Bakken Activity On The Rise

Shale oil drilling is picking up in the Williston Basin’s Bakken shale, one of the hottest oil plays in North America.

The Bakken, which extends through North Dakota and eastern Montana in the US and into Saskatchewan and southwestern Manitoba in Canada, produced 225,000 b/d of oil in 2010, up from 3,000 b/d in 2005, according to the Energy Information Administration (EIA). Current EIA predictions indicate the Bakken could produce 350,000 b/d of oil by 2035. Most analysts think that estimate is too low.

Scott Sheffield, head of Pioneer Natural Resources Co., estimates new technology will allow the US to produce an additional 2 MMbbl/d of oil from the Bakken and other shale oil plays. “It’s going to have a major impact on the United States reducing imports,” Sheffield said at IHS CERA’s CERAWeek in March 2011 in Houston.

Guy Caruso, former head of the EIA and currently an advisor at the Center for Strategic and International Studies, agrees. “If we get 2 MMbbl/d, that could have a major impact on world oil prices,” he told CERAWeek delegates.

Increasing Bakken Activity

Over the last five years, leasing in the Bakken has increased significantly, and bonus payments per acre also have gone up. According to the US Department of Energy’s National Energy Technology Laboratory (NETL), total lease payments exceeded US $100 million in 2009.

In 2008, the US Geological Survey estimated the US portion of the Bakken formation contains between 3 and 4.3 Bbbl (a mean of 3.63 Bbbl) of undiscovered, recoverable oil. The number of producing wells and the volume of oil production have grown with leasing and drilling growth. According to the NETL, Bakken production has reached approximately 8 MMbbl per month from nearly 4,500 producing wells.

The Elm Coulee field in Richland County, Mont., is one of the Bakken’s significant emerging fields. Discovered by Lyco Energy in 2000, the field has produced more than 41 MMbbl of oil and 24 Bcf of gas from more than 400 horizontal wells. It has relatively low porosity (8% to 10%) and an average of 0.05 md permeability, with natural fracturing likely contributing to production.

The reservoir has been developed over an area of 450 sq miles (1,165 sq km), targeting the middle member of the Bakken formation on 640- and 1,280-acre spacing. Recovery per well is 350,000 to 600,000 bbl, and ultimate recovery for the field is greater than 200 MMbbl.

The Parshall field, which also produces from the Mid- dle Bakken, was discovered in 2006 on the east side of the Nessen Anticline. As of April 2010, the field had produced approximately 32 MMbbl of oil and 13 Bcf of gas from 228 wells.

According to the NETL, the top 20 players in theBakken hold nearly 5.5 million acres of prime acreage, with the top three controlling more than two million acres. Continental Resources, the top driller and leaseholder in the play, has 864,559 net acres. Whiting Oil & Gas Corp. has 14 rigs operating in the Bakken and approximately 480,000 net undeveloped acres in the Bakken/Three Forks. EOG Resources Inc. has 11 rigs operating and 580,000 net acres.

Results from simultaneous fracture stimulations on three wells in Montana demonstrate the potential benefits of these enormous operations, but the logistics are daunting. (Photo courtesy of BJ Services Co.)

Developing New Technologies

The Bakken is a relatively young play, but companies working in the area already have helped to make an impact through new technologies.

In 2009, Continental Resources performed the first 24-hour continuous frac in the North Dakota portion of the play. In 2010, the company developed the ECO-Pad drilling concept, a system where multiple horizontal wells are drilled from a single pad with zero boundary-line setbacks. The concept can reduce drilling and completion costs per well by approximately 10%, with approximately 70% less surface footprint area than four conventional drilling pads and one access road.

The North Dakota Industrial Commission is projecting another 30 rigs will enter the Williston Basin in 2011 on top of the 170 already in the play. If true, those numbers amount to an 18% increase and imply an aggregate industry capital program of US $13 billion on the basis of 2,000 projected wells. (Source: “Four Bakken Themes for 2011” by Richard Mason, courtesy of UGcenter.com? )

Smith Bits has designed the Spear shale-optimized steel-body PDC bit, which can drill a curve and long lateral hole section for faster penetration rates in low hydraulic energy environments, reducing the number of trips downhole and the associated rig time. According to the company, the bit also reduces nonproductive time by minimizing vibration and preventing packed blades, plugged nozzles, and cutter damage. It permits high ROP through a combination of tall and thin blades, which provide a large area for cuttings flow. The hydraulic design directs flow toward the cutter faces, keeping them sharp while sweeping cuttings away from the bottom of the hole and around the bullet-shaped body into the annulus.

A more recent milestone occurred in March 2011, when Baker Hughes Inc. installed a 40-stage openhole completion system in the Williston Basin, the largest number of stages ever performed in a single lateral frac sleeve/ packer completion system. The company’s FracPoint EXC multistage fracturing system was deployed in Whiting Petroleum Corp.’s Smith 14 29XH horizontal well.

“The industry continues to push the limits of total frac stages in horizontal completions in the Bakken shale and other unconventional reservoirs,” said Paul Butero, president of the US Land region for Baker Hughes.

Reactive element packers allow for a wide range of openhole sizes and improve the capabilities of packer and sleeve completions. In many areas of the Williston Basin, Baker Hughes’ REPackers are used in the Frac-Point EX-C system to isolate intervals of a horizontal section, while frac sleeves are used to deliver the fracture treatment. The system extends current capabilities to 40 stages via 1/ 16 -in. incremental changes in ball size to increase the number of ball seats and provides additional mechanical support to the ball during pumping operations.

R&D Is Key

Developing new technologies specific to the area is a priority. The National Energy Technology Laboratory (NETL) has funded a number of R&D projects to improve recovery, decrease the operating footprint, and enhance safe and environmentally responsible shale oil development. The lab plans to develop and/or refine several key technologies to exploit the Bakken’s full potential.

The top 10 Bakken acreage holders cover 51% of the play’s geographic footprint. (Source: Hart Energy)

Further deployment of microseismic fracture monitoring will provide a greater understanding of fracture propagation and extent in the Bakken system, resulting in better frac jobs and enhanced production. MicroSeismic Inc. already has buried seismic arrays across more than 150 sq miles (388 sq km) in Mountrail County, N.D., using more than 1,200 geophone channels to monitor, map, and analyze hydraulic fracturing operations.

Extended-reach and rotary steerable drilling also are key to developing the Bakken. Without extended laterals and multistage hydraulic fracturing techniques, Bakken development would be uneconomical. With laterals now extending beyond 10,000 ft (3,048 m), precise well placement control is crucial, as is the ability to deliver a smooth well bore to enable single-trip fracturing and completion equipment installation.

The NETL also is investing in enhanced multistage fracturing to increase the ability to pump larger multistage fracs to improve economics. And projects in the works will target water use as well. Typical water use for hydraulic fracturing in the Bakken is 1.5 to 4 million gal per well. Surface water in the Williston Basin is in short supply, and costs associated with acquiring frac water and disposing of flowback and produced water can range from $2 to $11.75/bbl.

The NETL continues to fund R&D projects that will lead to more efficient oil recovery and improved environmental impact.

Contact the authors, Ashley E. Organ and Richard Mason, at aorgan@hartenergy.com and rmason@hartenergy.com.