future

23–24 April ◗ Lima—SPE Oil and Gas Facilities

2 April ◗ Bergen—SPE Bergen One Day Seminar

12–13 May ◗ Dubai—SPE Global Integrated Workshop Series: Production Forecasting

8–9 April ◗ Madrid—SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition

24–25 February ◗ Dubai—Completion and Stimulation of Maximum Reservoir Contact and Complex Wells 24–26 February ◗ Dubai—Reservoir Nanoagents: Taming Complexities on Road to Deployment 4–5 March ◗ London—SPE Effective Waterflooding: An Integrated Approach 4–7 March ◗ Kyoto—Nanotechnology and Nano-Geoscience in Oil and Gas Industry 5–6 March ◗ Baku—Sand Management in Poorly Consolidated Formations 9–12 March ◗ Bangkok—SPE Hydraulic Fracture: Building on the Past to Create the Future 9–12 March ◗ Langkawi—SPE EOR Stimulation: Are We There Yet?

13–14 May ◗ Canmore—Steam-Solvent, Solvent, and Steam Additive for Process Heavy Oil Recovery 13–14 May ◗ Halifax—SPE Environmental Impact: Technical Solutions for the Exploration of Oil and Gas Resources 18–21 May ◗ Bali—SPE Deepwater Drilling 18–21 May ◗ Sonoma—SPE Optimizing Liquids-Rich Development: Marginal to Mega 25–28 May ◗ Ho Chi Minh—SPE/AAPG Joint Workshop: Optimizing Production by Understanding the Reservoir: Reservoir Quality, Architecture, Petrophysics, Rock 26–27 May ◗ Dubai—SPE Reservoir Testing: Key Enabler for Accurate Reservoir Characterization

12–16 April ◗ Tulsa—Improved Oil Recovery Symposium 14–16 April ◗ Kuwait City—Oilfield Water Management Conference and Exhibition 17–18 April ◗ Denver—Western North American and Rocky Mountain Joint Meeting 21–24 April ◗ Al Khobar—SPE-SAS Annual Technical Symposium and Exhibition 5–8 May ◗ Houston—Offshore Technology Conference 12–13 May ◗ Aberdeen—International Oilfield Corrosion Conference and Exhibition

10–11 March ◗ Abu Dhabi—Challenges of Mega Projects: Managing Project Execution from Conception to Operation

27–29 May ◗ Quito—SPE Applying the Best Technologies in Extremely Sensitive Environments

11–12 March ◗ San Antonio— SPE/AAPG/SEG Pore Pressure Workshop

Conferences

19–20 May ◗ Houston—SPE Hydrocarbon Economics and Evaluation Symposium

25–27 February ◗ Vienna—SPE/EAGE European Unconventional Resources Conference and Exhibition

21–23 May ◗ Maracaibo—Latin America and Caribbean Petroleum Engineering Conference

26–28 February ◗ Lafayette—International Symposium and Exhibition on Formation Damage Control

FORUMS

17–18 March ◗ Abu Dhabi—SPE Working Towards Holistic Risk Management in Oil and Gas Industry 17–19 March ◗ Dubai—Petroleum Economics: Optimizing Value throughout the Asset Life Cycle 19–20 March ◗ London—SPE Petroleum Reserves and Resources Estimation— Petroleum Resources Management System (PRMS) Applications Guidelines Document and Case Studies 19–20 March ◗ Guadalajara— SPE Geomechanics 30–31 March ◗ Basra—Iraq Field Development Experiences 1–2 April ◗ Austin—SPE/ASPE Downhole Precision Tools in HPHT Applications: Filling the Gaps 6–9 April ◗ Kota Kinabalu—SPE Formation Damage Mitigation and Remediation

14–15 May ◗ Aberdeen—International Oilfield Scale Conference and Exhibition

4–6 March ◗ Fort Worth—IADC/SPE Drilling Conference and Exhibition

17–20 March ◗ Abu Dhabi—Overcoming Challenges in Developing Shale and Tight Gas Reservoirs

17–19 March ◗ Long Beach—SPE International Conference on Health, Safety, and Environment

18–23 May ◗ Bali—SPE High CO2 and H2S Gas Fields Development: Completions and Production Operations

25–26 March ◗ The Woodlands— SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition

1–6 June ◗ San Diego—Exploiting Tight Carbonates

25–28 March ◗ Kuala Lumpur—Offshore Technology Conference Asia

13–18 July ◗ Santa Fe—SPE Well Construction Efficiency: NPT, Reliability, and Process Improvement

31 March–2 April ◗ Muscat—SPE EOR Conference at Oil and Gas West Asia 1 April ◗ Calgary—Slugging It Out

27 July–1 August ◗ Newport Beach— Low Carbon Intensity Processes for Low-Mobility Oil Recovery

Find complete listings of upcoming SPE workshops, conferences, symposiums, and forums at www.spe.org/events. 136

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UNCONVENTIONAL

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KAPPA |

Unconventional Resources

Coming soon: Citrine A software collaboration between KAPPA and DeGolyer & MacNaughton to handle, visualize, analyze and forecast mass production data, in particular for unconventional plays.

www.kappaeng.com

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