Improved technology drives Brigham's success in Bakken

Dec. 1, 2008
EDITOR’S NOTE: The use of 3-D and other advanced technologies has always been a hallmark of Austin-based Brigham Exploration.

EDITOR’S NOTE: The use of 3-D and other advanced technologies has always been a hallmark of Austin-based Brigham Exploration. More recently, the company has become a significant player in the Bakken and Three Forks plays in the Williston basin where it is utilizing state-of-the-art drilling and fracturing methodologies to optimize oil production rates. Ben Brigham, chairman, president, and CEO, recently took time from his day to answer some of our questions about his company.

OIL & GAS FINANCIAL JOURNAL: Brigham Exploration operates in several core basins, but perhaps the one getting the most attention is the Bakken oil shale. The play is dominated by many large-cap independents like EOG. How did you successfully gain entry into the Bakken?

BEN BRIGHAM: Brigham entered the play in late 2005. Early that year, our board directed us to source resource plays with the potential to complement our successful but choppy conventional drilling program with lower risk and repeatable resource projects. After scouring the major emerging resource plays around the country, we determined that the Bakken provided the elements we were searching for, including attractive fundamental economics, low initial acreage costs, longer reserve lives, and the diversification of our portfolio into oil.

Once we identified the Bakken, we aligned ourselves with local experts with a strong track record in the area. We worked early on with an explorationist who was involved with Lycos in the successful early development of the Elm Coulee Field in Richland County, Montana. Working together, we sourced and successfully negotiated to sublease the Bakken and Three Forks rights under approximately 45,000 net acres in Williams and McKenzie Counties, North Dakota.

While drilling our initial three wells in that area with marginal results, we continued to map the Bakken throughout the basin and subsequently acquired what is now roughly 100,000 net acres in Sheridan and Roosevelt Counties, Mont., where we’ve now drilled two consecutive successful Red River wells.

We weren’t the first mover east of the Nesson anticline in Mountrail County, ND (EOG clearly was), but we had already prepared preliminary maps of the area when EOG made their Parshall Field discovery. As a result, we were able to aggressively begin building what is currently approximately 95,000 net acres east of the Nesson anticline in Mountrail and surrounding counties.

So in summary, our model was to first identify what we believed to be an optimal resource play, to align ourselves with local expertise to accelerate our movement up the learning curve, and then to aggressively map and explore in order to capitalize on our efficient and agile acreage acquisition competencies.

OGFJ: What percentage of your capex budget is allocated to the Bakken and what are your development plans in the Bakken for 2009?

BRIGHAM: Our 2008 capex budget that was announced in July has us allocating approximately 63% of our 2008 exploration and development capex, which includes drilling, land and seismic costs, to the Bakken. We’re currently in the process of developing our 2009 budget. At this time we anticipate that 75% to 85% of our exploration and development capex budget will be allocated to the Bakken and Three Forks plays in 2009. The majority of this capital will be directed to the areas where we’ve had the most success, such as the Ross and North Stanley Areas in Mountrail County, where we’ve drilled our strongest Bakken and Three Forks wells to date and where we control more than 37,000 net acres. Given our strong acreage position in this area we have the opportunity to drill up to 115 net long lateral wells in both the Bakken and Three Forks to fully develop this area alone.

OGFJ: We have heard of some Bakken wells having initial production rates of 1,900 barrels of oil per day? Is that typical of your experience and do you need that kind of production rate to generate compelling profits?

BRIGHAM: The highest rate wells have been drilled in the “sweet spots” such as in the Parshall/Austin/Sannish Field areas where peak rates range from 1,000 to as much as a recent 4,500 barrels of oil per day. Those areas are the exception and not the rule. Typical Bakken and Three Forks wells produce at initial rates of 300 to 1,000 barrels of oil per day, though wells in the upper end or above that upper end are becoming more common as we optimize drilling and completion technologies. Our two most recent Ross Area wells are good examples of the improving well results. Our Carkuff well, which targeted the Bakken, came on line at an early rate of 1,110 barrels of oil per day, while our Adix Three Forks discovery produced at an early rate of 892 barrels of oil per day. We believe these wells will likely produce around 500,000 barrels of oil, and therefore generate strong rates of return.

Generally, we’re expecting rates of return between 15% and 100% for most of our wells. Of course, we hope to achieve results at the higher end of the return spectrum as we and other operators continue to optimize drilling and completion techniques in the area. We believe this will happen given the large number of operators in the area drilling a significant number of wells and the sharing of information that you are seeing among the different players. Of course one benefit to us is our diverse acreage position, which allows us to participate via a small working interest in a number of different wells.

OGFJ: Can you describe to us the advancement in technologies in the Bakken that has generated the improved well results you mentioned?

BRIGHAM: To understand how rapidly things have evolved in the basin, you simply have to look back at where we’ve come from since late 2006 when the service companies were recommending to us completing Bakken wells with one large uncontrolled fracture stimulation. In 2007, a Barnett shale operator transferred its completion technology to the Williston basin and since that time the number of rigs in North Dakota has exploded.

One of the early keys to improved well results in the basin was the introduction of swell packers. Swell packers are rubber membranes surrounding the outside of the liner that help to create isolation along the well bore, thereby helping to ensure the entire length of the horizontal well bore is stimulated. Our wells in late 2007 and the first half of 2008 incorporated five or six swell packers along the length of a short lateral, which allowed us to fracture stimulate six or seven intervals. Beginning mid-year this year, our best wells to date have been completed with 9 to 11 swell packers along a short lateral, which allows us to fracture stimulate 10 to 12 intervals along the short lateral. Our best well to date, the Carkuff, was completed with 12 fracture stimulation intervals.

We believe the next advancement in technology is the use of 19 swell packers across a long lateral (9,000 to 10,000 feet). The long lateral helps us to achieve efficiencies by having to drill only one vertical well bore, saves on casing costs, reduces the number of mobilizations and demobilizations, and helps us hold more acreage as compared to the short lateral. Importantly, we believe we’re the first company to successfully run 19 swell packers in a long lateral in an attempt to stimulate 20 intervals with our Olson 1-15 #1H well.

Like other leading operators in the basin, we spent time conditioning the well bore prior to running the swell packers to bottom, so now the swell packers are setting and we have our frac scheduled for early December. During the frac we’ll be using the perf and plug method throughout the entire length of the long lateral, and that’s as opposed to sliding frac sleeves. We believe the perf and plug method is yet another advancement in technology as compare to the sliding sleeves as we believe the perforations help to initiate fractures in the reservoir and therefore generate more effective stimulations. We believe the use of long laterals with approximately 20 fracture stimulations and the use of perf and plug represents yet another step change improvement in the economics in the basin.

OGFJ: Is there enough infrastructure in the Williston basin to handle the increased oil production? If not, what do you see happening to improve the situation?

BRIGHAM: Oil production is growing in the basin and will likely continue to grow for the next five to ten years. It’s not inconceivable that oil production in the Williston basin could exceed that of Prudhoe Bay, North America’s largest oil field, within the next three to five years. Capacity expansions to move these volumes to market are happening and will continue to develop, though we recognize that in the short term there will be periods requiring the utilization of more expensive transportation options, such as rail, to move incremental volumes out of the basin.

OGFJ: Brigham recently moved an additional rig into the Williston basin. What results can your report to date on that rig?

BRIGHAM: Our second rig is drilling the Figaro 29-32 #1-H, our second long lateral well in which we plan to stimulate 20 intervals utilizing the perf and plug method. This well is in the same area of McKenzie County, ND, that we completed our Mrachek 15-22 #1H, which commenced production at approximately 727 barrels of oil equivalents per day, so we’re looking forward to seeing the results of a longer lateral with more fracture stimulations. Fundamentally, more reservoir exposed with more effective stimulations should generate substantially more production and reserves recovered. After completing the Figaro, the rig will be moving back to our Ross area to drill Anderson 28-33 #1-H.

OGFJ: In addition to your Bakken play, what are your company’s other primary growth drivers?

BRIGHAM:Our Bakken and Three Forks plays are beginning to provide the more predictable and consistent quarterly growth to complement our ongoing and successful conventional drilling program. We’ve had a 10-year track record of successful drilling in the Vicksburg play in South Texas with ExxonMobil, where we’ll be active again in 2009. In addition, we’ve enjoyed a remarkable run in southern Louisiana, where we’re bringing on line four strong production rate exploration wells that were drilled in 2008 that could add roughly 15 MMcfe per day of production by the first quarter of 2009. We believe that these high rate of return, albeit shorter reserve life, conventional drilling projects are an excellent complement to our longer reserve life Bakken and Three Forks projects.

OGFJ: How has Brigham Exploration been able to leverage technology to increase production and grow reserves? What results are you generating from these advancements in technology?

BRIGHAM:Our company’s niche is leveraging technology to generate organic growth in reserves and production. Our early growth during the 1990s was primarily driven by leveraging 3-D seismic imaging technology to find and develop more conventional reservoirs. The drilling and completions in those plays was fairly conventional. Few of our wells during that time period required fracture stimulations. Beginning in 1997, particularly in the Vicksburg of South Texas where we made our Home Run Field discovery, we began successfully utilizing the latest in drilling technology and large fracture stimulations to enhance our returns. In 2000, drilling technology again played a significant role in our growth, during that year we drilled the deepest well in Texas, a 25,000-foot directional well that became our Mills Ranch Field discovery.

As illustrated by our Bakken and Three Forks drilling successes, today we’re leveraging rapidly developing drilling and completion technologies to improve our production and reserve recoveries, and thereby generate strong and consistent net asset value growth for our shareholders. Given the improvements we’ve seen in these plays, almost on a well-by-well basis, we expect drilling and completion advances to continue to enhance our returns for some time to come.

OGFJ: How difficult is it to recruit and retain talent in today’s oil and natural gas industry? What steps is Brigham talking to ensure that it always employs and always has access to the best and brightest employees?

BRIGHAM:Brigham is blessed with a geographical advantage, given that we’re located in Austin, Tex. That, combined with the balanced lifestyle we strive to provide for our employees, and our open entrepreneurial team environment, has enabled us to attract and retain our quality staff, despite the intensely competitive environment we’ve experienced in recent years. Further, we are a small, very flat organization, which facilitates a more cohesive social and functional fabric for our people.

OGFJ: Oil and natural gas prices are trading well off their recent highs. How has the pullback in prices impacted the economics of your projects?

BRIGHAM: We’ve experienced a dramatic 50% reduction in oil prices in a matter of months. However, we tend to forget that we first experienced $60 oil in March of 2007, so prices are still very high by historical standards. Given the economics of the Bakken and Three Forks plays, we believe we can generate good returns in the current cost environment with oil prices in the $50 to $60 per barrel range.

Although they lag commodity prices, costs are coming down, so we expect our margins at today’s prices to expand as we move through 2009. So while we’re high grading our projects to the higher return areas, it’s apparent that the combination of lower costs and the continuing improvements we’re generating in drilling and completing our Bakken and Three Forks wells will combine to provide us with improving returns as we move through 2009.

OGFJ: Are you seeing any softening in service costs with the decline in oil and natural gas prices? Is access to services getting any easier?

BRIGHAM:Yes, with more to come. Changes in the cost structure associated with our business tend to lag meaningful changes in commodity prices. We’ve already seen more availability in particular areas, and we’re currently benefiting from recent reductions in certain cost components. We expect that to accelerate as we move into 2009, when companies’ decisions made months prior in the office are subsequently executed in the field. Fortunately, unlike some of our peers, we did not enter into any long-term contracts, so we’re positioning ourselves to take advantage of an improving cost environment.

OGFJ: Does your company hedge? If so, what percentage of your current production is hedged? At what prices?

BRIGHAM:We do hedge both our oil and natural gas production. Typically we use either costless collars or three-way collars. We believe we’re able to protect ourselves to the downside using these structures and still enable our shareholders to participate in commodity price upside. In the fourth quarter 2008, we’ve hedged approximately 11.7 MMcfe per day in production, which represents approximately 33% of the mid point of our production guidance for the quarter. Our weighted average floor price is approximately $9.29 per Mcfe.

OGFJ: Has the pullback in prices forced Brigham to curtail any of its spending plans for the remainder of 2008 or in 2009?

BRIGHAM:Our preliminary 2009 plans changed relative to just a few months ago in that we previously had anticipated adding a third, fourth, and potentially a fifth drilling rig to develop our Williston basin acreage. Today, we’re developing a budget that consists of utilizing primarily two rigs in the Williston basin.

In general, we are being more frugal with our expenditures. We’re focusing a higher percentage of our capital expenditures to the drill bit, to generate growth in production, cash flow and reserves.

Given that we own almost 300,000 net acres in the Williston basin’s Bakken and Three Forks plays, we don’t need to make substantial investments in land and seismic, so our capital investments are particularly efficient today. We meet weekly to reevaluate our plans in the light of a continually evolving environment. When the environment improves, we expect to be in excellent position to accelerate our program.

OGFJ: What is your 2009 Capex budget? How will you allocate capital to each of your core operating areas?

BRIGHAM:Our board will likely approve our 2009 budget in January. We’re currently working on a preliminary budget to present to the board in December, which likely includes the allocation of 75% to 85% of our expenditures to the Bakken and Three Forks plays of the Williston basin. At this point we expect our budget to likely be in the range of $90 to $120 million. Although that’s below that of our 2008 expenditures, it’s a very healthy budget relative to prior years.

OGFJ: How, if at all, has the recent credit crunch impacted Brigham’s access to capital?

BRIGHAM:Given the limited access to external capital in today’s environment, our 2009 budget will be funded primarily by cash flow. We have an excellent bank group in our credit facility, led by Bank of America, which provides us with plenty of availability to complement our cash flow. However, we plan to be very conservative as we move forward, so that we can be in position to accelerate when the environment improves.

OGFJ: Under what circumstances, if any, would Brigham consider divesting or acquiring additional assets?

BRIGHAM:Today, given our inventory of quality drilling projects, particularly in the Bakken and the Three Forks, we are more likely to be a seller rather than a buyer. For example, in late 2007 we divested non-strategic Granite Wash assets for approximately $36 million, which supplemented our cash flows in 2008 to further fund our growing capital expenditures in the Bakken. We’re continually evaluating opportunities to optimize our assets given our quality opportunity set, provided we can achieve fair value that’s a strategy we could replicate.

OGFJ: What are the greatest challenges you see in the oil and natural gas industry today?

BRIGHAM:Someone asked me this exact question about 10 years ago, and my answer was the same – volatile commodity prices. Fortunately, we’re much wiser today and better prepared to manage our enterprise in an environment with such remarkable volatility. It’s hard to believe that only four months ago oil was at record highs approaching $150 per barrel, while today oil is roughly $64 per barrel. Obviously, we prefer to operate in a higher commodity price environment, but we’re also in excellent position to benefit from some of the opportunities presented today, including a less competitive environment with lower costs just over the horizon.

OGFJ: Thanks for taking time to talk to us.