What's new in production

	Vol. 226 No. 12
VICTOR SCHMIDT, DRILLING ENGINEERING EDITOR

Win-win integration. The search for a win-win strategy in the oil production versus environmental impact struggle has turned a corner, following the success of an integrated CO₂ project. In 2000, global warming fears related to carbon dioxide release from burning hydrocarbons led to multi-national funding of the Weyburn CO₂ Storage and Monitoring Project in the Weyburn oil field of Saskatchewan, Canada. The project began that year, funded by $23 million donated from governments and industry. It has successfully injected five million tons of carbon dioxide, while doubling the field’s oil recovery.

The CO₂ for the project comes from the Great Plains Synfuels Plant near Beulah, N.D., where the gas is a by-product of coal gasification. Canada’s Petroleum Technology Research Centre in Regina, Saskatchewan, leads the project and EnCana Corp., the field’s operator, is co-sponsoring the effort. The project receives funding from government and industry organizations in Canada, the US, Europe and Japan.

Research sponsors ($21 million in cash ) include from governments: Natural Resources Canada, US Department of Energy, Saskatchewan Industry & Resources, Alberta Energy Research Institute and the European Community; and from industry: EnCana Corp., SaskPower, Nexen Canada, Total, Chevron, BP, Dakota Gasification Co., TransAlta Utilities Corp. and Engineering Advancement Association of Japan.

Research providers ($21 million in kind ) include from Canada: EnCana Corp., Saskatchewan Industry & Resources, Saskatchewan Research Council, University of Alberta, University of Calgary, University of Saskatchewan, University of Regina, J.D. Mollard and Associates Ltd., Alberta Research Council, Geological Survey of Canada (NRCan), Hampson Russell-Veritas, Rakhit Petroleum Consulting, Ecomatters, Inc. and Canadian Energy Research Institute. From the US, they include: Lawrence Berkeley National Laboratory, Lawrence Livermore National Laboratory, Colorado School of Mines, Monitor Scientific L.L.C. and North Dakota Geological Survey. From Europe, they are: British Geological Survey (UK), BRGM (France), GEUS (Denmark), ING (Italy) and Quintessa Ltd. (UK).

The first phase of the project injected CO₂ into the oil field to increase the field’s reservoir pressure and bring more oil to the surface. The gas injection raised oil production by 10,000 bpd and showed that permanent carbon sequestration is possible. Of course, the industry has been demonstrating enhanced oil recovery by CO₂ injection successfully for decades. The key is keeping the gas in the reservoir to prevent leakage back to the atmosphere. The Weyburn Project hopes to increase the recovery factor to 60%, produce an additional 130 MMbbl of oil and extend the field’s life for 20 years.

In Phase II, now underway, researchers will compile a best practices manual as an industrial reference. They will also expand the project’s reach to the Midale Unit, improve injection efficiencies, monitor CO₂ flooding and storage with seismic and geochemical surveys, and develop risk-assessment modeling techniques. US DOE officials project that billions of barrels of oil could be recovered, and one-third to one-half of CO₂ emissions could be eliminated over the next 100 years, if similar methods are widely applied.

Whether or not global warming by CO₂ is a real problem, government and industry are working together to find a mutually beneficial approach to address the issue. See http://www.fossil.energy.gov/news/techlines/2005/tl_weyburn_mou.html.

Defining heavy oil. The topic of heavy oil presented in September’s column (p. 21, World Oil, Sept. 2005) elicited follow-up comments that clarify the definition of these thick crudes. The history of the definitions begins when the US Department of Energy sponsored a Tar Sands Definitional Workshop in 1980 to guide regulatory treatment of these resources. Thirteen oil company representatives met to form a consensus that would define the resource, exclude conventional heavy oil, determine measurability and meet regulatory needs.

What came from the workshop was the use of dead oil viscosity as the standard measure, because testing live oil is difficult, uncertain and expensive. Dead oil viscosity is easily understood by non-technical people, is directly related to producibility, is inexpensive to test and does not require interpretation. In addition, a standardized test for dead oil viscosity already existed.

The value chosen to separate oils and tars was 10,000 cP, as shown on the accompanying 1997 US thermal enhanced oil production graph. This definition left 97% of the oils as conventional oil and the remaining 3% as tar. The definition preserved the oil industry’s historical heavy oil concepts and left the tar sands for mining interests, due to the cost and safety aspects of working with such deposits.

The World Petroleum Congress also opened a study group on the heavy oil question in 1980 and worked on its definition for many years. In 1982, the DOE work was carried forward to the United Nations through UNITAR, another international working group. That body determined heavy oil to be gas-free oil between 100 cP and 10,000 cP at original reservoir temperature, with a density between 10° and 20° API gravity. Tars were defined as gas-free oil with viscosities over 10,000 cP, or a density greater than 10° API gravity. This definition was later adopted by the World Petroleum Congress in 1987 with minor modifications.

Recently, Venezuela has added its own extra-heavy oil category. For its crudes, Venezuela recognizes extra-heavy oil as crude that is less than 10° API gravity, but less than 10,000 cP.

Heavy oil has been defined internationally from 100 to 10,000 cP, representing 97% of US thermal enhanced oil production in 1979.

Thanks to reader Ed Hanzlik, who participated in these early definitional workshops, for broadening my understanding of heavy oil and the international consensus on these crudes.