NewTechnology June 2011
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in this issue
departments
June 2011 | vol.17 | no.05
editor’s view The Long Shots 4
vanguard News. Trends. Innovators. 7 greenscene Solar-Powered EOR 15
New technology not quite ready for Canada yet
new tech Production Boost 39
New stimulation technique holds promise for under-achievers in mature carbonates
Efficient, Accurate, Green 42 NASA-inspired technology applied to the humble oilfield pump
Sky High 43
A new exploration technology hopes to uncover untapped resources 43
26
FEATURES 18
Plugged In
Amazing Wells
AOSC starts what may be the first test of electric heaters in bitumen carbonates with its TAGD process
30
Analyze That
Tight oil producers getting methodical about multistage fracking
Well Staged
New technology from Packers Plus accelerates multistage openhole fracking
26
24
Going Long
26
Full Speed Ahead
28
23
25
Records continue to tumble as Sakhalin-1 targets second field Advanced downhole motors setting the pace in shale gas
Setting The Pace
Modified tools, teamwork enable firm to drill record horizontal in the Montney
East Coast Treasure
Satellite offshore fields prompt innovative drilling solutions
The Fixer
Longer horizontals calling for ever lengthier intervention services
advertisers Baker Hughes Canada Company IBC Bear Den 4 Haul 16 Calfrac Well Services Ltd. 5 Canadian Association of Petroleum Producers (CAPP) insert Cathedral Energy Services Ltd. 37 Departure Energy Services IFC 2
New Technology Magazine | June 2011
dmg events 41 Entero Corporation 1 Expro Group Canada Inc. 6 Halliburton 29 JuneWarren-Nickle's Energy Group 14, 36 Kenwood Electronics Canada Inc. 12, 13 London Business Conferences 40
Momentive Specialty Chemicals Inc. 17 Oil Sands and Heavy Oil Technologies 38 Packers Plus Energy Services Inc. 9, 11 Pure Energy Services Ltd. 35 Schlumberger Canada Limited 3 Telus World of Science 33 Weatherford Canada Partnership OBC
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editor’s view the long shots The first time I came across General Fusion, a tiny Burnabybased company attempting to single-handedly conquer one of the greatest energy challenges of our time — nuclear fusion — I was skeptical. Here was an outfit not much removed from a garage inventor seriously chasing the holy grail of power, an almost limitless, clean source based on the reaction that fuels the stars. Huge potential, sure, but it’s also the power source that has been tagged as being a decade or two away from reality for several decades. Still, the tantalizing possibilities have managed to keep massive government-funded projects alive throughout those decades. The biggest current project — the International Thermonuclear Experimental Reactor (ITER) funded by the U.S., the EU, China, Japan, Russia, India and South Korea — is investing some $21 billion to build a demonstration reactor scheduled for completion in 2018. Assuming it works, a full-fledged commercial facility could be another couple decades and many more billions away. General Fusion hopes to complete in years what ITER plans over decades: to pilot “net gain” — producing more energy than it consumes, something never done before — in two years and be commercial by the end of this decade. (Its innovative concept, a thermonuclear diesel engine of sorts, would use 200, 220-pound pistons firing simultaneously against a sphere containing plasma of the isotopes tritium and deuterium, creating a shock wave powerful enough to compress the hydrogen atoms to fuse them into helium atoms — and release a colossal amount of energy in the process.) What has that got to do with the oil and gas industry? Well, in the oilsands at least, it takes a tremendous amount of energy to produce energy, usually meaning lots of natural gas to produce the bitumen. Though fusion might remain a pie-in-the-sky concept to many, major oilsands producer Cenovus Energy Inc., for one, has decided to take it seriously, with a $4 million investment in General Fusion announced in May. “Cenovus is impressed by General Fusion’s innovative, pragmatic approach,” Judy Fairburn, executive vice-president, Environment and Strategic Planning, said in a press release. The company’s Environmental Opportunity Fund finances environmental innovations in energy and technology. “This technology has the potential to revolutionize energy production,” she stated. To a cynic, the investment might appear to be nothing more than greenwashing — an attempt to portray itself as being serious about making major cuts in emissions with little or no real chance of doing so for the foreseeable future. Nuclear fusion, after all, is a major long shot, and $4 million is a drop in the bucket for a company that clears billions every quarter. But we have to start somewhere, and to a minnow like General Fusion, swimming among the whales of megaprojects like ITER, investments like this can keep it in the running and further the technology, no matter how long the odds. It’s also important because, sometimes, long shots pay off. There will be failures along the way, but there will be major advances, too, sometimes where they are least expected. In this issue, we profile a new oilfield pumping technology that had its origins in another long shot research project, the concept of a space elevator. Popularized by science fiction writer Arthur C. Clarke in the 1980s, the space elevator — also referred to as space lifts, space ladders or even beanstalks — could lift objects and people into orbit along a cable stretching from the planet’s surface, held taut by a counterweight orbiting above. A “climber” would provide lift up a high-strength cable made, perhaps, of carbon nanotube material. Researchers at the University of Saskatchewan had great success competing in a NASAsponsored project to develop climber technologies, including wirelessly powering a robotic prototype to three first place finishes and setting new records in areas such as the most power wirelessly beamed and fastest power beamed climbs. The space elevator may remain a long shot, but chasing the dream has not been without benefit, as the new and much improved oilfield technology can attest. In a world often limited to quarter-to-quarter thinking, we too often neglect early-stage research that may not lead to breakthroughs for 10, 20 or 30 years. It can be hit-and-miss, but with such big potential benefits, not to mention the likelihood of spinoffs we haven’t even considered, it’s worth the risk. • Maurice Smith 4
New Technology Magazine | June 2011
New Technology Magazine www.newtechmagazine.com editorial and production publisher | Stephen Marsters smarsters@junewarren-nickles.com editor | Maurice Smith msmith@junewarren-nickles.com art director/lead design | Andrew Brien abrien@junewarren-nickles.com ad traffic coordinator | Denise McKay writers | Jim Bentein, Godfrey Budd, Gord Cope, Lynda Harrison, Pat Roche, R.P. Stastny, Paul Wells sales sales manager – magazines | Maurya Sokolon msokolon@junewarren-nickles.com senior account executive | Tony Poblete tpoblete@junewarren-nickles.com sales | Nick Drinkwater, Diana Signorile sales administrator | Craig Cosens circulation circulation manager | Donna Rideout drideout@junewarren-nickles.com circulation/advertising | Tracy Wavrecan twavrecan@junewarren-nickles.com PUBLICATIONS MAIL AGREEMENT NO. 40069240 RETURN UNDELIVERABLE CANADIAN ADDRESSES TO OUR CIRCULATION DEPARTMENT 816 - 55 Ave NE, 2nd Flr, Calgary, AB T2E 6Y4
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vanguard
News. Trends. Innovators.
Q1
Encana Corporation was the busiest explorer in both Alberta and British Columbia during the first quarter, completing 38,809 metres of exploratory hole in the former province and 35,096 metres in the latter province. Crescent Point Energy Corp. was the busiest explorer in Saskatchewan with 42,088 metres of hole finished.
12,950
The Petroleum Services Association of Canada has raised its drilling forecast for this year, which is now expected to reach 12,950 wells drilled (rig released) across Canada, representing a 5.7 per cent increase in total wells drilled. The number is up from PSAC’s initial release of the Canadian Drilling Activity Forecast, released last November. PSAC is basing its updated 2011 forecast on average natural gas prices of C$3.85 per mcf (AECO) and crude oil prices of US$100 per barrel (WTI). Driving innovation and technological development was identified as a common theme in a report issued mid-April by the Canada West Foundation titled Finding Common Ground: The Next Step in Developing a Canadian Energy Strategy. The Canada West researchers note the reports they reviewed
“returned time and time again to the need for policy tools to foster and incentivize innovation through greater investment in infrastructure, human capital, science, research and development, and commercialization.” The study cites concerns that Canada is not moving fast enough on innovative performance and investment levels Photos courtesy of JuneWarren-Nickle's Energy Group
when compared internationally.
2012
Sasol Limited and partner Talisman Energy Inc. will make a key investment decision in the second half of next year regarding a possible gas-to-liquids (GTL) plant in Western Canada. “I think it would be the first of a series of investment decisions. But it would certainly be a very important milestone for us,” Talisman president John Manzoni told reporters after the company’s annual meeting.
“This is an inflection point in our history.” — Brenda Kenny, president and chief executive officer of the Canadian Energy Pipelines Association, told the Insight Information Ltd. North American pipeline forum. Canadian pipelines, which once operated virtually under the radar, are now seen as the centre point of a more controversial value chain and as a result face increasing environmental assessment requirements in applications for new projects.
“It is one of the most productive sweet gas provinces on the planet. The unique geologic setting offers multiple stacked opportunities in a concentrated geographic area.” — Mike Rose, president and CEO of Tourmaline Oil Corp., on the potential of Alberta’s Deep Basin
New Technology Magazine | June 2011
7
vanguard
ENVIRONMENT
Clear Costing
ICO2N tackles challenges of carbon capture cost analysis A carbon dioxide emitters group has released a series of recommendations on how to analyze the cost of CO2 capture technologies. The Integrated CO2 Network (ICO2N) released the recommendations in mid April in a 14-page report titled Perspective on Conducting Cost Analyses of CO2 Capture Technologies. Members of the six-year-old ICO2N group include oilsands and coal producers who are promoting carbon capture and storage (CCS) for climate change mitigation. 8
newtechmagazine.com
ICO2N defines CO2 capture costs as all the financial impacts of capturing CO2 that otherwise would be released to the atmosphere — including the cost of purifying, dehydrating and compressing the captured CO2 for transportation to storage sites. It said CO2 capture costs typically don’t include the cost of CO2 transport, storage or disposal; potential revenue associated with the possible sale of CO2; or costs avoided by complying with regulatory requirements.
However, the report notes there are several comparative analyses that can be done to ensure capture cost estimating is as robust as possible — including cost comparisons to recent builds and cost comparisons to recent FEED studies. Also, the report says it needs to be made clear whether the estimates are for first-of-a-kind plants to be built now or replicas to be built later. ICO2N stresses the need to clearly define how CO2 volumes are calculated. It says a core question is whether to count just captured volumes or abated volumes (net physical volumes after accounting for the impact of capturing CO2). The report says abated volumes provide a more robust assessment of the net CO2 reduction. “With abated volumes it is important to clarify what on-site and ex-site elements have been included.” It says elements that should be considered include the “energy penalty” associated with CCS operations — in other words, the increased CO2 emissions due to having to build a bigger facility to provide the extra energy needed for CO2 capture. The report recommends expressing capture costs as the cost per unit of the commodity produced (for example, the cost per megawatt hour of electricity generated, or the cost per unit of hydrogen produced) as well as cost per tonne of CO2 captured. “This will allow for the broadest analysis of the implications of CO2 capture at a plant,” the report says. “For instance, while some facilities may appear to have relatively low capture costs when viewed on a cost per tonne of CO2 captured, it is important to also portray costs relative to the underlying commodity being produced by the host facility. This allows for a more complete analysis of the overall economic impact.” • Pat Roche
Photo source: Photos.com
The report says the first step is deciding what costs to include. ICO2N has only included in its studies the costs directly attributable to CO2 capture processes and not the costs associated with different types of plants. It assumes the decision to build a plant is made independently of the decision to capture CO2. It says capital costs should include all direct, indirect and owner-operator costs that would be capitalized during construction, operation and retirement. This list of costs would include, for example, interest during construction, insurance, legal, regulatory/ permitting, project development and land. Operating costs should include all direct, indirect and owner/operator costs — including costs associated with lost productive capacity from the base facility due to capture operations, the report says. Cost estimates need to be adjusted for facility location. ICO2N notes construction costs in some parts of Alberta may be 140-160 per cent higher than on the U.S. Gulf Coast. The report says the most significant challenge with most CO2 capture studies is obtaining reasonable designs and relatively accurate cost estimates at the early stage of the CCS project development — in other words, pre-FEED (front end engineering design) studies. The cost of a full FEED study for a large facility can exceed $30 million. “Ultimately, cost estimates — whether for the host facility or the capture process — can only be established when there are contractual commitments to supply facilities or services within the costs projected,” the report says.
vanguard
Montney Assets Maximized Photo courtesy of Suncor Energy Inc.
Packers Plus increases well production. Packers Plus StackFRAC® multi-stage fracturing system allows production contribution Suncor’s Magrath wind power project in southern Alberta
eliminates the cost and risk of cementing and perforating.
RENEWABLES
Green Drumming Suncor defends renewables investments Suncor Energy Inc. was called to task by a shareholder at the company’s annual meeting in May for its use of food to produce energy and its investments in wind power. The shareholder questioned Rick George, president and chief executive officer, during the meeting’s question and answer period as to how those sources of energy fit in with Suncor’s commitment to social responsibility and how wind power, which needs to be subsidized, can be economic. Using grain to produce fuel is not a longterm solution but the federal government mandates that a percentage of ethanol be blended into gasoline and currently the only viable source is grain, said George. Suncor, industry and almost every university in North America is working on developing another source such as biomass but a solution appears to be a long way off, he said. Suncor has Canada’s largest ethanol plant by volume, in Sarnia, Ontario, where current capacity of 200 million litres per year doubled to 400 million litres per year when an expansion was completed in January. According to the company’s website, the plant displaces the
from the open hole lateral and
equivalent of 300,000 tonnes of carbon dioxide per year and uses 40 million bushels of corn annually, approximately 20 per cent of Ontario’s annual corn crop. The type of corn used as feedstock has traditionally been used to feed livestock. Once the starches are extracted from the corn to make ethanol, the remaining elements are used to make premium cattle feed. Wind is Suncor’s lowest-return business but the company is taking a long-term view of wind power, George told the meeting, adding the company is investing in its sixth such project. Suncor plans to spend $500 million over five years developing wind energy and biofuels. The renewable energy projects create partial offsets for its greenhouse gas emissions. By the end of 2011, Suncor expects its renewable energy projects will displace a total of nearly one million tonnes of carbon dioxide annually. The company’s renewable energy assets contributed operating earnings of $15 million in the first quarter of 2011, which was comparable to operating earnings of $14 million in the first quarter of 2010. • Lynda Harrison
Page 9 (Vanguard section) 514037-160 Packers Plus 1/3 pg vert ad 1 of 2
New Technology Magazine | June 2011
9
SYNGAS
Fuel For Thought Swan Hills syngas plant moving ahead A $1.5 billion project designed to use in situ coal gasification (ISCG) to convert non-mineable coal into clean, low-carbon synthesis gas (syngas) needs further funding but expects to file for regulatory approval sometime this year. Swan Hills Synfuels L.P. is targeting a construction start in late 2012 or early 2013 for the Swan Hills ISCG/Sagitawah Power project, with an onstream date in late 2015. The first phase of development will consist of 18 to 20 well pairs, consisting of an in situ coal gasification facility, power generation, carbon dioxide transportation and sequestration and a syngas pipeline. Swan Hills Synfuels is in the process of raising $100 million that will get the project to the start of construction, Douglas Shaigec, president of the Calgary-based company, told the Canadian Energy Research Institute 2011 Oil Conference in Calgary. To date, investors have been high-net-worth individuals, with some participation from institutional investors, and similar sources are being tapped for further funding, said Shaigec. The cost of the gas plant and well pairs is pegged at $600 million, which will be financed separately from the power plant’s estimated cost of about $500 million. That price tag depends on final project component siting and configuration decisions. The power plant will be in the Whitecourt-Swan Hills region of Alberta but the company has not yet pinpointed the exact location of the power plant and is in negotiations with stakeholders. About $70 million has been raised within the organization so far and largely been spent on 10
newtechmagazine.com
the demonstration project and first phase of the commercial project, he said. The demonstration project was completed in July 2009 at a cost of about $30 million, of which $8.83 million was provided by the province of Alberta through the Alberta Energy Research Institute. Shaigec’s company estimates two billion barrels of oil equivalent can be manufactured from its secured coal resource base using ISCG. The supply cost is less than $3 per gigajoule, he told the conference.
number [of producers who will use the gas] but the interest in the CO2 exceeds the available supply,” he said. The coal seam is 1,400 metres deep at nearly 2,000 pounds of pressure per square inch, and thus not economical to mine, he said. The demonstration project has one well pair: one horizontal well that injects oxygen and saline water while the vertical well brings the raw syngas to the surface where a conventional gas plant removes the carbon dioxide, resulting in a syngas that can be used as a fuel for power generation or further converted to liquid fuel. The use of saline water virtually eliminates the need for fresh water, said Shaigec. A series of chemical processes convert the coal to syngas,
CO2 TO CONTAINED OIL POOL FOR EOR/SEQUESTRATION CLEAN SYNGAS TO POWER GENERATION 0m INJECTION WELL
PRODUCTION WELL
200 m 400 m 600 m
DEPTH LIMIT OF FRESH GROUNDWATER
800 m 1000 m
RAW SYNGAS
1200 m
SALINE WATER + OXYGEN IN SITU GASIFICATION OF COAL
1400 m
COAL SEAM COAL + COMBUSTION + PRESSURE + STEAM
CO2 TO CONTAINED OIL POOL EOR/SEQUESTRATION 2800 m
The company’s proposed commercial-scale project will manufacture clean fuel for a new 300-megawatt power generation facility near Whitecourt while capturing more than one million tonnes per year of carbon dioxide for sale to nearby enhanced oil recovery customers. “I can’t give you the exact
POWER FROM BELOW Swan Hills Synfuels’ ISCG/ Sagitawah power project will use in situ coal gasification to tap deep, unmineable coal to produce syngas. The syngas will be pipelined to a combined cycle power generation station to produce low emission electricity. The captured CO2 will be sold to EOR customers in the region.
Shaigec told the conference. The oxygen supports a limited and controlled amount of combustion, raising the temperature of the coal and boiling the water to generate steam. The naturally existing deep underground pressure, along with the elevated coal temperature and the presence of steam, together form the right conditions to gasify the coal. Char and ash, which are remnants of the original coal, remain deep underground. Although the company is not doing anything differently with its demonstration plant than what’s been done with the technology in its 80-year history worldwide, until that plant was operating skeptics suggested the process would not work, he said. But it absolutely does work, he insisted. “In fact we were looking forward to getting the demo operating because it is actually the deepest in situ coal gasification that’s ever been done in the world,” he said. The company is seeing the benefits of syngas in both its quality and how clean it is, he added. “It certainly seems to support the theory and the past practice that being in the deeper coals in that high-pressure environment is definitely beneficial to the process,” said Shaigec. The province of Alberta has committed $285 million in grant funding to support the first phase of the project, under Alberta’s $2 billion carbon capture and storage funding program. Swan Hills Synfuels has entered into an agreement with PCL Industrial Management Inc. to construct the clean synthetic gas processing facility on a fixed-price, schedule-certain basis. Shaigec said the area’s transmission system will be able to accommodate the interconnection of the power plant without the need for any substantive system upgrades. The land footprint of the first commercial phase will use no more than five sections worth of land, he said. • Lynda Harrison
Illustration: JuneWarren-Nickle's Energy Group staff
vanguard
vanguard
Photo: JuneWarren-Nickle's Energy Group
Cardium Assets Maximized Packers Plus increases well production. Packers Plus StackFRAC® multi-stage fracturing system
DRILLING
allows production contribution
New Well Profile
from the open hole lateral and eliminates the cost and risk of cementing and perforating.
Modest rise in well count belies major changes in well costs and complexity Despite a modest prediction for nearly 13,000 wells this year, industry is spending a lot more time drilling much more expensive and complex wells and finding experienced staff is again becoming a major issue. The Petroleum Services Association of Canada raised its 2011 drilling activity forecast by 700 wells in late April to 12,950 wells drilled, but the modest increase belies significant underlying changes in activity favouring longer, deeper wells, oil drilling and unconventional resources, all of which are redefining the oilfield service market in Canada. “We’re forecasting that horizontal wells will account for 44 per cent of all wells by the end of 2011. That’s triple the 2007 level of 14 per cent,” said Mark Salkeld, president of PSAC, at its mid-year Drilling Activity Forecast update luncheon. PSAC noted the number of rig operating days has doubled in just three years because of the increased time required to drill and complete longer and deeper wells in unconventional formations. The average number of days it takes to drill a well has climbed to 11.5 in 2011 from 5.7 in 2008. “Well depth and reach is 33 per cent more than it was just five years ago,” Salkeld said. “To put that into perspective, well depths on average are almost 600 metres deeper than they were in 2008.”
Citing ARC Financial research comparing costs of a typical horizontal well in the Pembina region in 2010 to a vertical well in the same area in 2000, Salkeld said total well costs have climbed to $2.7 million for the average horizontal well versus $325,000 for a vertical well in the Pembina region. The highest cost component of a typical horizontal well is by far the completions and testing, representing 54 per cent of the total well cost versus 17 per cent in 2000. So even modest increases in well drilling activity today leverage the money spent, the total metres drilled and the labour required to carry out the work — all of which bodes well for drillers provided they are agile, prepared to change with their customers and embrace the step-changes in technology offered by mobile compression and fluid chemistry advances, according to Scott Treadwell, a Macquarie Equities Research analyst speaking at the PSAC event. Macquarie expects new capital expenditure announcements for the Horn River Basin by the middle of 2012 as producers prepare to send 1.5 bcf per day of gas to Kitimat for LNG exports. “You need two million horsepower to service that incremental demand, half a million of that going to the Horn River. So that’s a fundamental huge step in demand,” he said. • R.P. Stastny
Page 11 (Vanguard section) 514037-170 Packers Plus 1/3 pg vert ad 2 of 2
New Technology Magazine | June 2011
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Rendering courtesy of GlassPoint, Inc.
environmental technology
PRODUCTION
Solar-Powered EOR New technology not quite ready for Canada yet Enhanced oil recovery using concentrated solar power is being tested in California, where steam is forced deep underground to liquefy and release thick oil deposits, and will be studied for use in northern Alberta. GlassPoint, Inc. introduced the world’s first commercial solar enhanced oil recovery (EOR) project in February at Berry Petroleum Company’s 21Z lease in McKittrick, California. GlassPoint says its solar steam generators produce steam at a lower cost than steam produced from gas-fired steam generators, making it practical to replace up to 80 per cent of the gas used for EOR in sunny locations. The pilot project has been in daily operation most of the time since startup and is moving toward full automation. “The unit’s performing, it’s interconnected and it’s producing energy every day,” says John O’Donnell, GlassPoint’s vice-president of business development.
Designed to deliver about a million British thermal units per hour for eight hours a day during the summer, the Kern County 21Z Solar Project is operating as expected, O’Donnell tells New Technology Magazine on his cell phone from Muscat, Oman, where GlassPoint is investigating setting up solar steam generation projects. Using the GlassPoint solar array to directly generate steam for injection into wells reduces gas use. During sunny hours, solar steam is injected and during dark hours, gas-generated steam is injected. Control systems automatically adjust the gas-firing rate so that constant rate steam injection is maintained. The company says the secrets to its success are its software and sensing systems. Multiple sensors track the sun’s position in the sky and the energy is delivered to the receiver in real-time. The tracking system adjusts the mirror position relative to the structure so that it remains optically aligned at all times, while older systems have to be manually aligned individually.
SOLAR ASSIST Artists rendering of a fouracre GlassPoint solar power system. GlassPoint recently launched the world’s first concentrated solar power facility built to provide steam to feed a heavy oil EOR project.
New Technology Magazine | June 2011
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Western Canada use? Specifically designed for rugged oilfield environments, the technology has applications in regions with heavy oil and sunshine such as California, Texas, Venezuela and North Africa. What about northern Alberta and its steam assisted gravity drainage projects? Not so much, says O’Donnell, although his company has received intense interest from Canada and is conducting a feasibility study. Results should be ready in a month. It’s certainly feasible, but he questions whether solar-assisted
Photo courtesy of GlassPoint, Inc.
Another key element is the protected glasshouse structure, notes Katie Struble, a spokesperson. By isolating the mirrors from outdoor elements — wind, dust and sand — the system can operate in harsh oilfield environments. It also allows the use of an automated robotic washing system that eliminates the need for manual cleaning and minimizes water use, says Struble.
EOR is economical for Alberta, especially when natural gas prices are depressed, he says. He estimates it would deliver only about half as much energy in Alberta as California. There are three challenges, he says: the latitude, which puts the sun lower in the sky, the presence of snow and cold, and clouds. Of those, the snow and environmental conditions are the least problematic because of the greenhouses. “The big issue is sunny hours.”
According to GlassPoint, integrating solar heat into a thermal EOR project by using its solar array to pre-heat feedwater for conventional gas-fired steam generators reduces gas consumption by up to 10 per cent. Although hot water is only produced when the sun is shining, it’s relatively easy to store in an insulated tank, so solar heated water can be supplied to steam generators even when it’s dark, the company says. Oakland, California-based
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SELF-CLEANING Greenhouses allow the use of an automated robotic washing system that eliminates the need for manual cleaning and minimizes water use. Used daily by the agriculture industry for the past 20-plus years, the cleaning machines are widely deployed and proven to maintain optical efficiency of the system while significantly reducing O&M costs. No other solar steam provider has figured out this piece of the puzzle yet, says GlassPoint.
Brightsource Energy, Inc. is building concentrated solar power technology at a Chevron Corporation oilfield in Coalinga, California, to create steam injected into a heavy oil reserve. Thousands of mirrors, called heliostats, point to the sun, directing its energy toward a water boiler. The steam generated by the boiler is injected into wells to heat up heavy oil, thereby making it easier to extract. The steam is then aircooled and piped back into the
greenscene system in a closed-loop process. The system is slated to be in service this year. Curtis Berlinguette says he never likes to say something can’t be done, especially when it comes to solar because he is a huge proponent of using it in unconventional ways, but for now at least he doesn’t think northern Alberta’s oilfields are necessarily suited for this specific technology. “I think it should be explored but there are some serious hurdles for this type of solar thermal technology to be implemented,” says the Canada Research Chair in Energy Conversion and Alberta Ingenuity at the
University of Calgary’s Department of Chemistry. These types of solar technologies are better matched to an environment of intense sunlight, says Berlinguette, who is also a director of the Centre for Advanced Solar Materials and a fellow at the Institute for Sustainable Energy, Environment and Economy at the U of C. Moreover, he has concerns about whether infrastructure could withstand the extreme temperatures in northern Canada. Berlinguette cautions that his expertise is in solar electricity — not solar thermal — and so he is not intimately familiar with GlassPoint’s undertaking
“On the other hand, the ready access to water would be a significant advantage for placing a concentrated solar installation in Alberta. Concentrated solar thermal typically requires a lot of water.”
Momentive’s Canadian Advantage Fort Saskatchewan Manufacturing Plant Calgary Technical Sales Office
and its use of greenhouses. While he is optimistic that the greenhouses will improve the stability of the solar collectors, he speculates that about 15 per cent of incident sunlight will be lost due to reflective losses without even taking into account other issues with debris and precipitation. Brightsource’s concentrators are designed to reach temperatures of more than 500 C, which require many mirrors and intense sunlight. Considering that the output of a desert installation plummets in cloudy conditions, it will be a challenge to get really high efficiencies during the winter in northern Canada, he says. “On the other hand, the ready access to water would be a significant advantage for placing a concentrated solar installation in Alberta. Concentrated solar thermal typically requires a lot of water.” The Centre for Energy says Canada has abundant solar energy resources, with the
largest resources being found in southern Ontario, Quebec and the Prairies. Up to now, it says, the main applications of solar energy technologies in Canada have been for non-electricity active solar system applications for space heating, water heating, and drying crops and lumber. According to the National Research Council of Canada, Inuvik, with an average 12.59 daylight hours per day, receives the highest average number of daylight hours in Canada for solar power generation. During the summer, Inuvik receives 24 hours of daylight per day, which compensates for 24 hours of darkness during the winter. However, Calgary is not far behind, at an average 12.26 daylight hours per day, and Toronto receives an average 12.02. • Lynda Harrison CONTACT FOR MORE INFORMATION John O’Donnell, GlassPoint, Tel: 415-778-2800, Email: john@glasspoint.com
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Momentive Specialty Chemicals Inc., Oilfield Technology Group, Calgary, AB, Canada +1 780 721 3807 © 2011 Momentive Specialty Chemicals Inc. ®, ™ and SM denote trademarks owned by or licensed to Momentive Specialty Chemicals Inc.
New Technology Magazine | June 2011
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plugged in less water use
lower temperatures
AOSC starts what may be the first test of electric heaters in bitumen carbonates with its TAGD process By Pat Roche
lower operating costs
production
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ike many prospective oilsands producers, Athabasca Oil Sands Corp. (AOSC) acquired conventional leases — bitumen in sandstone McMurray and Wabiskaw reservoirs in northeast Alberta. In the normal course of business seismic lines were acquired to place delineation wells. Eying one of the seismic lines, an AOSC exploration geologist with many years of experience in the Western Canadian Sedimentary Basin spotted what looked like a reef beneath the target sands. To confirm this, AOSC shot new seismic. Lo and behold, it clearly revealed a carbonate Leduc reef beneath AOSC’s Dover West oilsands asset. So over two years AOSC quietly picked up acreage in Crown land sales, drilled delineation wells and built up its position until it owned nearly 100 per cent of the reef in the Dover West area. It was a light oil discovery in a Leduc carbonate reef that launched Alberta’s modern oil industry in central Alberta in 1947. However, AOSC’s Leduc carbonates contain bitumen, not light oil. Viscosities range from three million to five million centipoise — roughly the consistency of shortening or lard. At reservoir temperature this stuff isn’t going anywhere. Alberta government geologists estimate hundreds of billions of barrels of bitumen are locked in carbonate rock — a resource big enough to rival the conventional oilsands — but so far no one has figured out how to produce it commercially. According to published data, only a few pilots have been done, all using steam to melt the bitumen so it would flow to production wells. What these tests showed is the bitumen will flow when heated. The trick is finding a way to economically raise the reservoir temperature. The presence of fractures and vugs (cavities) may present challenges if using steam. As an alternative, a number of companies have schemes that would use electricity (instead of a flow process such as steam) to heat the reservoir. New Technology Magazine previously reported Royal Dutch Shell plc and E-T Energy have already field-tested their respective electric heaters in the conventional oilsands. But based on what has been publicly disclosed, AOSC appears to be the first to start fieldtesting electric heaters in Alberta’s bitumen carbonates. The prize could be huge. AOSC estimates it has 19 billion barrels of bitumen in place in the Leduc carbonates, though at this point it’s impossible to know how much, if any, might be economically recoverable. So for now, AOSC is focusing most of its resources on its conventional oilsands assets at Dover and MacKay. At both properties AOSC’s 60 per cent partner is PetroChina, but the Alberta company remains the sole owner of the Dover West asset where the Leduc carbonates are located. AOSC’s first commercial production as a company is expected to come from Dover in late 2014. (The company also has a stake in Alberta’s Grosmont carbonates, but considers this a long-term opportunity and hasn’t prepared a development schedule.) But at the same time AOSC has taken the first concrete steps toward unlocking the vast bitumen wealth of its Leduc carbonates. Recovery process Thermal assisted gravity drainage (TAGD) is the name the company coined for the recovery process it is developing using a pattern of horizontal heating wells. It will use conduction heating. A straightforward way of delivering heat, conduction is how common electric stoves work. Heat is conducted into a pot sitting atop an electric element. In the TAGD application the electric heating element is a mineral insulated (MI) cable New Technology Magazine | June 2011
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Illustration courtesy of AOSC
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Leduc
SAGD
Leduc
TAGD
D
SAG
strapped to the tubing run into the horizontal wellbores. MI cable is a wire surrounded by mineral insulation to prevent short circuiting. Like the elements on an electric stove, the wire turns red hot as power is cranked up. MI cable is available from several manufacturers for heat tracing — wrapping around pipes at outdoor industrial plants such as refineries to prevent freezing. MI cable has never been used commercially in a bitumen reservoir. Adapting an existing commercial product to this new application, AOSC is in effect acting as its own technology provider. In explaining the difference between TAGD and some of the other proposed bitumen recovery methods that use electricity, AOSC chief reservoir engineer Bruce Roberts lists what it’s not. It’s not just a near-wellbore stimulation process — the goal is reservoir-wide heating. Unlike resistance-based heating methods, TAGD does not apply electrical current directly to the reservoir. And it is not in situ upgrading, which Shell proved technically possible in its electric heater experiments in the Peace River oilsands last decade. AOSC is simply trying to make the bitumen flow, which requires much lower temperatures than the cracking process that converts bitumen to light crude. The lower the temperature required, the less energy that needs to go into the reservoir, which translates into lower operating costs. AOSC has embarked on a program to advance its understanding of TAGD to the point where it can make a decision on a commercial operation. “We’ve done a fair bit of delineation drilling. We have quite a bit of core data. We have logs. We have a reasonably good understanding of the geology,” says Roberts. The company has been making extensive use of modelling, or reservoir simulators, to estimate results such as recovery factor. As of late April it had done about 75,000 simulations, many of them automatically generated. But the real test is in the field, where the company recently started a two-well heater test. It drilled a pair of 220-metre horizontal wells with eight to 10 metres of vertical separation. The heating cables were installed in the wellbores and after a two-week test to define the thermal conductivity of the reservoir, the heaters will be turned up for about a year. Once the reservoir is sufficiently heated, the bitumen should flow with gravity to the lower heating well, which will also serve as a production well. If that test is successful, AOSC will file a regulatory application in late 2011 or early 2012 for the next step, which would be a combined pilot/demonstration project. The application would be for production of up to 12,000 barrels a day. That project would have two components. The first would be a pilot designed to get field evidence of drainage rates and recovery factor at a larger scale than the two-well test’s eight- to 10-metre spacing. 20
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CO-DEVELOPMENT SYNERGIES Schematic shows production methods in the bitumen-bearing carbonate Leduc reef, left and centre, and conventional oilsands, right. Steam assisted gravity drainage and thermal assisted gravity drainage are proposed options for the Leduc carbonates. Use of TAGD in the carbonates and SAGD in the overlying oilsands could present the unique opportunity to use cogeneration to simultaneously produce electricity for the former and steam for the latter.
The second component would be a demonstration project that would be the first step in commercializing TAGD, albeit at a smaller size than a full-scale commercial project. No decision has been made yet on the size of each component, but they would have a combined capacity of less than 12,000 barrels a day and both would be covered by the same regulatory application. Whether both components would be built at the same time has yet to be decided. If they’re done in parallel, the demo project would generate cash flow while the pilot would try to determine, for example, optimal well length and spacing. “Right now we have just 200 metres of heater,” says Roberts. “We could envision in a commercial operation going much longer — 1,500 to 1,600 metres.” TAGD’s benefits While AOSC believes TAGD currently holds the most promise for extracting bitumen from the carbonates, it isn’t writing off steam-based methods. In fact, it did a small steam test during the past winter. The company drilled a slant well and injected a single slug of steam to see how the reservoir would respond. “It looked, to our analysis, like we were able to develop a good steam chamber, which suggested SAGD can be viable,” says Roberts. “If fractures were posing tremendous thief zones, one would expect that you couldn’t build up pressure in that steam chamber; the steam
production would just escape…. But we were able to create a zone of pressure.” So if steam might be a viable option, why focus on electrical heating? AOSC says two big attractions of conductive heating over steam processes are more uniform heat distribution and lower operating temperatures. The company expects field tests will confirm it can mobilize the bitumen by heating the reservoir to 120 to 140 C. Many steam-based processes operate at more than 200 C, which means higher operating costs. As for heat distribution, a flow-based process such as steam takes the path of least resistance, channelling through fractures and stopping at shale layers. Conduction heat, on the other hand, travels through fractures, shales, water and oilbearing sands. “This scheme provides for fairly uniform heating because it’s dictated by heat capacity and thermal conductivity,” says Roberts. These can be affected by changes in mineralogy — for example, a carbonate has a somewhat different thermal conductivity than a sand. While these may vary by 10 or 20 per cent, permeability can vary by an order of magnitude — for example, the difference between a heavily fractured zone and one which isn’t fractured. Differences in permeability can have a huge impact on the effectiveness of a flow process — such as steam — to heat the reservoir evenly, but would only slightly alter a conductive process, says Roberts. “Regardless of whether you have fractures or high-permeability zones or lowpermeability zones, you achieve the same sort of uniform heating.” Another big advantage of TAGD is it requires essentially no water. “We really believe this is an important advantage,” says Roberts. “Water is becoming a bit of a scarce substance for use in a SAGD operation.” Besides avoiding environmental and stakeholder headaches, eliminating the need for water has commercial benefits. “It really does provide for a much simplified processing facility,” says Roberts. “We don’t have steam generation. We don’t have a lot of water handling, so that would be a less expensive facility which will have a very positive impact on the economics.” TAGD won’t entirely avoid water hand-
ling, though, because relatively small amounts of water naturally present in the reservoir will be produced with the bitumen. So where will the power come from? It will be generated on site from natural gas, either by an AOSC-operated power plant or one operated by an independent power producer, says Bryan Gould, the company’s vicepresident of corporate development. He believes this would be cheaper in the long run than buying from the grid.
“Right now we have just 200 metres of heater. We could envision in a commercial operation going much longer — 1,500 to 1,600 metres.” Cost savings The real saving in energy costs will occur if the company can develop its conventional oilsands at Dover West simultaneously with its bitumen-bearing Leduc carbonates. The carbonates lie directly underneath the sands. If the company can do SAGD and TAGD simultaneously at the same site, it would be a perfect application for co-generation, says Gould. Cogeneration — also called combined heat and power — is the simultaneous generation of electricity and steam from the same fuel. In this case, AOSC would use on-site generation to power its in situ electric heaters, and capture the heat from the gas turbines to boil water for SAGD. “It’s a perfect co-gen opportunity … because you have the steam host above and the electric usage below,” says Gould. “Co-gen is the most efficient use of the natural gas molecule. You’re really reaping as much benefit out of that natural gas molecule as you possibly can to deliver transportation fuel [bitumen] and energy [electricity].” “So it’s like you get a two-for-one deal on your natural gas — steam and electricity out of the same molecule.” Improving the economics could be make-or-break for TAGD as the technical feasibility seems to be less of an issue than the economic question. In a more ambitious experiment that also involved in situ upgrading, Shell proved in northwest Alberta last decade that it is technically possible to use electric heaters in a bitumen reservoir, albeit in the conventional oilsands (See “Game Changer,” New Technology Magazine, June 2008). The use of electric heat in another type hydrocarbon resource dates back even further. Gould believes in situ electric heaters were first used to extract oil from kerogen-bearing shale in Sweden as early as the 1940s. However, shale oil production in Sweden ended because it couldn’t compete with cheaper conventional crude oil. Next Unocal Corporation picked up the thread of the technology, Gould says, and did an electric heating test in a two API oil in California around 1960. He says the U.S. company was planning to bring the electric heaters to the Athabasca oilsands in Alberta but abandoned the research after the economic conditions changed. In the late 1970s Shell research scientists started experimenting with electric heat as a way to extract oil from its massive kerogen-bearing shale deposit in Colorado. In that case as well, Shell reported technical success but has yet to launch a commercial project. The big question AOSC plans to answer is: how many kilowatt hours, or units of electricity, will it take to produce a barrel of bitumen? Roberts says the company probably won’t have a good indication of how much electricity will be burned to produce a barrel of bitumen until it has at least completed the two-well heater test. “We’ve done the modelling work,” he says, “but we really need to calibrate our models before we come up with a more definitive answer.” Gould says the physics are well understood, but suggests electric heat wasn’t commercialized as a recovery method because no one found the right reservoir for the technology. “We’ve very optimistic that we now have the right combination of the right reservoir and the right technology,” he says. “We always say the geology dictates the technology. And we’re very hopeful that this [technology] unlocks the prize. And it’s a huge prize.” • New Technology Magazine | June 2011
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wells amazing
amazing wells
New technology from Packers Plus accelerates multistage openhole fracking
T
he same month Packers Plus Energy Services Inc. announced that its new multi-stage completion system called QuickFRAC was commercially available, the system earned its spurs by helping to complete a 23-stage slickwater frac in just under 10 hours in the Pembina Cardium in March. Using limited entry diversion techniques and other proprietary technology, the QuickFRAC system enables the fracturing of as many as four or five isolated stages in a single treatment within an openhole. “The limited entry system allows us to equally — or unequally — distribute fluid at each port, with the use of one ball [to activate flow ports] for, say, three intervals at the same time. The system allows the operator to pump 10 or 15 stages on surface, with 30 to 60 stages done downhole,” says Dan Themig, president of Packers Plus. With QuickFRAC, each multi-stage treatment zone includes several proprietary QuickPORT sleeves, with packers on either side to create a series of isolated stages within a single treatment zone. “Each treatment zone is activated by an actuation ball, which is available in multiple sizes, enabling several batch fracturing zones to be stimulated in succession with the biggest ball size at the top,” according to the company. Themig argues that the evolving microdarcy shale oil and gas sector appears bound to require increasing numbers of fracture stages in extended laterals. His company has completed several wells with over 10,000 feet in horizontal displacement. But the move from gas to oil and high-liquid reservoirs in microdarcy rock may require a doubling of the current stage numbers for long-reach laterals, he says. “If gas
RECORD PACE
Using its new QuickFRAC completion technology, which allows the fracking of four or five isolated stages in a single treatment, Packer’s Plus managed a record 23-stage slickwater frac in less than 10 hours. Each treatment zone includes several of the company’s proprietary QuickPORT sleeves with packers on either side.
moving through shale rock has difficulty achieving depletion over long periods [years], then oil will be worse.” He says that recent developments in reservoir modelling indicate that even after 10 years of production using standard stage densities of 12 to 18 stages, there will be near original pressure between most fractures. But performing 100 fracture treatments, as one company did recently, he suggests, is not generally practical when the plug and perf method used takes 40 days to complete operations — as happened in the example he refers to. Compare this, says Themig, to the record time — less than 10 hours — in which 23 stages were fracked using the new Packers Plus technology. Along with QuickFRAC, the other key technology that made the record possible was the repeater port system. “Our new ball and seat technology brought us from 10 to about 20 stages, but that was not enough. So we moved to a repeater port system in which one ball size can apply to up to six ports, that is, frac stages,” says Themig. Only two or three years ago, he says, doing completions of 10 to 12 stages “would have been viewed as huge. Then and earlier the attitude was, we’ll never get all the jewellery into the well.” The challenge was that you might be able to drill a 4,000 metre horizontal, but you would not be able to frac it all the way to the toe. Part of the solution lay in borrowing modelling techniques used in the drilling sector and applying them to packer-based completion systems. “This helped us design tools with low friction coefficients and centralizing devices that reduced friction — all on openhole
Illustration courtesy of Packers Plus Energy Services Inc.
well staged
with packers. What that does is take a 40- to a 100-day job and allow us to do it in a couple of says. The sophistication of our modelling capability has made a lot of difference,” says Themig. He points to another record, set in February, in the Williston Basin, in which 47 stages were stimulated in the longest horizontal completion ever done with an openhole multi-stage frac, using the Packers Plus StackFRAC multistage completion system. “The horizontal was 4,300 metres. It more than tripled what is common in our industry for lateral length. These records set new benchmarks for our industry,” says Themig. • Godfrey Budd New Technology Magazine | June 2011
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amazing wells
Sakhalin photos courtesy of Rosneft
Chayvo field Custom-designed for the Sakhalin-1 project and originally mobilized to develop the Chayvo field, which began production in 2005, the 16-storey-tall Yastreb rig is the most powerful onshore drilling rig in the industry. Targeting Chayvo between 2003 and 2008, it drilled 12 of the 16 longest ERD wells to date with distances exceeding 11 kilometres. At Chayvo a total of 20 ERD wells were drilled, setting records in depth, horizontal reach and drilling speed before the Yastreb rig was dismantled, modified and transported to the Odoptu field in 2009. From the 50-metre tall Orlan platform situated at 14 metre sea depth, another 21 ERD wells were drilled, most in the 5.5-kilometre range, with the longest well drilled measuring 7.5 kilometres long. Odoptu field The Odoptu field, located eight to 11 kilometres off the northeast coast of Sakhalin Island, began production in September. In June 2010, the field’s OP-9 well was completed at a total measured depth of 11,036 metres — at that time the longest well drilled at Odoptu
Records continue to tumble as Sakhalin-1 targets second field
going long F
or a project that routinely breaks world records, it must have been old hat for consortium personnel to have racked up another one in January, when they completed the longest extended-reach well ever drilled. The fact the project dished out yet another in a long string of firsts, however, doesn’t diminish the triumph — drilling to a total measured depth of 12,345 metres (40,502 feet or 7.67 miles). The Odoptu OP-11 well in the offshore Far East Russia also set a world record with a horizontal reach of 11,475 metres (37,648 feet). The consortium, operated by Exxon Neftegas Limited (ENL), a subsidiary of Exxon Mobil Corporation, completed the recordsetting well in only 60 days using ExxonMobil’s Fast Drill Process and Integrated Hole Quality technology to maximize performance in every foot of hole drilled. Six of the world’s 10 record-setting extended-reach drilling (ERD) wells including the OP-11 have been drilled by the Sakhalin-1 project using ExxonMobil drilling technologies, James Taylor, ENL president, noting in announcing the well in January. “The specially designed Yastreb rig has been used throughout, setting multiple industry records for measured depth, rate of penetration and directional drilling. We reached this significant milestone while achieving excellent safety, health and environmental performance,” he stated. In addition to Odoptu, Sakhalin-1 includes the Chayvo field — developed with both the onshore Yastreb rig and the offshore reinforced concrete Orlan drilling platform, built to withstand ice ridges reaching the height of a six-story building — and the undeveloped Arkutun-Dagi field. Development of Arkutun-Dagi and expanded gas production from the Chayvo field are expected to sustain production until 2050.
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SAKHALIN SUCCESSES Top: The Yastreb landbased drilling rig was custom designed for the Sakhalin-1 project. Above: The Orlan platform’s reinforced concrete structure can withstand the assaults of ice flows 1.5 metres thick. Next page: The single point mooring facility, where double-hull tankers with 720,000-barrel capacity are loaded, is the world’s largest.
and the fifth longest reach well in the world. As of November, seven production wells had been completed. By enabling drilling from the coast, beneath the seafloor to offshore reservoirs, the Yastreb greatly reduces the capital and operating expenses that would be required for large offshore facilities. It also reduces potentially adverse impacts on environmentally sensitive coastal areas in an area considered to be one of the most challenging sub-arctic environments in the world. Produced oil and gas is transported to
amazing wells the Onshore Production Facility (OPF) where it is processed and stabilized. Natural gas is transported a short distance from the OPF to a network of pipelines owned and operated by other companies for sale to customers in the Russian Far East or injected back into the Chayvo field to maintain reservoir pressure.
full speed ahead Advanced downhole motors setting the pace in shale gas
The oil is transported by a 24-inch, 226-kilometre pipeline across Sakhalin Island and under the Tartar Strait to the Russian mainland, where it is temporarily stored at the De-Kastri export terminal before transport by a six kilometre undersea pipeline to the world’s largest Single Point Mooring (SPM) tanker loading facility and onto specially designed double-hulled Aframaxclass tankers, carrying up to 720,000 barrels of crude, for distribution to the global market. Arkutun-Dagi Located some 25 kilometres off the northeast coast of Sakhalin in 35-metre water depth, the Arkutun-Dagi field will be developed from a gravity-base drilling and production platform and topsides now under construction, which are expected to be the largest in the industry. The field is anticipated to begin producing in 2014 with peak production estimated at 33 million barrels per year. Over the life of the project, Sakhalin-1 is expected to contribute over US$70 billion to Russia’s economy in taxes, royalty payments and the state’s share of oil production. Potential recoverable resources are 2.3 billion barrels of oil and 17.1 trillion cubic feet of natural gas. ENL is Sakhalin-1 project operator on behalf of the international consortium that includes affiliates of the Russian state company Rosneft — RNAstra and Sakhalinmorneftegas-Shelf; the Japanese corporation SODECO; and the Indian state oil company ONGC Videsh Ltd. • Maurice Smith
W
hen a race car takes the checkered flag, it’s usually due in no small part to what’s under the hood. Likewise, when companies set a new pace with the drill bit, the downhole motor probably played a big role in the achievement. At least Mpact Downhole Motors would like to think so. The Texas-based company has marked two field performance records in the Barnett shale of North Texas in recent months, with the longest single-run curve and lateral section drilled in just 125.5 hours and a daily footage record of 3,390 feet. While using an Mpact downhole motor drilling for Devon Energy Corporation on March 11, the downhole assembly was kicked off at 7,600 feet and drilled 7,392 feet through the curve and lateral to 14,992 total depth, for an average rate of penetration of 58.9 feet per hour. “The unique thing about this particular record was that, in normal operations in Barnett shale applications, there will normally be a trip between the curve and lateral section of the well; this particular one they drilled the curve and the lateral in one run, and doing that in 125 hours was the unique aspect about this particular well — it was an outstanding run,” says David Stuart, Mpact vice-president. The Denton County well, drilled with Patterson-UTI Drilling Company rig 208 with Halliburton Sperry Directional Drilling as service provider, featured the Mpact downhole motor configured with the company’s proprietary 7864 performance power section and premium stator elastomer. An 8 5⁄8 -inch kick pad was incorporated in the assembly, with a 1.6-degree fixed bent housing. “That particular motor is exclusive to Mpact, which we developed and have commercialized,” Stuart says. “It’s the configuration and setup of the motor that can enable us to reach that record.” Drilling for operator Chesapeake Energy Corporation last Sept. 3, Mpact set its daily footage record of 3,390 feet with an average rotating and sliding rate of penetration of 167.95 feet per hour in Johnson County, using Mpact motor model 7833 HTS. The motor was configured with a high torque, slow speed performance power section incorporating Mpact’s premium stator elastomer and an 8 ½-inch bearing stabilizer attached to the lower assembly. The proprietary adjustable bearing housing was set at 1.83 degrees. Mpact maintains extensive in-house engineering capabilities to ensure ongoing development of leading-edge motor technology. “Our positioning strategy is to try and differentiate ourselves through technology and in doing that, you have to invest in R&D,” Stuart says. He notes the independent downhole motor supplier is active in the Bakken shale play just south of the Saskatchewan border and is beginning to sell into Canada. “We offer a lot of motors in the Bakken shale and the Bakken extends up over the border. We don’t have a service facility north of the border — our closest facility is in Baker, Montana. But future plans are to eventually have something in the Nisku or Edmonton area,” he says. “The lateral sections that are drilled in the Bakken are slightly smaller diameter typically than what’s in the Barnett; however we have had some excellent runs throughout the Bakken play as well and anticipate more as the trend continues to grow north of the border. We certainly anticipate more activity in Canada.” • Maurice Smith New Technology Magazine | June 2011
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amazing wells
Modified tools, teamwork enable firm to drill record horizontal in the Montney
setting the pace D
eparture Energy Services Inc., a directional drilling firm, recently drilled a horizontal in record time on a well located in the Dawson main pool in the Montney formation of northeast B.C. The well, which received recognition as a Pacesetter, was drilled for ARC Resources Ltd. “ARC designated it a Pacesetter, based on their benchmark system. It was the fastest rate of penetration [ROP] from spud-in to TD [total depth]. We achieved that benchmark on three occasions for ARC in the Montney,” says Dan Robson, director of strategic development at Departure. The well was drilled to a depth of 3,890 metres and took only 11.42 days. “This is not the deepest they drill to but it was on the deep side. These wells average 14 to 17 days, depending on the depth. One of the keys to this performance was getting the well drilled with three bits versus the seven that they can take,” says Robson. Modern cutter technology has made a big difference, he says. “As little as five years ago, there was almost no way you would use PDC [polycrystalline diamond compact] bits to this depth, but the cutter technology has improved so much. In the past, you wouldn’t use PDC bits in these kinds of formations. You would use a tricone.” Halliburton, which manufactures the drill bits that were used under the Security brand, has featured this as a record well in its literature. Although launched barely five years ago, the firm saw a steady increase in activity through 2010, much of it in Alberta’s northwest and in northeastern B.C., gaining recognition and attracting business from a range of clients. Departure has been on one rig for ARC over the last year and will be on two rigs for the next year. Robson attributes the success of the firm and its record ROP to a range of factors. Making sure the power section is carefully matched with the formation that is being drilled was a critical one. Another was using high quality mud motors. “In these wells, we were using Hemis [for mud motors],” says Robson. Hemi is an informal term for National Oilwell Varco’s Hemidril motors, high-performance mud motors designed for both directional and straight hole applications. He says that power section technologies have also been developing rapidly in recent years, and the best and latest materials and systems configured optimally improve efficiencies. “Power sections can be configured in numerous different ways. We’ve been using hard rubber power sections, which the latest sections have. The elastomers that have been used previously deform under pressure, but the hard rubber ones do not. With deformation, efficiency decreases.” Another important part of the mix in Departure’s wells is the use of modified positive pulse MWD tools from Blue Star Tools, a firm now owned by General Electric, which sells the tools under another name. Departure has engineered some performance modifications that increase the mean-time between failures. “We’ve also designed retrievability into the tool so that if the drill string is stuck, we can retrieve the tool,” says Robson. He also underlines that a combination of experience and teamwork played a part in the record wells. “There was an operations meeting once a week in which people from our offices met with the ARC operations team.” • Godfrey Budd 26
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East Coast treasure Satellite offshore fields prompt innovative drilling solutions
Graphic and photo courtesy of Husky Energy Inc.
amazing wells
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n efforts to grow its offshore East Coast production, Husky Energy Inc. is seeing more records fall as it drills ever more complex wells to reach satellite fields surrounding its existing White Rose field development 350 kilometres off St. John’s, Newfoundland and Labrador. Of the three additional pools discovered between 2003 and 2006 — North Amethyst, West White Rose and the South White Rose extension — Husky has targeted the first two for production.
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North Amethyst North Amethyst became Canada’s first subsea tieback when production began in May 2010. And its second producer, G-25 3, entered the record book last fall as the first on the East Coast to use inflow control device (ICD) screens and as the world’s second longest string ever installed in this configuration. ICD screens aid the flow of oil into the well while creating an even presw sure along its length, maximizing the Vie ast E amount of oil produced throughout the life of the well. 0 According to Husky, its East Coast 0 40 Operations team executed the drilling 00 8 and lower completion stages of the 00 12 “world class” well more than 11 days 00 16 A 00 ahead of schedule, at significant savings 20 B 00 to the company. 24 C 00 28 Producing from the same Ben 0 D 0 32 Nevis-Avalon sandstones as the main 00 36 White Rose field, North Amethyst contains an estimated 90 million barrels of reserves and is expected to add 37,000 barrels a day to White Rose production when all wells are com-
TAPPING NEW POOLS Above: The SeaRose FPSO at the White Rose field off Newfoundland is flanked by two drilling rigs. Husky is setting new records in its efforts to develop satellite fields. Below: the complexities of the 5.5 kilometre E-18 10 well targeting the West White Rose satellite pool are apparent. Containing a hairpin turn and multiple curves, it is the second longest ever drilled in the region.
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pleted. Husky plans to further assess the deeper Hibernia sandstones underneath the main reservoir, where the presence of 55 metres of net oil bearing reservoir was confirmed by drilling in 2008. West White Rose With the North Amethyst well complete, the team turned to the even more complex E-18 10 well targeting the West White Rose satellite pool. With a profile the company describes as “a little like a treasure map,” with a hairpin turn and multiple curves, the 5.5 kilometre pilot well is the second longest in the region. Its length was necessitated by the desire to drill from the existing infrastructure at the Central Drill Centre at White Rose, at a significant cost saving for the company. The well’s configuration, in what Husky calls a three-zone intelligent completion design, can be thought of as drilling and completing three wells in one, a design that will give the company a better understanding of the reservoir at less cost than drilling three separate wells. Husky will use the knowledge gained to optimize its development strategy for West White Rose. Located in the Jeanne d’Arc Basin, about 50 kilometres from the Hibernia and Terra Nova offshore developments, the $2.35 billion White Rose project (in which Husky holds 72.5 per cent working interest and Suncor Energy holds 27.5 per cent) began production in November 2005 from the floating production, storage and offloading (FPSO) vessel, the SeaRose. More than 65 kilometres of flexible flowlines and risers connect the icestrengthened double hulled SeaRose to the subsurface reservoirs, while electrical and hydraulic umbilicals tied to the FPSO control subsea manifold valves and wellheads situated in glory holes excavated into the ocean floor to protect against iceberg scour. The region still possesses plenty of potential for Husky, which holds exploration rights to 14 parcels of land and working interests in 23 significant discovery areas, including 16 in the Jeanne d’Arc Basin. The company holds 35 per cent working interest in the 2009 deepwater Mizzen O-16 discovery in the Flemish Pass and has extended its agreement for the Henry Goodrich offshore drilling rig until January 2013. • Maurice Smith
New Technology Magazine | June 2011
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the fixer Longer horizontals calling for ever lengthier intervention services
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fter spending millions of dollars boring into subsea reservoirs thousands of metres deep, there must be few things as frustrating, and potentially costly, as dealing with an obstruction or access issue that could hamper or kill the ability to produce the well. A Danish company that came up with a unique innovation to deal with such challenges, based on self-conveyed downhole tools with wheels, has been the saviour for many caught in such a predicament, setting and breaking its own records along the way. One of Welltec’s most recent records was established off the East Coast, when one of the company’s Well Tractors completed the longest cumulative distance of 82,157 metres while completing the deepest well intervention the company has ever recorded. Another was across the pond, where Welltec completed the first nipple milling operation for Nexen Inc. to get the Calgary-based company out of a tough situation at its Buzzard field in the North Sea. Nexen is operator and 43.2 per cent owner of Buzzard, the largest discovery in the U.K. North Sea since 1990. Located about 60 miles northeast of Aberdeen in the Outer Moray Firth, central North Sea, in 317 feet of water, it was discovered in 2001 and came onstream in early 2007. Nexen required a nipple — a short piece of pipe or wall tubular with a machined internal surface that enables installation of flow-control devices — to be milled out of one of its wells in order for a straddle to be run into the lower completion and set at 10,000 feet. The nipple was located at 9,147 feet and needed to be milled out from 4.437 inches to 4.5 inches, says Welltec. The initial plan was to perform a well kill, mill out the nipple on coiled tubing and then run the straddle in one piece. But the high loads and logistics associated with coiled tubing operations raised several concerns, Welltec says, prompting an assessment of possible alternative 28
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CLEAR THE PATH Welltec’s Well Miller NPR (nipple profile removal) tool provides precision milling without mobilizing heavy surface equipment for circulating and handling fluids, eliminating risk of damaging the reservoir. In its inaugural job, the tool was used to mill out a nipple at 9,147 feet well depth at Nexen’s Buzzard North Sea field.
and lightweight solutions. When invited to provide a solution, Welltec recommended running one of its Well Miller tools with a Well Stroker to provide the necessary load on the milling bit. The combined assembly was run and after a positive tag on the nipple, milling was initiated and completed in about 90 minutes. The Well Miller is revolutionary in the sense that it enables milling without the need of a conduit pipe back to surface to enable fluid circulation, says Welltec. Circulation needed to cool the cutting face and remove cuttings is generated by a built-in electric motor and pump system. The motor creates a rotational force that allows drilling at 20-2,000 revolutions per minute. The tool allows for precision milling without the risk of damaging the reservoir from circulating fluids, as well as eliminating the need to mobilize coiled tubing or heavy surface equipment for circulating and handling fluids. The Well Stroker can perform many of the jobs traditionally done with slick line or coiled tubing. It is designed to apply up to 33,000 pounds axial force downhole using a bi-directional hydraulic ram, which may be fitted with various shifting tools. The technology provides more precise depth and force control than conventional methods, according to Welltec. A slick line run into the Nexen well with a 4.480-inch drift confirmed the operation had been a success. This allowed the retrievable straddle system to be set in the well followed by perforation of the casing in the desired pay zone. “The nipple milling operation was a first for us,” Alastair Skelly, Completions and Intervention team leader for Nexen Petroleum U.K., said in January. “Had the latter operation not been successfully undertaken then the only alternative would have been a coil tubing operation. The nipple milling using [Welltec’s] tractor/mill was therefore critical to whether this intervention could proceed or not,” he said. Off the East Coast, an unnamed operator that needed to convey logging and perforation equipment to as deep as 10,068 metres was finding that, using other methods, it could not get beyond 6,000 metres. Welltec was called in for a contingency plan that required a two-man crew with the company’s standard Well Tractor 318. The Well Tractor uses an electric over hydraulic power unit that feeds the drive sections. Power to generate hydraulic pressure is supplied by attached cable or wireline, which is also used for control and communication. Traction is provided by wheels pressed against the casing or borehole wall. Each wheel has its own independent hydraulic motor, which drives the wheel and provides forward motion. The Well Tractor overcomes the limitations of traditional wireline operations by being able to reach the toe of a deviated or horizontal well and carry out operations throughout the entire length of the wellbore, the company says. Twelve runs were completed last summer to conduct all necessary logging and perforation jobs all the way to the required 10,068 metres measured depth to establish the deepest ever well intervention by the tractor. And the cumulative distance driven with a tractor in the 12 runs, at 82,157 metres, also marked a new world record, the company said, while it also managed to cut the cost of people on deck, reduce operational time and increase operational efficiency. • Maurice Smith
Photos courtesy of: Nexen Inc. (top), Welltec A/S (bottom)
amazing wells
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what's the optimum number of fracs for your tight oil play? 30
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Photo courtesy of Photos.com
tight oil
analyze that Tight oil producers getting methodical about multistage fracking By Maurice Smith
tight oil
U Photo: Karen Bleier/AFP/Getty Images
ntil recently the darling of the North American oil and gas industry, shale gas may be temporarily falling out of favour as natural gas prices continue to languish in the $4 per mmBtu range. But the magic that unlocked the massive shale gas prize — horizontal drilling and multistage fracking — has hardly skipped a beat as it jumps to a new host and leads the resurgence of oil production in played out or “vintage” plays across the continent.
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Just as the technology has had to be adapted to each new shale gas play to be a success, producers are finding adjustments to the techniques are necessary in emerging tight oil plays such as the Bakken and the Viking of Saskatchewan and the Cardium of Alberta. And as yet they are a little earlier along the learning curve as the technology migrates to light oil. With little in the way of detailed analysis undertaken or historical evidence to draw on, many companies are relying as much on trial and error and imitation as on hard data and science to complete their wells, say some producers. “In my opinion, a lot of what has happened is there has been a few companies [that] have done it, and maybe been quite successful at it, and then everybody else just looks over the
fence at what they are doing and follows them — they are doing it, but they don’t necessarily know why they are doing it,” says Dennis Hahn, completions engineer advisor with Enerplus Resources Fund. “What I am saying is, you should be doing it with a certain element of technical work to know why you are doing what you are doing. We are trying to validate what our predictions are, calibrate them with some actual data and that way we are going to be able to optimize production.” Hahn’s primary role over the last year and a half has been to provide direction on both frac sizing and frac frequency. “I believe by doing the technical work you can get to the end result quicker than drilling a bunch of wells, trying a bunch of things, and then having to wait a fairly long time in tight plays to see what your real results are. “We are trying to build some capital efficiencies into what we do by combining the technical aspects and then seeing what we see in the field results. It’s not so much a validation, it’s more a calibration, of your predictive tools. That’s the approach we are taking. And we have seen good results in our Viking oil and our Cardium oil.” Despite their similarities in benefiting from horizontal drilling and multistage fracking, tight oil and shale gas need to be approached differently, Hahn points out. “In the tight oil you spend a little more time trying to work with your frac fluids, and your jobs aren’t nearly as big. Their pays are much thinner, so you are working with a much more confined space within the rock deposition.” The Canadian Bakken, for instance, is a lot thinner and shallower than its American cousin and has neighbouring water zones the U.S. generally lacks, so multistage fracking has to be approached delicately. “To get good coverage and make it economic, you put more fracs in there but
TELUS World of Science 831289-39 full page
tight oil
Bakken pilot success could see waterflood tested in other tight oil plays Crescent Point Energy Corp.’s Viewfield Bakken waterflood pilot programs are showing positive initial results and could encourage other producers to attempt secondary recovery on other tight oil plays. The prize is a big one as many of Western Canada’s tight oil resource plays have large in-place volumes but relatively low recovery factors. Secondary recovery has the potential of boosting the amount of oil recovered from the reservoirs while slowing the high decline rate typically encountered with multistage fracturing of tight oil formations. Travis Wood, an analyst with Dundee Securities Ltd., says that while Crescent Point’s waterflood program is still in the early stages of development, the firm’s research indicates that “initial results support management’s expectations that recovery factors could materially improve.” Wood notes that in a recent report, the firm highlighted the production and injection response, various completion techniques, lateral length, well spacing and the design (i.e. the number of producer and injector wells) of each pilot. “We believe Crescent Point currently has 11 waterflood pilots either running or constructed [eight in the Bakken and three in the Lower Shaunavon]. Based on our estimates, there are a total of 17 injectors running on the first five pilots, which keeps them on schedule for 36 by the end of the year,” Wood says.
According to the Dundee report, Crescent Point’s first Bakken pilot, comprised of four horizontal producers and one injector, began injecting water in the fourth quarter of 2006, with production response identified in the third quarter of 2008. Wood says the first pilot saw a robust production response through the back part of 2008 and into much of 2009. Since reaching peak production rates of about 550 barrels per day (up from 50 to 100 barrels per day pre-injection), production has declined about 25 per cent over the past two years. “Impressively, production response is also identified on wells outside of the defined pilot, which would further improve daily rates, cumulative volumes and capital efficiencies,” Wood says. According to the April 4 Dundee report, the most recent production data indicates that the second pilot is producing about 125 barrels per day, down an estimated 42 per cent from peak rates of about 350 barrels per day. The second pilot is comprised of three injectors and two producers, which are staggered on a toe-to-heel basis. Crescent Point’s third Bakken waterflood pilot is also its largest to date and is comprised of six producers and five injector wells. Because water injection only began in the third quarter of last year, Wood says it is a bit early to compare production volumes with the earlier pilots, but management has indicated the
pilot is performing as expected. The lateral lengths and spacing are similar to the second pilot (1,400 metres and 200 metres range, respectively). The five injector wells were completed using Packers Plus Energy Services Inc.'s technology, while the six producing wells included four completed (two Packers Plus and two cement liners) and two uncompleted. Pilot four also started water injection in the third quarter of 2010 and as a result information is limited. Wood says that pilots five through eight still appear to either be in the construction or planning phase. “We believe that all the injector and producers will be completed using cement liners,” he says. Trent Stangl, Crescent Point’s vicepresident of marketing and investor relations, says his company’s waterflood pilot results should help convince some skeptics who doubted the process could work in tight reservoirs. He says that waterflood in the Viewfield Bakken looks like it could have a profound affect on recovery factors, noting that between 17 per cent and 19 per cent recovery is achievable from primary production based on eight wells per section. “The data suggests that we could be well north of a 30 per cent recovery factor. That’s a massive increase. The area that we have initially targeted for waterflood is probably 1.5 to two billion barrels in place,” Stangl says. “So, you can imagine a 10 per cent increase in recovery factor is upwards of 150 to 200 million barrels of potential incremental reserves if pilot one is right.” • Paul Wells
they are a lot smaller and you pump them at some out there as close as 30- or data inputs, are far more complex and can take much lower rates. Extra volume makes 40-metre spacing.” Whether they are weeks to provide answers — analytical models your frac grow more upwards and you end using coiled tubing, mongoose style fracs take mere hours and require inputs that are up in water, and then you end up with a or plug and perf style, he notes, “every relatively simple: “just your typical height, net water well,” says Hahn. frac costs a significant amount of money.” pay, porosity, permeability, water saturation, It is important to decide on optimum reservoir pressure, oil properties, what do you Understanding the reservoir well length, fracture spacing and well think you are getting for frac half lengths, Murray Reynolds, senior completions spacing very early in the field development that kind of thing,” Reynolds says. “Usually I technical advisor with Taqa North Ltd., program, he says. “I think the key is to do some 3D frac modelling work up front to who once consulted with Hahn, is on understand the reservoir, what is the resertry to figure out what the frac half lengths the same path. He believes there is too voir telling you, and do some modelling are.” much of the attitude of “whatever the work to come up with an initial guesstimate, In a relatively short period of time, an other guy is doing is what I will do” — then go out into the field, complete the operator can do a number of sensitivities, he an attitude that is costing producers wells, review it in three to six months after says, on aspects like permeability, net pay, unnecessarily. you have got some production data and see if frac half length and number of fracs along “I think in general people are putting it still goes around.” the horizontal. “Then [the model] will protoo many fracs into the ground, so they A good place to start is with some kind of vide a forecast of initial production, a proare spending too much capital,” he says. analytical model, which are available from duction versus time curve, production rate “Over time, people have migrated to various vendors, he says. Compared to numeriversus time and cumulative production tighter and tighter spacing — I saw cal reservoir models — which require a lot more recovery over time, so you can fairly quickly 34
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tight oil Data analysis zoom in on what type of recovery modelling came to a similar conclusion. Having performed the modelling work and you are going to get in, say, a “I did some fairly extensive work in the collected data in a busy season of drilling, Ener10-year period.” Bakken, some less extensive work in the plus is in the midst of evaluating its results, Permeability is one of the key Cardium, and they are both indicating Hahn says. “We are taking the data that we parameters, he notes. “If you have a the same thing. For the Bakken — not have and plugging it back into our predictive higher perm reservoir you’ll need the deep, high pressure North Dakota work and trying to make sure, or confirm, fewer fracs along the horizontal. In Bakken but more like the Viewfield where we need to adjust our approach on a these types of tight oil environments Saskatchewan Bakken — optimum spacgo-forward basis. where you have a range from maybe ing is between 100 and 150 metres,” he You calibrate what you have and you see if you 0.05 to 0.5 millidarcy, if your average says. Spacing may need to be tempered by can do better, or better understand what perm is 0.5 versus 0.05, it makes a big the operator's view of heterogeneities in difference on the number of fracs, just the reservoir, as well as future possibilities changes you want to make as you go forward, be it increasing your density, be it increasing because the oil can move more easily of waterflood and EOR operations. This proppant size or whatever other changes through the reservoir.” may support some tighter frac spacing. will optimize production.” In a study of Society of Petroleum The next question operators will be The company has come to some concluEngineers (SPE) literature of the addressing is: are we happy with only 10 sions already, such as determining that using Bakken and Cardium plays, Reynolds to 15 per cent recovery factors from foam rather than a gelled water style of frac found a wide range of conclusions on producing these expensive wells by has its advantages. “The beauty of foams is, optimum number of fractures. Anywhere primary production?” from three to more than 40 frac stages His study concluded that at both 0.5 and of your total fluids volume that you are pumping down there, only 15 per cent of it have been pumped in Cardium and 0.2 millidarcy permeability, there was no is water, so you are not pumping near as Bakken horizontal wells, he notes, with advantage to pumping more than 10 frac much water. From the water management little consistency, even within the same stages (155 metre spacing) and that side, that’s a positive, because you don’t operator, as to optimum frac stages. at 0.05 millidarcy permeability, optimum have to dispose of as much water.” In four SPE papers Reynolds highlights IP and reserves recovery was at 20 stages However using foam, which is generally for an upcoming tight oil conference presen- (74 metre spacing). No cases showed an 85 per cent nitrogen, results in a lot of comtation, he found the optimum frac spacing advantage to applying more than 20 stages pressibility, Hahn says. “So to predict what range should be between 90 and 150 metres, (closer than 74 metres), while optimum your hydrostatic pressure and friction are is with three of the four suggesting about 150 spacing for all permeability ranges was very, very difficult.” A key diagnostic tool metres is the optimum. His own analytical between 75 and 150 metres.
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487551-4711 With over $40 billion invested annually, is the second-largest service and supply JWN In-houseCanada market in the world. But Canada’s service half-page horzindustry has outgrown its domestic boundaries.
Reporting on the Canadian oilfield service and supply sector, this magazine keeps readers regionally informed, covering important developments from northeastern British Columbia to the East Coast of Canada. Feature articles track the vital issues and technologies that impact the service sector as a whole.
pick up your issuE by EmaiLing booksaLEs@junEwarrEn-nickLEs.com. to subscribE or to viEw our digitaL Edition, visit www.oiLandgasinquirEr.com
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This month’s Oil & Gas Inquirer looks at which markets Canadian service companies are expanding into, and how they are beating the competition. oilandgasinquirer.com
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tight oil therefore is a downhole pressure gauge at the “More fracs will give you higher point of fracking to get a reading on frac geom- IP but probably no higher cumulaetry. “You use that pressure to actually detertive recovery,” Reynolds says. “If mine what’s happening at the bottom. That you put more fracs in early, those pressure signature tells you lots about how additional fracs interfere with each your frac is growing, how much height you other quicker, so you get a higher have and how much lateral length you have.” decline and ultimately you will get “We have had some real good well results about the same recovery you would where we haven’t seen damage issues, and have had with a lot fewer fracs.” we have got very good and quick cleanup — “More is not necessarily better. we got the water out that we pumped.” It may give you good IPs, but is there
Involved in the oilpatch since 1970, Hahn says he has seen a tendency for the industry to go in stages up the learning curve, a pattern now repeated in tight oil plays. “The first one is the drilling side. We can almost drill anything now, so that is well up the learning curve. Then comes the completions, and then comes production and reservoir management, where I think there are a lot of things that we still need to grasp. “We need to think about how we manage our wells, how we isolate areas in “I think in general people are putting too many fracs into the the horizontal, and the whole production aspect. It’s about setting up our wellbores ground, so they are spending too much capital. Over time, such that we can do something with them people have migrated to tighter and tighter spacing — I saw later on because a lot of what we have now, in order to do intervention work or to do any some out there as close as 30- or 40-metre spacing.” kind of selectively shutting off zones or selectively producing zones, is quite costly. Fracture spacing, which Hahn says is a economics to it if it stabilizes out at the same As an industry we need to look at setting function of rock permeability, has been about rate or an even lower rate?” asks Hahn. up our wells with the right hardware and 60 metres in generally 600-metre laterals in “Quite often when you pump bigger capabilities to do it a little cheaper down the Viking, where hole stability is more of an jobs you are just getting more vertical the road,” he says. issue, and about 125 metres in 1,000- to growth, so you are not getting more The major service companies are developing 1,200-metre laterals in the Cardium. lateral exposure of your rock and thus tools that will allow operators to remotely It has been suggested that boosting the you are not gaining anything. So there activate downhole tools to perform tasks such number of fracs is sometimes used as a strategy again the bigger hammer is not necessaras shutting off or opening different zones to inflate initial production (IP) rates, at a long- ily better, if there is no economics to it. from surface, he says, some in the early pilot term cost to overall production. Reynolds You have spent more money to get a stage. “I think that is where we have to go and Hahn say it could have that effect. similar result.” in some of these plays.” •
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Illustration courtesy of Sanjel Corporation
TOOLS AND TECHNIQUES
PRODUCTION
Production Boost
New stimulation technique holds promise for under-achievers in mature carbonates A new stimulation technique for optimizing carbonate oil wells has been showing impressive results with previously underperforming wells in Mississippian formations in southeast Saskatchewan. Over the last few years, beginning in 2008, Sanjel Corporation’s new technique has been applied in the Frobisher, Frobisher-Alida and Midale formations in older fields in the region, some of which first began producing in the mid-1950s. “The technique is applicable to any carbonate formation that’s completed openhole. It hasn’t been tried yet specifically on gas wells but it’s applicable to them,” says Chris Medhurst, an engineering technologist and team leader for Canadian acidizing at Sanjel. Several companies have been using the technique, called SanStim, on openhole horizontals. For one group of 15 wells, which received the SanStim treatment in 2008 and 2009, the average initial well production “increased about three times the normalized monthly production,” according to a paper by Medhurst. The produc-
tion range of the wells improved from 200 to 500 barrels per month to 500 to 1,500 barrels per month post treatment. “Better performing wells have shown the increased production rates stabilize over a five to six month post-treatment period,” stated the paper, which provided the basis for a PowerPoint presentation at the CADE/CAODC drilling conference in Calgary in May. It also noted that, “The payout period of the treatment averaged two to three months, depending on commodity pricing and well response from the treatment.” SanStim involves a process in which acid — typically 15 per cent hydrochloric acid — is pumped through nozzles on a tool at the end of a coiled tubing string. The new technique combines key elements of two traditional treatment processes for stimulating wells. One is matrix acidizing, used for stimulating oil wells. In this, hydrochloric acid is either placed at the formation face in order to soak it or is put under pressure in order to penetrate further into the formation.
POWERFUL COMBINATION Sanjel’s SanStim, which brings together matrix acidizing and abrasive jetting in one tool, has bolstered production in some wells up to three times over normalized monthly rates.
New Technology Magazine | June 2011
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In the other process, known as abrasive jetting, fluid carrying abrasive material such as sand is forced through nozzles, “jetting radially towards the casing or openhole. The kinetic energy of the sand particles induces erosion and penetration into the formation, bypassing near wellbore damage,” according to Medhurst’s paper. Recent applications of the SanStim process have omitted the use of abrasives, with the acid content acting to dissolve the carbonate formation. The SanStim technology marks a refinement of a technique first tried on two wells in southeastern Saskatchewan in 2003. Data from those initial treatments suggested that too much acid had been pumped, resulting in excessive treatment costs and stimulation of undesirable zones. The two wells, A and B, had pre-treatment water cuts of 75 and 96 per cent, respectively. Well A was suspended a month
Photo courtesy of Sanjel Corporation
new tech
after the treatment was performed, despite tripling production over the previous three months. Well B was put on production after completion and continued with a water cut in the 90-per-cent range. As Medhurst’s paper notes, “Well B continued to produce from 300 to 500 barrels of oil per month with a continued
increase in water cut to 100 per cent by fall 2008.” With one of the two wells shut in within a month, data was effectively limited to one well. But the technique looked promising. It had shown that it could either erode or dissolve nearwellbore damage and result in 1.5 to two times the normalized production rates.
WELL REVIVAL Coiled tubing equipment deploys Sanjel’s SanStim system into carbonate formations completed openhole. The technique has primarily been used in southern Saskatchewan, in formations such as the Frobisher, Frobisher-Alida and Midale where production dates back as far as the 1950s.
TIGHT OIL
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new tech Design tweaks About five years later, Medhurst began looking at the data on the 2003 treatment wells as interest in southeast Saskatchewan was rebounding because of increasing commodity prices and the region’s high quality oil. Also, he says, by 2009, capital was tight but companies wanted more production from their fields in the region. “There was a need to look at cost-effective ways to improve production without drilling or fracking,” he says. He noticed that the openhole volume had increased by nearly 20 per cent as a result of the treatments. “This was mostly as a result of the fluid, not the acid. So if smaller nozzles had been used, the wells could have been washed out with less acid. There was still excess dissolving capacity because of the amount of acid that had been used,” he says. He concluded that the critical factor in improving production in the 2003 treatments was “the higher than
“The technique is applicable to any carbonate formation that’s completed openhole. It hasn’t been tried yet specifically on gas wells but it’s applicable to them.” normal velocity” of the fluid jets. These observations led to tweaking some key design concepts. The changes would ensure that fluid velocity was maintained but enable a reduction in fluid volumes by as much as 60 per cent — and cut costs. Also, says Medhurst, “The jetting tool is designed to fit down the wellbore with very little stand-off from the rock face.” For the next stage in a program to further develop and improve the technique, a dozen wells were selected for treatments in 2008. Two were excluded as outliers, leaving 10 wells. “All of the remaining 10 had been in production for
a minimum of two years,” says Medhurst. Other key criteria for the candidate wells were water cuts below 65 per cent, highly soluble carbonate formation, underperformance and good formation pressure. Results from the initial 10 wells have been good. They were located across three fields in the Frobisher-Alida and Midale formations — and there’s now substantive posttreatment data. “Averaged over two years, the 10 wells have had an 86-per-cent increase in production,” says Medhurst. Part of successfully implementing a SanStim treatment entails selecting the right inter-
vals of the horizontal leg. In addition, the annulus can be left open to observe reaction to the treatments so adjustments can be made on the fly. NAL Resources Limited has been using SanStim for about a year and has treated nine wells so far. “We’re getting increased oil and gas from the wells,” says Paul Skoczylas, a production technologist at NAL. “When you set out an expectation for each job, you have a number in mind, and this exceeded expectations, averaged out over the nine wells. My best case tripled oil production and doubled gas production. All the wells are in southeastern Saskatchewan.” NAL wells have been treated with SanStim across seven fields and in three different formations, Skoczylas says. “So, we have a wide range of data.” • Godfrey Budd CONTACT FOR MORE INFORMATION Ken Berg, Sanjel, Tel: 403-269-1420, Email: kberg@sanjel.com
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gasandoilexpo.com New Technology Magazine | June 2011
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new tech
PRODUCTION
Efficient, Accurate, Green NASA-inspired technology applied to the humble oilfield pump
SPACE-AGE TECHNOLOGY Trido Industry’s solar-powered oilfield pumping system, left, is based on an activator, above, originally created as part of a NASA project to build a space elevator.
The irony is not lost on Jim Graham, associate professor emeritus, who spent 25 years at the University of Calgary trying to promote the diversification of Alberta’s economy away from overreliance on the oil and gas industry. “I taught entrepreneurship and new ventures at the faculty of management and all of our funding was dependent upon diversification away from the oil and gas industry,” he says. And now, 15 years after retiring from the U of C, Graham is product development manager for Calgary-based Trido Industries Inc., which is involved in that most basic of oil and gas related areas — pumps used in the upstream sector. However, he’s quick to point out there is something transformative about the technology that Trido has developed; it’s based on a solar-powered system developed for NASA. “Our primary product is the activator for the chemical injection pumps used in the industry,” he says. “Up to now solardriven pumps have been unreliable and expensive to operate, but our system is both reliable and cost-efficient.” 42
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Based on a technology licensed by Calgary-based technology firm General Magnetic, headed by former Calgary mayor Al Duerr, it was developed at the University of Saskatchewan for a futuristic space elevator project NASA sought proposals for. That project was based on a concept popularized by science fiction writer Arthur C. Clarke, who visualized a cable stretching to upper Earth’s orbit as an alternative to rockets. But it turns out the technology works on more practical applications as well, such as Trido’s solar-powered chemical injection pump. Thousands of pumps are used annually in the industry, particularly for natural gas production, and the industry spends hundreds of millions a year on them. In Canada, various chemicals need to be pumped into the reservoir to prevent liquidsprone gas from freezing, while corrosion and other reservoirplugging problems must also be prevented no matter where geographically the gas is being produced. Operators also need to pump emulsifiers into the reservoir to
prevent the gas, as it cools or as pressure drops, from plugging up the well. Trido’s activators can be attached to any one of the dozens of conventional pumps used industry-wide. “We use any of the standard fluid ends,” Graham says. “The same companies that service any pumps
tional pumps are powered by fuel gas. “A diaphragm at the end of the pump takes gas from the well, under water pressure, using a valve system,” he says. “But the problem with those conventional systems is they’re unreliable. It’s difficult to get them to run or stop as fast as operators want.” Wells often freeze up or seize up. Conventional systems also release methane gas into the atmosphere, a major greenhouse gas (GHG), contributing about 15 per cent of the GHGs the Canadian oil and gas industry produces. No methane is released with Trido’s systems. Upstream fuel gas-driven instruments vent three billion cubic metres of methane annually, equivalent to about 6.5 million tonnes, and conventional chemical injection pumps account for 60 per cent of that. “There are about 100,000 to 150,000 of these conventional pumps in the Western [Canadian] Sedimentary Basin at any one time,” says Graham. “I’ve been in areas where there have been as many as six pumps in one well.”
“There are about 100,000 to 150,000 of these conventional pumps in the Western [Canadian] Sedimentary Basin at any one time. I’ve been in areas where there have been as many as six pumps in one well.” that are standard in the industry can service our units.” But Trido’s solar-powered pumps certainly don’t operate like conventional systems, he says. While the activators start out being more costly than conventional systems — at $7,000 they’re perhaps 40 per cent more expensive — Graham says the lifecycle costs of the systems lead to substantial savings for producers. For the most part, conven-
Efficiencies gained In addition, the conventional systems use perhaps 15 per cent of the gas from the well. Trido’s solar technology provides reliability beyond any conventional systems and also, because the units don’t use gas from the well, there are major savings, since that gas can be marketed. Solar-powered systems have been used in the industry for many years, but they have not
new tech been widely adopted because they, too, have not been reliable. “That’s because the solar systems that have been used in the past start and stop a lot and use a lot of power,” Graham says. “But our motor, which draws less than three amps, uses less power and can be operated as part of a SCADA [supervisory control and data acquisition] system, a computerized control system that allows for great accuracy. “With our system you achieve more accuracy, substantially reduce the GHGs you release, use lower quantities of chemicals and you also have the gas to sell,” he says. Three-year-old Trido has had a number of its units used in trials and recently shipped 15 of them. Because of that operating history, including one study of 300 wells, the company can provide statistics that prove the systems work, he adds. Conventional systems lead to about 60 per cent of the wells being over-injected and 40 per cent being underinjected, but Trido’s system virtually eliminates that inefficiency. “Our system achieves about 94 per cent efficiency,” says Graham. Trido’s technology is slowly being adopted but he says the industry needs to abandon its past negative experience with solar power. “The industry has heard the solar pitch before, but our technology is different.” Privately-owned Trido is a family affair, with Graham’s son, Russell, being president. Their partner is Clint Mason, a well-known oilfield service industry entrepreneur, who is partnered with Russell in Calgary-based Axiom Well Solutions Inc., an innovative provider of wireline and surface oilfield services. • Jim Bentein CONTACT FOR MORE INFORMATION Jim Graham, Trido, Tel: 403-620-2919, Email: jgraham@tridoind.com
NOSE SCOOP Sky Hunter Exploration’s Skydrocarbon hydrocarbon detection system uses an aircraft-fitted air intake device to scoop air samples that can be analyzed for molecular anomalies indicative of subsurface oil and gas deposits.
EXPLORATION
Sky High
A new exploration technology hopes to uncover untapped resources The retrofitted plane looks, to put it bluntly, like an anteater. But inside the flying laboratory is the latest technology for high-grading undiscovered oil and gas deposits — at a fraction of the cost of conventional methods. “Our technology is much less expensive than traditional exploration,” says Russ Duncan, principal of Calgary-based Sky Hunter Exploration Ltd. “Running a 3D seismic survey over an area the size of a township can cost $8 million. A 2D survey can cost $1.2 million. It costs around $100,000 to do a Skydrocarbon survey.” Skydrocarbon is an airplanemounted hydrocarbon exploration system that measures molecular anomalies that form in the atmosphere directly above untapped oil and gas deposits. Using the technology, petroleum companies can explore over large tracts of land quickly, efficiently and affordably. The oilpatch, of course, has had more than its fair share of eccentric inventors promising pie-in-the-sky results from magic black boxes. The promoters of Skydrocarbon, how-
ever, have long pedigrees in the sector. Russ Duncan is a professional engineer with a degree from the University of Alberta and has spent four decades working as a petroleum engineer and executive at Ocelot Energy Inc., Paramount Resources Ltd. and Newalta Corporation. His partner at Sky Hunter, Kenneth Bradley, is a professional geologist, also with a degree from the U of A. Over the last three decades, he has served as a geologist and executive with Tenneco Oil of Canada Ltd., Bonanza Oil & Gas Inc. and Prism Petroleum Inc. Other companies have devised various versions of aerial molecular survey systems in the past. Several years ago, Shell began to develop its own proprietary system called Light Touch, which measures airborne methane. The concept for Skydrocarbon emerged several decades ago, when an Australian mining engineer (who asked not to be identified by name in the press) discovered that minute traces of hydrocarbons existed in the air. He developed a rudimentary airborne system as a hobby, but
never ran it as a business to detect hydrocarbon deposits. While in Canada, he met Bradley, who was intrigued enough with the concept to co-found Sky Hunter with Duncan in the late 1990s in order to commercialize the idea. How it works The theory behind Skydrocarbon is relatively simple. It has been known for over a decade that small amounts of hydrocarbons seep through the caps on conventional reservoirs. As they rise to surface, the molecules become negatively charged. The negativelycharged molecules emerge into the atmosphere at sufficient rate that, even with wind dispersal, a small, but measurable plume remains over the reservoir. Working with Richmond, B.C.-based MacDonald Dettwiler & Associates Ltd. (the inventors of the Canadarm), Sky Hunter has devised a plane-mounted plasma unit that can detect and measure the negatively charged particles. Flying at a height of 100 metres, the airplane scoops air samples once per second and feeds them into the unit,
New Technology Magazine | June 2011
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new tech which measures negativelycharged dry gas, propane and pentane molecules. By flying back and forth in a grid pattern, the plane collects a sizeable number of data points over the target area. The data points are compared as percentages of strength of signal to background (around 14 parts per million in Alberta); anomalies show up as contoured blips. In 2006, Sky Hunter ran a test survey over the Peerless region of northern Alberta, home to several Devonian Keg
(moisture from rain and snow fouls the sensors) and calm (flying at 100 metres altitude in winds over 40 kilometres per hour is dangerous). Other than that, the sky’s the limit. “We can fly any time of the year, and even run surveys over water,” says Duncan. Also, older reservoirs do not show up on surveys. As reservoirs are produced, their pressures decrease to the point where there is insufficient discharge of negatively-charged molecules to form an atmo-
MICROSEEP DETECTION Map shows oil and gas footprints detected by Sky Hunter Exploration’s Skydrocarbon technique, which the company says validates prospective areas.
River reef fields. Oil wells supplied control points over known reefs that correlated to anomalies, but the survey also turned up several anomalies where no one had ever drilled before. “We ended up selling a set to a company that is now trying to raise money for an exploration project,” says Duncan. There are minor constraints to running a Skydrocarbon survey; skies must be clear 44
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spheric plume; the technology only works on untapped reservoirs. “When Shell discovered the Tay River gas field west of Rocky Mountain House a few years ago, we flew a survey before they started producing, and it showed up,” says Duncan. Sky Hunter is under confidentiality agreements and cannot divulge potential clientele or results of preliminary work in detail, but various indepen-
dent industry veterans have examined the system. Paul Moller, a former geologist, is a director of Cornerstone Capital, a merchant bank based in Toronto. Several years ago, he was asked by Sky Hunter for advice regarding commercialization of the technology. “I cannot comment as an expert on the technology, but it certainly looked like it had a lot of merit,” he recalls. “I recommended to certain oil companies that I work with that they look at it and test to see what validity it has.” Skydrocarbon has also passed under the watchful eye of Petroleum Technology Alliance Canada (PTAC), a not-forprofit association that facilitates collaborative research and development in the oilpatch, matching promising ideas to industry supporters. Bruce Peachey is a professional engineer contracted with PTAC as a technical advisor to help evaluate new ideas. “Our main role is to facilitate good ideas moving forward, to help develop them to commercialization,” he notes. Peachey first learned of Sky Hunter’s system four years ago, when the company contacted PTAC with their concept. “When someone approaches us, we don’t have the budget to run lab tests, but we do conduct an assessment of the idea and the people.” Peachey liked what he saw. “The principals at Sky Hunter had lots of experience in the oilpatch, a good reputation and a plan to develop their idea with all of the right people involved.” PTAC annually sets up a technical forum in which small to medium sized companies can make pitches of their ideas and products to larger oil firms. “We invited them to our showcase in March 2011,” says Peachey. “A number of producers were interested.”
“For the first nine years, industry reception was cool,” admits Duncan. “But, now that we have applied for a patent, we can explain the technology and people understand what we’re doing.” Many different types of companies and plays can benefit from the technology. “Let’s say you’re a large company with a five-township lease in an area with very little well control,” says Duncan. “You want to high-grade the land and find some sweet spots. Skydrocarbon can show the presence of untapped reservoirs. You can then focus your seismic on those sweet spots.” Smaller companies often invest in areas where they have good well control, but want to know which way a trend of untapped reserves is going. “They may be looking for channels, pinch-outs or structural trends; they can run a survey and match to what they know,” says Duncan. All companies benefit in greater employee efficiency. “Everybody is having a tougher time these days with people resources,” says Duncan. “When it comes to evaluating prospects, you don’t want people focusing on land with low likelihood of success.” Duncan hopes to have paying clients in the near future. “We will have a plane in the air by mid-summer,” says Duncan. “In the meantime, we are talking to different operators, including a group that has a history of doing speculative surveys.” But the proof, as they say, will be in the pudding. “The only way to really test it is in the field,” says Peachey. “The potential benefit is so huge that you can’t ignore it.” • Gordon Cope CONTACT FOR MORE INFORMATION
Why use it? Not surprisingly, in a conservative industry like O&G, Skydrocarbon has had few takers.
Russ Duncan, Skydrocarbon, Tel: 403-228-2175 ext 208, Email: russ.duncan@skyhunter.ca
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