A Literature Analysis of the WAG Injectivity Abnormalities in the CO2 Process
- John D. Rogers (New Mexico Petroleum Recovery Research Center) | Reid B. Grigg (New Mexico Petroleum Recovery Research Center)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- October 2001
- Document Type
- Journal Paper
- 375 - 386
- 2001. Society of Petroleum Engineers
- 5.6.4 Drillstem/Well Testing, 4.3.1 Hydrates, 5.8.7 Carbonate Reservoir, 5.2.1 Phase Behavior and PVT Measurements, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 4.1.4 Gas Processing, 5.5.8 History Matching, 4.3.3 Aspaltenes, 1.2.3 Rock properties, 5.4.2 Gas Injection Methods, 5.1 Reservoir Characterisation, 5.1.1 Exploration, Development, Structural Geology, 7.1.9 Project Economic Analysis, 5.8.8 Gas-condensate reservoirs, 4.1.2 Separation and Treating, 4.2.3 Materials and Corrosion, 1.6.9 Coring, Fishing, 4.1.5 Processing Equipment, 5.4 Enhanced Recovery, 5.8.9 HP/HT reservoirs, 2.7.1 Completion Fluids, 3 Production and Well Operations, 5.2 Reservoir Fluid Dynamics, 5.3.4 Reduction of Residual Oil Saturation, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.8.6 Naturally Fractured Reservoir, 5.5 Reservoir Simulation, 5.7.2 Recovery Factors, 5.3.1 Flow in Porous Media, 4.3.4 Scale, 7.1.10 Field Economic Analysis, 5.3.2 Multiphase Flow, 5.1.5 Geologic Modeling, 2.2.2 Perforating, 5.4.1 Waterflooding, 1.8.5 Phase Trapping, 5.4.10 Microbial Methods, 5.4.9 Miscible Methods, 6.5.2 Water use, produced water discharge and disposal, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 4.6 Natural Gas, 1.8 Formation Damage
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This paper summarizes the hypotheses and theories relating to the causes and expectations of injectivity behavior in various CO2 and gasflooded reservoirs. The intent of the paper is to:
Provide a concise compendium to the current understanding of the water-alternating-gas (WAG) mechanism and predictability.
Provide a comprehensive single-source review of the causes and conditions of injectivity abnormalities in CO2/gasflood EOR projects.
Aid in formulating the direction of research.
Help operators develop operational and design strategies for current and future projects, as well as to input parameters for simulating current and future projects.
Moritis1 identified 94 gas improved oil recovery (IOR) projects in the U.S. Of these, 74 are still active and 64 are CO2 miscible projects. New CO2 projects start each year. Five new U.S. miscible CO2 projects were being planned as of January 2000. Brock and Bryan2 presented a summary of CO2 IOR projects and reviewed the performance of 30 full-scale field projects and field pilots up to 1987. In 1992, there were 45 active CO2 projects in the U.S.3 Because of the low oil prices following the 1985-86 price collapse, the initial industry outlook was pessimistic; however, by 1992, most projects had been shown to be technically and economically successful. In a number of projects, the production performance has been better than anticipated.3
At the beginning of 2000, and based on 1999 production figures, the U.S. production from gas-injected IOR was estimated at 328,759 B/D, or approximately 5% of the total oil production in the U.S. Oil production from CO2 activity alone contributed 189,493 B/D, which is an increase of 5.8% over 1998 production attributable to CO2 production and represents 3% of the 1999 U.S. oil production.1 This increase occurred despite the 1998-99 price collapse, which was deeper than the mid-1980s collapse. The Permian Basin of west Texas and southeastern New Mexico remains a very active area for CO2 projects. However, CO2 IOR field or pilot projects also exist in seven other states: California, Colorado, Kansas, Michigan, Mississippi, Oklahoma, and Utah.
Analysis of individual projects4 and reported problems are not presented here. A review of 23 projects regarding injectivity is included in a U.S. Dept. of Energy annual report.5 A number of reviews have appeared in the literature.1-3,4,6 During the spring of even years, the Oil & Gas Journal usually publishes a survey of active IOR projects.
Industry's Initial Concerns.
There are two basic IOR techniques in gasflooding a reservoir-continuous gas injection and the WAG injection scheme. Industry initially had a number of concerns about CO2 injection, especially during the WAG process, in terms of controlling the higher-mobility gas: water blocking, corrosion, production concerns, oil recovery, and loss of injectivity. Careful planning and design along with good management practices have allayed most concerns, except for loss of injectivity.
Lower injection rates of CO2 slugs and water slugs have been a concern because CO2 field tests were conducted in the early 1970s.7 Currently, the problem is still a concern in the management of a WAG process.4 This concern is the primary focus of this paper.
There are two separate but related questions regarding this perplexing issue.
What causes the unexpectedly low injectivity during gas injection?
What is the reason for the apparent reduction in water injectivity during brine injection after gas injection?
Injectivity is a key variable for determining the viability of a CO2 project. Potential loss of injectivity and corresponding loss of reservoir pressure (and possibly loss of miscibility resulting in lower oil recovery) have potentially major impacts on the economics of a gas-injection process. Many of the projects evaluated by Hadlow3 showed higher CO2 (gas) injectivity than that obtained in prewaterflood water injection. However, substantial loss in water injectivity after CO2 or gas injection also has been seen. On the average, an approximately 20% loss of water injectivity can be expected in the WAG process3; attempts to mitigate this include decreasing the WAG ratio to decrease the mobility control, increasing the injection pressure, and adding additional injection wells.
Optimization of operations can improve the economics of existing CO28 and other enhanced oil recovery (EOR) projects significantly. Three major management parameters that effect the economics of a CO2 or gasflood are:8
The CO2 and water half-cycle slug sizes.
The gas/water ratio profile.
The ultimate injected CO2 slug size.
Overview of WAG Injection Process
WAG Process Description.
The WAG scheme is a combination of two traditional techniques of improved hydrocarbon recovery: waterflooding and gas injection.9 The first field application of WAG is attributed to the North Pembina field in Alberta, Canada, by Mobil in 1957,6 where no injectivity abnormalities were reported. Conventional gas or waterfloods usually leave at least 50% of the oil as residual.10 Laboratory models conducted early in the history of flooding showed that simultaneous water/gas injection had sweep efficiency as high as 90%, compared to 60%10 for gas alone. However, completion costs, complexity in operations, and gravity segregation from simultaneous water/gas injection indicated that it was an impractical method for minimizing mobility. Therefore, a CO2 slug followed by WAG has been adopted.
The planned WAG ratios of 0.5:4 in frequencies of 0.1 to 2% PV slugs of each fluid11 will cause water-saturation increases during the water cycles and decreasing water saturations during the gas half of the WAG cycle. The displacement mechanism caused by the WAG process occurs in a three-phase regime; the cyclic nature of the process creates a combination of imbibition and drainage.9 Optimum conditions of oil displacement by WAG processes are achieved if the gas and water have equal velocity in the reservoir. The optimum WAG design is different for each reservoir and needs to be determined for a specific reservoir and possibly fine-tuned for patterns within the reservoir.12
There are a number of different WAG schemes to optimize recovery. Unocal patented a process called Hybrid-WAG, in which a large fraction of the pore volume of CO2 to be injected is injected followed by the remaining fraction divided into 1:1 WAG ratios.11 Shell empirically evolved a similar process called DUWAG (Denver Unit WAG) by comparing continuous injection and WAG processes.
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