LOW COST METHODS FOR IMPROVED OIL AND GAS RECOVERY

Based on a workshop sponsored by PTTC's Central Gulf Region in Shreveport, Louisiana on January 27, 2005.

BOTTOM LINE

Improved oil and gas recovery processes need not be costly and complex. Often overlooked low cost methods include a double displacement process for oil recovery, cyclic CO₂ huff & puff treatments, co-production of gas and water from water-drive gas reservoirs, and water flooding of low-pressure gas reservoirs. This workshop summarized the concepts of these processes, presenting some case history data. It must be noted that, except for cyclic CO₂ huff & puff treatments, the other processes have not been widely applied.

PROBLEM ADDRESSED

A common perception is that improved oil and gas recovery is costly and complicated. Several low cost improved recovery methods have been field tested. Objective of this workshop is to present the concepts underlying these low cost methods.

KEY WORDS:

Co-production of gas & water from water-drive gas reservoirs, Double displacement process using air injection, Single well cyclic CO₂ injection, Waterflooding of low-pressure gas reservoirs

SPEAKERS:

Improved Oil and Gas Recovery Methods,
Zaki Bassiouni, Louisiana State University

Modeling Pressure and Displacement Management in Enhanced Gas Recovery,
Thomas Walker, Louisiana State University

TECHNOLOGY OVERVIEW

The Double Displacement Process (DDP) Using Air Injection
In a water-drive oil reservoir, the oil-water contact (OWC) moves upstructure as depletion occurs. Near depletion there is a large water-swept oil zone with oil saturation near residual oil saturation. In a dipping light oil reservoir, upstructure air injection can improve oil recovery in two ways: (1) air injection can raise reservoir pressure increasing production rates and (2) gas displacement of water from a water-invaded oil column can mobilize a fraction of residual oil. Laboratory corefloods indicate that more than 50% of residual oil to water can be mobilized. This mobilized oil moves downstructure via gravity drainage to down structure producers.

The DDP was demonstrated in the West Hackberry Field (Cam C-1 sand, Reservoir A) in Louisiana in the mid 1990s in a DOE-supported Class I field demonstration project. Goal was to inject 4 MMSCFD of air at 4,300 psig maximum surface pressure. High-pressure air injection requires special design and operations practices to deal with the ignition/combustion hazards. It is critical that air and hydrocarbons not mix in the surface equipment and in the injection wells. In the reservoir, ignition with low temperature oxidation actually occurs.

In West Hackberry in July-1996 when air injection began, production from four producers had declined to about 225 bopd with a 50% water cut. Response to air injection occurred quickly with production rising to 250 bopd over normal decline. By December 1997 more than 70,000 bbls of incremental oil was produced. SPE Paper # 39462 (Low Cost IOR: An Update on the W. Hackberry Air Injection Project, April 1998) provides detailed data on operational experience in this air injection project.

Single-Well Cyclic CO₂ (Huff & Puff) Injection
Cyclic CO₂ injection consists of injecting a slug of CO₂, allowing it to soak for a period of time, and then placing the well back on production. Production interruption during the soak period is more than made up for with stimulated production when the well is brought back on line following the soak period. Production may decline rapidly, approaching the pre-slug after a period of time. At this point (or sooner) the process is repeated—thus the term cyclic. There are three major recovery mechanisms: oil swelling, viscosity reduction and decreasing water saturation near the well bore. There may be additional benefits from injection increasing the bottom hole pressure, which increases rate when the well is brought back on production. Compared to full scale CO₂ flooding, much smaller amounts of CO₂ are involved and project life, even with multiple cycles, is shorter. If there is poor inter-well communication, huff & puff is still feasible whereas actual field-scale flooding would be difficult.

In 1989 Louisiana State University compiled a database of field results with CO₂ huff & puff treatments. Data from 106 projects in 12 fields were collected. Oil gravities ranged from 23 to 38° API; pressures ranged from 100 to 4,450 psia; depths ranged from 1,200 to 13,000 ft. The entire spectrum of primary reservoir drive mechanisms was represented in the database.

82% of the projects were deemed successful. Not surprisingly, the more CO₂ that was injected, the higher the incremental oil production with a fairly good correlation evident. Slug volumes are designed to limit undesirable interference with other wells. The higher the swelling factor, the higher the incremental oil production. The swelling depends upon oil composition with heavier oils swelling less. All other conditions being equal, higher production increases are seen as pay thickness increases. The longer the soak period, up to a point, the higher the incremental recovery.

Reservoir simulation can be used to predict performance. Since success is not that sensitive to reservoir heterogeneity, reservoir description need not be extensive. This is attractive considering that data may not be available or the time and effort for detailed description would not be warranted for economically marginal reservoirs.

Enhanced Recovery from Water-Drive Gas Reservoirs
Conventional production in a water-drive gas reservoir terminates when the producing wells load up with water, leaving high-pressure bypassed gas in the watered-out areas and in the gas cap updip of the watered-out wells. Water-drive gas reservoirs generally have much lower recoveries than depletion-drive reservoirs, from 35 to 75% compared to up to 90% in depletion-drive reservoirs. The stronger the water drive, the higher the reservoir pressure remaining at abandonment. Because residual gas saturation is independent of pressure, larger amounts of gas (residual gas) are trapped at the higher pressure.

With the co-production process, as the downdip wells begin to water out, they are converted to high-rate water producers, while the updip gas wells maintain gas production. This enhances recovery in three ways: (1) production of water lowers reservoir pressure and more gas is produced because of expansion; (2) water production slows the advance of the water front; and (3) previously immobile gas in the swept zone might become mobile again as the pressure is lowered. The process is applicable in moderate-to-active water-drive gas reservoirs. Co-production is most beneficial when initiated long before a reservoir is watered out. Downdip wells are converted to water producers as they water out, while gas production updip is maintained. The updip gas wells can, if warranted, be produced at a high rate, thus incorporating the benefits of accelerated blowdown. Data were shared for incremental recovery from co-production in a sand reservoir in Eugene Island Block 305, Gulf of Mexico.

Water Flooding of Low-Pressure Gas Reservoirs
In volumetric (depletion-drive) gas reservoirs, primary recovery is a function of abandonment pressure. The conventional approach to achieve additional recovery is compression, but waterflooding is an alternative for some situations. Water displaces gas very efficiently because of extremely favorable mobility of gas. Incremental recovery depends on the initial reservoir pressure and the pressure at which waterflooding is started. Economic feasibility is controlled by the amount of water needed, which is high because of high gas compressibility. The amount of needed water increases dramatically as the reservoir pressure decreases.

The only known implementation was in the 1970s in Duck Lake Field, D-1 reservoir in South Louisiana. Water injection over 10 years resulted in additional recovery of 3.6% of OGIP, which in this case amounted to 25 BCF incremental recovery. Water requirements were high.

Years later Louisiana State University researchers evaluated data from Godcheaux Reservoir A, Live Oak Field, Vermillion Parish, Louisiana in a "what if" waterflooding had been initiated scenario in a depletion-drive gas condensate reservoir (SPE Paper # 69651, "Physical and Economic Feasibility of Waterflooding of Low-Pressure Gas Reservoirs," March 2001). Reservoir pressure at discovery in 1955 was 6,170 psig. Compression was installed in 1969 when pressure had fallen to 2,200 psig and was even lower at the time of the evaluation.

The "what if" analysis looked at compression, pressure maintenance (maintains reservoir pressure), pressure support (only partial pressure maintenance) and waterflood/blowdown. Recovery with compression and waterflood/blowdown end up with the same incremental recovery, in this case 160 BCF. Pressure maintenance and pressure support (both without blowdown) recover less, only 107 BCF. Highest net present value would be realized for the waterflood/blowdown scenario, about 20% higher than for the compression option. Life was about half that required for compression. Net present value for pressure maintenance (no blowdown) fell in between, while net present value for only pressure support was about that for compression.

Modeling Pressure and Displacement Management in Enhanced Gas Recovery
A Visual Basic model has been developed as a screening tool for waterflooding and co-production processes in gas reservoirs. It couples material balance and well deliverability. Using generally available information (production data, well tests, reservoir and well geometry), it performs a material balance history match and predicts future performance, allowing different production/injection scenarios to be readily evaluated. Applicability was demonstrated in field examples from the High Island area in offshore Texas.
 

CONNECTIONS:

Zaki Bassiouni
Dean of Engineering
Louisiana State University
CEBA 3304
Baton Rouge, Louisiana 70803-6417
Ph: (225) 578-5701
Email: pezab@lsu.edu

Thomas Walker
Louisiana State University
CEBA 3304
Baton Rouge, Louisiana 70803-6417
Baton Rouge, Louisiana
Ph: (225) 578-6691
Email: twalke2@paws.lsu.edu

For information on PTTC’s Central Gulf Region and its activities contact:

Mr. Robert H. Baumann, Managing Director
Center for Energy Studies, Louisiana State University
Energy, Coast and Environment Building, Nicholson Drive Extension
Baton Rouge, Louisiana 70803
Phone 225-578-4400 Fax 225-388-4541
E-Mail rbaumann@lsu.edu

Disclaimer: No specific application of products or services is endorsed by PTTC. Reasonable steps are taken to ensure the reliability of sources for information that PTTC disseminates; individuals and institutions are solely responsible for the consequences of its use.

The not-for-profit Petroleum Technology Transfer Council is funded primarily by the US Department of Energy’s Office of Fossil Energy, with additional funding from universities, state geological surveys, several state governments, and industry donations.

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toll-free 1-888-THE-PTTC; fax 281-921-1723; Email hq@pttc.org; web www.pttc.org