JIM REDDEN, Contributing Editor
As of July 2012, some 25 widely divergent, advanced technology projects have been completed under the auspices of the Research Partnership to Secure Energy for America (RPSEA). The U.S. Department of Energy (DOE) selected the 501(c)(3) non-profit consortium as the administrator for most of the program’s resources, which are derived from royalties and lease bonuses that operators pay to produce from federally controlled offshore and onshore acreage. A portion of the funds was also earmarked for use by the DOE’s National Energy Technology Laboratory (NETL) for research complementary to that carried out by RPSEA.
Since 2007, more than 100 long-term extramural research projects have been undertaken as part of the partnership defined in Title IX, Subtitle J, Section 999 of the Energy Policy Act. The program specifically relies on a consortium of more than 160 major and independent operators, service companies, research organizations, universities, national labs, financial entities, non-profits and consumer, trade, civic and environmental organizations to administer cost-shared research contracts with private contractors, based on an annual plan approved by the DOE secretary, with input from independent experts.
According to DOE, the objective of this approach was to focus the best industry and governmental minds on research projects that industry was not likely to pursue independently, but that would have a significant chance of ultimately increasing oil and natural gas recoveries. The program specifically addresses research needs in ultra-deepwater fields in the Gulf of Mexico, onshore unconventional natural gas and oil reservoirs, and mature fields, which overwhelmingly are operated by small producers.
According to RPSEA, the leveraging of public and private funds has been shown to be a viable methodology for conducting critical research programs that may not realize any tangible results for a decade or longer.
“An oil or natural gas producer’s or oilfield service company’s primary motivation is to maximize returns, very often short-term returns, to its shareholders. These companies are motivated to spend money to improve their bottom line performance next quarter or next year,” said James Pappas, V.P. of the RPSEA ultra-deepwater program. “Funding research that could have an impact 10 to 20 years or more in the future is not typically part of most producers’ business plans.”
Across-the-board benefits. Until now, the RPSEA model for a public/private partnership, which resembles one that the National Research Council (NRC) recommended in a 1999 study, did not exist on such a large scale in the oil and gas industry.
“This network of networks avoids reinventing the wheel by utilizing and leveraging the robust individual capabilities of the network components,” RPSEA said. “Moreover, member company volunteers are subject matter experts in their lines of work, who routinely collaborate to solve problems and address the most important technology needs.”
Within RPSEA, myriad advisory committees drawn from the broad membership base are incorporated into the consortium’s planning process, as well as in the recommendation and vetting of the proposed R&D projects to be awarded, and the reviews of project results. Collectively, this network has accounted for about 37,200 hr of volunteer participation, the value of which cannot be over-emphasized, and could not otherwise be procured easily at any reasonable cost. The companies, universities and other organizations that receive funds through RPSEA provide cost-share contributions of at least 20% of total project expenditures. Moreover, the involvement of industry partners in all phases of the R&D process increases the likelihood that technologies developed through RPSEA will move into the marketplace.
DOE-sponsored innovations. Since the mid-1970s, DOE-sanctioned public/private partner research projects have recorded a number of industry innovations that later became commercial technologies, not the least of which is the pioneering work that helped launch the shale gas revolution. At the time, a relatively small share of the nation’s natural gas came from unconventional sources, such as shale, tight sandstones and coal seams. Today, according to the U.S. Energy Information Administration (EIA), roughly 70% of the gas produced in the U.S., about 7.7 Tcf/year, comes from these unconventional sources, Fig. 1.
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| Fig. 1. DOE research on shale gas potential and development that began in the mid-70s is one of the factors responsible for the explosion in U.S. natural gas production. |
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The benefits derived from DOE’s unconventional gas research programs, which are credited with laying the foundation for the technologies that helped spur the rapid growth in gas production, were documented in a 2001 NRC report, “Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research, 1978 to 2000.” According to the NRC, the reported benefits of $600 million in incremental state and federal tax revenues, and consumer savings from lower natural gas prices and increased supplies, are tied specifically to DOE’s Eastern Gas Shales Research Project (EGSP), begun in 1976. The public funds spent on this research program amounted to just under $92 million over 16 years.
Since 2000, production of shale gas has grown 17-fold. In 2010, unconventional gas activity, primarily in shale plays, supported 1 million jobs, and, despite today’s low prices, that number is expected to grow to nearly 1.5 million in 2015 and to more than 2.4 million by 2035. Federal estimates project continued development of unconventional gas, generating an aggregate total of nearly $1.5 trillion in federal, state, and local tax and royalty revenue between 2010 and 2035.
According to the federal agency, “the early DOE research was not solely responsible for today’s shale gas supply, but it helped make available, when needed, the tools for developing this resource. The same model of public/private research is being applied, through the Section 999 program, to other resources, where new technology is needed to catalyze development: emerging shale gas plays that are geologically challenging, residual oil found in previously water-flooded reservoirs, and economically marginal oil accumulations located in ultra-deep water.”
Projects to reduce environmental impact. Since its creation, the partnership has taken a proactive approach in reducing the environmental footprint of oil and gas operations. Two of the more high-profile onshore projects are the Environmentally Friendly Drilling (EFD) program and an NETL project that is building a baseline database to ascertain the actual net environmental impact of Marcellus shale gas development activity.
Early on, the Section 999 program supported the multi-faceted EFD program that Texas A&M University and the Houston Advanced Research Center (HARC) jointly established in 2005 to address environmental issues associated with oil and natural gas drilling. In addition to the DOE, the program includes 20 industry sponsors, 18 from academia, and six national laboratories, with NGOs, such as the Nature Conservancy and the Natural Resources Defense Council, also participating.
The coalition is working to develop low-impact technologies that reduce the drilling footprint, lightweight drilling rigs with reduced-emission engines; new approaches to on-site waste management, and environmentally friendly site-access systems that feature the engineering of so-called “disappearing” lease roads. A prototype lay-down mat road system has been field-tested and shown to help minimize the environmental impacts of drilling-related traffic in vulnerable desert ecosystems.
The EFD program also designed publicly and privately accessible online databases, including the collection of 8,500 “best management practices” for oil and natural gas operations in the Intermountain West. Since its roll-out, this free database has drawn more than 5,000 site visitors a month.
“DOE involvement as a sponsor of this program provides critical support to an effort that would otherwise be unlikely to evolve without federal funding,” said Rich Haut of HARC, who is director of the EFD. “Government funding helps create and support a structure for such collaboration, and encourages the development of win-win technologies that industry may not have a strong financial incentive to develop without specific regulatory drivers.”
In another project, NETL used some of its portion of Section 999 funding to spearhead a joint industry/government effort to quantify the environmental impacts of shale gas development in western Pennsylvania, where it has orchestrated an exhaustive pre-drilling environmental assessment of a multi-well drillsite. This effort was carried out in concert with the operator, and has provided baseline data on the status and condition of the air, flora and fauna, surface water, and pre-development groundwater quality. According to NETL, there are plans to follow the initial assessment with data collection during and after the drilling, completion and production stages of the targeted wells.
“This type of objective—a rigorous ‘before and after’ approach to assessing any net environmental impact—is the single best way for science to inform, and perhaps settle, the policy debate surrounding shale gas development. The Section 999 Program has provided a straight forward mechanism for carrying out this timely assessment,” NETL said.
Furthering deepwater safety. The deadly 2010 Deepwater Horizon blowout and subsequent oil spill in the Gulf of Mexico accelerated focus on improving HSE standards in deep and ultra-deep waters, an effort that had been underway within RPSEA since its creation. The ongoing efforts led to significant advancements, among them the continuing development of an autonomous underwater system for monitoring and inspecting deepwater structures.
Unlike the oft-employed remotely operated vehicles (ROV) typically used in the deep and ultra-deep waters, an autonomous vehicle is not tethered to a support vessel, thereby sidestepping a host of operational limitations. As part of its ultra-deepwater program, RPSEA engaged Lockheed Martin and other research team members to develop and test an AUV that can be used to remotely monitor underwater activity, or inspect underwater structures, in deep water. The system can be used for pre- and post-hurricane inspection of platforms, or to detect any changes to subsea structures or equipment over time.
From environmental, economical and operational perspectives, analyses suggest an AUV can reduce the surface footprint by 75% and perform ultra-deepwater subsea structural inspections up to four times more efficiently than an ROV. In addition, its developers say an AUV accommodates inspection of longer subsea tiebacks.
Another noteworthy development arising from the partnership is the preliminary design of an ultra-deepwater dry-tree drilling and production system for the Gulf of Mexico. The RPSEA-directed research project has progressed to pre-front-end engineering design (pre-FEED), and cost estimates for the novel architecture required for the system.
Det Norske Veritas is leading the project, together with Houston Offshore Engineering and other offshore architecture design partners. “This project is accelerating development of an alternative dry-tree semisubmersible design that can be cost-competitive with the current spar alternative. More rapid development of such a technology will provide deepwater operators with greater flexibility in making development decisions, and will lead to more rapid production of domestic deepwater offshore oil and gas resources. A new dry-tree system for ultra-deepwater GOM has the potential to increase total reserves recovery for the U.S. and lower the overall cost for extracting hydrocarbons from beneath the seafloor,” RPSEA said.
Efforts to increase the resource base. As its name implies, RPSEA has been heavily focused on increasing the U.S. recoverable reserve base, with a primary emphasis on smaller producers. Along with a groundbreaking project to optimize fracturing and re-fracturing, research also is being directed at identifying and developing technologies that will enable smaller independents to economically produce from residual oil zone (ROZ) fairways in West Texas and elsewhere. The research also could lead to the development of a potential storehouse for carbon dioxide, RPSEA says.
The research is aimed at exploiting reserves within the 200-to-300-ft-thick ROZs locked beneath the original oil-water contact, where perhaps upwards of 40% of the pore space contains residual oil that cannot be produced by waterflooding and other conventional recovery techniques. Preliminary DOE research estimates more than 30 billion bbl of residual oil residing within 56 fields in the Permian basin alone, with at least 11.9 billion bbl technically recoverable.
“It appears that, in favorable situations, perhaps 20% to 30% of the residual oil can be recovered by CO2 flooding. The problem is that little is known about the true extent of these ROZs, while even less is known about their potential response to CO2 flooding. The companies still producing the fields overlying these ROZs typically are small independents that do not have the expertise or financing to investigate these issues unilaterally,” says RPSEA.
The University of Texas of the Permian Basin leads the ROZ research team, which includes four small producers and six other organizations with specific expertise. According to the researchers, deliverables will include Permian basin maps showing trends favorable for ROZ locations. The project also is mapping organic indicators and core and drill cuttings data related to potential ROZs, and will offer advice to small producers on how to use the data effectively. The team has already collected well logs, oil-water contact data, groundwater samples and core data and has developed a regional hydrological model that can be used to explain the presence of ROZs and, hopefully, predict their likely occurrence.
Further, since the ROZs are very large saline aquifers, they may prove to be ideal storage for CO2 on a major scale, when carbon capture, utilization and sequestration (CCUS) become widespread.
In another project, the consortium is combining powerful numerical models with field observations to enhance understanding of how hydraulic fracturing changes reservoir stress distribution and the expected fracture orientation for re-fracturing. The project combines modeling experts at The University of Texas at Austin with gas producers and service companies in the Barnett shale play, including Anadarko, BP, Baker Hughes, ConocoPhillips, Halliburton, Shell, Schlumberger and Total. As part of the project, the participating companies provided data on well completion practices and production results.
Results of the project, to date, emphasize that care must be taken in selecting candidate wells for re-fracturing and that a time window exists for optimal re-fracturing performance, based on the nature of the reservoir. The research team developed type curves for choosing the most advantageous timing of re-fracture treatments, as well as the optimum spacing of fractures in horizontal wells to maximize ultimate recoveries. Operators have already begun to apply these findings to improve the results of wells in the Barnett shale and other shale gas plays.
As reflected in the projects it has spearheaded, RPSEA is quick to point out that both operators and consumers benefit from government investment in public-private partnerships designed to develop new technologies. While the initiative affords the former access to enhanced tools and information sooner than might otherwise have been possible, the larger beneficiary is the public, which will enjoy affordable, less volatile energy supplies, increased economic growth and, in the case of dramatically increased natural gas supplies, enhanced environmental benefits. 
REFERENCES
1. EIA, Annual Energy Outlook, Reference case estimated production for 2012, June 2012.
2. Hass, M. R., and A .J. Goulding, “Impact of Section 29 tax credits on unconventional gas development and gas markets,” SPE 24889, presented at the SPE Annual Technical Conference and Exhibition, October 1992.
3. National Academies Press, “Energy research at DOE: Was it worth it?—Energy efficiency and fossil energy research, 1978 to 2000,” 2001, available at www.nap.edu/openbook.php?isbn=0309074487.
4. IHS Inc, “The economic and employment contributions of unconventional gas development in state economies,” June 2012, prepared for America’s Gas Alliance.
5. Permian Basin Oil and Gas Magazine, “The other revolution,” February 2012.
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