Exciting future for gasResults of the ND study can be used as planning tool for industry and government Mike Ellerd For Petroleum News Bakken
By 2025 natural gas production in the Williston basin could increase nearly six-fold over current levels, pushing North Dakota into a competitive position in the U.S. natural gas market. That was one of the conclusions drawn by Bentek Energy in a recently released report commissioned by the North Dakota Pipeline Authority and North Dakota Industrial Commission.
Based on its high case scenario, the study also found that oil production could quadruple to 2.8 million barrels per day by 2025.
Titled “The Williston Basin: Greasing the Gears for Growth in North Dakota,” the Bentek report was commissioned to forecast natural gas production in the Williston basin through 2025 to determine whether North Dakota has sufficient infrastructure to handle natural gas demands in the future as oil wells mature and the gas-to-oil, GOR, ratio changes.
The growth in natural gas production in the basin will have a significant impact on the pipelines and other infrastructure necessary to handle the predicted volumes of natural gas according to Justin Kringstad, director of the North Dakota Pipeline Authority.
“It’s exciting,” Kringstad told Amy Dalrymple of the Jamestown Sun in a recent interview. “There’s tremendous potential for additional investments in gas processing and gas transportation.”
North Dakota officials had previously estimated $3 billion to $5 billion would be required to build the necessary infrastructure to handle the basin’s natural gas demands, but with the results of the Bentek study, Kringstad said that investment may need to be as much as $15 billion.
The Bentek study may also be used as a planning tool by private industry to develop the necessary natural gas infrastructure. “There are companies that are looking for the next opportunity,” Kringstad said.
Another positive for Williston basin gas is the relatively high content of natural gas liquids, NGLs, in the gas, which increases the dollar value. “Those natural gas liquids make it very economical to continue the investment,” Kringstad said.
Bentek estimates that an average well in the basin currently has a return of 58 percent, which makes the Williston basin one of the best performing basins in North America. But the gas has to get to market and there is competition for pipeline space to Chicago and other Midwest markets. For the long term, there will be sufficient interstate pipeline capacity, but currently there is insufficient gathering and processing capacity. While some of this insufficient capacity is being addressed, Bentek found that in the long term, additional gathering and processing projects will be necessary to move the 3.1 billion cubic feet per day of natural gas that Bentek predicts will be produced through 2025.
Overall, Bentek expects the Williston basin in North Dakota to continue to grow, and that the investment in the basin “will be greased by strong overall demand for production out of the basin and relative economics to competing supply areas.”
Current North American natural gas market In evaluating the future for natural gas production in the basin, Bentek first looked at the current natural gas market in North America, and noted that the market “is undergoing dramatic changes as new technology and efficiency improvements in the exploration and production (E&P) sector continue to drive rapid gas production growth.” Funded by Henry Hub gas prices as high as $13 per million Btu in 2008, research advanced such technologies as pad drilling, drill bit steering and hydraulic fracturing among others. These technologies enhanced natural gas production, not only in conventional plays, but also in unconventional plays such as the Pinedale/Jonah in Wyoming, the Piceance in Colorado, the Barnett in Texas, the Fayetteville in Arkansas, the Woodford in Oklahoma, the Haynesville in Louisiana and the Marcellus in Pennsylvania.
According to Bentek, total Lower 48 natural gas production increased from 47.5 billion cubic feet per day in 2005 to the current production of 63.9 bcf per day, an increase of 35 percent, and total U.S. production increased 30 percent.
Along with the increase in production came a corresponding increase in infrastructure, including such pipelines as the Rockies Express, Midcontinent Express, Gulf Crossing, Fayetteville Express and the Southeast Supply Header. “Billions of dollars in pipeline and storage field construction spending characterized the past five to 10 years of U.S. gas production growth” the Bentek report said.
With the new natural gas production and transportation infrastructure, the newly emerging unconventional gas plays began seeing a greater market share, and long-haul pipelines began receiving gas at new locations along the lines or even at downstream ends. This, in turn, resulted in rate challenges for pipelines, and some even began reversing their flows. According to Bentek, these trends are likely to continue because of production growth in such plays as the Utica in Ohio and the Bakken.
Another effect of the gas boom was a decline in imports. Bentek reported that U.S. liquefied natural gas send out declined by 60 percent from 2005 to 2011, and natural gas imports from Canada fell nearly 40 percent.
However, concurrent with the increase in natural gas production and transportation infrastructure in recent years there has been a sharp decline in natural gas prices. From 2008 to date the average Henry Hub price has fallen from $8.85 per million Btu to $2.38 per million Btu, a decline of over 70 percent. According to Bentek, this decline was due in part to the economic crisis, but market oversupply was also a contributing factor.
As a result of the fall in natural gas prices and much higher prices for crude oil and NGLs, many producers have shifted drilling rigs to oil and liquids-rich plays such as Eagle Ford and Permian in Texan, the Anadarko in Oklahoma, and the Williston in both North Dakota and Montana. Bentek reports a major migration away from lean gas basins such as the Barnett, East Texas and Haynesville, and into basins with higher Btu gas. Since early 2012 rig activity has increased significantly in liquids-rich plays like the Marcellus, Eagle Ford, Permian, Anadarko and Bakken.
But even with the shift toward oil and liquids-rich plays, there has not been a significant decline in gas production and total U.S. natural gas production has remained relatively steady because, according to Bentek, there is a backlog of wells in numerous plays where producers are waiting on fracking crews or infrastructure to get the wells on-stream. But another reason, Bentek says, is the increase in associated gas production in oil and gas liquids plays.
Bentek found that the rig count in the North Dakota side of the Williston basin has nearly tripled from approximately 70 rigs in January 2010 to over 200 in June of this year. And over that same period, oil production has increased by 375,000 barrels per day, an increase of 93 percent. Additionally, gross natural gas production has increased by over 0.5 bcf per day to a current estimated production of 0.86 bcf.
U.S. gas production is expected to increase over the next five years, and by 2017 U.S. production is predicted to average 74.9 bcf per day, which would be an increase of 22 percent over average 2011 levels, according to the Bentek report. Production in 2012 is expected to average 63.9 bcf per day, and by 2017 production in the Williston basin is expected to increase 1.6 bcf per day over 2011 levels.
But the demand for natural gas has not kept pace with the increase in production. Bentek reported that in 2011 the demand for residential/commercial, industrial and power sectors, and exports to Mexico, increased only 12 percent, but the overall U.S. supply increased by 30 percent. Most of the 12 percent increase in demand during this period was in the power sector which alone saw a demand increase of 32 percent. However, between 2011 and 2017 U.S. gas demand is expected to further increase by an estimated 10.4 bcf per day, an increase of approximately 16 percent. Most of this demand will come from the power sector, although demand in the residential and commercial sectors, and exports to Mexico will continue.
Challenges and opportunities Although oil production in the Williston basin increased by 630 million bpd from January 2005 to June 2012, an increase of more than 400 percent, gas production also increased by more than 250 percent to 620 million cubic feet per day in that same period. But getting the oil and gas to market presents challenges and the basin has several disadvantages, according to Bentek. For example, in 2011 Bakken producers were getting an average of approximately $11 per barrel less for their light, sweet crude than West Texas Intermediate at Cushing, Okla. Harsh winters pose another problem and can result in drilling and completion difficulties and natural gas producers are further constrained by insufficient gathering and processing capacity. Distance to markets was also noted as a challenge by Bentek.
But on the upside, there still exists significant revenue potential for companies willing to invest in gas infrastructure, and strong oil and gas economics make the play attractive to producers and transportation companies. According to the Bentek report, there are currently plans for six major oil pipeline expansions, nine rail expansions, three proposed refineries, one refinery expansion, three gas and liquids pipelines and four gas processing plants.
Williston basin geology The Bentek report presents a detailed discussion of the geology of the Williston basin. In short, the basin is a large, intracratonic sedimentary basin encompassing parts of western North Dakota, eastern Montana, southern Saskatchewan and southern Manitoba. Low-porosity and permeability reservoirs, organic-rich source rock, and regional hydrocarbon changes characterize the basin’s Mississippian-Devonian-age Bakken petroleum system.
Three formations comprise the Bakken petroleum system: the lower Lodgepole, which overlies the Bakken formation, which, in turn, overlies the Three Forks formation. The Mississippian Bakken formation consists of an upper shale member, a middle silty dolostone or dolomitic siltstone and sandstone member, and a lower shale member. Although both the upper and lower members are organic-rich marine shales can serve as source rock, the principle oil reservoir in the Bakken formation is the middle dolomite member, commonly known as the middle Bakken. The depth of the middle Bakken averages 10,500 feet to 11,000 feet. The Devonian Three Forks formation consists of silty dolomite and extends below the Bakken at depths of 10,600 to 11,000 feet.
Estimated reserves Recent estimates by the North Dakota Industrial Commission and the North Dakota Geological Survey put the volume of recoverable Bakken oil at 2.1 billion barrels and the volume of recoverable Three Forks oil at 1.9 billion barrels. According to an April 2008 U.S. Geological Survey estimate, the technologically recoverable hydrocarbon resources in the Bakken petroleum system consisted of approximately 3.65 billion barrels of oil, 1.85 trillion cubic feet of associated/dissolved gas, and 148 million barrels of natural gas liquids. However, USGS is currently in the process of reevaluating recoverable reserves and those estimates, which are scheduled to be released in 2013, are expected to be much higher than the 2008 estimates, according to Bentek.
Gas-to-oil ratios Bentek looked the GOR in several production areas in the basin and found that in many cases GORs that started at less than 1 million cubic feet per barrel, increased to over 2 million cfb within a few years of production. GORs as high as 10 million cfb have been observed in some fields in the basin, although increased oil production through horizontal drilling has lowered the GOR in some fields. Regardless, Bentek projects a rising GOR in the basin over time.
Long-term outlook As of June 2012, Bentek reported that oil production in the Williston basin increased over 400 percent over the last five years producing more than 800 million bpd, making the Bakken one of the largest oil plays in the U.S. And since 2005, gas production in the basin has increased over 250 percent with an average production in June 2012 of 600 million cfd.
Looking forward, oil and gas production are expected to increase. According to the Bentek report, only about 15 percent of the 143,000 square miles of the Williston basin have been drilled with a total of approximately 6,800 wells, 5,300 of which are in North Dakota and the remaining 1,500 in Montana. The North Dakota Oil & Gas Division believes that drilling and development of infrastructure in the basin could continue for an additional 15 to 20 years and could result in an additional 10,000 wells that could produce for 50 to 100 years.
IRR comparisons Bentek developed a model to compare internal rates of return, or IRR, on wells in various plays in the U.S. on a relative or “apples-to-apples” basis. It is a discounted cash flow model in which a 10 percent discount rate is used to calculate the IRR for a typical well in each play. In this model, Bentek used data from multiple company sources, including drilling and completion costs, operating expenses, initial production rates, Btu content, decline curves, production taxes and royalty rates. Using this model, Bentek calculated a single IRR for each play and then compared the various IRRs.
According to the Bentek study, the North American plays with the highest returns are those plays with significant oil production and high Btu gas, and plays richer in oil have the highest returns. Some of the highest calculated returns are in plays in the Anadarko Mississippian play which has a gas/oil/NGL percent production mix of 26/55/19 and a corresponding IRR of 88 percent. The Permian-Delaware basin, with a production mix of 9/81/9, has an IRR of 85 percent. Toward the lower end is the Pinedale play with a production mix of 99/4/0 and a corresponding IRR of only 11 percent. The Bakken, with a production mix of 6/87/7, has a corresponding better-than-average IRR of 58 percent. In other words, at current prices a typical well in the Bakken today will yield a “healthy” 58 percent return.
Because of the high percentage of oil in the Bakken’s production mix, the revenue stream is directly affected by oil prices, which in turn, affects profitability according to the Bentek assessment. And while Bakken gas has a high Btu and NGL content, Bakken well returns are not sensitive to gas and NGL prices because of the lower gas content in the Bakken production mix.
The Bentek IRR assessment also found that as drilling and completion costs increase, IRRs decrease. However, with producers moving to pad drilling and longer laterals, returns should improve. According to Bentek, the most significant efficiency gains will result from switching to pad drilling, such as the ECO-Pad method developed by Continental Resources where the company has drilled four wells from a single pad in as little as 48 days, for an average of 12 days per well.
Bentek’s predictions In its study, Bentek examined three different scenarios in evaluating the future for gas production in the Williston basin through 2025; the “Base” case, the “Low” case, and the “High” case. In the Base case, Bentek looked at a scenario in which adequate oil infrastructure exists for the next five years of production, after which additional infrastructure will be built. The High case considered a scenario in which there is not adequate oil pipeline capacity and drilling efficiencies in the basin. The Low case forecasted production in the basin where well head prices have fallen to $50.
In all three scenarios, Bentek assumed an initial production rate, IP, for oil of 400 bpd and an IP for gas of 340,000 cfd. Bentek also noted that in general, oil production in Williston basin wells declines more quickly than does gas production, and in the later years of a well’s production, the corresponding GOR is 1.5. Two additional but essential parameters necessary for the predictions were the number of wells that would be drilled and the number of rigs operating in the basin through 2025, and based on various assumptions Bentek established values for these parameters for the three scenarios.
Base case scenario In the base case scenario, Bentek predicts the average annual oil production in the basin will increase approximately 250 percent from 479,000 bpd in 2011 to nearly 1.8 million bpd by 2017, and production will reach approximately 2.2 million bpd by 2025. Infrastructure forecasts indicate sufficient infrastructure until 2020, assuming construction of Enbridge’s Sandpiper pipeline. If that pipeline is not built, additional capacity would be needed in 2017.
Gas production in the base case would continually rise from the 2011 level of 536 million cfd to 2.1 billion cfd in 2017 and eventually to 3.1 billion cfd in 2025.
Low case scenario
The low case scenario predicts that oil production would reach only 1.1 million bpd by 2017 and would remain at that level through 2025. Under this scenario, Bentek predicts that oil transportation projects would likely be cancelled.
In the low case scenario, gas production would also continue to increase but lower rates, increasing from the 536 million cfd in 2011 to 1.4 billion cfd in 2017 and 2.0 billion cfd in 2025.
High case scenario In the high case scenario, oil production would reach nearly 2.2 million bpd in 2017 and then continue to rise to nearly 2.8 million bpd in 2025. Under the high case scenario, production by 2016 would overwhelm infrastructure.
Gas production under the high case scenario would increase from the 2011 level of 536 million cfd to 2.5 billion cfd in 2017 and then to 3.8 billion cfd in 2025.
Oil and gas infrastructure Bentek also evaluated existing and planned infrastructure in the basin to assess if there will be sufficient capacity to meet future demands for both oil and gas.
For the oil side, the current transportation infrastructure is “barely enough to accommodate the rapid production grown in the basin, leading to at times steep price discounts to WTI,” according to Bentek. And even with the planned crude pipeline expansions, rail expansions, refinery expansions and new refineries, Bentek predicts these will not be sufficient enough to keep up with the increasing production growth and that producers will continue to rely on rail and truck transport over the forecast period.
On the gas side, the Bentek study found that with the existing and planned gas infrastructure projects, along with incentives to put in additional infrastructure, the basin will eventually have sufficient capacity to meet gas demand throughout the forecast period. Currently there is not sufficient capacity, resulting in gas that is not transported out of the basin or locally consumed being flared. However, a number of new gathering and processing projects along with new pipeline laterals to interstate systems are planned that will help meet the gas demands in the basin.
The Bentek report provides a detailed analysis of current and expected gas flows on existing pipeline systems and gas infrastructure requirements in the basin, including Northern Borders Pipeline, Alliance Pipeline, WBI Energy and Bison Pipeline.
Current gas processing capacity, according to Bentek, is approximately at 50 percent due to a lack of connectivity from the production areas to the plants, although a number of expansions are planned to address this issue. But with a current lack of sufficient gathering and midstream infrastructure, Bentek believes that “significant revenue can be captured by companies willing to invest in additional infrastructure in the region.”
NGL trends? While Williston basin gas has a high NGL content, NGL production in the basin has not been extensively analyzed and Bentek was not able to clearly define a trend of the NGL content over time in Williston basin natural gas. In its report, Bentek stated that while it is reasonable to infer that the gallons of NGLs per million cubic feet of gas will increase over time as the pressure in a reservoir continues to decrease, it was not able to substantiate or refute this conjecture for the Williston basin.
In an evaluation of publicly available NGL production data from a processing plant, Bentek found an increase in NGL content over time, but it also found that a number of other factors could have contributed to the trend, therefore Bentek was not able to conclude that the NGL content of a Williston basin well will increase over time.
Bentek also evaluated NGL content data corresponding to a subset of basin wells over a four year period, but those data did not support a clear trend. In the end, Bentek was not able to establish a trend for the NGL content in basin wells over time.
Getting the gas to market Currently Williston basin gas constitutes approximately 0.65 percent of U.S. dry gas supplies, but with the base case scenario, coupled with expectations that U.S. dry gas supply will reach 75.5 billion cfd by 2017, Bentek believes that Williston basin gas could represent 2 percent of the total U.S. supply by 2017.
But this gas has to get to market. Presently about 140 million cfd of Williston basin gas goes to local markets, but with the projected growth in gas production in the basin, more gas will need to move to downstream markets. Producers in the Williston basin do have an economic advantage in that gas production in the basin is primarily a byproduct of oil production, and high oil and NGL prices cover the cost of gas production. This, according to Bentek, allows producers to accept lower gas prices without having a negative effect on returns. Consequently, Williston basin producers are price-competitive with upstream supplies from Canada and the Rockies. Bentek also noted that as contracts on Alliance and Northern Borders “roll off in the coming years, new and current shippers will increasingly gain the option to source their gas supply in the Williston.”
The primary end-use market for Williston basin gas is Chicago and other Midwest cities, which are accessed directly through the Alliance and Northern Borders systems. While there is much competition for the Chicago market, according to Bentek Alliance and Northern Borders deliveries to Chicago are expected to remain very competitive, due primarily to the competitive nature of Williston basin gas. Other regions competing for the Chicago and Upper Midwest markets are the Rockies, Mid-Continent, Texas, the southeast, and the northeast including the Marcellus play.
Other markets? Other possible markets for Williston basin gas include transport to the Rockies because of production declines in that region and possible reversals of pipelines such as several Powder River lines that are seeing declining utilization. There are also possibilities for the Canadian market in order to meet local demands as well as meet demands of the oil sands. This would essentially split the Northern Border operation by moving gas both north and south out of the Williston basin. This reconfiguring of gas pipeline systems is presently occurring in other regions of the U.S., with Tennessee moving gas both east and west out of the Marcellus in northern Pennsylvania. In Texas, Tennessee Gas Pipeline and Texas Eastern Transmission will move gas out of the Eagle Ford both north to Ship Channel and Louisiana and south to Mexico.
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