Williston Basin Reserves May Top 21 Billion Barrels, Peak Production in 6 to 7 Years
Trent Jacobs, JPT Technology Writer
More than 21 billion bbl of light, sweet crude oil will be extracted over the lifetime of the Bakken and Three Forks shale plays, according to the latest projections from energy consultancy group Wood Mackenzie. The two plays are found in the United States’ prolific Williston basin and together produce approximately 1 million BOEPD. As production rises from the deeper Three Forks formation, the firm predicts that between 2020 and 2021, production from the Bakken Shale will reach its peak.
Despite the fact that production growth is slowing in the Bakken, Wood Mackenzie said there will be commercial opportunities throughout the basin for years to come. Reductions in drilling and completion costs and increased recovery rates are driving operators to explore less-rich areas of the Bakken. “It might not have made sense in 2010 to spend (USD) 13 million on a Bakken well that is only going to get about 300,000 BOE out of the ground,” said Jonathan Garrett, an upstream analyst at Wood Mackenzie who specializes in the Williston basin. “But flash forward to today; now it might make sense to spend (USD) 6 or 7 million on a well to get 300,000 to 350,000 BOE.”
Garrett said new technology, better well completion methods, and tighter well spacing will lead to higher overall recovery rates from the two shale plays than previously thought. Last year, the US Geological Survey (USGS) estimated that ultimate production of light, sweet crude from the Williston basin would top out at 7.4 billion bbl. Wood Mackenzie said its reserve estimate was higher because operators will increasingly drill wells closer and closer together, a practice known as down spacing. “We looked at likely and proven operator down-spacing patterns throughout the play, whereas the USGS is of the mind that probably fewer than four wells per spacing unit into the Bakken and Three Forks will be the ultimate development pattern,” Garrett said. “We regard that as a bit conservative given the fact that we have seen much more dense projects throughout the Williston basin.”
In areas where the Bakken has been most developed, operators are increasingly turning their attention to the deeper Three Forks shale that is formed of multiple sections known as benches. Production rates from wells drilled into the uppermost bench of the Three Forks has been positive, but less-than-expected production rates from the lower part of the formation has downgraded the play’s outlook. Garrett said that because of this, “the footprint for commercial development of the Three Forks will be considerably smaller than previously expected.”
“There are pieces of the Bakken that are becoming more interesting,” he said. “But we really do think it will be offset by the smaller economic footprint of the lower benches of the Three Forks.”
US Offshore Regulator to Focus More on Technology
Trent Jacobs, JPT Technology Writer
The United States’ top offshore regulator said his agency is adopting new policies and measures to improve its working relationship with the offshore industry. To accomplish this, the director of the Bureau of Safety and Environmental Enforcement (BSEE), Brain Salerno, said that his agency will increase its focus on technology assessment. Salerno explained that traditionally, BSEE has based regulatory standards in part on industry standards but the ongoing advancements of offshore technology have presented a challenge to this model. “We still rely on that basic approach, but regulations have always had a tough time keeping up with technological change,” said Salerno, who spoke at the Offshore Technology Conference in Houston in May. “For that matter, industry standards are having a tough time keeping up as well. And that has become even more of a problem as the pace of technological innovation and change has accelerated.”
The director said the agency will open a technology center in Houston to work more closely with equipment manufactures and to study emerging technologies. The technology center will not replace any of the regulatory processes, Salerno said, “but it will add depth and capacity to the bureau, so that as industry continues to innovate and develop new capabilities, we will be keeping pace with you.” BSEE is in the process of choosing a location and assessing staffing requirements and gave no timeline for opening the technology center.
The director also announced BSEE’s establishment of the Ocean Energy Safety Institute (OESI) to serve as a forum for regulators, the industry, and academia to study the role of emerging technology. The inaugural event for the OESI was held at the University of Houston the week following OTC and focused on the topic of risk management. BSEE is also introducing new language to help clarify the standard of safety it is seeking from offshore companies and will make accommodations for new technological approaches not covered by existing rules. JPT
First Transboundary GOM Leases Awarded Under New Rules
Jack Betz, JPT Staff Writer
The US Department of the Interior and the US Bureau of Ocean Energy Management have awarded ExxonMobil three offshore leases in the US-Mexico boundary area of the Gulf of Mexico, the first leases subject to the terms of the 2012 US-Mexico Transboundary Hydrocarbon Agreement.
The agreement governs reservoirs that are split by or close to the boundaries of the US and Mexico. It allows US operators and Mexican state oil company Pemex to explore transboundary reservoirs as single units, encouraging unitization—the process by which multiple leaseholders agree to extract resources through the work of a single operator. Unitization encourages the drilling of fewer wells, which increases efficiency of production and reduces waste as well as the likelihood of environmental accidents, the agencies said. In cases where a transboundary unitization agreement cannot be reached, parties can each produce as much oil that is calculated to lie on its side of the boundary.
Additionally, the 2012 agreement created a framework allowing each country to regulate activity on its side and inspect the activity of operators on the other side of the boundary. The specifics of this system have not been released.
The ExxonMobil leases sit in the Alaminos Canyon area, about 170 km east of Port Isabel, Texas. The US government estimates that the lease area contains up to 172 million bbl of oil and 304 Bcf of natural gas.
More boundary leases will be up for auction in August. These blocks are located in the Western Gap area of the Gulf of Mexico, north of the continental shelf. JPT
Saudi Aramco Progresses on Shale, Confirms Red Sea Find
Abdelghani Henni, JPT Middle East Staff Writer
Saudi Aramco has made significant progress developing its shale gas reserves and will begin using shale gas for domestic industrial projects, the company said in its 2013 annual review.
The company said its unconventional gas program became fully operational in 2013, 2 years after it launched a program to develop unconventional gas in the frontier Northern Region, offering new resources for the country’s energy needs. Saudi Aramco is now ready to commit shale gas for the development of a 1,000-MW power plant that will feed a massive phosphate mining and manufacturing project. “Saudi Arabia will be among the first countries outside North America to use shale gas for domestic power generation,” the company said in the annual review.
Saudi Aramco is also actively exploring for unconventional gas resources in three areas of Saudi Arabia: the northwest, South Ghawar field, and the Rub’ al-Khali (Empty Quarter). “Due to the large scale of these unconventional gas resources and the complexity and intensity of the activity associated with their development, significant investment opportunities and economic benefits lie in the full value chain of this emerging industry,” the report said.
In addition to the progress in its shale gas program, Saudi Aramco announced that it discovered three oil fields and two gas fields over the past year. These include the deepwater Al-Haryd field in the Red Sea, which followed a significant gas discovery in the Shaur structure nearby in 2012.
The company said its first deepwater drillstem test operation was successfully executed at Duba-1, located in the northern Red Sea. Tests conducted at a depth of 2,127 ft indicated tight reservoirs for potential future development.
Saudi Aramco increased gas production in 2013 to 11 Bcf/D, from 10.72 billion Bcf/D in 2012.