Massive oil resource to be targeted by new EOR techniques

Dec. 13, 1999
Significant oil remains in the ground that can be recovered with technically proven enhanced oil recovery techniques, but economics still inhibit these methods from being widely implemented.

Significant oil remains in the ground that can be recovered with technically proven enhanced oil recovery techniques, but economics still inhibit these methods from being widely implemented. Without a doubt, this will remain an issue in the next millennium as oil prices fluctuate while new technology and understanding decrease both EOR risk and costs.

Imperial Oil Ltd.'s bitumen operations at Cold Lake, Alta. produce over 100,000 bo/d, and a proposed $500 million (Canadian) expansion will add 30,000 b/d from a new operating area called Mahkeses.
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But EOR targets are substantial and include mature US fields as well as the huge Middle East fields that will be experiencing steep production declines in the next millennium. Oil production from EOR and heavy oil deposits is bound to increase from current levels, which a 1998 Oil & Gas Journal survey indicates is about 3.5% (2.3 million b/d) of the world's oil production.

The dominant EOR process will likely continue to be steam, with gas injection (carbon dioxide, light hydrocarbons, and nitrogen) accounting for much of the remainder.

Sequestering CO2

Carbon dioxide (CO2) injection for improving oil recovery could be a process that may see expanded use in the next millennium because most countries are actively seeking ways to remove CO2 from the atmosphere out of concern for postulated catastrophic global warming. Sequestering this CO2 emitted by industry and electric power generations stations into oil reservoirs may turn out to be win-win type of solution.

Norsk Hydro Production AS advanced one plan that combined CO2 and electric power generation for its proposed development of Grane heavy (19° gravity) oil field off Norway. Norsk Hydro plans to first generate CO2 and hydrogen from natural gas, then inject supercritical CO2 in Grane while using the hydrogen to fuel onshore gas-fired power plants. These hydrogen-fired power plants would use steam reforming to convert natural gas to hydrogen and carbon monoxide. In the process, water also combines with carbon monoxide to form CO2 and hydrogen. Norsk Hydro estimates that burning hydrogen in power plants reduces CO2 emissions by 90% compared with conventional gas-fired power plants.

In another project, which has sequestering implications, PanCanadian Resources Ltd. will inject CO2 in Saskatchewan's Weyburn field. This will be the first large-scale CO2 project in Canada and could be a catalyst for more such projects in Canada, once a related CO2 pipeline is built and the flood demonstrates its potential. The sequestration part of the project is that the CO2 is supplied by the Great Plains synfuels plant, near Beulah, ND, which currently vents the CO2 to the atmosphere. Dakota Gasification Co. owns and operates the plant that produces 160 MMcfd of natural gas from coal gasification. The CO2, a by-product of the gasification process, will be transported in a dense phase from Beulah to Weyburn via a 330-km pipeline, currently under construction. About 95 MMcfd of the 240 MMcfd of vented CO2 will be injected into the Weyburn reservoir beginning in fall 2000. PanCanadian expects oil production with the CO2 at Weyburn to reach 30,000 b/d by 2008 compared with its estimate of only 10,000 b/d without the CO2.

In another sequestration example, some CO2 previously vented by gas plants near the Permian basin of West Texas is now being used for recovering oil. PetroSource Corp.'s pipeline, which replaced a line that was converted to natural gas service from its previous CO2 service, now allows gas plants in the Val Verde area of Texas to transport vented CO2 to the Permian basin CO2 pipeline infrastructure. The first buyer for this CO2was the Sharon Ridge CO2 EOR project, operated by Exxon USA, in Scurry Co., Tex.

A number of other projects, including some in Oklahoma and Canada, also take advantage of vented CO2 for enhancing oil recovery.

Other projects

A host of new and planned EOR projects around the world feature new approaches and new technologies.

Some projects are pilots while others are substantial. Some, such as Pemex Exploración y Producción, depend on innovative contracts that provide benefits for both operators and suppliers, a trend that likely will continue in the next millennium.

As part of an upgrade of its Cantarell oil fields complex in the Bay of Campeche off Mexico, Pemex will start in 2000 injecting nitrogen gas, extracted from the atmosphere, into Akal, the main producing field in the Cantarell complex. Pemex expects the nitrogen to arrest the steep decline in reservoir pressure experienced because of depletion. The Akal field produces a 19-22° gravity crude.

Pemex estimates the pressure maintenance from nitrogen injection will allow it to produce an extra 2 billion bbl of oil from the Cantarell complex. The estimated $1 billion cost of the 1.2 bcfd onshore nitrogen extraction plant, at Atasa, is being handled with a build-own-operate (BOO) contract for the nitrogen plant.

Under its BOO contract, the contractor furnishes the capital and Pemex pays the contractor at a cost per volume for the nitrogen. Pemex estimates that its nitrogen cost will be $0.56/Mscf in the first year and decrease to $0.23/Mscf by 2016, with the average put at $0.36/Mscf-which Pemex indicates is significantly less than if natural gas were injected for reservoir pressure maintenance.

Pemex expects Module 1 of the nitrogen plant to begin deliveries in April 2000 with the fourth module ready by September 2000. Each module has the capacity to deliver 300 MMscfd of nitrogen, compressed at 1,500 psig.

Shell CO2 Co. Ltd., over the last few years, has aggressively promoted CO2 for enhancing oil recovery. It has expanded its McElmo Dome CO2 source field in southwestern Colorado as well as its pipeline capacity to deliver over 1 bcfd of CO2 to the Permian basin. One part of its strategy involves innovative contracts to make CO2 flooding more attractive for Permian basin independent operators. But low oil prices again have diminished activity, and Shell has seen CO2 deliveries to the basin fall to 600-700 MMscfd. But it is still pursuing new opportunities to sell CO2.

Shell recently announced that it will participate in a pilot project for proving CO2 EOR potential in US Midcontinent oil fields. The pilot, partially funded by the US Department of Energy, is in Hall-Gurney field, Russell County, Kan.

According to DOE, CO2 EOR has never been tested in the depleted waterfloods of Central Kansas. Shell estimates CO2 flooding in the Central Kansas uplift could potentially recover an incremental 150 million bbl.

The target of the Hall-Gurney pilot is the Lansing-Kansas City formation, a large carbonate deposition, but other formations such as the Morrow and Arbuckle also have potential for CO2 floods, according to Shell. The Morrow formation is already being successfully swept with CO2 in Mobil Exploration & Producing Co.'s Postle field in Texas County, Okla.

One large reservoir that may see new life in the next century, if CO2 injection proves effective, is the giant Spraberry trend in West Texas. The fractured siltstone reservoir covers about 2,500 sq miles and may have contained 10 billion bbl of original oil in place, with only about 12% recovered over 40 years of waterflooding. Again, DOE is partially sponsoring the pilot, which involves CO2 injection starting start in early 2000.

Marathon Oil Co. has initiated an innovative steam pilot in Yates field, Pecos and Crockett counties, Tex. that incorporates use of modern seismic and logging technology. Its pilot aims to assess the viability for steam to improve gravity drainage in the gas cap of a fractured San Andres carbonate reservoir.

Marathon monitors the performance of the injected steam with downhole geophones that receive passive seismic events caused by thermal expansion of the rock. These signals are used for estimating areal and vertical extent of the heated zone. Time-lapsed carbon-oxygen logs indicate the oil saturation changes behind the thermal field.

Marathon describes the basic recovery at Yates as a double-displacement process, which may be defined as: gas displacement of a water-invaded oil column. Marathon is injecting nitrogen gas to create a gas cap to allow gravity drainage of the liquids. It says the steam is not a displacing agent but is for heating the remaining oil, thereby reducing oil viscosity and mobilizing the oil so that it flows from the matrix to the fractures. Once the oil is in the fractures, Marathon expects it to flow laterally into producing wells.

Another steam pilot aims to prolong the life of the largest oil field in Southeast Asia. PT Caltex Pacific Indonesia has initiated a $50 million light (32° gravity) oil steamflood pilot in Sumatra's Minas field.

Caltex expects the steam to both mobilize and displace remaining oil by-passed by primary and waterflood production, as well as to extract light ends from the residual oil from the field that still produces about 200,000 bo/d and has recovered 4 billion bbl.

The vast heavy oil sands and tar sands that lie at relatively shallow depths in the world are likely to see more steam EOR activity. Steam-assisted gravity drainage with horizontal wells is being used in Canada and is under test in China to recover heavy oil. But so far, heavy oil production is relatively minor when compared with estimates of known resources.

For instance, Venezuela's Orinoco oil belt has been estimated to hold 1.3-1.8 trillion bbl of heavy and extra-heavy oil in place. Several joint ventures between Petroleos de Venezuela SA and foreign oil companies are in various stages of development, but these projects will only scratch the surface at recovering the oil in place. Over a 30-40 year contract period, each of these projects is expected to recover 5-10% of OOIP. This is about 2.5 billion bbl reserves per project over the contract period. During the contract period, the projects will be relying on horizontal wells and natural influx from the reservoir to move oil into the wellbore. But this still leaves about 90-95% of the oil as a target for such EOR processes as steam, after the contract period ends.

More options

CO2 flood injection wells, such as this well in Mobil Exploration & Producing U.S. Inc.'s operated Salt Creek field, Kent County, Tex., must be designed to handle alternative slugs of CO2 and water.
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Steam and gas injection are likely to continue to be the dominant EOR processes used, but other EOR technologies involving chemicals, polymers, microbes, etc., have found economic niches that are likely to grow as the technologies advance.

These processes are being applied in commercial or pilot projects and are likely to continue to be used in the next century to help recover the substantial amounts of residual oil left behind by primary and secondary recovery processes.

Extensive research and a number of pilot tests have shown microbial EOR can recover additional oil but the process still has not found widespread commercial use. Most pilot tests, to date, have used a huff-and-puff process and have demonstrated that treatments can reduce the viscosity and wax content of crude from shallow (less than 1,500 ft) reservoirs that contain relatively fresh water.

In Lake Maracaibo, microbial treatments in four wells raised oil production by 50-200 b/d using naturally-occurring and nongenetically engineered microbes that improved oil mobility. The process becomes more economic if naturally occurring suitable microbes are identified and food for the microbes, such as molasses, is minimized.

In China, several pilots have reported improved methods for microbial EOR.

For instance, in the shallow Fuyu oil field, huff-and-puff pilots determined that a microbial solution is more effect than molasses-only solution. The field's operators, Japan National Oil Corp. and Jilin Petroleum Group Co. Ltd., are now planning to test the process with a flood-type pilot.

In the Qinghai Seven Springs oil field, also in China, a pilot test reported that after a microbial treatment, oil production increased to 28 bo/d from 17 bo/d, with water cut decreasing by 12.5%. The production remained at an elevated level for about 2 months. This test also demonstrated the effectiveness of microbes in more-saline reservoirs.

Chemicals, including polymers, have the potential of removing close to 100% of the residual oil as long as these chemicals can contact all the pores in a reservoir. But chemical treatments can be costly if not properly evaluated.

When properly designed in appropriate reservoirs, these types of treatments have been shown to be economic. One company claims that, based on 29 successful projects, colloidal dispersion gel injection chemical cost per incremental bbl ranged was $0.47-4.08/bbl, with estimated ultimate recovery of over 40% of OOIP.

Alkaline surfactants are other chemicals that have been used in the past for enhancing oil recovery and may find a place in the next century, if costs can be reduced.

The Author

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Guntis Moritis is Production Editor of Oil & Gas Journal.