DAVID MICHAEL COHEN, Managing Editor
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| Brigham’s Abelmann 23-14-1H well in the Rough Rider project area of McKenzie County, North Dakota, was drilled with Nabors Drilling Rig 266. The well was completed with 33 frac stages and produced at an early 24-hr peak rate of 4,169 boe. Photo by Jim Blecha. |
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Horizontal drilling in the Bakken shale formation of the Williston basin has been going on since 2000, but since 2009 the play has seen an unprecedented surge in drilling activity. The current drive was launched in part by a US Geological Survey (USGS) petroleum resource assessment in 2008 that named the Bakken formation the country’s largest “continuous” oil accumulation, and has been spurred on by strong oil prices against the backdrop of a stagnant gas market. The drilling bonanza, now targeting both the Bakken and the underlying Three Forks formation, has caused production to exceed the region’s takeaway capacity, forcing oil companies to use rail transport to carry the oil to market.
EXPLORATION AND PRODUCTION
The 2008 USGS assessment estimated the Bakken’s technically recoverable resources at 4.3 billion boe, consisting of 3.65 billion bbl of oil, 1.85 Bcf of gas and 148 million bbl of natural gas liquids. Subsequent exploration and production have pushed estimates considerably higher, due largely to early delineation and production of the underlying, more permeable Three Forks formation, Fig. 1. Considered part of the Bakken petroleum system but separated by the thin dolomitic Sanish formation, the Three Forks is made up of sand and porous rock containing an estimated in situ total of 20 billion bbl of oil. That’s far less than the 169 billion bbl believed to be held in the Bakken shale, but because of its greater porosity and permeability, a much larger percentage of Three Forks oil is recoverable. Recent estimates have put the total recoverable resources in the Bakken system at 9 billion boe (Wood Mackenzie), 11 billion boe (North Dakota Department of Mineral Resources) and even 24 billion boe (Continental Resources founder Harold Hamm)—almost enough to double US oil and gas reserves.
The vast majority of activity has taken place in western North Dakota, which holds about two-thirds of the total Bakken acreage. In 2010, North Dakota production from Bakken and Three Forks formations averaged over 234,000 bopd from 2,123 wells, accounting for 76% of the state’s total output, according to the state Industrial Commission. That’s 73% up from an average of 135,000 bpd in 2009 from 1,344 wells (62% of that year’s total).
The bulk of Bakken activity moved from Montana to North Dakota in 2006 with the discovery of Parshall field, and since then Montana’s Bakken oil production has been in steady decline, from 52,000 bpd to a current level of 31,000 bpd, according to figures supplied by the Montana Board of Oil and Gas and reported by Platts Oilgram News. There are indications of an upcoming increase in activity on the Montana side; the state issued 109 Bakken well permits in 2010, almost all in the first half, and has issued at least 40 so far this year, vs. just 20 in the first half of 2009. According to the Platts report, in mid-July there were 10 rigs running in the Montana part of the Bakken, and 170 on the North Dakota side.
TRANSPORTATION
Increasing production is already putting a strain on the rail lines that operators are increasingly using to transport their Bakken oil to market—pipeline capacity in the region being woefully insufficient. It has been estimated that current rail lines out of North Dakota can handle up to 780,000 bpd. According to Platts blog “The Barrel,” national railway BNSF has doubled the amount of Bakken oil it hauls in the past year, as well as the destinations for the oil. Savage Cos. recently began work on a 270-acre multi-user rail terminal in Trenton, North Dakota, to move Bakken crude to market. In July, Tesoro said it was involved in a rail project to move up to 30,000 bpd of Bakken crude west to its Anacortes, Washington, refinery, and ExxonMobil reported that it is shipping Bakken crude by rail to feed its Midwest refineries.
Among a number of potential pipelines, the one that could make the biggest difference for the Bakken is TransCanada’s proposed 2,700-km Keystone XL project, which would transport Alberta oil sands to Port Arthur, Texas, crossing Montana on its route. In January, the company agreed to build an 8-km spur that would allow the shipment of 65,000 bopd from the Bakken. An environmental impact statement for the $7 billion project is expected this month, and the State Department has said it will decide by the end of the year whether to permit construction to go forward. However, the pipeline faces intense opposition from environmental activists, particularly in the wake of ExxonMobil’s Silvertip pipeline spill in Montana last month, which released an estimated 1,000 bbl of oil into the Yellowstone River.
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| Fig. 1. Stratigraphy of the Bakken petroleum system. Image courtesy of GMXR Resources. |
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OPERATOR ACTIVITY
Development plans in the Bakken were slowed down during the first quarter of 2011 by a record cold winter, flooding and road closures, but by the end of the half operators were reporting that they had added frac crews and were expecting to make their projected production by the end of the year. There are literally scores of large and small independent companies that hold acreage in the Bakken; this report only covers a handful of the biggest and most significant.
Hess is the largest leaseholder in the Bakken, with more than 900,000 net acres in the North Dakota portion of the play containing net reserves estimated at 365 million boe. The New York-based major made two large acreage acquisitions in the Bakken during December 2010. It bought 167,000 net acres from Tracker Resource Development subsidiary TRZ Energy for $1.075 billion in cash, and added 85,000 net acres through the purchase of American Oil & Gas in a stock deal worth about $445 million. In a conference call in April, Hess Chairman and CEO John B. Hess said the company is focusing most of its 18-rig drilling program for 2011 on developing these two acreage acquisitions, which are located near Hess’ previously acquired Bakken acreage. The company plans to spend a total of $1.8 billion for Bakken drilling and infrastructure in 2011.
Hess’ Bakken production in the first half of 2011 averaged 25,000 boepd, up 25% from the 20,000 boepd being produced at the end of 2010. Part of that increase is due to improved completion design. According to Barclays Capital, Hess was using 24–28 frac stages per well in first-quarter 2011, compared with 22–24 stages in fourth-quarter 2010. As of early June, the company had adopted a 38-stage design and had four dedicated frac crews working and a fifth expected to be added in July. Second-quarter production was adversely affected by the combination of a record cold winter and severe flooding, which put the company 50% behind its completion schedule. But in a July 27 conference call, CEO John Hess said production was already up to 34,000 boepd and expressed confidence that the company would close the year with Bakken production close to its forecast of 40,000 boepd. To support this rising production, Hess is in the process of expanding its Tioga gas plant in northwestern North Dakota and building a crude rail loading terminal, and plans to add three compressor stations. The $325 million Tioga expansion, which is expected to be finished in late 2012, will increase the plant’s capacity to 250 MMcfd from 100 MMcfd.
Continental Resources has made the Bakken play its primary area of focus over the last few years, and is continuing that trend in 2011 with 75% of its drilling budget, or $1.137 billion, earmarked for Bakken wells. Of that total, $102 million will be spent in the Montana portion of the play, where Continental is one of the most active operators. Continental is currently running 25 rigs in the Bakken.
The Enid, Oklahoma-based independent has the second-largest net leasehold in the Bakken with 868,900 acres, of which 68% is derisked and in the development phase. In production, Continental leads the pack with net Bakken output of 25,523 boepd in the first quarter of 2011, a 67% increase over the same quarter last year. This brings Continental’s Bakken production to about half of the company’s total. In an interview with Forbes in June, Continental founder Harold Hamm said he expects the company to be producing 100,000 boepd from the basin by 2016. The Bakken also holds a majority of the company’s proved reserves, with 43% (157 million boe) in the North Dakota part of the play and 11% (40 million boe) on the Montana side.
Continental has been working to maximize productivity on its acreage using its Eco-Pad technique, which employs a walking rig to drill four horizontal wellbores from a single pad, two into the Middle Bakken and two into the Three Forks, Fig. 2. The concept was launched in February 2010, and as of March 2011 seven sites had been drilled using the method, and three others were underway. In addition to increased productivity and time savings, the method has greatly reduced land disturbance.
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| Fig. 2. Using its Eco-Pad method to drill eight wells from two sites on a 1,280-acre unit, Continental Resources has achieved EURs of 4.1 billion boe. |
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Whiting Petroleum added 76,000 net acres to its Williston basin holdings during the second quarter of 2011 to bring its total leasehold in the Bakken hydrocarbon system to 680,000 net acres—the area’s third largest—located within a number of separate areas in North Dakota and eastern Montana. At the end of 2010, the company held about 1.3 billion boe of proved reserves in the Bakken/Three Forks play; that number will likely increase substantially as the newly acquired acreage is delineated. On July 19, the company reached a new production record of 58,105 boepd gross (31,161 boepd net) from the Williston basin. With more than half of its E&P budget directed at the Bakken/Three Forks play ($707 million), Whiting is currently operating 17 rigs there, as well as two dedicated frac crews and one half-time frac crew that the company says are capable of fracing about 18–20 wells per month between now and year-end 2011. Though 44 operated wells were waiting on completion as of July 15, the company hopes to lower that number to 25 by the end of November.
Activity to date has been concentrated in Sanish and Parshall fields of Mountrail County, North Dakota, where the company has over 84,000 net acres and produced 24,350 boepd net during the second quarter of 2011, more than three-quarters of its Williston basin total. And that output was down 6% from the first quarter, due to difficult weather conditions. As of March 31, Whiting had 194 producing wells in Sanish and 127 in Parshall. The company drilled 99 wells in the two fields last year, and plans to drill 106 there in 2011.
Whiting is just beginning to ramp up activity in its largest Williston basin leasehold, about 255,000 net acres in the Lewis and Clark prospect. The company drilled 10 wells there between April 15 and July 15, bringing its total number of operated producing wells in the area to 26. Six rigs are currently running in the field, and the company expects to run eight there from September through the end of the year. Whiting’s production at Lewis and Clark almost doubled in the second quarter, to an average of 2,640 boepd. Unlike Whiting’s other properties in the Williston basin, Lewis and Clark targets only the Three Forks formation, with no Bakken production. Based on the relatively shallow decline rate observed so far, Whiting expects its Lewis and Clark wells to have estimated ultimate recoveries (EURs) in the range of 300,000–500,000 boe. In early April 2011, the company broke ground on a gas processing plant at Lewis and Clark. The Pronghorn gas plant, near Belfield, North Dakota, will have an initial inlet capacity of 30 MMcfd and is expected to be completed by November.
Whiting’s other Williston basin properties include acreage in the Hidden Bench/Tarpon and Cassandra prospects within North Dakota and the Starbuck prospect in Richland County, Montana. The company plans to drill 18 wells, six wells and five wells, respectively, in 2011 in these three areas, all of which target the Middle Bakken member.
EOG Resources drilled the first horizontal Bakken well in eastern Montana’s Elm Coulee field in 2000, and built a strong acreage position in the North Dakota part of the play during the early leasing period of 2004–2007. Last year, the company increased its total Bakken/Three Forks position to about 600,000 net acres. The Houston-based producer drilled 111 wells in the Bakken and Three Forks formations in 2010, and is currently running a 10-rig program there to maintain a similar activity level in 2011.
EOG moves much of its Bakken oil production to market, along with third-party production, via its train-loading facility near Stanley, North Dakota. In 2010, the company loaded 148 train units of 68,000-bbl capacity each at the facility for transport to Stroud, Oklahoma. EOG’s Bakken Lite system, to gather production from its non-core assets in the play, is expected to be operational this year.
Two majors hold large acreage positions in the Bakken/Three Forks play. ConocoPhillips has 460,000 net acres and produced 14,000 boepd last year. In its 2010 annual report, the company reported plans to run five rigs in the play this year, and CFO Jeff Sheets said in a July 27 conference call that the company plans to double its Bakken and Barnett rig counts by the end of 2012. ExxonMobil holds 410,000 acres, which it picked up in its acquisition of XTO last year. In the first half of 2011, XTO received permits for 25 new wells in the Montana part of the Bakken, more than any other company.
Marathon holds 391,000 net acres in the Williston basin within five North Dakota and three Montana counties, and maintains a working interest of about 80% in its operated assets. At the end of the second quarter, the company had seven rigs operating in the North Dakota Bakken, with plans to drill 70–75 operated wells in 2011, plus an additional 50–70 non-operated wells. Net production, currently at 16,000 boepd, is expected to increase substantially in the second half as Marathon adds a second frac crew, to finish the year at 20,000 boepd. Marathon has 28 gross operated wells awaiting stimulation and plans to fracture stimulate 50 total wells before the end of the year. By 2016, the company expects to be producing 33,000 boepd in the Bakken.
Brigham Exploration has 378,000 net acres in the Bakken shale, of which almost 60% is under development. The Austin, Texas-based independent increased its operated rig count in the play to eight in early June, with five rigs drilling in the Rough Rider project area, two in Ross area (both in North Dakota), and one in Montana. The company plans to reach 10 operated rigs by midyear and to add two walking rigs in early 2012. With two dedicated frac crews working and efficiencies gained from the use of “zipper fracs,” Brigham estimates that it will be capable of fracing and bringing online a minimum of eight wells per month, with the goal of achieving 10 fracs per month. The zipper frac technique involves alternating perforation and fracturing operations between two adjacent wells so that each crew is able to work without downtime until the job is completed. Pressure is not bled off between stages, resulting in a stress barrier that prevents the fractures of the two wells from intersecting.
Brigham estimates its second-quarter production in the Bakken to be slightly more than 12,000 boepd, up from 11,300 boepd in the first quarter. To date, the company has completed 68 consecutive long-lateral, high-frac-stage wells at an average early peak rate of about 2,800 boepd.
Occidental Petroleum initially entered the Bakken in 2008, but greatly increased its leasehold in December 2010, snapping up 180,000 contiguous net acres from Anschutz Exploration for $1.4 billion to bring its total to over 200,000 acres, with a net risked reserve potential in excess of 250 million boe. The North Dakota acreage was producing 5,500 boepd at the time of the transaction and is prospective for the Three Forks formation. Anschutz divested the remainder of its $115 million. Oxy hopes to increase its Bakken/Three Forks production to 30,000 boepd by 2017.
Newfield Exploration is currently operating five rigs in the Williston basin, where it holds about 150,000 net acres. During the second quarter of 2011, the Houston-based explorer completed nine new wells in the basin, and it expects to complete an additional 13 wells in the third quarter. The company’s 2011 development plan for the play calls for almost all wells to be drilled with 9,000-ft laterals, following two such “super extended lateral” wells drilled in late 2010.
GMX Resources spudded its first Williston basin well, targeting the Three Forks formation, on July 7, and plans to complete it during the third quarter. The Oklahoma City-based operator holds about 24,500 net acres in the basin, including 136 development locations. It plans to bring in a second rig in September.
PetroBakken operates in the portion of the Bakken play located within southern Saskatchewan. The Petrobank subsidiary drilled 45 Bakken wells (33.1 net) in the first quarter of 2011, of which 24 (21.2 net) were bilateral, with two horizontal legs extending from a single vertical wellbore. Production averaged 23,400 boepd, essentially flat from the previous quarter.
TECHNOLOGY APPLICATIONS
Wells across the Williston basin are generally completed on 640-acre or 1,280-acre spacing, resulting in 5,000-ft and 10,000-ft horizontal wellbores, according to information provided by Baker Hughes. Operators in the development stage are drilling as many as three wells within a given spacing unit in the Bakken and Three Forks formations. Most wells are oriented either north-south or northwest-southeast, usually to take advantage of induced fracture propagation in the direction of maximum horizontal stress.
Wells are always lined with casing from the surface to the heel to ensure isolation of the target formation. Single-lateral completions are standard in the North Dakota Bakken, although many variations of multilateral completions have been attempted, most notably the bilateral design successfully employed by PetroBakken in Saskatchewan.
Openhole multistage completions. Openhole completions are often used in place of cemented liners. Early in development of the Bakken, openhole completions were used for limited-entry fracture stimulation employing a single fracture treatment for the entire lateral. Since then, multistage openhole completions have become the norm, as operators generally hold a large amount of contiguous acreage in the rural region compared with other shale plays, allowing for longer laterals. Furthermore, the overlying geology dictates a relatively high-cost wellbore architecture in the vertical section of Bakken wells, making long horizontal sections economically attractive.
In a recent case study, Packers Plus Energy Services compared production results from two sets of sample Bakken wells drilled in the same field with the same basic well architecture: one set employing openhole multistage completions and the other having multistage cemented-liner, plug-and-perf completions. Located on Slawson Exploration’s acreage in the East Nesson anticline in Montrail County, North Dakota, the wells all employed an identical treatment design for each stage, consisting of a hybrid fluid and proppant loading of 0.5– 5.0 lb/gal with a total proppant volume of about 100,000 lb.
The results demonstrated substantially better performance in the openhole wells. The average initial production (IP) rate for the openhole wells was 1,474 bopd, 58% higher than for the cemented-liner wells. This differential was sustained over time, with the average 30-day and 60-day rates for the openhole wells being 48% and 57% higher, respectively.
An important driver of improved well productivity in the play has been the use of ball-activated sliding-sleeve fracturing systems in openhole completions, which allow for very precise placement of fracture treatments (see Contributing Editor Ali Daneshy’s column, page 65). In March, Baker Hughes announced the installation of a 40-stage openhole completion system in the Williston basin for Whiting Petroleum, which the service company called “the most number of stages ever performed in a single lateral frac sleeve/packer completion system.” The service company’s modular FracPoint EX-C multistage fracturing system enables treatment of 40 stages by varying ball size by only 1/16 in. to achieve a higher than usual number of ball seats. The system’s patented design provides additional mechanical support to the ball during pumping operations.
According to Baker Hughes, reactive element packers are used with sliding-sleeve frac system in many areas of the Williston basin, to isolate intervals of a horizontal section. The company says these packers allow for a wide range of openhole sizes and improve the capabilities of packer-and-sleeve completions.
Lift automation and surveillance. Bakken production is typified by high IP rates followed by rapid pressure decline curves, so wells often must be put on artificial lift relatively early in their productive lives. Proppant flowback in these early production stages can cause premature pump failures. As a result, a common form of lift in the play is progressing cavity pumps, which are more resistant to sand plugging than rod pumps.
A primary challenge of PCP operation is to control the production rate to avoid pump-off. A method introduced by Canada’s Kudu Industries, called the PCP Well Manager, combines wedge flowmeter technology and microprocessor control of electric and hydraulic motors to extend run life while increasing cumulative production. This automated technology is combined with a web-based system that feeds back real-time data to a dedicated supervisory control and data acquisition (SCADA) host, allowing technical experts to diagnose problems and operators to respond quickly to changing well conditions.
In a single Bakken well producing heavy oil in 2008, four pump changes were required due to sand and inflow issues. The well, located in Court field of west-central Saskatchewan, had produced about 17,000 bbl in six months (93 bpd) at an operational cost of $198,000. On July 1, 2008, Kudu installed a new PCP and a hydraulic PCP controller. Over the next six months, the well produced 124,000 bbl (680 bpd) with no workovers. The pump ran for 14 months before it needed to be changed out due to wear and tear from abrasion. The hydraulic control system maintained speed changes using proportional-integral-derivative (PID) loop control on the proportional valve without adding heat to the system.
Drilling waste recycling. In May, UK-based environmental contractor TWMA was contracted by Hess Corporation to process, recover and recycle drilling wastes at multiple Bakken shale rig locations in North Dakota, using the service company’s TCC RotoTruck processing equipment. The mobile truck-mounted unit separates hydrocarbon-contaminated drill cuttings into their constituent parts of water, solids and oil for reuse or recycling. By treating drilling wastes at the source, the technology reduces the volume of wastes and provides significant cost savings through simplified logistics and recovery of drilling fluids.
Identifying sweet spots with 3C seismic. The middle member of the Bakken formation is a very tight dolomitic siltstone, requiring natural fractures to support economic accumulations of oil. Yet the Middle Bakken has eluded detailed imaging because its thickness, typically 15–60 ft at 8,000-ft depth, is well below the resolution of conventional seismic methods, and because the P-wave response in the fractured vs. non-fractured rock is virtually identical. In 2009, Vector Seismic Data Processing formed a consortium to evaluate the seismic signature of fractured reservoirs in the Middle Bakken. A dual-source, three-component (3C), high-resolution 2D seismic line was recorded in Mountrail and Ward Counties, North Dakota. The seismic line ran through the bulk of Parshall and Sanish fields and proximal to dozens of wells, including some very prolific discoveries.
The seismic signature of the waveform on the converted-wave image showed marked differences that can be correlated to natural fractures in the Bakken and wells with high productivity. The strong relationship between the converted-wave seismic signature and Bakken productivity suggests that polarized surface seismic data can play an important role in successful Bakken exploitation.
NEXT STOP: SECOND-LEADING OIL RANKING
At midyear, North Dakota’s Bakken/Three Forks production had surpassed 350,000 bpd, and the state Department of Mineral Resources recently projected that it could potentially double to 700,000 bpd within the next four to seven years, which would make North Dakota the second biggest oil-producing state after Texas, overtaking Alaska and California. The only economic threat that could derail the high-speed Bakken oil train is the recurrence of a recession, which could lead to a drop in crude prices. 
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