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Conformance is a measure of the uniformity of the flood front of the injected drive fluid during an oil recovery flooding operation and the uniformity vertically and areally of the flood front as it is being propagated through an oil reservoir. Conformance problems can be divided into six categories:
- Poor sweep efficiency and/or excessive co-production of the oil recovery drive fluid in a relatively homogeneous matrix-rock (unfractured) reservoir resulting from poor mobility control and/or oil recovery drive-fluid fingering
- Poor sweep efficiency and/or excessive co-production of the oil recovery drive fluid in a matrix-rock reservoir resulting from substantial permeability variation and heterogeneity
- Poor sweep efficiency and/or excessive co-production of the oil recovery drive fluid occurring in a naturally fractured reservoir
- Water or gas coning
- Excessive and competing water or gas production emanating from a casing leak
- Excessive and competing water or gas production emanating from flow behind pipe
The remediation, or partial remediation, of the first conformance problem is exemplified by a mobility-control polymer flood conducted in a reservoir containing a viscous oil and/or a reservoir that is characterized as being relatively homogeneous.
Successful conformance improvement treatment is dependent on correctly assessing the nature of the conformance issue. There are two key distinctions that must be made in order to identify the appropriate treatment:
Areal and vertical conformance problems
Vertical conformance problems, which are probably the most pervasive and most easily remedied conformance problems in matrix-rock (unfractured) reservoirs, are commonly manifested by geological strata of differing permeability overlying one another. In matrix-rock (unfractured) reservoirs, areal conformance problems, also referred to as “directional” high-permeability trends, can exist. Such conformance problems can be addressed through the application of a mobility-control flood such as a polymer waterflood. Areal conformance problems in matrix rock oil reservoirs are often more effectively remedied through well-pattern alignment strategies, which are not discussed here.
Whether geological strata of differing permeability are in fluid and pressure communication with each other is another consideration. Is there vertical permeability communication between the zones or are there impermeable layers (e.g., a shale layer) separating the geological strata? If these geological strata are not in vertical fluid communication throughout the reservoir or the well pattern to be treated, then this conformance problem can be remedied or alleviated simply by reducing the injectivity into the high-permeability strata at the injection well or by reducing the productivity from the high-permeability strata at the production well. This problem can often be treated cost effectively in the wellbore or the near-wellbore environment with:
- Mechanical packer systems
- Tubing patches
- Squeeze cementing
- Near-wellbore polymer-gel treatments
When such a treatment involves the placement of a chemical fluid-flow shutoff material (e.g., a gel or resin) in the offending strata surrounding a radial-flow well of a matrix-rock reservoir, then it is imperative that the treatment be placed selectively only in the offending geological strata and that none of the treatment shutoff material be placed in the oil producing strata. This type of treatment for improving vertical conformance is referred to by some as a profile modification treatment.
If vertical pressure communication and fluid crossflow exists between the geological strata, then the oil recovery sweep efficiency problem and/or the associated excessive drive-fluid production problem cannot be remedied effectively with a wellbore operation or by a near-wellbore blocking agent treatment. As Fig. 1 shows, when a conformance treatment blocking agent is placed near wellbore in the high-permeability geological strata at either the production or injection well, the conformance improvement gains are short lived in terms of improved sweep efficiency and/or reduced rate of the excessive oil-recovery drive fluid (e.g., water during waterflooding) production. If the blocking agent is placed selectively in the high-permeability strata near wellbore to the injection well, the subsequently injected oil-recovery drive fluid will be injected into, and flow through, the low-permeability strata for a relatively short distance until it flows beyond the radius of the blocking agent. At this point, the oil-recovery drive fluid will tend to rapidly crossflow into the high-permeability strata where the fluid flow resistance is less. Other than very early in the life of a flooding operation, the near-wellbore volume of the low-permeability strata is likely already swept of its mobile oil saturation. In this case, little, or often no, sweep improvement or incremental oil production is gained from the placement of the blocking agent in the near-wellbore volume of the high-permeability strata.
If the blocking agent is placed selectively in the high-permeability strata near wellbore to the production well when crossflow between the reservoir strata occurs, a relatively small, and often uneconomic, volume of incremental oil production and a short-lived reduction in the undesirable high rate of the oil-recovery drive fluid production are realized after the treatment. After placing the blocking agent near wellbore in the high-permeability strata, the oil recovery drive fluid will flow from the high-permeability strata to the low-permeability strata at a point just beyond the outer radius of the emplaced blocking agent.
Thus, when crossflow exists between the geological strata, when radial flow exists, and when the reservoir is undergoing an oil recovery flooding operation, the selective placement of a blocking agent at, or near, the wellbore in the high-permeability strata of a matrix-rock reservoir renders little or no significant sweep improvement or reduction in the deleterious co-production of the oil recovery drive fluid (e.g., water during waterflooding).
If a matrix-rock reservoir with crossflow between geological strata and with radial-flow production is to be treated successfully with a blocking-agent conformance treatment, it must be treated such that the blocking agent is placed selectively deep in the reservoir in the high permeability strata. The technical and economic feasibility of successfully applying water-shutoff treatments to this type of conformance problem has been questioned. On the other hand, there are some reports in the literature, as exemplified by Mack and Smith, that certain specialized polymer microgels have been applied through injection wells in the form of large volume conformance-improvement gel treatments that are intended to treat deeply into “matrix rock” reservoirs with crossflow between the reservoir geological strata.
A better strategy for rendering conformance improvement in layered reservoirs of matrix rock reservoirs where crossflow exists would be to use a mobility-control flood, such as a polymer flood. When flooding with a viscosity-enhancing mobility-control drive fluid, more of the injected drive fluid will be injected into, and flow through, the lower permeability and more poorly sweep geological reservoir strata. In this case, the strategy will result in accelerated oil production and reduced production of the oil-recovery drive fluid.
High permeability anomalies
The second key conformance-problem distinction is whether the high-permeability flow path of the conformance problem is simply a high-permeability flow path through unfractured matrix rock or is a high-permeability anomaly, such as a fracture. For this purpose, the cut off between a high-permeability flow path in matrix reservoir rock and a high permeability anomaly is the equivalent of about two Darcies in a sandstone reservoir. High-permeability anomalies within a reservoir can include:
- Fractures (both natural and hydraulically induced)
- Fracture networks
- Solution channels
- Interconnected vugular porosity
- Cobble layers
- Course sand strata
- Rubblized zones
- Localized matrix reservoir rock with permeabilities greater than two Darcies
Reservoir fractures tend to be the most often encountered high-permeability anomaly. At depths greater than about 4,000 ft, natural fractures tend to be vertical in orientation and promote areal conformance problems. At depths less than about 2,000 ft, fractures tend to be horizontal in orientation and can cause serious vertical conformance problems.
The distinction between conformance problems involving high-permeability flow paths through matrix reservoir rock and high-permeability anomalies is very important to the successful application of a number of technologies used to improve conformance. Differentiating between these two conformance-problem regimes is critical to the success of the most widely applied polymer-gel treatment technologies because different versions of these polymer-gel technologies are normally required to treat these two different problems successfully. A polymer flood, which is applied to conformance problems involving solely matrix-rock permeability variation within a given well pattern or reservoir, is more likely to be successful than the same polymer flood that is applied to a similar well pattern or reservoir in which the conformance problem is dominated by high-permeability anomalies such as a carbonate well pattern or reservoir with numerous and extensive large solution channels. Classical mobility-control foam flooding is an inefficient option for use in a reservoir with high-permeability anomalies, such as an extensive and highly conductive fracture network.
Because the true nature of vugular-porosity conformance problems has often not been fully appreciated by many petroleum engineers, there have been a number of polymer-gel conformance treatment failures when treating vugular-porosity conformance problems. As Fig. 2 depicts, the true and original definition of vugular porosity is relatively small voids (smaller than caverns) that exist randomly in matrix reservoir rock (especially carbonate reservoirs) where the vugular voids are not interconnected. If this is truly the vugular-porosity conformance problem that has been encountered in a given instance, then a matrix-rock conformance treatment is normally required. If, however, the conformance problem is dominated by large and extensive solution channels in the matrix reservoir rock (i.e., tubular flow pathways of often greater than 1/8-in. diameter), a high-permeability anomaly type of conformance treatment is required. The chances that a matrix-rock type of polymer-gel conformance treatment will be successful are remote when encountering reasonably large solutions channels. As is often the case when vugular-porosity conformance problems are encountered, the vugular porosity is actually vugs that are interconnected with solution channels. If this is the actual nature of the vugular-porosity conformance problem, a high-permeability anomaly polymer-gel treatment is required. Failure to make the proper distinction between these two types of vugular-porosity problems can spell doom for a polymer-gel conformance improvement treatment that is applied to such a vugular-porosity problem. When vugular-porosity conformance problems are encountered in those situations that the vugs are not interconnected, then a high-permeability anomaly polymer-gel treatment will not perform as expected and will not remedy this particular vugular-porosity conformance problem. Likewise, when vugular-porosity conformance problems are encountered in those situations that the vugs are interconnected, the application of a matrix rock polymer-gel conformance treatment will not be well suited for remedying such a vugular-porosity conformance problem.
How conformance problems are manifested
An alternate means of categorizing oilfield conformance problems is by the way conformance problems manifest themselves, such as by:
- Poor sweep efficiency during oil-recovery flooding operations
- Excessive and deleterious competing water co-production
- Excessive and deleterious competing gas co-production
- Coning and cusping
- Casing leaks
- Water or gas flow behind pipe
Two distinct types of water production exist. The first type, usually occurring later in the life of a waterflood, is water that is co-produced during oil/water fractional flow in reservoir matrix rock. When the production rate of this water is reduced, there will a proportional reduction in the oil production rate. The second type of water production directly competes with oil production. This water often flows to the production wellbore via a flow path separate from that of the oil (e.g., water coning or a fracture emanating directly from a water injection well to the production well). For the second type of water production problem, reducing water production can often lead to a greater pressure drawdown and/or an increase in the oil production rate. Thus, reducing the production of the second type of water production should be the objective of conformance improvement floods and of water-shutoff treatments with gels, foams, and resins.
A number of sources/causes of excessive and deleterious co-production of water or gas exist:
- Early water or gas breakthrough during flooding operations resulting from poor sweep efficiency caused by vertical permeability variation in matrix-rock reservoirs (i.e., geological stratification)
- Early water or gas breakthrough during flooding operations resulting from poor sweep efficiency caused by variation in areal permeability in matrix-rock reservoirs
- Early water or gas breakthrough caused by poor sweep efficiency that results from oil-recovery drive-fluid viscous fingering, where the viscous fingering is caused by an unfavorable mobility ratio between the oil-recovery displacement fluid and the reservoir oil
- Fracture communication between the injector and producer (either extending fully or partially between wells).
- Fracture networks (with and with out directional trends)
- 2D coning via fractures
- 3D coning via unfractured matrix reservoir rock
- Flow behind pipe
- Casing leaks
Coning and cusping can involve either water or gas. Cusping involves the production of aquifer water that flows to the production well through an inclined geological strata or zone, or gas-cap gas that flows to the production well through an inclined geological strata. In large part because of the relatively low viscosity and associated high mobility of gas, gas cusping tends to occur more easily than water cusping.
There are two distinctly different types and mechanisms of coning as it relates to conformance treatments such as water or gas shutoff coning treatments with gels:
- 2D coning occurs when water cones up, or gas cones down, to the production well’s producing interval through vertical fractures or a fracture network. Conformance treatment blocking agents, such as gels, can be used effectively and profitably to reduce such water or gas coning.
- 3D coning occurs when water cones up or gas cones down through matrix reservoir rock to the production well’s producing interval. The use of conformance treatment blocking agents, such as gels, has a very low probability of success when applied to a 3D coning problem.
When large flow conduits with apertures substantially greater than approximately 1/16 in. are the cause of flow behind pipe and the cause of the deleterious water or gas production, then the use of Portland cement is often favored for remedying such problems (not discussed further here).
Treatable conformance problems
Table 1 provides guidelines as to which conformance problems are attractive and unattractive to treat with polymer gels.
- Sydansk, R.D. and Southwell, G.P. 2000. More Than 12 Years of Experience with a Successful Conformance-Control Polymer Gel Technology. SPE Prod & Fac. 15 (4): 270. SPE-66558-PA. http://dx.doi.org/10.2118/66558-PA
- Sorbie, K.S. and Seright, R.S. 1992. Gel Placement in Heterogeneous Systems With Crossflow. Presented at the SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, Oklahoma, 22–24 April. SPE-24192-MS. http://dx.doi.org/10.2118/24192-MS
- Seright, R.S., Lane, R.H., and Sydansk, R.D. 2001. A Strategy for Attacking Excess Water Production. Presented at the SPE Permian Basin Oil and Gas Recovery Conference, Midland, Texas, 15-17 May 2001. SPE-70067-MS. http://dx.doi.org/10.2118/70067-MS
- Seright, R.S. 1988. Placement of Gels to Modify Injection Profiles. Presented at the SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, Oklahoma, 16–21 April. SPE-17332-MS. http://dx.doi.org/10.2118/17332-MS
- Mack, J.C. and Smith, J.E. 1994. In-Depth Colloidal Dispersion Gels Improve Oil Recovery Efficiency. Presented at the SPE/DOE Improved Oil Recovery Symposium, Tulsa, Oklahoma, 17–20 April. SPE-27780-MS. http://dx.doi.org/10.2118/27780-MS
- Martinez, S.J., Steanson, R.E., and Coulter, A.W. 1987. Formation Fracturing. In Petroleum Engineering Handbook, H.B. Bradley ed., Ch. 55, 55-2. Richardson, Texas: SPE.
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