EOR continues to unlock oil resources

April 12, 2004
Every 2 years, the Oil & Gas Journal surveys worldwide projects that use various injection technologies to enhance oil recovery from reservoirs.

About this report...

Every 2 years, the Oil & Gas Journal surveys worldwide projects that use various injection technologies to enhance oil recovery from reservoirs. Tables showing the projects surveyed start on p. 53, while the following pages describe events and trends, affecting EOR activity.

Oil & Gas Journal's exclusive biennial enhanced oil recovery (EOR) survey, p. 53, shows that enhanced oil recovery methods continue to recover remaining oil from mature fields and are also effective for recovering the heavy oil or bitumen contained in the massive oil sand resources of Western Canada.

EOR methods may become more important in the future, especially if the bulk of future oil projects involve extracting oil from known resources rather than from exploration efforts that find new oil accumulations.

The projects usually are long-lived. Because of this, companies tend to use long-term price forecasts to justify initiating these projects. Therefore, the last few years of high oil prices have produced less new EOR projects then some might have expected.

Other factors that have suppressed new projects include high natural gas prices that increase the cost of generating steam and contracts that tie the purchase of carbon dioxide for enhancing oil recovery to the price of oil.

But such drivers as the elimination of flaring of stranded associated gas may foster new hydrocarbon gas miscible and immiscible projects. Ganesh Thakur, principal technical advisor with ChevronTexaco Inc., said he is aware of a number of companies that have studies and plans related to these technologies.

OGJ published its first EOR survey in May 3, 1971, and the survey has been a regular biennial OGJ feature since 1974.

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Tables A through F (pp. 53-65) list projects in the 2004 EOR survey.

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Projects in the survey are those that involve injecting fluids into a reservoir other than water or methane to improve or enhance oil recovery. Operators use the injectants during the initial production stage, after the primary depletion stage, or after the secondary production stage, which also is known as tertiary recovery.

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Click here to view the Worldwide EOR survey in PDF.

The most common injectants include:

  • Steam in heavy oil fields at shallow depths.
  • Air for in situ combustion projects.
  • Carbon dioxide floods in lighter oil fields.
  • Hydrocarbon miscible gas in lighter oil fields.
  • Chemical and polymer in lighter oil fields.

US projects

OGJ's survey shows that EOR contributed 663,451 b/d to US oil production (Tables 1 and 2), which is a 5,546-bo/d decrease from the 2002 survey (OGJ, Apr. 15, 2002, p. 44). The survey covers 143 projects.

The decline in oil production from the mature thermal heavy-oil projects in California is mainly responsible for this decrease. Oil production from these projects peaked in 1986 at 480,000 b/d and has declined to the current 340,000 b/d.

A trend in the number of active California thermal projects is difficult to ascertain from OGJ's surveys because companies have consolidated projects. For instance, in the current survey ChevronTexaco Inc. combined several projects that it previously reported separately. The 2002 survey listed 23 Chevron and Texaco projects producing 193,700 bo/d, while the current survey lists 10 projects producing 175,500 bo/d.

ChevronTexaco's Kern River remains the largest single EOR project in the US, producing about 100,000 b/d. Aera Energy LLC, a venture of ExxonMobile Corp. and Shell Inc., has the second most EOR production, 141,000 bo/d from 17 projects.

Table 1
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In the US the number of CO2 miscible injection projects for enhancing oil recovery have increased (Table 1). The ongoing projects on Jan. 1, 2004, compared with 66 on Jan. 1, 2002 (OGJ, Apr. 15, 2002, p. 45). Enhanced oil recovered by these projects has also increased to 205,775 b/d from the 187,410 b/d shown in the previous 2002 survey.

Occidental Permian Ltd. remains the most active operator of CO2 projects, with 19 active floods in the Permian basin. Two of its floods, North Cowden and West Welch, are listed as completed. The sidebar discusses Oxy's current EOR strategy and presents the results to date of its successful Cogdell flood.

One recent highlight in CO2 EOR is Anadarko Petroleum Corp.'s completion of a pipeline to transport CO2 to the Salt Creek field and Monell Unit in Wyoming. The company expects that the CO2 injection will increase oil production to about 30,000 bo/d by 2008 from the current 1,000 b/d. Injection in Salt Creek began in February 2004.

ExxonMobil Corp.'s La Barge gas plant in Western Wyoming will sell the CO2 to Anadarko.

Table 2
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Another highlight in CO2 EOR is Kinder Morgan CO2 Co. LP's restoration of CO2 injection in the Scurry Area Canyon Reef Operators Committee (SACROC) unit. In OGJ's 2002 survey, about 2 years after Kinder Morgan purchased the unit, the field's production credited to EOR was about 10,000 b/d. This production has more than doubled since then and at the beginning of 2004 was 23,000 b/d.

In 2003, Kinder Morgan acquired interest in the Yates field with plans to convert it from a nitrogen immiscible to a CO2 immiscible injection. In the past, the Marathon Oil Corp., the previous operator, injected nitrogen or CO2 based on which injectant cost less. Kinder Morgan expects the restoration to a CO2 project will increase oil production by swelling the oil and reducing its viscosity. It started injecting CO2 in March 2004.

Another area that is seeing CO2 EOR activity is Michigan. Core Energy purchased two CO2 floods in Otsego County, Mich., from Diamond Petroleum Co. and in 2004 began a third flood nearby. It also has plans to start a fourth flood in 2005. These are small floods involving two or three wells and producing about 100 b/d each.

Anadarko Petroleum Corp. recently completed a 16 in.,125-mile pipeline to carry CO2 to its Salt Creek EOR project. Photo from Anadarko.

Canadian EOR

Canada has many planned steam-assisted gravity drainage (SAGD) projects in the oil sands in Alberta. Some of these primary oil recovery projects have begun producing.

Encana Corp. started production from its MacKay River SAGD project in September 2002 and currently the project produces about 30,000 b/d of bitumens.

Suncor Energy Inc. started its Firebag SAGD at yearend 2003. Suncor expects the $460 million first phase of the project to produce 35,000 b/d by mid-2005.

Suncor plans three-more phases in Firebag that would increase production to about 140,000 b/d by 2010. It estimates that the Firebag project has 9.3 billion bbl of reserves in place.

Encana's Christina Lake SAGD project may produce between 50,000 and 70,000 b/d from up to 700 horizontal wells, by 2009. Also a $350 million expansion of Japan Canada Oil Sands Ltd. (Jacos) SAGD Hangingstone pilot is slated to produce 50,000 bo/d by 2006.

Canadian Natural Resources Ltd.'s Primrose, Wolf Lake, and Burnt Lake oil sands project includes both cyclic and SAGD technologies. These projects produce about 38,000 b/d and CNRL plans to expand production to 120,000 b/d during the next 15-20 years by drilling about 600 new horizontal wells and installing additional facilities.

OPTI Canada Inc. and partner Nexen Inc. are developing the $3.4-billion Long Lake oil sands project that is the first oil sands project to integrate SAGD with an onsite upgrader.

The companies estimate that the project contains more 1 billion bbl of recoverable bitumen. They plan to commence production in 2006 with the upgrader starting up in 2007. The plans include the SAGD wells producing 72,000 b/d that will be upgraded to about 60,000 b/d of synthetic crude.

ConocoPhillips recently started construction on its $1.4 billion Surmont oil sands project that will start producing in 2006 and will reach a production level of 27,000 b/d.

The largest steam project remains Imperial Oil Ltd.'s Cold Lake. A recent expansion has raised Cold Lake's production to 129,000 b/d. Imperial has used a phased development approach to the area.

The latest to start were Phases 11-13 from which Imperial expects to recover 250 million bbl. The phases included more than 500 wells, drilled from 21 surface pad locations, and new steam-generation, oil processing, and electrical cogeneration facilities.

Imperial expects to add 300 more wells in 2004 and has applied for two additional expansions that will add an additional 350,000 million bbl to recoverable reserves and increase production from the field to 180,000 b/d.

Encana's Weyburn CO2 miscible flood remains the main CO2 flood in Canada, producing about 6,500 b/d of incremental oil. It buys its CO2 from the Dakota Gasification Synfuels plant, Beulah, ND, and is recognized as the world's largest joint implemented project for reducing CO2 emissions.

One estimate is that during 15 years about 14 million net tons of CO2 will be stored in the reservoir rather.

Another project in Canada is Talisman Energy Inc.'s nitrogen EOR project in the Turner Valley oil field. Talisman plans for the $150 million 3-year pilot to prove out the possibility of recovering more than 15% of the 1 billion bbl of oil in place recovered to date. With nitrogen injection, it expects to recover an additional 3-10% of the oil in place or 30-100 million bbl.

Other countries

The PT Caltex operated Duri field on Sumatra Island in Indonesia remains the largest single EOR project in the world, producing about 220,000 b/d.

Other countries with active EOR projects include China and Venezuela, although up to date statistics for these projects were unavailable at press time.