Massive oil resource to be targeted by new EOR techniques

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.

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