PEH:Polymers, Gels, Foams, and Resins

Publication Information

Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume V – Reservoir Engineering and Petrophysics

Edward D. Holstein, Editor

Copyright 2007, Society of Petroleum Engineers

Chapter 13 – Polymers, Gels, Foams, and Resins

Robert D. Sydansk, Sydansk Consulting Services

Pgs. 1149-1260

ISBN 978-1-55563-120-8
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This chapter provides an overview of selected chemical systems and technologies that promote improved conformance during light oil-recovery operations. These conformance-improvement systems and technologies include fluid systems for use during oil-recovery flooding operations in which the fluids promote sweep improvement and mobility control (e.g., polymer waterflooding) and oilfield conformance-improvement treatment systems (e.g., "small-volume" gel treatments). A conformance-improvement fluid system for promoting flood sweep improvement and mobility control involves injecting a volume of an oil-recovery fluid that constitutes a significant fraction of the reservoir pore volume. The volume of an oil-recovery flooding system that is applied for sweep improvement is usually greater than 5% of the reservoir and/or well-pattern pore volume. Conformance-improvement treatment systems normally are of a relatively small volume and usually are used to treat the near-wellbore region or a relatively small fracture volume within the reservoir.

This chapter provides an overview of the following conformance-improvement systems: polymer waterflooding and treatments, gel treatments, foam flooding and treatments, and resin treatments. This chapter does not discuss improving conformance during oilfield drilling and stimulations operations for which the application of conformance-improvement technologies also can be quite advantageous.

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. If there were perfect conformance in a perfect regular five-spot well pattern during an oil-recovery flooding operation, the flood front would reach all four of the offset producers at the same time, and the flood front would reach the entire vertical interval of all four of the producing wells at the same time. Of course, there never has been a reservoir that has exhibited perfect conformance during an oil-recovery flooding operation. The issues that must be considered are how imperfect is the conformance for a given flooding operation in an oil field, and what is the economic or other beneficial rate of return if a conformance-improvement flood or treatment is implemented.

Improved conformance during an oil-recovery operation will result in incremental and/or accelerated oil production and/or will result in reduced oil-production operating costs. Properly designed and executed conformance-improvement flooding or treatments will improve the effectiveness, efficiency, and profitability of an oil-recovery operation, regardless of whether the oil-recovery operation is primary production, secondary waterflooding, or tertiary-mode flooding.

This chapter contains seven major sections. Sec. 13.2 discusses conformance improvement and the benefits imparted by the technologies and treatment systems reviewed in this chapter and imparted during light oil-recovery flooding operations. Sec. 13.3 provides an overview of the conformance problems that flooding technologies and treatment systems are intended to reduce or eliminate. Sec. 13.4 briefly discusses disproportionate permeability reduction. Secs. 13.5 through 13.8 review, respectively, polymer waterflooding and treatments, gel treatments, foam flooding and treatments, and resin treatments.

Conformance Improvement

Improving conformance, in its original and most limited definition, is synonymous with improving the drive-fluid sweep efficiency during an oil-recovery flooding operation. Improving the conformance and/or sweep efficiency for any given oil-recovery drive fluid during a reservoir flooding operation involves improving one, or both, of two components of flood sweep efficiency: vertical and areal sweep efficiency.

The volumetric sweep efficiency of a given oil-recovery drive fluid during a flooding operation within a reservoir or well pattern is defined as

....................(13.1)

where E_A is the areal sweep efficiency, and E_I is the vertical sweep efficiency. For Eq. 13.1 to be strictly correct, the geological layers or strata of the reservoir must be uniform in terms of porosity, thickness, and oil saturation.

Strictly speaking for a real reservoir, volumetric sweep efficiency is more precisely defined as

....................(13.2)

where E_P is the pattern sweep efficiency, which is the areal sweep efficiency for a reservoir with variations in thickness, porosity, and oil saturation. Areal sweep efficiency is defined as

....................(13.3)

where A_f is the area contacted by the oil-recovery displacement fluid, and A_t is the total reservoir area under consideration.

Vertical sweep efficiency is defined as

....................(13.4)

where A_V is the reservoir vertical cross section contacted by the oil-recovery displacement fluid, and A_tV is the total reservoir vertical cross section.

For any given oil-recovery drive/displacement fluid, poor sweep efficiency often results primarily from spatial variation and/or heterogeneity in the permeability (fluid flow capacity) of the reservoir rock. Poor vertical conformance and poor vertical sweep efficiency in matrix rock (unfractured) reservoirs usually result primarily from geological strata of differing permeability overlying one another in a reservoir. Conformance treatments to improve poor vertical sweep profiles and/or to shut off competing water or gas production, emanating from a subset of geological strata, are referred to as profile modification treatments. The Dykstra-Parsons coefficient is a widely used measure of the vertical permeability heterogeneity of an oil-producing reservoir and is discussed in Lake.

For any given oil reservoir, poor sweep efficiency that results from flooding with an oil-recovery drive fluid is aggravated as the viscosity of the drive fluid decreases. Within any reservoir with a given degree of permeability heterogeneity, as the viscosity of the drive/displacement fluid of an oil-recovery flooding operation decreases, the degree of viscous fingering and the associated poor sweep efficiency increases. The mathematical and engineering term that relates the viscosity of the oil-recovery drive fluid to conformance and sweep efficiency is "mobility ratio."

Mobility ratio is defined as

....................(13.5)

where λ_D is the mobility of the oil-recovery displacement fluid phase, and λ_d is the mobility of displaced fluid phase. In this chapter, the mobility of the displaced fluid phase is the mobility of the reservoir oil phase. Eq. 13.5 holds for a piston-like oil-recovery flooding operation in which the flood front is sharp. Mobility is defined as

....................(13.6)

where k_i is the permeability to phase i, and μ_i is the viscosity of phase i. Thus, as the viscosity of the oil-recovery displacement/drive fluid is increased in a reservoir with a given degree of permeability heterogeneity, the sweep efficiency and the degree of the oil-recovery flood conformance are improved. See Willhite for the definition of mobility ratio in the case in which a waterflood does not exhibit piston-like displacement.

When the sweep efficiency and the degree of conformance are improved during an oil-recovery flooding operation, the rate at which the reservoir oil is recovered is increased, and the amount of oil-recovery drive fluid, which must be coproduced for a given oil recovery factor, is decreased. Reducing the amount of oil-recovery drive fluid (e.g., water) that must be coproduced for the attainment of a given oil-recovery factor reduces the operating and production costs associated with producing a given amount of oil. It also often reduces certain environmental liabilities, including the production of excessive and unnecessary amounts of saline reservoir brines that can contain toxic heavy-metal ions and the production of excessive and unnecessary volumes of possibly environmentally unfriendly secondary or tertiary flooding oil-recovery drive fluids.

For the most part, conformance-improvement flooding operations and treatments do not decrease residual oil saturation. However, there has been a contention made in the literature that polymer flooding can reduce residual oil saturation under certain circumstances. This contention is discussed briefly later in this chapter. Also, by virtue of the fact that surfactants are incorporated into foams of foam-flooding operations, foam flooding can, in principle, reduce residual oil saturation. However, oilfield foams that are applied for mobility control are believed to function primarily by improving flood sweep efficiency. For the most part, conformance-improvement treatments accelerate oil production and/or delay premature economic abandonment of wells, well patterns, and fields, and can do so while conducting normal primary, secondary, or tertiary oil-production operations.

As previously noted, conformance-improvement floods and treatments do not normally promote reductions in residual oil saturation. Therefore, conformance-improvement operations should be limited to well patterns or reservoirs with a substantial and economically viable amount of moveable oil that can be recovered as a result of conducting the conformance flood or treatment.

As originally and purely defined, conformance-improvement flooding operations and treatments involve improving the uniformity of the flood front of an injected drive fluid during an oil-recovery flooding operation. In addition to the original definition, the working definition of conformance-improvement treatments now includes treatments applied to production wells to shut off excessive, deleterious, and competing coproduction of water or gas coming from a source other than the producing oil-formation interval. Examples of such coproduction are the coning of water from an underlying aquifer and the coning of gas from an overlying gas cap. Thus, using this expanded working definition of conformance-improvement treatments, conformance treatments can include water or gas shutoff treatments that are applied to production wells during primary oil-recovery operations. In this chapter, we use the modern and expanded definition of conformance improvement. Kabir presents a high-level overview of the use of polymers, gels, foams, and resins as water and gas shutoff treatments.

The vast majority of conformance-improvement treatments function by reducing the permeability and fluid-flow capacity of the offending and treated reservoir high-permeability flow paths, channels, and conduits. The only practical exception to this is acid stimulation treatments to improve the wellbore flow profiles in injection or production wells. Discussion of near-wellbore conformance-improvement treatments using acid stimulation is beyond the scope of this chapter. Although this chapter is focused primarily on conformance improvement for application to light oil reservoirs, many of the conformance-improvement technologies discussed can be applied during gas and heavy-oil recovery operations (i.e., gel and resin water-shutoff treatments).

In summary, conformance improvement facilitates improved sweep efficiency of an oil-recovery flooding operation and/or reduces the coproduction of water and gas, which impede the full production potential of any given production well. All the polymers, gels, foams, and resins discussed in this chapter are used for conformance improvement in oil or gas producing operations.

Conformance Problems

Conformance problems can be divided into six categories:

• Poor sweep efficiency and/or excessive coproduction 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 coproduction of the oil-recovery drive fluid in a matrix-rock reservoir resulting from substantial permeability variation and heterogeneity.
• Poor sweep efficiency and/or excessive coproduction 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.

Key Distinctions

The first of two key distinctions relating to conformance problems is to differentiate between vertical conformance problems and areal conformance problems. 5 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, which as a whole are usually less often treated by the technologies discussed in this chapter, are normally best addressed (by technologies of this chapter) 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 beyond the scope of this chapter.

Within the conformance-problem category involving vertical matrix-rock problems and involving reservoir geological strata of differing permeabilities, there exists another aspect of this critical conformance-problem distinction that needs to always be made when considering technologies for reducing vertical conformance problems. This distinction is whether the geological strata of differing permeability are in fluid and pressure communication with each other. That is, 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, sandpacks, squeeze cementing, near-wellbore polymer-gel treatments, or resins. 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 (as is discussed in more detail in Sec. 13.6) 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. 13.1 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.

• 

  Fig. 13.1 – Near-wellbore blocking agent placed in the high-permeability strata of a matrix rock reservoir exhibiting crossflow and suffering from a conformance problem.

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 coproduction 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. 6 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.

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 chapter, 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, faults, joints, solution channels, interconnected vugular porosity, caverns, cobble layers, course sand strata, rubblized zones, and 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, 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. As discussed in Sec. 13.6, 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. 13.2 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.

• 

  Fig. 13.2 – Vulgar porosity and solution channels.

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 coproduction, excessive and deleterious competing gas coproduction, coning and cusping, casing leaks, or 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 coproduced 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 coproduction 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.
• Cusping.
• 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. The use of Portland cement for these purposes is beyond the scope of this chapter.

Implementing Conformance Treatments and Diagnosing Conformance Problems

In general, a conformance-improvement treatment (e.g., a gel treatment) to improve sweep efficiency and to generate incremental oil production is applied most effectively from the injection well side. When implementing a conformance-improvement treatment to reduce production operating costs by reducing the rate of competing water or gas production, these treatments usually are applied most effectively from the production well side. Treatments for both improving sweep and reducing excessive water and/or gas coproduction during gas or supercritical-liquid (e.g., CO₂) flooding operations in naturally fractured reservoirs normally are applied most effectively from the injection well side.

The nature of the reservoir conformance problem to be addressed through the application of polymers, gels, foams, or resins needs to be diagnosed or deduced correctly or substantial negative consequences can occur. A detailed discussion of how to properly and effectively diagnose and/or deduce reservoir conformance problems and flood sweep-efficiency problems is beyond the scope of this chapter. Multiple sources enumerate a number of techniques for diagnosing conformance problems and excessive water- and gas-production problems. Among the techniques discussed in these references are the use of interwell chemical and radioactive tracers, simple injectivity/productivity calculations to determine if fluid flow around a wellbore is radial or linear in nature, wellbore production and injection logs, various other logging tools, and pulse and pressure transient testing. An important element in successfully implementing a water or gas shutoff treatment is to determine at the onset, or at least hypothesize, the "plumbing" of the reservoir flow path of the excess water or gas production from its source to the production wellbore. Production water/oil ratio (WOR) diagnostic plots have also been used to help diagnose conformance problems. WOR diagnostic plots should be used in conjunction with another independent conformance-problem diagnostic tool, because many diagnostic plots can be interpreted in more than one way.

There historically has been a trend whereby petroleum engineers, when first considering the application of a conformance-improvement treatment in a new field, tend to underestimate the permeability and fluid-flow capacity of the high-permeability channels and flow paths within the reservoir to be treated. This has contributed significantly to the low success rate of first-time conformance-improvement treatments being applied in a new field by an inexperienced petroleum engineer.

Disproportionate Permeability Reduction

Disproportionate permeability reduction (DPR) is a phenomenon whereby many water-soluble polymers and many polymer gels reduce the permeability to water flow to a greater extent than to oil or gas flow. Most of the early work on, and application of, DPR involved fluid flow in reservoir matrix rock. More recently, water-shutoff chromium(III)-carboxylate/acrylamide-polymer (CC/AP) gels for use within fractures have been reported to impart DPR in gel-filled fractures. However, because these relatively strong fracture-problem gels significantly reduce simultaneously the permeability to oil flow in fractures, these gels are better characterized as total-fluid-flow-shutoff gels and not DPR water-shutoff gels.

DPR is also referred to as relative permeability modification (RPM). However, some practitioners of this technology make the following subtle distinction. They tend to reserve the term DPR for relatively strong polymer gels that impart a large degree of disproportionate permeability reduction and a relatively large reduction in water permeability. These practitioners reserve the term RPM for systems, such as solutions of water-soluble polymers or relatively weak gels, that impart more subtle disproportionate permeability reduction and more subtle reductions in water permeability. As used in this chapter when referring to water-shutoff treatments, the terms DPR and RPM are synonymous.

Alternatively, DPR conformance-improvement treatments, which involve relatively strong gels, can be successfully applied in hydraulically or naturally fractured reservoirs. In this case, the gel is placed and functions within the matrix rock that is adjacent to the fractures.

DPR has the most value when used in water-shutoff/reduction treatments that are applied to production wells. DPR has little or no value for use during sweep-improvement treatments that are applied from the injection-well side.

A distinction needs to be made regarding classical and relatively strong (not DPR) polymer-gel water-shutoff (total-fluid-flow-shutoff) treatments that are placed within fractures that surround production wells. Such gel treatments tend to be placed, or place themselves, so that they will selectively reside in the water-producing fractures where the gels effectively block water flow. Such gel treatments (when properly designed and executed) tend to reduce water production without substantially reducing oil production. Here, the selective water shutoff results from selective placement of the gel in the water-producing fractures and not by the DPR mechanism.

The ability of acrylamide polymers to impart DPR to water flow in porous media was recognized as early as 1964 by Sandiford and in 1973 by White et al. The mechanism by which polymers and gels impart DPR and RPM effects has been the subject of a number of investigations. Several sources are representative of these investigations. More recently, a set of plausible mechanisms have been proposed that explain how CC/AP polymer gels impart DPR.

The application of DPR conformance-improvement technologies for water-shutoff (and/or water-reduction) purposes is not a panacea. The successful application of bullheaded DPR long-term water-shutoff/reduction treatments, which involve radial flow in matrix reservoir (unfractured) rock and where the drawdown pressure on the producing interval is not increased after the gel treatment, is limited to when the following conditions are met:

• A conformance problem exists in a matrix rock reservoir involving differing geological strata.
• No fluid crossflow can occur within the reservoir between the water and the oil or gas producing geological strata.
• The water strata is producing at an undesirably high water cut, and the oil or gas strata will produce for the economic life of the water-shutoff treatment at 100% oil or gas cut.

Possible exceptions to these limitations are as follows. First, if the DPR treatment induces an increase in the drawdown pressure on the producing interval, the DPR treatment may promote increased oil production. Second, if the DPR treatment material in the presence of oil flow breaks down, or is otherwise inactivated (with respect to its water-blocking ability), then selective water shutoff can occur over a wider range of excessive water-production problems.

For applications in radial-flow matrix-reservoir rock, commercially available DPR water-shutoff/reduction treatments usually attempt to reduce the permeability to oil or gas flow by a factor of two or less in the treated reservoir volume and reduce the permeability to water flow by a factor on the order of ten or more. Variability in performance of these systems has often led to erratic results when trying to accomplish this objective. To date, commercially available DPR water-shutoff/reduction treatments for application in radial-flow matrix-rock reservoirs have been based, almost exclusively, on the use of either solutions of water-soluble polymers or relatively "weak" gels.

For application to fractured wells, a DPR scheme for treating excess water production is discussed in the DPR subsection of Sec. 13.6.1. This scheme relies on placing a relatively strong DPR water-shutoff gel in the matrix rock that is adjacent to the fractures.

DPR water-shutoff treatments are of no practical value [in terms of providing long-term (i.e., years) water shutoff] when applied to a single zone reservoir that is producing at a high water cut in the radial flow mode from a matrix rock reservoir. This is because a relative-permeability water block will form just beyond the outermost radial penetration of the DPR water-shutoff treatment. What is less obvious is that for the same basic reason when producing from matrix rock reservoirs in the radial flow mode, DPR water-shutoff treatments are not effective at promoting long-term water shutoff/reduction anytime the oil-producing zones are producing at a finite water cut or crossflow exists between the oil- and water-producing zones.

Another issue with DPR water-shutoff treatments is that for such treatments, which are based on the use of solutions of water-soluble polymers or relatively "weak" gels, their water-shutoff performance is erratic and not highly reproducible in both the laboratory and field settings. For DPR water-shutoff treatments, the restoration (or near restoration) of the oil permeability following the placement of the treatment in matrix reservoir rock can be quite slow. An important point regarding DPR water-shutoff treatments is that DPR imparted in the treated volume of the matrix reservoir rock does not necessarily correspond in the field to a proportionate reduction in the water production rate.

An additional important distinction that needs to be made is to whether the DPR treatment is being applied for long-term (i.e., years) or short-term (i.e., hours to months) water-shutoff purposes. For the relative-permeability water-block reason discussed previously, many DPR water-shutoff treatments will render short-term or transient water-shutoff/reduction during treatments that are applied in the field. The water-block problem goes a long way in explaining why so many DPR water-shutoff treatments have failed to provide long-term water shutoff and have tended to render only short-term water shutoff. There are scenarios for limited reservoir conditions, where DPR treatments that render only transient water shutoff, can be engineered to be economically attractive and profitable.

The reason that bullheadable DPR water-shutoff treatments have created such a great interest in the oil industry is that they do not require the use of mechanical zone isolation when applied to layered matrix-rock reservoirs. Mechanical zone isolation often requires costly workover operations. Use of mechanical zone isolation during water-shutoff-treatment placement is not normally feasible when the well possesses a slotted-liner or gravel-pack completion or when the well involves a subsea tieback flow line.

Historically, a large number of ineffective DPR (RPM) water-shutoff treatments have been conducted. The high failure rate of DPR water-shutoff/reduction treatments has resulted from a combination of overexpectations by operators regarding DPR water-shutoff treatments, overselling of DPR water-shutoff treatments by oilfield service companies, and failure to recognize the constraints to the successful application of DPR water-shutoff treatments within matrix-rock (unfractured) reservoirs. However, DPR treatments remain one of the few options available to successfully treat excessive water-production problems in matrix rock reservoirs for which mechanical zone isolation is not possible or practical during treatment fluid placement. At the time of the writing of this chapter, the investigation, development, and exploitation of DPR conformance-improvement technologies were being actively pursued by petroleum industry R&D efforts.

Polymers

Early application of polymers for use during oilfield conformance-improvement operations was focused on improving volumetric sweep efficiency of waterfloods. More recently, polymers have been used extensively in DPR and RPM treatments for water shutoff and in conformance-improvement polymer-gel treatments. Most of this section focuses on the use of polymers in polymer waterflooding operations. Sec. 13.5.8 reviews the use of polymers in DPR and RPM treatments that are applied for "selective" water-shutoff/reduction.

Polymers Fundamentals

Polymers are large molecules and chemical entities referred to as macromolecules. Polymer molecules are the resultant chemical specie when a large number of relatively small and repeating molecular entities, called monomers, are joined together chemically. The chemical process of joining together the monomers and forming polymer molecules is referred to as the polymerization reaction process. Polymers, both natural and man made, have numerous beneficial uses and applications in modern society (everything from wood, to plastics, to man-made thickening agents added to milk shakes). Polymers can come in pure solid and liquid forms. Some polymers can be dissolved in liquids. This chapter is limited to polymers that can be dissolved (or dispersed) in an aqueous solution and that usually increase the viscosity of the aqueous solution.

Basic Oilfield Polymer Types. There are two fundamentally different types of water-soluble and viscosity-enhancing polymer chemistries that have been used during polymer waterflooding and conformance-improvement treatments. The first type is biopolymers, such as Xanthan gum polymer. The second type is man-made synthetic polymers, such as acrylamide-based polymers.

Biopolymers of the type used in conformance improvement are polysaccharides (poly sugars) in which the monomer chemical linkages of the polymer backbone are glycoside linkages, involving carbon-oxygen-carbon chemical bonds. In aqueous solution, the multistranded molecular complexes of xanthan polymer are fairly rigid molecular species, causing the polymer molecules to take on an extended molecular conformation.

Synthetic polymers of the type used in conformance improvement are usually highly flexible molecules in which the polymer backbone consists of a relatively chemically stable carbon molecular chain with single and flexible carbon-carbon bonds. Pendant water-soluble chemical groups (e.g., amide groups) on the molecule render the polymer molecule to be soluble in water.

Synthetic polymers have emerged to become the predominant and preferred polymer type for use in commercial oilfield conformance-improvement operations because of the inherent chemical and biological stability of synthetic polymers, along with injectivity and cost issues.

Historically, the two types of biopolymers primarily used in polymer waterflooding have been xanthan and scleroglucan polymers. The only synthetic polymers that have been used extensively during polymer waterflooding (and in polymer-gel conformance treatments) are those based on acrylamide-polymer chemistry.

Viscosity Enhancement and Permeability Reduction. Water-soluble polymers used in conformance-improvement operations operate by reducing fluid mobility by increasing viscosity of the oil-recovery drive fluid (primarily the flood water) and/or by reducing permeability, by which the polymers, directly or indirectly, act as a fluid-flow blocking agent. Reducing permeability is the conformance-improvement mechanism by which conformance treatments operate when polymers and polymer gels are used for imparting DPR. Polymers used in waterfloods often have a secondary component in their conformance-improvement mechanism that involves permeability reduction within the flooded volume of a matrix rock reservoir.

Chemistry of Polymers Used in Conformance Improvement. The chemistry of polymers used in conformance improvement is reviewed before discussing polymer waterflooding and DPR polymer treatments because several of the polymer chemistries that are reviewed are used in both of these oilfield conformance-improvement applications. In fact, some of the polymer chemistries discussed in this section are also used in conformance-improvement polymer gels (see Sec. 13.6).

Biopolymers. In addition to being environmentally friendly and readily available, advantages of biopolymers are their relative insensitivity to salinity and mechanical shear degradation. The two major concerns relating to the use of biopolymers are their susceptibility to biological and chemical degradation, and injectability issues resulting from cell debris that usually remain in the biopolymer solutions that are derived from microorganism fermentation processes.

Xanthan has been the most widely used biopolymer for polymer waterflooding. Fig. 13.3 shows the chemical structure of the xanthan biopolymer molecule. For a xanthan molecule with a molecular weight of 4 million daltons (atomic mass units), the xanthan molecule comprises on the order of 20,000 repeating sugar monomer units. Xanthan polymer is derived from a microorganism fermentation process that usually leaves a substantial amount of cell debris in the final polymer solution.

• 

  Fig. 13.3 – Chemical structure of a xanthan polymer molecule.

Flooding reservoir matrix rock with fully filtered xanthan polymer solutions tends to result in much less permeability reduction than the comparable flooding with appropriate acrylamide-polymer solutions. Xanthan polymers and the resultant solution viscosity are relatively insensitive to the salinity of the brine into which the Xanthan polymers are dissolved, and Xanthan polymers tend to be relatively insensitive to mechanical shear degradation. Xanthan polymers are quite susceptible to biological degradation.

Scleroglucan, with a triple-stranded molecular configuration, has been suggested to be a biopolymer possessing more favorable stability and performance properties for use during high-temperature polymer waterflooding (e.g., 195°F).

Synthetic Polymers. Acrylamide polymers have emerged to be the most widely used synthetic polymer family for application in polymer flooding and in polymer and polymer-gel conformance-improvement treatments. This has come about in large part because of cost and availability issues and because of the favorable chemical robustness and biological stability.

Polyacrylamide (PAM) is the simplest and most basic form of acrylamide polymers. Fig. 13.4 shows the chemical structure of polyacrylamide and partially hydrolyzed polyacrylamide. For polyacrylamide with a molecular weight of 7 million daltons (a representative molecular weight of an acrylamide polymer to be used in polymer waterflooding), the value of n in Fig. 13.4 and the number of repeating monomer units is on the order of 100,000. When all other factors are equal and when dissolved in brine with a relatively low salinity, polyacrylamide is not as good a viscosity-enhancing agent and is not propagated as well through sand reservoirs when compared to partially hydrolyzed polyacrylamide (HPAM). Because pure polyacrylamide is slightly positively charged (cationic) in an acidic or "neutral" pH environment, polyacrylamide tends to adsorb onto reservoir rock surfaces, especially sands and sandstone pore surfaces. For these reasons, partially HPAM is most often favored for use in polymer flooding.

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  Fig. 13.4 – Chemical structure of PAM and HPAM polymer molecules.

When polyacrylamide is manufactured commercially, it normally contains 1 to 2 mole percent hydrolyzed (carboxylate) content that is inadvertently imparted during the manufacturing process. This carboxylate "impurity" in many of the commercial polyacrylamide polymers is enough carboxylate content to render such polyacrylamide to be a good candidate for use in conformance-improvement polymer gels that involve chemical crosslinking reactions occurring through the polymer’s carboxylate groups. A specialized polyacrylamide polymer is available commercially that contains essentially no carboxylate groups (less than 1 carboxylate groups in 1,000 acrylamide groups). Such polyacrylamide is referred to as ultra-low hydrolysis polyacrylamide. To manufacture ultra-low-hydrolysis polyacrylamide, normal acrylamide monomer feed stock is polymerized as usual, except the polymerization conditions (pH and temperature) are more tightly controlled. Polyacrylamide is normally not referred to as HPAM until the carboxylate content exceeds approximately 2 mole percent.

HPAM is the most widely employed water-soluble polymer for use in both polymer waterflooding and in oilfield conformance polymer-gel treatments. As mentioned previously and as compared with polyacrylamide, HPAM polymer tends to be a better viscosity-enhancing agent in low-salinity brines and tends to adsorb less onto the rock surfaces of reservoirs that are good polymer-waterflooding candidates. Thus, the use of the salt form of HPAM is favored over the use of straight polyacrylamide in most polymer-flooding applications. A number of practitioners of polymer flooding believe that because of the salt sensitivity of HPAM, this polymer performs best during polymer flooding conducted in reservoirs with low-salinity reservoir brines. However, there have been some instances in which HPAM, when dissolved in a fresh flooding brine, has performed well when flooded in a reservoir with a saline brine. Sohn, Maitin, and Votz cites such an example.

A 30% hydrolysis level within polyacrylamide is near the optimum in terms of simultaneously promoting maximum viscosity enhancement of the polymer solution and minimizing polymer adsorption onto reservoir rock surfaces during most polymer waterfloods. For crosslinked polymer gels, the optimum hydrolysis level of 5 to 10 mole percent (in this case) simultaneously maximizes gel strength and minimizes unproductive intramolecular crosslinking.

As Fig. 13.4 shows, HPAM can come in two forms as it relates to the chemistry of the carboxylate groups. The carboxylate groups can be in the acid or salt form. For use in polymer waterflooding and in polymer gels, HPAM is almost always used in the sodium salt form. Unless specifically stated otherwise in this chapter, when referring to HPAM, we are referring to HPAM with its carboxylate groups in the sodium salt form.

In low salinity brines, the electrostatic charge repulsion between carboxylate groups of HPAM molecule tends to cause the flexible-backbone polymer to assume a distended tertiary conformational form that is a more effective for enhancing aqueous-solution viscosity than is the more balled-up form occurring for such polymers dissolved in a high salinity brine and the balled-up molecular conformational form of unhydrolyzed polyacrylamide. Fig. 13.5 depicts the stretched out and more effective viscosity-enhancing molecular form of HPAM that exists in a low-salinity aqueous environment. Fig. 13.5 also shows the balled-up conformational form that HPAM assumes in a high salinity brine environment. High salinity causes the electrostatic fields around the carboxylate groups to shrink substantially and allows the HPAM molecule to assume a more balled-up form because of the elimination of a high degree of electrostatic repulsion between the negatively charged carboxylate groups on the polymer’s backbone. The balled-up polymer form does not generate nearly as much viscosity as the distended form in otherwise comparable polymer-waterflood solutions.

• 

  Fig. 13.5 – Schematic of the effect of solution ionic strength on the molecular conformation of flexible coil. polyelectrolye molecules such as HPAM.

Hydrolyzed acrylamide groups, or equivalently termed carboxylate groups, can be introduced into polyacrylamide polymers by several means. First, polyacrylamide that is dissolved in aqueous solution can be reacted with caustic material, such as sodium hydroxide, to convert a portion of the polymer’s pendant amide groups to carboxylate groups. This form of HPAM is referred to as partially hydrolyzed polyacrylamide. Second, during the polymerization process, acrylamide monomers can be copolymerized with acrylate monomers to form HPAM. This form of HPAM is referred to as being a copolymer of acrylamide and acrylate. All polyacrylamides and all commercially available HPAMs, when heated in aqueous solution, slowly undergo an autohydrolysis reaction in which a portion of the acrylamide polymer’s pendant amide groups spontaneously hydrolyzes to carboxylate groups. The final degree of carboxylate content that is attainable within a polyacrylamide molecule increases with temperature, but does not reach 100 mole% carboxylate groups. That is, the acrylamide polymer cannot be converted in aqueous solution at high temperature (under reservoir conditions) to pure polyacrylate by means of the autohydrolysis reaction. The autohydrolysis reaction of acrylamide polymers is both acid and base catalyzed.

In high-temperature reservoirs after polyacrylamides or HPAMs autohydrolyze to sufficiently high levels, hardness ions, such as calcium or magnesium, in the reservoir brine cause the polymer to undergo a phase change, precipitate, and cause the polymer to lose most of its viscosity-enhancing function. This outcome is the major limitation of acrylamide-polymer flooding in high temperature reservoirs. Fig. 13.6 shows the degree of polymer hydrolysis vs. time at various selected temperatures for 1,000 ppm PAM polymer dissolved in a brine of 5% salinity.

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  Fig. 13.6 – Degree of hydrolysis vs. time at various temperatures for 1,000 ppm unhydrolyzed PAM in 5% salinity.

Copolymers containing 2-acrylamido-2-methyl-propanesulfonic acid (AMPS) monomers and acrylamide monomers have been suggested to form acrylamide polymers for use in polymer waterflooding of high-temperature (e.g., 200°F) and high-salinity reservoirs where the AMPS copolymer’s performance and stability will be somewhat better than comparable HPAM.

Copolymers of vinylpyrrolidone and acrylamide, along with ter-polymers of vinylpyrrolidone, acrylamide, and acrylate, have been reported to be candidate polymers for use in polymer floods and conformance polymer-gel treatments that are to be applied to high-temperature reservoirs with harsh environments. Certain vinylpyrrolidone polymers were reported to not precipitate from seawater after aging for six years at 250°F. Potential concerns regarding these co- and ter-polymers of vinylpyrrolidone are their relatively high cost as compared with more conventional acrylamide polymers and the relatively low molecular weight of the commercially available forms of these co and ter polymers.

Fig. 13.7 shows the general chemical structure of ter-polymers of vinylpyrrolidone, acrylamide, and acrylate. The primary beneficial function of the incorporated vinylpyrrolidone monomer into an acrylamide polymer is that it prevents the acrylamide monomer content of the polymer from autohydrolyzing at high temperatures to the excessively high levels of hydrolysis whereby the polymer would become susceptible to precipitating out of solution when the polymer encounters hardness divalent ions.

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  Fig. 13.7 – Chemical structure of a ter-polymer poly (vinylpyrrolidone-acrylamide-acrylate) molecule.

Cationic polyacrylamides are acrylamide polymers that have positively charged chemical groups attached to at least some of the polymer’s pendant amide groups or acrylamide polymers that have been copolymerized with monomers containing positively charged pendant groups. These polymers have an exceptionally strong tendency to adsorb onto reservoir rock surfaces, especially sand and sandstone surfaces.

Cationic acrylamide polymers find specialized applications in conjunction with a variety of conformance-improvement treatments. These applications include use as polymer-anchoring agents to help promote conformance polymer-gel adsorption onto reservoir rock surfaces, "bridging-adsorption" and/or "flow-induced-adsorption" polymers for injection before a conformance gel treatment to purportedly promote the selective placement of the gel treatment during the bullheaded treatment-placement mode, and polymer for use in certain polymer DPR conformance treatments. Water-soluble cationic acrylamide polymers come in a wide variety of forms and chemistries. Fig. 13.8 shows the chemical structure of two cationic acrylamide polymers that have been studied for use in the bridging-adsorption phenomenon.

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  Fig. 13.8 – Chemical structure of two cationic acrylamide polymers for possible use in the bridging-adsorption selective placement process for conformance gel treatments.

Benefits of Applying Conformance-Improvement Polymer Technologies

The application of oilfield polymer technologies, in the form of polymer waterflooding and polymer DPR treatments (and as polymer-gel treatments), can promote conformance improvement during oil-recovery-flooding and oil-production operations. They do so by the following means.

• Improve sweep efficiency—The application of polymer waterflooding and polymer DPR treatments promote more effective economic use of injected oil-recovery drive fluids, such as water during waterflooding. DPR treatments can also be used to reduce the amount of injected oil-recovery drive fluid that must be coproduced to yield a given oil-recovery factor.
• Accelerate production—Successful polymer waterflooding and polymer DPR treatments accelerate oil production during a waterflood or other oil-recovery flooding operations by reducing the amount of injected oil-recovery drive fluid that must be coproduced to attain a given level of oil recovery.
• Promotes incremental oil production—Polymer waterflooding and DPR treatments rarely reduce waterflood residual oil saturations. However, they do promote incremental oil recovery by increasing the amount of oil production before reaching the economic WOR limit of a production well, well pattern, or field during a waterflood or other oil-recovery flooding operation.
• Extend economic lives—Polymer waterflooding and DPR treatments can extend the economic lives of production wells, well patterns, and fields by increasing oil cuts as a function time and deferring the time when the economic WOR limit of a well, well pattern, or field is reached.

Polymer Waterflooding

When conducting a polymer waterflood, a high-molecular-weight and viscosity-enhancing polymer is added to the water of the waterflood to decrease the mobility of the flood water and, as a consequence, improve the sweep efficiency of the waterflood. The primary purpose of adding polymer to most polymer waterfloods is to increase the viscosity of the flood water; however, polymer addition to the flood water in many instances also imparts a secondary permeability-reduction component. Polymer waterflooding is normally applied when the waterflood mobility ratio is high or the heterogeneity of the reservoir is high. Fig. 13.9 shows the polymer waterflooding process.

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  Fig. 13.9 – Schematic of the polymer waterflooding process. The method shown requires a preflush to condition the reservoir, the injection of a polymer solution for mobility control to minimize channeling, and a driving fluid (water) to move the polymer solution and resulting oil bank to production wells. Mobility ratio is improved and flow through more permeable channels is reduced, resulting in increased volumetric sweep.

How Polymer Flooding Improves Recovery. Polymer waterflooding promotes improved sweep efficiency by improving the mobility ratio. Improved sweep efficiency imparted during polymer flooding is primarily accomplished by increasing the viscosity of the waterflood drive fluid. Conventional wisdom states that polymer waterflooding does not reduce irreducible oil saturation (residual oil saturation to waterflooding); however, at least one paper has called this contention into question when flooding with selected acrylamide polymers.

Polymer Solutions. The principal beneficial property of polymer solutions for use in flooding oil reservoirs is the aqueous solution’s enhanced viscosity. Aqueous polymer solutions that are used for conformance-improvement flooding normally exhibit non-Newtonian viscosity properties.

Viscosity of Polymer Solutions. The viscosity of a polymer solution is a measure of how "thick" a fluid is. For example, molasses is characterized as being "thicker" and more viscous than water. The viscosity of a fluid or solution may, in general terms, be defined as the solution’s resistance to being sheared or as the resistance of a fluid mass to change its form.

Fluid viscosity, μ, is defined as

....................(13.7)

where τ is shear stress and γ. is shear rate.

Many common fluids, such as water and motor oils, exhibit Newtonian viscosity. For fluids with Newtonian viscosities, the fluid’s viscosity is independent of the shear rate that the fluid is experiencing. That is, the value of the viscosity of a Newtonian fluid at a given temperature is a single value that is independent of shear rate.

The viscosity-enhancing power of a polymer is related to the size and extension of the polymer molecule in a particular aqueous solution. For a number of reasons, the viscosity of a polymer solution that is measured in a viscometer and the effective viscosity of the polymer solution that is measured during flow through porous reservoir matrix rock often have different values.

To predict the viscosity-enhancing power of a polymer in a given solution, the polymer’s intrinsic viscosity, [η], can be measured by

....................(13.8)

where c is polymer concentration, η is polymer solution viscosity, and η_s is solvent viscosity. Intrinsic viscosity is obtained by determining the value Lim_c→0(η-η_s)/cη_s) that is obtained from the plot of (η-η_s)/cη_s) vs. polymer concentration and extrapolating the plotted data back to zero polymer concentration. See Chap. 3 of Sorbie for more details regarding intrinsic viscosity of polymer solutions. For a given polymer in an aqueous solution, the intrinsic viscosity for the polymer increases with polymer molecular weight (MW) according to the Mark-Houwink equation:

....................(13.9)

where K′ and a are polymer-specific constants, and M_P is the polymer molecular weight. See Chap. 3 of Sorbie for more details regarding the Mark-Houwink equation.

The empirical Flory equation can be used to estimate the mean end-to-end distance of a polymer in solution. The Flory equation is

....................(13.10)

where d_p is in Angstroms (10⁻¹⁰ m), and [η] is in dl/g.

MW and Size. When all other factors are equal (such as polymer type and the brine solution into which the polymer is dissolved), as the MW of the polymer increases, the size of the polymer increases. As the size of the polymer increases, so does the polymer’s viscosity enhancing ability when dissolved in a given brine. On the negative side, as the MW of a polymer increases, the propensity for the polymer to be retained during transport through matrix reservoir rock is increased, and the propensity for the polymer to exhibit injectivity problems is increased.

Because polymers used in polymer waterflooding are polydispersed in MW, polymer MW distribution is an important factor relating to how a given polymer will function during a polymer flood. Unfortunately, good MW distribution data are not readily and widely available for the polymers that are normally used in polymer flooding, because the determination of a polymer’s MW distribution is relatively expensive and time consuming.

Fig. 13.10 shows the MW distribution for a typical HPAM polymer sample used in polymer flooding. The high MW tail of the MW distribution is quite significant. The small number of polymer molecules in the polymer’s MW distribution have a disproportionately large effect on the viscosity-enhancing power of the polymer; are the polymer molecules that are first and most easily degraded by mechanical shear under intermediate- to high-shear flow conditions; are the polymer molecules that will be first and most easily retained during polymer transport through reservoir matrix rock; and are the polymer molecules that are most prone to causing injectivity damage.

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  Fig. 13.10 – Molecular weight distribution of a typical HPAM polymer used in polymer flooding.

Fig. 13.11 shows a series of MW distributions for a family of HPAM polymer samples. MAR-1 through MAR-9 denote sample numbers 1 through 9. When applied in a relatively high-permeability reservoir in which polymer retention during polymer transport and polymer injectivity are not major issues, polymers with higher molecular weights and narrower MW weight distributions perform relatively more effectively as viscosity-enhancing agents during a polymer waterflood.

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  Fig. 13.11 – Molecular weight distribution of a series of HPAM polymer samples.

For a polymer that is dissolved in a given solvent, polymer MW is proportional to molecular size. For several illustrative polymers used in polymer waterflooding, their molecular size, as related to MW, is as follows. A 30% HPAM polymer of approximately 4×10⁶ dalton (atomic mass units) MW dissolved in a good solvent is expected to be fibril in form and to have a diameter of 0.7 to 2.5 μm and a backbone chain length greater than 10 μm. The hydrodynamic length of a xanthan molecule commonly used in polymer flooding has been reported to be approximately 1.5 μm. The MW of such a xanthan molecule is approximately 4×10⁶ daltons.

Rheology. The non-Newtonian viscosity of polymer solutions used in polymer waterflooding normally exhibit shear-thinning behavior when subjected to sufficiently high shear rates (but not at low shear rates). The viscosity of a Newtonian fluid does not vary with the shear rate to which the fluid is subjected. For a shear-thinning fluid, the apparent viscosity of the fluid decreases as the fluid experiences increasing shear rates.

Figs. 13.12 and 13.13 show the shear-thinning viscosity behavior of two polymers of the type used in polymer flooding. In Fig. 13.12, at low shear rates (< 0.1 s⁻¹), the viscosity behavior of the polymer solutions at all polymer concentrations is invariant with shear rate and, thus, is Newtonian. At shear rates exceeding 1.0 s⁻¹, the viscosity of the polymer solutions decreases with increasing shear rate, thereby exhibiting shear-thinning viscosity behavior. The shear-thinning viscosity behavior of the polymer in Fig. 13.12 becomes relatively less pronounced as the concentration of the polymer in solution decreases. This trend is observed for all polymers that are used in polymer flooding. The shear-thinning viscosity reduction behavior results from the water-soluble high-MW polymers becoming uncoiled and unentangled when they are aligned and elongated in the fluid-flow shear field under sufficiently high shear-rate (~1 to 100 s⁻¹) conditions. When the polymers are aligned and unentangled by the shear field in this shear-rate range, the polymers become less effective viscosity enhancing agents. At the low shear rates of Fig. 13.12 (< 0.1 s⁻¹), the shear field is not strong enough to appreciably uncoil and untangle the polymer molecules. The viscosity is invariant over this shear-rate range, and the viscosity behavior is characterized as being Newtonian over this shear-rate range.

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  Fig. 13.12 – Polymer solution viscosity vs. shear rate as a function of xanthan polymer concentration.

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  Fig. 13.13 – Polymer solution viscosity vs. salinity as a function of AMPS polymer concentration.

As expected, the apparent viscosity at any given shear rate increases as polymer concentration increases. For the studied AMPS polymer, Fig. 13.13 shows the dramatic and undesirable effect that increasing the salt concentration in the makeup water has on reducing the viscosity of the polymer solution at any given shear rate. Similar detrimental effects of increasing salt concentration are observed in polymer solutions of high-MW HPAM. Note also the trend, which is quite generalized, that as the salt concentration of the polymer solution increases, the degree of shear thinning of the polymer solution decreases.

The shear-thinning viscosity behavior of these polymer solutions is favorable because the shear rate experienced by the polymer in the vast majority of the reservoir is usually quite low (approximately 1 to 5 s⁻¹) and is a shear rate at which the polymer exhibits near maximum viscosity. In the near-wellbore region, share rates are often in the shear-thinning range for the polymer (e.g., 1 to 100 s⁻¹). This polymer shear thinning is fortuitous because the viscosity reduction improves the injectivity of the polymer solution.

The mathematical equation that describes the viscosity vs. shear-rate behavior (of the type of Figs. 13.12 and 13.13) for oilfield polymer solutions over the shear-rate range of approximately 1 to 100 s⁻¹ is the power-law model that takes the form of

....................(13.11)

where K and n are, respectively, the power-law coefficient and exponent, and γ. is shear rate. For polymer-flood fluids that are shear thinning, the value of the power-law coefficient, n, ranges between 0 and 1 and equals 1 for these fluids when they are Newtonian. The viscosity behavior of a polymer solution becomes more shear thinning as the value of the power-law exponent, n, decreases. The numerical value of the viscosity and the power-law constant, K, become equal when the value of the shear rate, γ, equals 1.

As it relates to polymer solutions of polymer flooding, the power-law viscosity model is only applicable over a limited range of shear rates. For a description of other analytical mathematical expressions for describing polymer-solution viscosity vs. shear rate, especially expressions covering a wider range of shear rates, and for discussions on the viscoelastic properties and the extensional and elongational flow properties of high-MW polymer solutions, see Chap. 3 in Sorbie. Extensional viscosity, which occurs under very high shear-rate conditions, can lead to pronounced increases in the apparent viscosity of polymer solutions and often leads to mechanical shear degradation of high-MW water-soluble polymers. The only location in a reservoir that a polymer solution is likely to experience extensional-viscosity conditions of any consequence is near wellbore to an injection or production well.

"Apparent viscosity" or "effective viscosity" refers to the viscosity of a polymer solution for which the viscosity is determined during flow of the polymer solution through porous media. This is discussed further later in this section.

Measuring Viscosity. When measuring the viscosity of polymer solutions to be used in polymer waterflooding, the use of standard laboratory steady-shear viscometers is often quite satisfactory. In addition to the use of conventional viscometers, the screen factor (SF) device has been used extensively to measure viscosity properties of polymer solutions that are used in polymer flooding. Fig 13.14 shows the SF device. The SF "viscometer" consists of a small fluid reservoir in the glass unit that is in fluid communication above several wire-mesh screens, often three to five 100-mesh stainless-steel screens. A fluid sample of fixed volume is placed in the fluid reservoir, and the time is recorded for the fixed volume of fluid to flow through the screens under the influence of gravity. The SF value for a given polymer is the time it takes the fixed volume of polymer solution to flow through the screen viscometer divided by the time it takes the fixed volume of the solvent brine to flow through the screen viscometer. The SF value of a polymer solution is quite sensitive to the nature of the high-MW tail of the polymer’s MW distribution. Some practitioners suggest that the SF value better correlates with mobility and permeability reduction exhibited by the polymer solution as it is propagated through matrix reservoir rock. However, this contention is not universally agreed on. The SF measurement is a simple, straightforward, and useful qualitative viscosity characterization of polymer solutions for use in polymer flooding.

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  Fig. 13.14 – Screen factor device.

Effects of Salt, Hardness, and pH. The effects of salt and hardness on polymer-flood biopolymers are of relatively small consequence at lower temperatures (< 170°F), as compared with the effects on HPAMs polymers that are used in polymer flooding at the same reservoir temperature. Salt insensitivity is one of the attractive features of polymer-flood biopolymers such as xanthan. Likewise, pH within the range likely to be encountered in low-temperature (< 140°F) oil reservoirs is of relatively small consequence to the viscosity and mobility-control properties of xanthan polymer.

The effect of salt and hardness on the viscosity and mobility-control function of polymer-flood HPAM, and similar and related synthetic polymers, is quite significant and can be very deleterious. Cations of dissolved salts reduce the electrostatic repulsion of the negatively charged hydrolyzed carboxylate pendant groups on the polymer backbone of HPAM. Cations do this by screening and collapsing the local negatively charged double layer formed around the carboxylate species. The degree of collapse of the negatively charged electrostatic fields surrounding the polymer’s carboxylate groups increases with increasing salt concentrations; and at constant salt concentration, with increasing charge of the cations of the salt. As the electrostatic fields surrounding the polymer’s carboxylate groups collapse, the electrostatic repulsive forces that promote polymer backbone-chain distension decrease. As Fig. 13.13 shows, this leads to substantial reduction in polymer-solution viscosity. As a rule of thumb, the polymer-solution viscosity decreases by a factor of 10 for every factor of 10 increase in NaCl concentration. The negative impact of divalent hardness ions, such as Ca⁺⁺ and Mg⁺⁺, are much more deleterious at the same concentration than monovalent ions, such as Na⁺ and K⁺.

As the concentration hardness cations, such as Ca⁺⁺, in the brine of a HPAM solution increases, the polymer becomes relatively more sensitive to mechanical shear degradation. The effect of pH on the viscosity of ionic HPAM can be significant. Decreasing the solution pH tends to convert the ionic salt form of the polymer’s carboxylate groups to the relatively nonionic carboxylic acid form of carboxylate groups. This diminishes the electrostatic repulsion of the ionic carboxylate groups along the polymer’s backbone and leads to less distention of the polymer molecule and to less viscosity-enhancing power for the polymer in a low pH solution. For a studied hydrolyzed-polyacrylamide polymer solution, its viscosity decreased by a factor of approximately four when the pH of the polymer solution was decreased from 9.8 to 4.

Flow in Porous Media. Polymer solutions used in waterfloods must be able to be transported successfully and effectively through the reservoir. Thus, the manner in which polymer solution flows through porous rock and the associated polymer interaction with the pore walls of matrix reservoir rock are important aspects regarding the attainment of the technical and economic success of a polymer flood.

Polymer Transport. Polymer retention during flow through reservoir matrix rock is discussed in an upcoming subsection. Polymer retention by adsorption and entrapment retards the rate of polymer propagation.

Inaccessible and Excluded Pore Volume. Accelerating the rate of polymer propagation, as compared with the rate of an inert chemical tracer dissolved in the injected polymer solution, is the inaccessible pore volume (IPV) phenomenon. Two explanations for, and contributions to, the IPV phenomenon have been reported. The first IPV explanation is that the large size of the polymer molecules prevents entry into smaller and dead-end pores. This promotes propagation of the polymer molecules faster than an inert chemical tracer because the polymer flows only through the larger-pore flow paths.

The second IPV explanation is the wall-exclusion effect. It is hypothesized that polymer molecules flow and concentrate in the center of the pore-level flow channels of matrix reservoir rock because the polymer molecule flow and the free tumbling of the polymer molecules are excluded from the near-surface volume of the pore walls. Such flow behavior accelerates the rate of polymer propagation through the porous media relative to the rate of propagation of an inert chemical tracer.

Mobility Reduction. When polymer in solution flows through reservoir matrix rock, it imposes a mobility reduction that is the primary conformance-improvement benefit of polymer waterflooding. The mobility reduction can be imparted by one of two distinctly different mechanisms. First, the polymer can cause an increase in the viscosity of the brine being flooded through the porous media. This is normally the desired effect when flooding with polymer solutions for mobility control. The second mechanism reduces the permeability of the reservoir matrix rock. One measure of mobility reduction imparted by polymer-solution flow is the resistance factor, R_f, which is defined as

....................(13.12)

where λ_w is the mobility of the solvent of the polymer solution, and λ_p is the mobility of the polymer solution. When the polymer solution imparts no permeability reduction and for measurements made at ambient temperature,

....................(13.13)

where μ_eff is the effective viscosity of the polymer solution as it flows through the reservoir matrix rock. Alternatively, for a single-phase polymer solution flowing through matrix reservoir rock at a given temperature and there is no imparted permeability reduction,

....................(13.14)

where μ_w is the viscosity of the brine in which the polymer is dissolved.

Permeability Reduction. Polymer flow through reservoir matrix rock can cause permeability reduction. A measure of the polymer-induced permeability reduction is the residual resistance factor, R_rf:

....................(13.15)

where k_b is brine permeability measured before polymer flooding, and k_a is brine permeability measured after polymer flooding.

Permeability reduction induced by polymers tends to be greater in lower permeability reservoir rock. This is, in general, counterproductive. Polymers, especially HPAMs, that undergo even a small amount of mechanical shear degradation often lose much of their permeability reduction propensity because the relatively small number of exceptionally large molecules of a given polymer MW distribution (especially for many HPAMs) are the first polymer molecules to be shear degraded. These large molecules contribute disproportionately to permeability reduction.

Extensional Flow. As mentioned in the discussion on rheology, when flexible, coiled, high-MW polymers, such as HPAM, are forced to flow through matrix reservoir rock at exceptionally high rates and experience exceptionally high-flow shear fields, the polymer can enter extensional and elongational flow at which point the polymer solution’s apparent viscosity can rise rapidly. In this flow regime, the polymer is also often mechanically shear degraded. Solutions of well-designed polymer floods are likely to experience extensional flow of noticeable consequence only in certain instances in the very near-wellbore region adjacent to the injection or production well.

Polymer Retention. Polymer retention will often profoundly affect the technical and economic success of a polymer-flooding project. The amount of oil that will be recovered per pound of polymer injected is inversely related to polymer retention.

Retention for a given polymer during a polymer flood increases as the permeability decreases, increases as the polymer molecular weight increases, increases as the clay content in the reservoir rock increases, usually decreases as oil wetness increases, tends to increase in sand and sandstone reservoirs with decreasing anionic charge and increasing cationic charge of the polymer’s pendant groups, and has been reported to increase at times in the presence of crude oil.

Polymer retention should be determined carefully, or at least estimated carefully, before initiating a polymer waterflood. Polymer retention for a given polymer flood is normally best estimated by conducting flooding experiments in reservoir rock with reservoir fluids at reservoir temperature.

"Field-measured values of retention range from 7 to 150 μg of polymer per cm³ of bulk volume, with a desirable retention level being less than approximately 20 μg/cm³." Laboratory measurements of polymer retention in reservoir rock are usually reported as mass of polymer adsorbed per unit mass of rock, Γ, and is usually reported as μg/g of polymer adsorbed onto reservoir rock. Frequently, it is preferred to have polymer retention reported in terms of mass of polymer adsorbed per unit volume of reservoir rock, Γ v , or, more specifically, in terms of pounds of polymer adsorbed per acre-foot of reservoir, lbm/acre-ft. To convert from Γ to Γ_v,

....................(13.16)

where ϕ is porosity, ρ_RG is the density of the reservoir rock grains (no pore space included), Γ_v is in units of lbm/acre-ft, and Γ is in units of μg/g. Polymer retention, as measured during field projects, has been reported to range from 20 to 400 lbm polymer/acre-ft bulk volume, with desirable retention reported to be less than 50 lbm/acre-ft.

Adsorption. Polymer adsorption results primarily from physical adsorption and not chemisorption. Polymer adsorption is often the major cause of polymer retention.

Mechanical Entrapment. Mechanical entrapment of polymer during propagation through reservoir porous media results from the larger polymer molecules becoming lodged in narrow flow channels (e.g., pore throats). Gogarty found that the HPAM polymers, under the conditions of his flooding experiment studies, had an effective size between 0.4 and 2 μm. There are several significant consequences of mechanical entrapment: permeability reduction, loss of the entrapped polymer’s favorable viscosity enhancing functionality beyond the point of entrapment, loss of the largest of the polymer molecules first has a disproportionately large negative impact during the remainder of the polymer flood on viscosity and mobility-control properties, and loss of a disproportionately large portion of its viscosity and mobility control functionality relatively soon after the polymer solution is injected into a reservoir.

Hydrodynamic Retention. Hydrodynamic retention is the least understood and least well defined retention mechanism. Polymer retention can increase as the flow rate of the polymer solution through reservoir matrix rock increases. Hydrodynamic retention is thought to normally be a relatively small contributor to the total polymer retention during a polymer flood. This retention mechanism is more significant in lower permeability reservoir rock. Hydrodynamic retention is thought to result from polymer molecules becoming temporarily trapped in stagnant flow regimes by hydrodynamic drag forces.

Precipitation. Polymer precipitation from solution, especially in the presence of high reservoir brine salinity, is another source of polymer retention. Precipitation is especially problematic when flooding with HPAM in high-temperature reservoirs with formation waters containing hardness divalent cations.

Polymer Degradation. A decrease in the average molecular weight of the polymer can be caused by chemical, biological, mechanical, or thermal degradation. Polymer stability, the inverse of degradation, should be evaluated and quantified under reservoir conditions in terms of a time span relevant to the lifetime of the polymer flood in question.

Chemical. Chemical free-radical species will degrade both biopolymers and synthetic polymers of polymer flooding. Free radicals cause chemical backbone scission of the polymer. Examples of free-radical sources that can be problematic for flooding and conformance-treatment polymers are free oxygen (O₂), hydrogen peroxide, sodium hypochlorite of bleach, and gel breakers such as ammonium peroxide. The combination of free oxygen and ferric ions is particularly problematic in causing oxygen free-radical degradation of polymer-flood polymers, especially of acrylamide polymers. Another source of polymer-degrading free radicals is free-radical or free-radical-precursor impurities within the polymer that are induced, in this case, during the manufacturing process. Polymer-degradation problems, caused by low levels of free radicals, are most problematic when conducting high-temperature (> 150°F) polymer-flooding experiments, especially during the high-temperature laboratory evaluation of polymers for high-temperature flooding. A countervailing phenomenon relating to free-radical chemical degradation is that oil reservoirs tend to quite rapidly neutralize and consume chemical free-radical species.

Two procedures are recommended for removing free oxygen from polymer-solution samples to be used during laboratory evaluation of polymer solutions for high-temperature applications. The first procedure uses a glass ampoule, which is glass-blown sealed after oxygen removal, and high-quality vacuum to reduce oxygen content to < 10 ppb. The second procedure consists of bubbling high-purity argon gas through the polymer solution. The need to deoxygenate polymer-solution samples in the laboratory during high-temperature testing is an aboveground laboratory artifact because polymer solutions that exist in most reservoirs are in an anaerobic and chemically reducing environment.

Hydrolysis reactions are important degradation reactions for both biopolymers and synthetic polymers; however, the hydrolysis reaction degrades the polymers in a much different manner for each of these two polymer types. Both acid- and base-catalyzed hydrolysis of the carbon-oxygen-carbon bonds of the backbone monomer chemical linkages of polysaccharide biopolymers cause polymer backbone scission and serious polymer MW degradation. The pH sensitivity of a biopolymer being used in a polymer flood needs to be considered. Serious polymer hydrolysis questions are raised if an acid-stimulation treatment contacts a previously placed conformance-improvement biopolymer gel treatment.

Hydrolysis (autohydrolysis) reactions of the amide pendant groups of the acrylamide polymers are of significant concern when such polymer is being flooded through a high-temperature reservoir that contains a significant concentration of hardness divalent ions in the formation water. If an acrylamide polymer, which is dissolved in a hardness-containing brine, autohydrolyzes to excessively high levels at high temperatures, the acrylamide polymer will undergo a phase change to an undissolved solid state that causes the polymer to precipitate. When this happens, the polymer loses its viscosity-enhancing properties. Technically, this type of acrylamide-polymer autohydrolysis is not polymer degradation, but simply leads to a phase change of the polymer from being dissolved in solution to being an undissolved solid specie.

Biological. Biological degradation is a serious potential problem for biopolymers, especially for use in shallow reservoirs and for the biopolymer as it resides in surface tanks and tubulars. For a properly designed acrylamide-polymer flood that uses solid polymer as the polymer source, potential biological degradation is essentially not an issue.

Mechanical. The form of mechanical degradation that is of most concern for polymers of polymer waterflooding is shear degradation. All dissolved polymers mechanically degrade if subjected to a sufficiently high-flow shear rate. During polymer flooding, deleteriously high- flow shear rates can exist in surface-injection equipment (valves, orifices, pumps, and tubing), at downhole constrictions (tubing orifices, perforations, or screens), and at the formation face of the injection well.

Xanthan biopolymer is usually not mechanically shear degraded under polymer-flood injection conditions. Under most radial-flow injection conditions, high-MW acrylamide polymers are quite susceptible to mechanical shear degradation. This is especially true if the flooding brine is high in hardness and salinity. When a water-soluble polymer encounters a sufficiently high-velocity flow field, both shear and elongational stress destroy the polymer solution’s viscosity. Maeker and Seright correlated permanent viscosity loss of a polymer solution to the product of the elongational stretch rate multiplied by the stretch length. The higher the MW of a given polymer, the more sensitive it is to mechanical shear degradation.

Thermal. All waterflooding polymers have an upper temperature limit above which they are no longer chemically stable, both with and without the addition of an appropriate thermal stabilizer package. This upper temperature limit varies with water chemistries of the polymer-dissolution and reservoir brines, polymer chemistry, manufacturer, and polymer lots from a given manufacturer. For the most part, the upper limit of thermal stability is fixed for a waterflood polymer obtained from a given manufacturer. It must be determined if the polymer to be used is thermally stable under reservoir conditions at the reservoir temperature of the polymer flood and that it will be sufficiently stable for the life of the polymer flood.

Stabilizers. Although once popular, the addition of chemical, biological, and thermal stabilizers to polymer-waterflooding solutions has lost a lot of its original attractiveness because of toxicity, environmental concern, effectiveness, and cost issues. A stabilizer that historically has been used widely as both a biological and thermal stabilizer for polymer-flood polymers is formaldehyde. Formaldehyde is now considered highly toxic and is highly regulated. Also, a number of the stabilizers used to protect against free-radical degradation can become, in themselves, polymer-degrading free radicals at high temperatures. In addition, early practitioners of chemical stabilizers did not fully appreciate chemical loss and chromatographic separations issues. If a chemical stabilizer is to be considered, it is prudent to proceed cautiously.

Polymer Injectivity. Polymer-solution injectivity is an important consideration for several reasons. First, the rate at which the polymer solution can be injected directly impacts the economics of a polymer-flood project. Second, routine injection-well cleanup jobs may be required if polymer or polymer-microgel damages injectivity. These cleanup jobs can detract from the polymer flood’s economics and effectiveness. Injectivity decreases as polymer MW increases. Polymer-solution injectivity is more favorable when the polymer solution exhibits shear-thinning viscosity behavior.

When and Where Applicable

The following screening guidelines can be used to determine where polymer waterflooding is most applicable, in terms of reservoir properties.

• Oil viscosity < 150 cp (preferably < 100 and > 10 cp) and API gravity > 15.
• Matrix-rock permeability > 10 md, with no maximum.
• Reservoir temperature: low temperatures are best (best at < 176°F; maximum of approximately 210°F).
• Water injectivity should be good with some spare capacity (hydraulic fracturing of injection wells may help).
• Reservoir clay content should be low.
• Low salinity of the injection and reservoir brines are preferable.

Polymer waterflooding has been conducted successfully in sandstone and carbonate matrix-rock reservoirs, fractured reservoirs, and in water-wet, mixed-wetting, and oil-wet reservoirs. For example, see DeHekker, et al..

Field Implementation

The following subsections focus on the field implementation of a polymer waterflood.

Flood Design. Working up a flood design is one of the first steps when implementing a polymer-waterflooding project.

Selecting a Polymner. When selecting a polymer for a polymer-waterflooding project, one should try to maximize, as best as possible, all the following polymer attributes. The polymer should

• maximize the amount of viscosity enhancement and/or mobility reduction per unit cost.
• readily dissolve.
• propagate well and have low retention as transported through the reservoir.
• exhibit good shear stability.
• possess good chemical stability.
• have good biological stability.
• be thermally stable at reservoir temperature.
• possess acceptable injectivity properties.

Polymer Concentration. The optimum concentration of the polymer to be injected is a critical parameter in the design of an effective polymer-waterflooding project. The concentration of the injected polymer profoundly affects the cost, economics, and performance of a polymer-flooding project. The optimum concentration is a function of reservoir properties, the nature of the reservoir’s conformance problems, and the business objective of the polymer flood. Business objectives of a polymer flood can include maximizing oil recovery, maximizing the rate of return on the cost of the polymer-flooding project, and minimizing the cost of the polymer flood.

DeBons and Braun provides a literature review of 12 international polymer-flooding projects conducted between 1975 and 1992. The projects included both pilot and fieldwide projects. Ten of the polymer-flooding projects involved the use of acrylamide polymers, and two projects involved the use of xanthan polymers. All the flooding projects were conducted in reservoirs with temperatures less than 140°F. For the 12 international polymer-flooding projects, the median incremental oil recovery, as calculated from data in the paper, was 13% original oil in place (OOIP), and the range of incremental oil recoveries was reported to be 6 to 52% OOIP. The average pore volume (PV) of the polymer slug injected was calculated to be 51%, with the range of PVs being 21 to 100%.

These flooding parameter values are noteworthy when viewed in terms of comparable values reported in the paper, or calculated from data presented in the paper, for 128 polymer floods performed in the U.S. between 1980 and 1993. The median incremental oil production for the U.S. polymer floods was 4.9% OOIP. The average concentration of polymer injected in the U.S. projects was 460 ppm vs. 920 ppm for the international polymer floods. Debons and Braun states that it appears the amount of incremental oil production for the 12 international projects best correlates with the numerical value that is obtained from multiplying the PV of the polymer slug injected by the average concentration of the polymer injected during the polymer-flooding project.

On the basis of the 12 international polymer-flooding projects, 900-ppm polymer concentration in the polymer slug would be a good starting value in designing a polymer-waterflooding project. Working from this initial concentration, it should be determined, using appropriate engineering and evaluation tools, whether the optimum polymer concentration for the proposed polymer flood is actually higher or lower.

Sizing Volume Injected. At this writing, optimum sizing of the polymer-solution slug to be injected was one of the most controversial aspects of designing a polymer-waterflooding project. This design parameter profoundly affects the cost, economics, and performance of a polymer-flooding project. Underdesigning the size of the polymer slug injected has been thought to be a major cause for the disappointing performance of many polymer floods conducted in the U.S. Using the general arguments made in previous subsections, the optimum size of the polymer-solution slug during polymer flooding is a function of reservoir properties, nature of the reservoirs conformance problems, and the business objective of the polymer flood. Business objectives of a polymer flood can include maximizing oil recovery, maximizing the rate of return on the cost of the polymer-flooding project, or minimizing the cost of the polymer flood.

On the basis of 12 international polymer-flooding projects, a 50% PV slug of polymer solution would be a good starting value to use in designing a polymer-waterflooding project. 69 Working from this initial polymer-solution slug size, it should be determined, using appropriate engineering and evaluation tools, whether the optimum polymer-solution slug size for the proposed polymer flood is actually higher or lower. When attempting to design the optimum size of the polymer-solution slug, two important parameters that need to be accounted for are polymer retention and the rate and nature of the viscous fingering of the polymer-slug chase drive water into the polymer-solution slug.

Grading of Polymer Concentration. To overcome, or substantially reduce, the problem of viscous fingering of the polymer-slug chase drive water into the polymer slug, most polymer floods are designed with a tapered, decreasing-polymer-concentration chase slug beginning at or near the end of the design volume of the primary polymer-solution slug.

Timing. There is general agreement that, when all other factors are held constant, the earlier in the life of a waterflood that a polymer flood is initiate, the relatively more effective the polymer flood will be. Two factors offset the benefits of an early start. First, it is more difficult to definitively assess the oil-recovery potential and economic effectiveness of a polymer flood until definitive waterflood performance has been established. Second, reservoir description and associated reservoir conformance problems are often less well defined, especially in a new reservoir.

Suggested Steps for Designing a Polymer Flood. Lake and Sorbie suggest that the design and planning procedure for a polymer waterflood should entail the following elements.

• Screen the candidate reservoirs for both the technical and economic feasibility of performing a successful polymer waterflooding project.
• If appropriate and needed, improve the reservoir description.
• Select the polymer that should be used in the flooding project.
• When and where cost-effective, conduct laboratory studies under reservoir conditions to perform screening and compatibility tests on the polymer and polymer-solution core-flooding tests to determine polymer-solution flow properties and to estimate incremental oil recovery (on the scale of the core size used).
• Estimate the amount of polymer that will be required for the polymer flood.
• Design the polymer-injection facilities.
• When and where cost-effective, conduct a polymer-injectivity test and a field polymer-flood pilot test.
• If feasible and cost-effective, conduct reservoir simulation studies.
• Optimize the reservoir, operational, and economic performance of the polymer waterflooding project, such as optimizing well and pattern spacing, completion strategies, and injection rates.

One of the primary causes of failure for polymer-flood projects is that the reservoir description used was inaccurate.

Polymer Injection. The polymer-injection facilities and the actual injection of the polymer solution are important aspects of a successful polymer-waterflooding operation.

Polymer Degradation. If the polymer is allowed to become mechanically shear degraded during surface mixing and pumping operations or during injection into the reservoir, the polymer will have lost a substantial amount, if not most, of its viscosity-enhancing and mobility-reducing power before leaving the injection-well near-wellbore region. The higher the rate that a polymer solution is injected across a unit area of injection surface, the greater the propensity for mechanical shear degradation of the polymer. It is most often the goal to inject the polymer solution as rapidly as possible without exceeding reservoir parting pressure. The strategy usually implemented is to use injection equipment and well completions that permit desired injection rates without substantial mechanical degradation.

To minimize mechanical shear degradation, the operator needs to use specialized pumping equipment, be sure that the polymer solution is not passed through any valves or orifices that cause high and damaging shear fields, and use special mixing and dilution equipment, such as the use of static mixers, to not shear degrade the polymer during mixing and dilution operations.

Well Completion. Injection wells of polymer floods are often openhole or gravel-packed completions. Hydraulically fracturing the injection well with short, wide fractures has been reported to have been used successfully to aid in injecting HPAM without excessive shear degradation. The injection of polymer solutions through mandril completions, with associated flow of the polymer solution through mandril orifices, has proved to be detrimental in several instances.

Polymer Dissolution. Historically, the polymer, as supplied to (or near) the final wellsite, must be dissolved and/or diluted to some degree. The polymer dissolution or dilution process needs to be implemented so that the polymer is fully dissolved, at the proper concentration before injection into the reservoir, and dissolved or diluted in a manner that does not mechanically shear degrade the polymer. The dissolution or dilution process can range from a fairly simple process for broths of xanthan polymer to a quite difficult and technically challenging process for ultra-high-MW solid HPAM. A long dissolution time is an economic determent for a polymer flood, because it requires extra equipment and extra polymer-solution holding tanks.

Polymer Filtration. The polymer solution normally should be filtered before injection to ensure that it is readily injectable and does not unduly damage injectivity. This is a particularly critical and challenging issue when injecting biopolymer solutions, such as xanthan solutions, that are notorious for containing substantial amounts of cell debris from the polymer’s fermentation process and cell debris that are difficult to remove fully with filters.

HPAM polymer, when obtained in the solid form and then dissolved in the field, should normally be filtered to remove microgels or undissolved "fisheyes." The amount of microgel and fisheye material in a given hydrolyzed acrylamide polymer varies from manufacturer to manufacturer and even with manufacturing lots from the same polymer manufacturer. These microgels and fisheyes of partially hydrated solid HPAM in solution often largely result from the final drying process in the manufacturing of the polymer, in which overheating, overdrying, and other factors cause some of the polymer molecules to crosslink together chemically during the drying process.

Parting Pressure. Downhole injection pressure should normally be kept below formation fracturing and parting pressures. If injection-well fracturing is required to obtain adequate polymer solution injectivity or to eliminate mechanical shear degradation, the injection wells are normally appropriately hydraulically fractured during a separate hydraulic fracturing operation.

Pilot Testing. It is recommended that a pilot test of a polymer-waterflooding design be implemented in one or several injection wells before a polymer-waterflooding project is implemented field wide and/or before implementing an expensive polymer-flood project. The primary objective of a pilot test is to assure that there will be adequate injectivity and that there will be no substantial injectivity issues. The polymer-solution injectivity trial can be as short as several days. Proper interpretation of a single-well polymer injectivity test can be difficult. If time and economics permit, a secondary objective of the pilot test is to demonstrate that the polymer flood will perform in the reservoir as expected in terms of mobilizing and recovering incremental oil. If it proves to be cost-effective, observation wells can be drilled near the injection well to observe, in a relatively short time frame, how the polymer flood can be expected to perform in the reservoir.

Issues Regarding Manufacturing of Polymers. Polymers used in polymer waterflooding can be manufactured and provided to the end user in one of four forms. First, polymers in solid particle form, the oldest form, are readily transported and stored. Polymers supplied in solid particles are a challenge to dissolve properly and fully. In addition, the polymer of solid particle polymers can be damaged in the drying process during polymer manufacturing, may contain undesirable chemicals that coat the polymer particles, and often contain undissolvable microgels that are not injectable into matrix reservoir rock and that damage the injectivity of the polymer-solution injection wells. The second form, concentrated (~10%) broths of aqueous polymer (especially biopolymers), is more easily dissolved in the field, but is more costly per pound of polymer to transport to the field. The third form is either aqueous emulsions that contain up to 35% or more active polymer or hydrocarbon-fluid suspensions/dispersions that contain ~50% active polymer. The challenge in using polymers supplied in this form is to routinely and consistently fully invert the emulsion/suspension in the field to permit the polymer to be dissolved fully in the flood water and to be fully effective during the polymer waterflood. Fourth, where economic and project scale permit, field-manufactured polymer, especially field-manufactured partially hydrolyzed polyacrylamide, can be an attractive option for providing polymer of high quality and exceptional performance characteristics.

Quality Control. Quality control is an essential element for the successful implementation of a polymer-waterflooding project. A quality control program should include, but not be limited to, the following elements:

• Routine verification of the polymer concentration in the polymer as supplied and in the polymer solution injected.
• Routine determination of the viscosity and SFs of the injected polymer solution.
• Check of the filterability of the polymer solution to be injected.
• Check of the dissolution-rate properties of the polymer as supplied.
• Check of the polymer to be injected for complete dissolution.
• Periodical check of the thermal and chemical stability of the polymer by measuring the viscosity and SF of wellhead polymer samples that have been aged for appropriate periods of time at reservoir temperature under scrupulous anaerobic conditions in sealed glass ampoules. (See the recommended polymer-solution-sample deoxygenation procedure discussed previously in Sec. 13.5.3.)

Illustrative Field Results and Trends

This section provides a brief review of illustrative field applications of polymer waterflooding, along with a very brief discussion of trends in the field application of polymer waterflooding in the U.S.

Comprehensive Manning Survey. In 1983, Manning et al. published a comprehensive and classic summary of the field results and performance of more than 250 polymer waterflooding projects and provided information relating to the early field applications of polymer waterflooding.

North Burbank Unit Flood. Fig. 13.15 shows the incremental oil production response for the North Burbank polymer flood.

• 

  Fig. 13.15 – Tertiary polymer flood response at the North Burbank unit, Osage County, Oklahoma.

Wyoming Polymer Floods. A polymer-waterflooding project that involved a large full-field flooding project at the North Oregon Basin field in Wyoming’s mature Big Horn Basin oil-producing area was reported in 1986 to be producing 2,550 BOPD of incremental oil production. It was reported that this polymer-flooding project would recover ultimately more than 10 million bbl of incremental reserves from the mature North Oregon Basin field. The field project involved the flooding of both a fractured carbonate formation and a fractured sandstone formation with a polymer flood using partially hydrolyzed polyacrylamide. The polymer used in this flooding project was field manufactured at the North Oregon Basin field in a plant with a capacity of 23 million pounds of polymer per year. This is an example of a successful polymer-flooding project using HPAM and conducted in naturally fractured sandstone and carbonate reservoirs where both the polymer dissolution brine and the reservoir brine were relatively saline and relatively hard (relatively high concentrations of divalent cations and anions).

Chinese Polymer Floods. The Chinese have reported on a number of polymer-flooding projects. During a pilot test of polymer flooding with HPAM in the 167°F Shuanghe reservoir of the Henan oil field in China, the incremental oil production was expected to approach 9.8% OOIP, and the polymer flood was expected to recover 0.7 bbl of oil per pound of polymer injected.

It has been reported that polymer waterflooding, using HPAM, in the Daqing field in China has recovered cumulatively more than 300 million bbl of oil. This polymer waterflooding project was reported to be producing 70 million bbl/yr of oil in 2001. The cost of the oil from the polymer waterflooding project was stated to be U.S. $6.60/bbl. The field was reported to be producing at a rate 310% greater than that expected for waterflooding alone. Incremental oil production attributed to the Daqing polymer waterflood is projected to be in the range of 12% to 15% of the OOIP.

French Polymer Flood. In 1995, an update was reported on the French Courtenay polymer flood that was conducted in the secondary recovery mode in a shallow sand reservoir with a 40 cp viscosity oil and 86°F reservoir temperature. Waterflooding was not conducted in this reservoir because of the combination of thin, high-permeability sand channels and an unfavorable mobility ratio. Oil recovery for the polymer flood was 6.6% PV. The total cost of oil production from this polymer flood project was U.S. $12/bbl.

Canadian Rapdan Polymer Flood. A 13-producer and 5-injector pilot of polymer waterflooding was conducted in 1986 in the 130°F and 110 md average permeability Upper Shaunavan formation of the Rapdan Unit in Saskatchewan, Canada. The polymer-flood pilot consisted of injecting 17% PV of 1,100 to 1,500 ppm polyacrylamide polymer solution. Polymer flooding was started after waterflooding. As a result of polymer flooding, oil production was reported to have increased from 410 BOPD at 18% oil cut to peak production of 1,100 BOPD at 36% oil cut.

Review of Worldwide Polymer Floods. As Sec. 13.5.5 describes, a literature review was conducted on twelve international polymer floods, both pilots and fieldwide projects, that were conducted between 1975 and 1992. All floods were conducted in reservoirs with a reservoir temperature of less than 140°F. In ten of the floods, partially hydrolyzed polyacrylamide was used as the polymer, and, in two of the floods, xanthan was used as the polymer. The international polymer floods recovered between 6 and 52% of the OOIP, compared with the medium recovery of 4.9% OOIP for 128 U.S. polymer floods. The general conclusion of DeBons and Braun was that there tended to be a correlation between the polymer-flood incremental oil production and the total amount of polymer used in the polymer floods, as defined by PV of polymer injected multiplied by the average concentration of polymer injected.

Survey of U.S. Polymer-Flood Project Production. Moritis reported the total U.S. enhanced oil recovery (EOR) oil production from polymer-waterflooding projects in 1998 was only 139 BOPD. This production figure was down from 21,000 BOPD in 1988 for U.S. EOR oil production resulting from polymer-waterflooding projects. In the same survey in 2000, EOR production for polymer and chemical flooding were combined so that the EOR production figure for polymer flooding alone was not discernable. The reported combined U.S. oil production in 2000 resulting from chemical and polymer flooding was 1,600 BOPD.

In 2002, EOR production from polymer flooding was reported to have fallen to zero, and it was reported that the number of polymer-flooding projects in the U.S. had fallen from 178 in 1986 to 4 in 2002. In the 2002 survey, 20 polymer-flooding projects that were being conducted outside the U.S. and Canada were listed. There is, at this writing, a trend in the U.S. toward less EOR polymer-flood oil production.

Additional Reading

Polymer waterflooding is thoroughly documented in Sorbie and nicely reviewed in Chap. 8 of Lake. Also, see Chap. 5 of Green and Willhite.

Polymers for Imparting DPR and RPM

In Sec. 13.4, a review was presented of the concepts, applicability, limitations, and desirability of the DPR phenomenon as it applies to conformance-improvement water-shutoff (and/or water-reduction) treatments.

As early as 1964, certain polymer-flood water-soluble polymers were known to impart DPR to water flow in reservoir rock that had been previously flooded with the polymer. Although, in concept, water-soluble permeability-reducing polymers can be injected (using appropriate polymers and conditions) into matrix rock to reduce the absolute permeability to all fluids (including water, oil, and gas), the injection of water-soluble permeability-reducing polymers into matrix rock is most often performed to impart DPR.

Advantages and Issues. Bullhead injection of a simple aqueous solution containing a water-soluble polymer to treat conformance problems, such as excessive water production, in matrix rock (unfractured) reservoirs is a highly appealing concept. Most DPR polymers (also known as RPM polymers) are not usually highly exotic or costly. Thus, polymer-alone DPR treatments for reducing excessive water production are much simpler and less risky, in concept, than conducting the same task using a relatively strong total-shutoff gel, particularly a "strong" crosslinked polymer gel. A polymer solution alone poses less risk of totally sealing off the treated reservoir volume compared with injecting a water-shutoff gel. The chemical and operational aspects of injecting a polymer solution for water-shutoff/reduction purposes are substantially less complicated than injecting a comparable polymer gel.

However, polymer DPR water-shutoff and/or water-reduction treatments do have a number of significant limitations, in addition to those already discussed in Sec. 13.4. First, how fast will the treatment polymer be desorbed and flow back to the production well? Second, DPR polymer treatments for conformance improvement are normally successful only when applied to matrix rock oil reservoirs with a relatively low permeability (usually less than 1 Darcy). In addition, many existing DPR polymer conformance-improvement treatments are only applicable to sand and sandstone reservoirs. DPR polymer conformance-improvement treatments are not directly applicable within fractures and other high-permeability anomalies. Third, the amount of DPR, which is imparted by polymer systems available at this writing, is often quite small as compared with the amount of DPR that can be imparted by DPR polymer gels. Mennella provides guidelines for well-candidate and chemical selection for use when considering the application of polymer DPR water-shutoff/reduction treatments. Fourth, the performance of polymer DPR treatments has been erratic in both the laboratory and field setting.

Mechanism for Imparting DPR. Although the mechanism by which polymers impart DPR to water flow in reservoir porous media is currently under active study, the basic mechanism is thought to involve polymer adsorption onto the pore body walls and/or retention at the pore throats. In most cases, DPR polymers tend to decrease the relative permeability to water with little effect on the oil or gas relative permeability curve.

Fig. 13.16, taken from Zaitoun and Kohler, depicts the DPR and RPM effect on relative permeability curves imparted in a 4.8 Darcy sand pack that was flooded at 140°F with a 10 g/L solution of biopolymer Polysaccharide G in 10 g/L KCl brine. The figure shows, as a result of flooding the sand pack with the biopolymer solution, how the relative permeability curve to water was substantially reduced while the relative permeability curve to oil was relatively unaffected.

• 

  Fig. 13.16 – Relative permeability modification effect induced in a sand pack by Polysaccharide G.

Range of Applicability of DPR Polymer Treatments. While DPR polymer systems for imparting conformance improvement have been targeted primarily at sand and sandstone reservoirs, presumably being water wet, favorable DPR polymer effects have been observed when nonionic polyacrylamide was placed in various carbonate rocks with either water-wet and oil-wet conditions. DPR polymer treatments have been applied to reservoirs with temperatures up to 225°F; however, DPR polymer systems for use in conformance-improvement treatments are only applicable over a limited lower permeability range (approximately 5 md to hundreds of md in most cases). Because the upper permeability limit varies with the specific DPR polymer system and with specific reservoir rock lithologies, it is difficult to provide a universal upper permeability limit for the successful application of DPR polymer systems. The upper permeability limit for the successful application of any specific DPR polymer system is a treatment variable that should be scrutinized closely. The application of polymer DPR treatments to reservoir conformance problems involving flow channels with permeabilities exceeding the upper permeability limit of a DPR polymer is a major cause of failures for such polymer conformance treatments.

Illustrative Technologies and Field Applications. The earliest polymers (uncrosslinked) reported to have DPR properties used in water-shutoff/reduction treatments applied to production wells were polyacrylamides, which is the same general type of water-soluble polymer that has been used extensively in polymer flooding for mobility-control and sweep-improvement purposes. In 1973, SPE literature reported on a proprietary and commercially available "brush" polymer for "selectively reducing water production."

In 1988, Zaitoun and Kohler reported on how the adsorption of, respectively, polyacrylamide and a polysaccharide onto water-wet sand and sandstone promotes DPR to water flow. Also, it was reported how the adsorption of these polymers increase the irreducible water saturation. The same research group reported on the development of two polyacrylamide-based DPR water-shutoff processes and the field application of one of the processes in an underground gas-storage facility.

Gruenenfelder et al. reported on the application of DPR polymer water-shutoff/reduction treatments to two gravel-packed wells of high-temperature (190 to 200°F) sand reservoirs of the U.S. Gulf Coast. The DPR polymer treatments involved the use of a nonionic triple-stranded polysaccharide biopolymer.

The application of DPR polymer water-shutoff/reduction treatments, involving an amphoteric polymer material, to five wells in a high-permeability and high-temperature (up to 225°F) sandstone reservoir in Indonesia has been reported.

A couple of sources discuss the use of cationic polyacrylamide as a candidate polymer for use in polymer DPR treatments to impart conformance improvement.

In 2001, Eoff et al. reviewed the structure and process optimization of a commercial "brush" polymer that has been used since 1973 in various forms and under various trade names as a RPM polymer in conjunction with conformance-improvement treatments.

Gels

Gels are a fluid-based system to which, at least, some solid-like structural properties have been imparted. In other words, gels are a fluid-based system within which the base fluid has acquired at least some 3D solid-like structural properties. These structural properties are often elastic in nature. All of the conformance-improvement gels discussed in this section are aqueous-based materials. The term "gel" as used in this chapter (unless specifically noted otherwise) refers to classical, continuous, bulk, and "relatively strong" gel material and does not refer to discontinuous, dispersed, "relatively weak," microgel particles in an aqueous solution. Gels discussed in this chapter, when formed in a beaker for example, constitute a single and continuous gel mass throughout its entire volume within the beaker. The term "gelant" refers to a gel fluid before any appreciable crosslinking of the gel’s chemical building blocks has occurred. The term gel refers to a gel fluid that has attained either partial or full chemical-crosslinking maturation. This chapter discusses polymer gels, as well as inorganic gels and monomer gels. Sec. 13.8 briefly discusses a conformance-improvement plugging material (i.e., a resin) that involves an organic-fluid-based gel.

An older definition of gel is "a jelly-like substance formed by the coagulation of a colloidal solution into a semisolid phase." In modern oilfield and technical literature, the term gel includes the elastic and semisolid material that results from chemically crosslinking together water-soluble polymers in an aqueous solution. Crosslinked-polymer gels can possess rigidity up to, and exceeding that of, Buna rubber. They contain polymer concentrations in the 150 to 100,000 ppm range (but more commonly 2,000 to 50,000 ppm and most commonly 3,000 to 12,000 ppm). Gels are often formulated with relatively inexpensive commodity polymers.

Gels have found broad application as oilfield fluid-flow blocking agents because gels are often an exceptionally cost-effective plugging and/or permeability-reducing agent for use in a number of different conformance-improvement treatments. Conformance-improvement gels are, for the most part, essentially nothing but water (often produced brine) with the remainder of the gel constituents incorporated as low concentrations of relatively inexpensive polymers and chemical crosslinking agents.

The use of conformance-improvement gels is an emerging technology that, at this writing, is still not well understood by petroleum engineers nor widely applied. Conformance-improvement gels are another conformance technology and engineering tool that should be added to the "petroleum engineering toolbox." However, gels are not a panacea for remedying reservoir and flooding conformance problems, but rather simply another tool that can be used to alleviate conformance problems when there is a good match between a conformance problem and the application of a particular gel technology.

Conformance-Improvement Treatments

Gels operate, for the most part, either by diverting fluid flow from high-permeability, low-oil-saturation reservoir flow paths to low-permeability, high-oil-saturation flow paths, and thereby promoting improved flood sweep efficiency and incremental oil production, or by reducing oil-production operating costs by reducing excessive, deleterious, and competing coproduction of water or gas.

Oilfield gel conformance treatments can be applied in a number of forms including sweep improvement treatments, water shutoff treatments, gas shutoff treatments, zone abandonment treatments, squeeze and recompletion treatments, and water and gas coning treatments involving fractures and other linear-flow high-permeability reservoir anomalies. Gels are particularly effective for treating oil-production coning problems when the coning is occurring via linear flow in "vertical" fractures.

When there is a good match between a given conformance problem and a particular gel technology, relatively large volumes of incremental oil production and/or substantial reductions in oil-production operating costs, by means of the shutting off of excessive, deleterious, and competing coproduction of water or gas, can be achieved profitably. Gel treatments are usually applied in the course of normal and ongoing primary, secondary, or tertiary oil-recovery operations, just as an operator would apply an acid or scale-inhibition treatment. Gel treatments are an emerging oilfield technology that can help extend the life of maturing oil reservoirs that are approaching their economic limit.

Background and Historical Information. Although conformance-improvement gel treatments have existed for a number of decades, their widespread use has only begun to emerge. Early oilfield gels tended to be stable and function well during testing and evaluation in the laboratory, but failed to be stable and to function downhole as intended because they lacked robust chemistries. Also, because of a lack of modern technology, many reservoir and flooding conformance problems were not understood, correctly depicted, or properly diagnosed. In addition, numerous individuals and organizations tended to make excessive claims about what early oilfield gel technologies could and would do. The success rate of these gel treatments was low and conducting such treatments was considered high risk. As a result, conformance-improvement gel technologies developed a somewhat bad reputation in the industry. Only recently has this reputation begun to improve. The information presented in this chapter can help petroleum engineers evaluate oilfield conformance gels and their field application on the basis of well-founded-scientific, sound-engineering, and field-performance merits.

How Gel Treatments Function. Gels used in conformance-improvement treatments reduce permeability in the reservoir treatment volume in which the gels are ultimately placed. Conformance gels do not function as viscosity-enhancing agents during oil-recovery flooding operations.

Although microgels (discussed in a later subsection of this section), which are colloidal-sized aggregates of suspended and noncontinuous gel particles, have, at times, been claimed to be viscosity-enhancing agents during their "propagation" through reservoir flow paths possessing high permeabilities, there is no substantiation in the petroleum engineering literature of any microgels substantially enhancing the viscosity of an aqueous oil-recovery drive fluid beyond the viscosity of the gel’s polymer solution alone. In fact, microgel-gel-containing aqueous solutions tend to have lower viscosities than the polymer solutions from which they were derived. Permeability reduction is the dominant mechanism by which microgels impart conformance improvement. Oilfield microgels are also referred to, at times, as colloidal dispersion gels.

The more widely applied conformance-improvement gels are characterized as being bulk gels that function as permeability-reducing agents. Bulk gels have a continuous chemically crosslinked polymer network structure throughout the entire macroscopic scale of the gel. These gels are blocking and plugging agents to fluid flow in the reservoir volume in which they have been placed. For example, gels used in near-wellbore water-shutoff treatments of producing wells are selectively placed in a high-permeability strata (that are not in fluid or pressure communication with the other reservoir strata) to function purely as a plugging and blocking agents to fluid flow.

If a gel is placed some significant distance into the fractures of a naturally fractured reservoir surrounding an injection well, the gel not only functions as a blocking agent, but also as a diverting agent. These gels divert injected oil-recovery drive fluid from predominantly flowing through the high-permeability, low-oil-content fractures to predominantly flowing through the relatively low-permeability, high-oil-saturation matrix reservoir rock adjacent to the gel-filled and gel-treated fractures.

What Benefits Can Be Expected. For good gel-treatment well and well-pattern candidates, the following is a partial list of benefits that can be achieved.

• Generate incremental oil production through conformance improvement, and possibly generate large volumes of incremental oil production per unit cost of chemical expended.
• Substantially reduce oil-production operating expenses per unit cost of chemical expended.
• Reduce competing water production that can be unproductive, costly, and environmentally unfriendly.
• Reduce competing gas production that can be unproductive, excessive, and economically detrimental.
• Improve the performance of an ongoing oil-recovery operation.
• Reduce certain environmental liabilities by reducing the amount of excessive and unnecessary coproduction of environmentally unfriendly fluids, such as highly saline and hard reservoir brines.
• Extend the economic lives of marginal wells, well patterns, and oil fields.

Properties of an Ideal Gel System. An ideal conformance-improvement gel technology should be applicable as injection and production well treatments, as sweep improvement treatments, and as water and gas shutoff treatments. It should also be applicable to all reservoir mineralogies and lithologies and to a wide variety of reservoir and flooding-operation conformance problems. The ideal gel technology should be a single-fluid system and should possess a robust gel chemistry, which requires that it be insensitive to oilfield and reservoir environments and chemical interferences (especially H₂S and CO₂); be insensitive to all reservoir minerals and fluids; and be applicable over a broad pH range.

An ideal conformance-improvement gel technology should also involve a simple and straightforward gel-forming chemical system; be applicable over a broad range of reservoir temperatures; be stable over the long term; provide for a broad range of gel strengths, including rigid gels, and provide highly controllable and predictable gelation-delay onset times. For matrix-rock reservoir treatments, an ideal gel technology must include gelant solutions that are readily injectable into matrix reservoir rock. An ideal gel must be environmentally acceptable and friendly, be formulated with low concentrations of relatively inexpensive chemicals, and be formulated with readily available (preferably commodity) chemicals. Finally, it should reduce the permeability to water flow in matrix rock more than the permeability to oil and gas flow.

Gel Systems and Chemistries. Oilfield conformance-improvement gels come in a wide range of forms and chemistries. Table 13.1 provides an overview of various conformance-improvement gels.

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  Table 13.1

Chromium (III)-Carboxylate/Acrylamide-Polymer Gels. Widely applied as sweep-improvement treatments and as water and gas shutoff treatments, chromium (III)-carboxylate/acrylamide-polymer (CC/AP) gels are aqueous acrylamide-polymer gels in which the chemical crosslinking agent is a chromium (III) carboxylate complex. CC/AP gels have an exceptionally robust gel chemistry and are highly insensitive to oilfield and reservoir interferences and environments. They are also applicable over an exceptionally broad pH range. As a result, these gels, when properly formulated, are applicable to the acidic conditions associated with CO₂ flooding for which most earlier oilfield polymer gels did not function well. The chromium (III), as used in the crosslinking agent of this gel technology, is relatively nontoxic, but it is highly regulated. This single-fluid gel technology provides a wide range of gel strengths and a wide range of controllable gelation-onset delay times. The gel technology is applicable over a broad range of reservoir temperatures and applicable to a broad range of conformance problems and reservoir mineralogies and lithologies. Chromic triacetate (CrAc₃) is the often-preferred crosslinking agent used with the CC/AP gel technology. A chemical gelation-rate-acceleration additive package, involving chromic trichloride, has been developed for use with the CC/AP gel technology. Two chemical means are available to retard the rate of gelation of CC/AP gels that are applied to high-temperature reservoirs. The first involves the use of low or ultra-low hydrolysis polyacrylamide and capitalizes on the slow formation of the required chemical crosslink sites on the polymer by means of autohydrolysis. The second chemical means is the addition of relatively strong carboxylate ligands, such as lactate or malonate, to the gelant solution.

Chromium (VI) Redox Gels. One of the early conformance-improvement gel technologies involved acrylamide polymers that were chemically crosslinked together using a chromium (VI) redox system. This oilfield gel system has largely fallen from favor because of issues relating to the use of a crosslinking agent that contains toxic and carcinogenic chromium (VI) and because the crosslinking chemistry is rather complicated and subject to a number of oilfield interferences.

Aluminum Crosslinked Gels. Although other aluminum crosslinking agents have been developed and used in conformance-improvement gels, aluminum-citrate-crosslinked gels have historically been the most widely applied. The early widespread application of the aluminum-citrate gel technology was conducted in the sequential-injection mode, involving the repeated sequential injection of aqueous slugs containing, respectively, the polymer and the aluminum-citrated crosslinking agent. Sequential-injection aluminum-citrate gel technology is discussed in more detail later in this section. The application of conformance-gel treatments, involving the sequential injection of aqueous slugs containing the different chemicals that are required to form the gel in the reservoir, have largely fallen from favor.

More recently, aluminum-citrate acrylamide-polymer gels, which are formulated with low concentrations (200 to 1,200 ppm) of polymer and which are referred to as colloidal dispersion gels (CDGs), have been somewhat widely used as large-volume treatments applied through injection wells to "matrix rock" for improvement of waterflood sweep efficiency. CDGs are a form of discontinuous microgel particles. The mechanism and means by which this particular gel technology generates incremental oil production is not fully understood.

Published laboratory studies have reported the following regarding aluminum-citrate CDGs. First, CDGs of acrylamide polymers crosslinked with aluminum citrate are not readily injectable into, and propagatable through, matrix rock of normal permeabilities (e.g., sandstone of < 1,000 md). Seright discusses an experimental flooding study where an aluminum-citrate CDG was observed to not be readily propagatable, after two hours of aging, through matrix rock during a flooding experiment involving the injection of an aluminum-citrate colloidal dispersion gelant solution, containing 300 ppm high-MW HPAM, into a 700 md Berea sandstone core plug at 105°F and at a superficial velocity through the sandstone of 16 ft/d. Second, aluminum does not readily propagate through reservoir matrix rock. Third, aluminum crosslinking of the polymer of CDGs normally occurs within several hours. Fourth, aluminum-citrate CDGs do not preferentially enter high-permeability zones any more selectively than is dictated by Darcy’s law. Fifth, aluminum-citrate CDGs do not viscosify water more than do the gel’s polymer without the addition of the crosslinking chemical. If aluminum-citrate CDGs are not readily injectable into and propagatable through matrix reservoir rock of normal permeabilities (sub-Darcy permeabilities), there are two possible explanations for the apparent success of a number of large-volume aluminum-citrate CDG treatments in terms of generating conformance improvement and generating incremental oil production when treating "matrix-rock conformance problems." First, the successfully treated "matrix rock" reservoirs may actually have been at least somewhat naturally or otherwise fractured. Second, the offending high-permeability strata within the successfully treated matrix-rock reservoirs may have possessed multi-Darcy permeabilities.

Gels Crosslinked With an Organic Crosslinker. There has been a long-standing desire within the oil industry to develop effective conformance-improvement polymer-gel technologies using benign organic chemical crosslinking agents that would impart carbon-carbon-bond chemical crosslinks between the gel polymer molecules. This would avoid the use of metal crosslinking agents and would result in exceptionally strong and stable polymer gels. However, with the possible exception of the polyethyleneimine-crosslinked gel technology briefly discussed later in this section, no such gel technology has been developed and reduced to commercial practice.

The majority of organically crosslinked polymer-gel technologies developed to date have been based on phenol-formaldehyde chemistries. These gels either use phenol and formaldehyde as the chemical crosslinking agent or use derivatives or precursors to phenol and formaldehyde. There have been attempts to identify and use less toxic and more environmentally friendly derivatives of phenol and formaldehyde as the crosslinking agents.

Some of the most thermally stable polymer gels for use in high-temperature conformance-improvement treatments have been formulated with acrylamide polymers that are chemically crosslinked with organic crosslinking agents that are based on phenol-formaldehyde type chemistry.

At this writing, an organically crosslinked gel technology that does not involve a phenol-formaldehyde type crosslinking chemistry was somewhat recently developed. The gel technology involves the use of a specially manufactured and derivatized acrylamide polymer and the use of polyethyleneimine as the crosslinking agent. This gel technology is most readily applicable to reservoirs with temperatures exceeding approximately 180°F, and reports regarding the field application of this conformance polymer-gel technology have been favorable overall.

Biopolymer Gels. Gels based on the crosslinking of biopolymers with organic or inorganic crosslinking agents have been pursued. A popular conformance biopolymer-gel technology in the 1970s and early 1980s was based on gels of xanthan polymer crosslinked with an inorganic chromium (III) crosslinking agent.

Monomer Gels. Conformance-improvement gels based on the in-situ polymerization of organic monomers to form polymers with and without the inclusion of crosslinking monomers have been developed and successfully applied. Early monomer-gel treatments were often based on the in-situ polymerization of the acrylamide monomer; however, this is seldom practiced currently because of toxicity and environmental concerns. Most modern monomer-gel technologies for oilfield application are based on the in-situ polymerization of less toxic acrylate monomers.

An advantage of monomer gel technologies is the low water-like viscosity of the gelant solution. Disadvantages include cost and the sensitivity of the polymerization reaction to oilfield interference and environments. Care also needs to be taken to carefully distinguish between "linear" (uncrosslinked) and crosslinked oilfield monomer gels.

An older monomer gel technology involved gels formed from the reaction of formaldehyde with phenol. A modern day concern with this gel technology is the toxicity and environmental issues associated with the use and handling in the field of formaldehyde, phenol, and/or their chemical derivatives.

Polymer Self-Induced Gels. A conformance-improvement biopolymer gel system has been reported that involves the injection of the polymer into the treated reservoir volume in the form of an alkaline high-pH solution. Once emplaced in the reservoir rock, the pH of the polymer solution is reduced by spontaneous or induced means. Following the reduction in the polymer solution’s pH, the polymer solution spontaneously forms a gel.

Inorganic Gels. A variety of inorganic gel technologies have been developed and applied over the years. These include gels based on, respectively, silicate or aluminum ion chemistries, along with gels of hydroxides of iron and magnesium.

Gels based on silicate chemistries were some of the earliest gel technologies applied for conformance improvement. A silicate gel is formed when a relatively high-pH aqueous solution, containing a sufficient concentration orthosilicate monomers or oligomers of orthosilicate, has its pH reduced or is exposed to hardness cations. Aqueous-based conformance-improvement silicate gels can be formed in a petroleum reservoir by either "internally catalyzed" or "externally catalyzed" means. Internally catalyzed silicate gels are formed by including in the aqueous gelant solution an acid-generating chemical that will spontaneously decrease the pH of the gelant solution when it is placed in the reservoir. Externally catalyzed silicate gels are usually formed by contacting the orthosilicate monomer or oligomer solution with a brine (e.g., reservoir brine) that contains a high level of harness cations (e.g., Ca⁺⁺). Internally catalyzed silicate gels are often favored for use in conformance-improvement treatments during oil-recovery operations. Externally catalyzed silicate gels are often used during drilling operations for lost circulation applications. Several potential concerns should be noted. Solution-aging, filterability, and quality-control issues can be a concern for silicate gelant solutions that are to be injected into matrix-rock reservoirs. There can be safety and environmental issues associated with the acid-generating chemical used in internally catalyzed silicate gel systems.

Silicate-based gels of conformance-improvement treatments have been applied successfully in Hungary. A large-volume sodium-silicate gel treatment was reported to have been applied to an offshore Norwegian oil production well. A large number of silicate-based conformance-improvement gel treatments have been applied worldwide.

The main advantage of inorganic gels is their environmentally friendly nature. Disadvantages historically have been that many of the inorganic gels were relatively weak gels, and a number of the inorganic gels do not provide good long-term fluid-shutoff performance. The latter is especially true for inorganic hydroxide "gels" that tend to convert over time to solutions containing ineffective oxide solids.

Gels Formulated With Synthetic Organic Polymers. Although a number of the early conformance-improvement gel technologies were based on inorganic gels and biopolymer gels, the recent trend has been toward the application of oilfield polymer gels based on the use and crosslinking of synthetic organic polymers, primarily acrylamide polymers.

Classification of Gel Treatment Types. Conformance-improvement gels can be classified in several manners. First, conformance-improvement gels can be classified as to whether they are intended to treat matrix-rock conformance problems, involving permeabilities less than roughly two Darcies, or treat reservoir high-permeability anomalies (usually fractures), involving permeabilities greater than roughly two Darcies. A subcategory of this classification is whether the gel treatments for treating matrix-rock conformance problems are to be placed in the near-wellbore environment (radial penetration of less than ~15 ft) or to be placed deeply in the far-wellbore environment (radial penetration of greater than ~15 ft). Although this classification scheme was originally developed for the CC/AP polymer-gel technology, the classification scheme is also generally applicable to all other conformance-improvement polymer-gel technologies.

Gels used to treat high-permeability-anomaly conformance problems are often treating fluid-flow problems involving linear flow, such as that occurring into fractures. Near-wellbore gel treatments placed in unfractured matrix rock are usually used to block radial fluid flow. Near-wellbore gel treatments that are placed in matrix rock are of relatively small volume, are often total-fluid-shutoff gel treatments, and are often relatively simple and straightforward to apply. These gel treatments usually have a relatively low risk factor if they can be placed properly and if the conformance problem is correctly diagnosed. In addition, these gel treatments can have high payout-to-cost ratios. Gels placed deep in matrix rock are large volume treatments that can be relatively costly and technically complex. In addition, these gel treatments can have a relatively high risk factor associated with them and tend to render a relatively low payout-to-cost ratio. The application of low-concentration aluminum-citrate CDG treatments that are applied via injection wells has been cited as a possible exception to this trend.

Second, the widely applied form of conformance-improvement gel treatments, namely crosslinked organic-polymer bulk gel treatments, can be classified as to whether when being injected from the wellbore into the reservoir, the gel fluid is a gelant solution or is a preformed or partially preformed gel fluid. In most instances, such as with the CC/AP gel technology, the polymer-gel fluid must be in its gelant form (i.e., before any initial microgels form) for the gel fluid to be readily injectable into matrix reservoir rock (such as sandstone having a permeability less than 1,000 md). However, for polymer gels to be selectively placed in high-permeability anomalies such as fractures, the gel should be designed so at least some initial gelation has occurred when the gel leaves the wellbore to assure that the gel will not substantially leak off from the high-permeability anomaly (e.g., a fracture) into the adjacent matrix reservoir rock. This is the key to properly formulated polymer gel being able to selectively treat fracture conformance problems, without substantially damaging the adjacent matrix reservoir rock.

Third, conformance-improvement organic-polymer gels are classified as to whether they are the more widely applied bulk gels possessing relatively high polymer concentration with a continuous crosslinked polymer-gel structure on the macro scale or they are microgels, alternately know as colloidal dispersion gels. Microgels have been purportedly used to treat deeply in matrix reservoir rock. Microgel solutions contain low polymer concentrations (usually < 1,300 ppm) and do not have a continuous crosslinked polymer gel structure on the macro scale. Examples of conformance-improvement microgels are low concentrations of acrylamide polymer crosslinked with aluminum citrate and low concentrations of acrylamide polymer crosslinked with zirconium lactate. As mentioned previously, the conformance-improvement mechanism by which microgels function when treating "matrix-rock" reservoirs is not fully understood.

The fourth classification relates to the injection mode of the gel chemicals. Early oilfield conformance gel technologies tended to be based on the sequential injection of fluids containing, respectively, two of the reactive chemicals of the gel’s chemical make up. For example, the polymer would be injected in one aqueous fluid followed by injection of the crosslinking agent in a second fluid. This was done at that time because the gelation-delay onset time could not then be controlled and/or delayed sufficiently to permit the gel to be injected into the reservoir as desired and required. This strategy is flawed for two reasons. First, operational constraints almost always require a substantial inert fluid spacer be placed between the two reactive gel-forming solutions to prevent mixing of the reactive chemicals in the injection tubing. This practice essentially precludes formation of a gel in the near-wellbore region. Second, when the second reactive fluid begins to diffuse and/or finger into the first reactive fluid in the reservoir, gel will begin to form and tend to divert the second reactive fluid from further mixing. In general, this outcome leads to the highly inefficient use of injected chemicals. Most current oilfield gel technologies do not involve the sequential injection mode. Essentially all current technologies involve the injection of a single gelant solution that contains all of the gel chemical constituents. State-of-the-art single-fluid gel technologies have sufficient chemical gelation-onset-delay-time chemistries to allow proper placement.

A popular early polymer-gel technology for improving conformance within matrix rock reservoirs was the repeated sequential injection of aqueous slugs containing, respectively, HPAM and aluminum-citrate crosslinking agent. The mechanism by which the sequential-injection aluminum-citrate gel treatments were originally purported to operate was the so-called "layering mechanism." This mechanism envisioned that repeated sequential injection of the gel-forming aqueous slugs would result in alternate adsorbed layers of crosslinking agent and polymer that would crosslink to form gel that would build out from the pore walls of matrix reservoir rock. The layering mechanism was later recanted by its original proponents. Today, most polymer-gel treatments involving acrylamide polymers crosslinked with aluminum citrate are injected as a single-fluid.

Gel Parameters and Evaluation. This section focuses on important formula parameters and on temperature effects as they relate to gelation rate and gel strength of conformance-treatment polymer gels. Similar relationships often hold for other gel technologies. Figs. 13.17 through 13.20 relate to gel formula parameters and the effect of temperature for a specific CC/AP gel formula. Other oilfield polymer-gel technologies tend to follow similar relationships. The gel formula of Figs. 13.17 through 13.21 is a fracture-problem fluid-shutoff gel that has a rigid and soft Buna rubbery consistency. The gel was formulated in fresh water and contained 2.0 wt% active polyacrylamide (PAM) polymer possessing 11 million MW and 2% hydrolysis. The polymer was chemically crosslinked together to form the gel using chromic triacetate (CrAc₃) as the crosslinking agent.

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  Fig. 13.17 – Varying polymer concentration in a CC/AP gel.

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  Fig. 13.18 – Varying polymer MW in a CC/AP gel.

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  Fig. 13.19 – Varying crosslinking agent concentration in a CC/AP gel.

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  Fig. 13.20 – Temperature effect on the gelation rate of a CC/AP gel.

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  Fig. 13.21 – Accelerating the gelation of a CC/AP gel.

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  Fig. 13.22 – Retarding the gelation rate of a CC/AP gel.

In Figs. 13.17 through 13.22, dynamic oscillatory viscometry was used to measure the elastic strength of the gel sample as a function of aging time during the gel maturation process following the addition of the crosslinking agent to the gelant solution. The dynamic oscillatory viscosities were measured at an oscillation frequency of 0.1 radians per second.

These plots of dynamic oscillatory viscosity vs. gel aging time can be used to discern two important properties of any given gel sample. First, the equilibrium dynamic-oscillatory viscosity value that is eventually obtained for a given gel sample is a measure of the elastic strength of the gel. Second, the rate at which the dynamic oscillatory viscosity of the gel sample reaches the equilibrium viscosity value is a reflection of the gelation rate of the sample.

Polymer Concentration. As Fig. 13.17 shows, gel strength increases with polymer concentration when all other gel formula parameters are held constant. For the gels of this figure, the crosslinker loading was held constant at a 20:1 weight ratio of weight active polymer to weight active CrAc₃ crosslinking agent. The gel samples were aged at 140°F. The trend shown is a near universal relationship for all gel technologies. As the concentration is increased of the polymer, monomer, or fundamental chemical building block of the gel’s solid-like structure (up to its solubility limit), gel strength increases.

Polymer Molecular Weight. When all other gel formula parameters are held constant, polymer-gel strength increases as the polymer molecular weight (MW) is increased. For Fig. 13.18, which depicts this trend, the crosslinking agent concentration within the gel samples was 1,000 ppm CrAc₃. The trend shown explains why a gel formulated with a low-MW polymer needs a higher concentration of polymer to obtain the same strength of a comparable fracture-problem gel formulated with high-MW polymer. Comparable gels formulated with higher-MW polymers tend to be more elastic in nature.

Crosslinker Concentration. As Fig. 13.19 shows, when all other polymer-gel formula parameters are held constant, increasing the crosslinking agent concentration increases gel strength. Although not readily apparent in this figure, in general, increasing the crosslinking agent concentration also increases the gel’s rate of gelation.

It should be emphasized that, for a given polymer gel, there usually is an optimum concentration for the crosslinking agent. For the samples of Fig. 13.19, that concentration is approximately 1,000 ppm CrAc₃ (or alternatively stated as a weight ratio of 20:1 active polymer to active crosslinking agent). The optimum crosslinking agent concentration is often specified in terms of the ratio of weight of active polymer to weight of active crosslinking agent (or, alternatively, in terms of the weight of the active polymer to the weight of metal ion in the crosslinking agent). Above a gel’s optimum crosslinking-agent concentration, syneresis (expulsion of water from the gel) will occur. Below the optimum concentration, the gel is underoptimum in terms of gel strength. For most oilfield applications, the petroleum engineer wants to maximize effective gel strength to maximize economic performance per pound of polymer used in a given gel formula.

Syneresis results from shrinkage of the gel volume. Syneresis, a thermodynamic equilibrium phenomenon, results from excessive chemical attractive forces within the gel structure. Syneresis of a given polymer-gel formula usually results from one of two causes. First, syneresis for a given polymer-gel formula (fixed salinity and pH) can result from excessive crosslinking agent being incorporated into the gel formula. The second cause results from additional and excessive crosslinking chemical sites developing on the polymer over time, as exemplified by autohydrolysis of acrylamide polymers of CC/AP gels at high temperatures.

Syneresis is usually considered undesirable and unacceptable for gels to be used in near-wellbore treatments that are applied in matrix-rock reservoirs for total-fluid-shutoff purposes or in gels for sealing fluid flow in fractures. However, for gels, especially microgels, that are to be used in deeply placed gel treatments of matrix-rock reservoirs and to function where the microgel particles act as check valves in pore throats, gel syneresis may not be of significant concern. Gel syneresis and gel degradation/degelation can be, and often are, distinctly different phenomena; however, both of these phenomena can result in expulsion of water from a gel.

The optimum concentration of the crosslinking agent for a given CC/AP polymer-gel formula decreases as the MW of the polymer increases, decreases proportionally with increasing polymer concentration (i.e., less pounds of crosslinker per pound of polymer), and increases with increasing temperature.

Temperature. Fig. 13.20 shows how the rate of gelation substantially increases with increasing temperature. For the CC/AP gel technology, the rate of gelation for a given gel formula approximately doubles with every 10°C increase in temperature.

Gelation Rate Acceleration. There are instances when applying conformance-improvement gel treatments that the optimum treatment design will call for the acceleration of the gelation rate of a given gel formula. This is especially true for gel treatments applied to low-temperature (e.g., subambient temperature) reservoirs. For example, for the CC/AP gel technology, a chemical gelation-rate-acceleration additive package involving the use as chromic trichloride as the accelerating agent has been developed. Fig. 13.21 illustrates the use of this acceleration package with the CC/AP gel technology.

Gelation Rate Retardation. There are instances when applying oilfield gel treatments that the optimum treatment design will call for the retardation of the gelation onset time of a given gel formula. This is especially true for gel treatments that are to be applied to high-temperature reservoirs.

For example, for the CC/AP gel technology, a chemical gelation-rate-retardation additive package has been developed involving the use of strong carboxylate ligands as the gelation-rate retardation agent. Fig. 13.22 illustrates the use of this chemical gelation-rate-retardation additive package with the CC/AP gel technology. In the study of Fig. 13.22, the gel being investigated was a gel formula that was intended to impart total near-wellbore fluid shutoff in matrix-rock reservoirs at elevated temperatures. The gel was formulated in fresh water and contained 5.0 wt% active polyacrylamide (PAM) having a MW of ~250,000 daltons. Two versions of the PAM polymer were used in the study. The first PAM was 1.9 mole% hydrolyzed. The second PAM was ultra-low-hydrolysis PAM that had a hydrolysis level of < 0.1 mole%. The gelation-rate retardation agent used in the study of Fig. 13.22 was sodium lactate (NaLac). As the figure shows, the gelation rate was nearly instantaneous at 248°F when the gel was formulated with normal polyacrylamide (1.9% hydrolyzed) and no gelation-rate retardation agent was used. By using various combinations of gelation-rate chemical retarder addition and ultra-low-hydrolysis PAM in appropriately formulated gel recipes, the gelation onset delay time at 248°F could be extended in increments out to 23 hours. As the figure also shows, if the near-wellbore reservoir rock is cooled to 212°F (as can normally be easily done near wellbore through the use of ambient-temperature water injection), the gelation onset time could be extended to 68 hours. Appropriately formulated lactate-retarded CC/AP gels usually contain somewhat higher loadings of polymer and/or crosslinking agent. These increased gel chemical loadings are incorporated to counteract the slight weakening and destabilization of the gel that is imparted by the lactate addition.

Gel Strength. There are several different measurements of polymer-gel strength. These gel strengths have at least some analogous correlations in most other gel technologies.

The first measurement is elastic strength. As discussed previously, dynamic oscillatory viscosity can be used to measure the elastic strength of a gel. In practical oilfield terms, the measure of the elastic strength of a gel relates to the resistance to physical deformation that a gel will exhibit while extruding through a constriction in its flow path, such as a constriction in a fracture flow path.

The second measurement is yield or failure strength. When this strength is exceeded, portions of the chemical gel structure are broken. An example of exceeding the gel yield or failure strength is the rupturing of the chemical bonds of the polymer’s backbone structure of a shear-non-rehealable gel. This gel strength is measured by placing a mature gel sample in a large container and increasing container pressure until there is flow through a small orifice in the testing container. The yield or failure strength of a total-fluid-flow-shutoff and shear-non-rehealing gel formed and residing in a sandpack is measured by the differential pressure required to make the gel flow from the sandpack. The yield or failure strength of a polymer gel is often much larger than its elastic strength.

The third measurement is compressive strength. Polymer gels do not possess large compressive strengths compared to Portland cement. Thus, polymer gels should not be applied as plugging material where substantial compressive strength is required. Adding solids to a polymer gel can greatly increase its compressive strength, especially at high solids loading.

The relative effectiveness of gels for plugging fluid flow through flow channels and flow paths, as measured by the differential pressure that causes the gel to breakdown and flow, increases as the size of the flow channel decreases. Gels that are placed as clear-fluid gelant solutions are particularly effective and strong plugging agents for use when plugging or reducing the fluid-flow capacity in microflow paths, such as is pores of matrix reservoir rock. Gels are especially effective at plugging small fluid-flow paths where solids-containing plugging agents, such as cement or even "microfine" cement, cannot be readily placed.

Gel Onset Time. There have been many and, at times, apparently conflicting means proposed to define and measure gelation onset times. There are two distinctly different and important times in the gel maturation process. The first is the initial onset of gel formation. The second is the time required to reach full gel strength. Because the time required to attain full gel strength is often reached asymptotically, pragmatically it is often better to measure the attainment of "near full gelation," where "near full gel strength" is quantitatively defined.

When determining the time of initial onset of gelation for a classical bulk polymer gel to be used to treat matrix reservoir rock, the investigator needs to determine when the first onset of microgel particle formation occurs. It is at this point that the gelant usually ceases to be readily injectable into sandstone of less than 1,000 md. Filtration testing, core flooding injectivity experiments, bottle testing, and dynamic oscillatory viscosity techniques have all been used successfully to determine the first onset of such gelation. For a bulk polymer gel, microgel formation usually occurs at a time just before the onset of first being able to visually detect any gel structure in the gelant solution. For classical bulk polymer gels, initial microgel formation constitutes the formation on a colloidal scale of the first discreet crosslinked polymer aggregates that are the precursor to the formation of the continuous macro-scale crosslinked polymer network of the bulk gel.

For crosslinked polymer gels, there are several different modes of the gelation onset delay and different ways these modes manifest themselves. First, there can be a substantial induction time before any gel formation, including microgel formation, can be detected. Second, and not mutually exclusive of the first mode, there can be "right angle gelation onsets." Here, once the gelation process starts, the final gel strength is reached very rapidly (almost instantaneously). Third, the gelation begins as soon as the crosslinking agent is added and proceeds over a protracted period of time. CC/AP gels widely applied to treat fracture conformance problems in reservoirs with temperatures < 150°F are of the third gelation-delay type mode.

Gel Bottle Testing. Although not a highly sophisticated and exacting quantitative technique, bottle testing (ampoule testing at high temperatures) has been used widely in both the laboratory R&D setting and the field quality-control setting to test and evaluate gels, especially polymer gels.

Bottle testing provides a highly cost-effective and straightforward technique to obtain a semiquantitative measure of gel strength and a semiquantitative measure of gelation rate. It is also a convenient means to evaluate the long-term stability of gels at a given test temperature. Bottle testing is often relatively easy to conduct in the field setting. Bottle testing in the laboratory provides a means to screen rapidly the performance of a large number of gel samples before selecting a few of the gels samples for more costly and rigorous testing, such as dynamic-oscillatory-viscosity and core-flooding experimental testing.

A polymer-gel bottle-test gel strength code has been developed and is now widely used (at times in various forms and with various modifications) for visually determining and evaluating, in a semiquantitative manner, the strength of polymer gels. Table 13.2 shows the gel strength code. The gel strength code is set up such that two observers, who view the same gel sample, could possibly assign to the sample a gel strength code that differs by one letter code. However, the gel strength code is designed such that it is "virtually not possible" for two reasonable observers to view the same gel sample and assign the gel sample a gel strength code that differs by two letter codes. The comparison of the strength of different gels using this bottle-testing gel-strength-code scheme should only be made when the same volume of gel sample is placed in a bottle or ampoule with the same size and geometric shape. When quoting a gel strength code, the size of the gel sample and the size of the bottle should be provided. Bottle testing at low to intermediate temperatures is often conducted with a 50 cm³ gel sample placed in a 120 cm³ (4 oz) wide-mouth bottle.

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  Table 13.2

When conducting polymer-gel bottle testing, there are several pitfalls to avoid. When performing field quality control work involving polymer gels containing H₂S, a nitrogen blanket should be applied to prevent the H₂S from reacting with atmospheric oxygen and forming intermediate free-radical chemical species that attack and degrade the polymer gel. This deleterious reaction with free oxygen does not occur in anaerobic oil reservoirs (most oil reservoirs are anaerobic). Free oxygen in the injected water of the gel formula tends to be chemically reduced and deactivated quickly in the chemically reducing environment of most oil reservoirs. Consumption of free oxygen in the chemically reducing reservoir environment is generally much faster than the oxygen-induced gel degradation reaction.

When conducting high-temperature ampoule testing of this bottle-testing scheme, the gelant solutions need to be scrupulously deoxygenated to less than 10 ppb free O₂. There are two recommended procedures to deoxygenate the gelant solution of polymer-gel samples for high-temperature testing in the laboratory setting. The first procedure involves vacuum degassing to the point that the aqueous solution boils (ebulates) for a minute or so and then glassblowing the ampoule shut under vacuum. It is highly recommended that properly tempered heavy-walled (~4 mm thick) glass ampoules be used for this purpose and that the glass ampoules be placed in appropriate transparent safety containers when the gel samples are aged in an oven at the test temperature. The second effective procedure for effectively deoxygenating gelant samples (to < 10 ppb O₂) for high-temperature laboratory testing is to bubble high purity argon gas through the gelant solution. The need to deoxygenate gel samples during high-temperature testing is a laboratory artifact because gels existing in a reservoir will normally be in an anaerobic environment.

Flow and Placement Considerations. The flow properties of a gelant or gel as it is being placed are important parameters.

Gelant and Gel Flow and Placement in Matrix Rock. To date, for all known gelant solutions used in conformance-improvement treatments (including polymer gelant solutions), these gelant solutions place themselves in all matrix-rock geological strata according to Darcy flow considerations and do so without any special selective placement in only the high-permeability strata and flow paths.

Mechanical Zone Isolation. Any placement of gel into, and the associated permeability reduction of, a low-permeability and/or high-oil-saturation strata in the near-wellbore region surrounding a radial-flow matrix-rock-reservoir well will almost always be counter productive to improving the conformance of that well. Thus, when applying a gel treatment, especially a near-wellbore gel treatment, to treat a vertical conformance problem of a radial-flow well in a matrix rock reservoir, mechanical zone isolation must be used to assure that the gelant is injected only into the high-permeability and/or low-oil-saturation geological strata to be treated.

Gel Treatments When Matrix Crossflow Exists. For a gel treatment to be successful when treating vertical conformance problems in matrix-rock reservoirs in which there is fluid-flow and pressure crossflow communication between geological strata of differing permeabilities, the gel treatment must be selectively placed deeply in the reservoir. In addition, the gelant solution should approach unit mobility, or stated another way, the resistance factor equals 1.0 (i.e., the gelant solution should approach the viscosity of water). The successful treatment of vertical conformance problems in matrix rock reservoirs of normal permeabilities (permeabilities < 1,000 md), where there is crossflow between the geological strata, requires the application of large-volume gel treatments for which the economic risks can be relatively high and the rates of returns can be relatively low. The large volume of gelant solution that needs to be injected begins to approach the volume of a traditional chemical flood, such as a polymer conformance-improvement waterflood. In addition, the requirement of being able to successfully propagate the gelant solution, or possibly microgels, deep into a matrix-rock reservoir (especially without damaging oil-productive zones) is a challenging task.

Gel Placement in Fractures. While no gel treatment fluid is available for the selective placement of gels (beyond Darcy flow considerations) into high-permeability flow channels of matrix reservoir rock of normal permeabilities, gels, especially polymer gels, can be routinely formulated for selective placement into fractures or into other high-permeability anomalies within a reservoir—such as fractures, solution channels, cobble packs, and rubblized zones. Such a polymer gel is normally designed so that the gelant solution is at least partially gelled when it leaves the wellbore, and initial microgels have formed. This initial gelation and the formation of microgel particles prevent the gel from substantially invading and damaging the matrix rock adjacent to high-permeability anomalies. The next subsection of this chapter discusses a gel fluid-loss mechanism involving gel dehydration and expulsion of water from the gel into matrix reservoir rock adjacent to the gel-filled fracture. This gel dehydration does not involve the loss of gel from the fracture. For a properly designed polymer-gel treatment, gel leakoff from treated fractures is most often insignificant in terms of gel-treatment functionality. CC/AP fracture-problem polymer gels that are placed in such a manner are capable of selectively plugging the treated fracture volume effectively.

Gel Extrusion Through Fractures. Because many of the most successful gel treatments have been applied as large-volume treatments to naturally fractured reservoirs and because the injection times of such gel treatments often exceed the injected gel’s gelation onset time (often by a factor of 10 or more), much of these gels must be flowing and extruding through the fractures in a mature gel state. Polymer gels used to treat fracture conformance problems have been shown, while extruding through fractures, to exhibit shear-thinning rheological behavior that correlates with gel superficial velocity and fracture width. When extruding these gels through fractures at high velocities, the resultant pressure gradients within the fractures are insensitive to flow rate. This is a partial explanation for why these polymer gels have exhibited unexpectedly good injectivity into fractured formations. This explanation is not intuitive to many petroleum engineers.

Fracture-problem polymer gels of the type that are widely applied as sweep-improvement and water-shutoff treatments have a minimum pressure gradient that is required to mobilize the flow of the gel. This minimum pressure gradient for gel flow is proportional, over a broad range of fracture widths and differential pressures, to the inverse of the square of the fracture width. The implications of this observation are extremely significant. One implication is that these polymer gels will tend to be selectively placed in the widest and most offending fractures when treating fracture conformance problems in naturally fractured reservoirs. A second implication is that fracture-problem gel water-shutoff treatments, which are applied to a naturally fractured reservoir, should be designed so that the drawdown pressure of normal production operations does not exceed minimum pressure gradient for gel flow. If the drawdown pressure exceeds the minimum pressure gradient for gel flow, any gel experiencing drawdown exceeding the minimum pressure gradient for gel flow will be mobilized and back produced. Of note, the pressure gradient in the intermediate- and far-wellbore region of most naturally fractured reservoirs during oil-recovery operations is quite small (often less than 5 psi/ft). For a widely applied fracture-problem CC/AP gel formula under the studied experimental conditions, the pressure gradient, dp/dl, required to extrude the gel from the studied fractures is described by the following mathematical equation:

....................(13.17)

where w_f is the fracture width. (See Fig. 13.23.) The data of Fig. 13.23 involved fracture widths ranging from 0.008 to 0.4 in. (0.2 to 10 mm) and pressure gradients from 0.1 to 1,000 psi/ft.

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  Fig. 13.23 – Pressure gradients required to extrude a gel through open fractures.

Aqueous polymer gels, being sponge like, can undergo dehydration while being propagated through fractures. Gel dehydration can occur any time a fracture-problem polymer gel experiences a differential pressure between the gel in the fracture and the adjacent permeable matrix reservoir rock. The rate of dehydration is not necessarily directly proportional to the differential pressure. This gel dehydration is loss of water from the gel and not leakoff of the gel itself. Gel dehydration decreases the rate at which the gel propagates through a given fracture and strengthens the gel that resides within the fracture. As previously noted, polymer-gel strength increases as the concentration of polymer and crosslinking agent increases within the gel. For a fracture-problem CC/AP gel formula that has been widely applied in the field and under experimental conditions simulating such field applications, the gel dehydration rate, μ_l in ft/D (or alternatively ft³/ft²/D), has been described, as Fig. 13.24 shows, by the empirical equation:

....................(13.18)

where t is time in days. During the laboratory flooding-experiment study of Fig. 13.24, the facture width was 0.04 in. (1 mm), fracture lengths varied from 0.5 to 4 ft, fracture heights varied from 1.5 to 12 in., and injection fluxes in the fracture varied from 130 to 33,000 ft/D.

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  Fig. 13.24 – Average gel-hydration leakoff rate from seven fracture flooding experiments at different velocities.

The dehydration of fracture-problem polymer gels is the reason why if the objective is to inject the fracture-problem gel as deeply into a reservoir as possible, the gel should be injected as rapidly as feasible (without exceeding formation parting pressure). Conversely, to maximize the strength of the emplaced gel, the gel should be injected as slowly as feasible.

Gel Shear Rehealing. When a mature gel is exposed to a high shear-rate field and the gel structure is sheared, the gel may or may not be able to spontaneously reheal. Most polymer gels of the type used in hydraulic fracturing operations employ polymer crosslinking chemistries that impart shear-rehealing properties into the gel. That is, if the gel is subjected to a sufficient intensity shear flow field, the gel will temporarily shear degrade. The polymer chemical crosslinks will be temporarily broken, and the chemically crosslinked polymer molecules will temporarily separate in solution. However, on termination of the shear flow field, the gel and its chemical crosslinks of the polymer molecules will spontaneously reheal (for the most part). As a result, the gel will regain all (or nearly all) of its original gel strength. However, these gels are not normally good plugging agents for use in conformance-improvement treatments, especially for placement under high differential pressure conditions surrounding production wells. These gels, just like the "linear gels" resulting from high concentrations of uncrosslinked water-soluble polymers alone, tend to "slowly" flow under high differential pressure conditions. This is one possible shortcoming of the use of in-situ polymerization of monomers for conformance-improvement purposes when no crosslinking monomer is incorporated into the in-situ polymerization process.

Many conformance-treatment polymer-gel technologies, such as CC/AP gels, use polymer-crosslinking and polymer chemistries that do not lend themselves to shear rehealing. These gels have effectively no tendency to flow through constricting microflow paths, such as pore throats, when subjected to differential pressure. When these gels are subjected to even very high shear-rate fields, the gel crosslinking sites and/or multiplicity of crosslinked sites on any given polymer molecule do not permit the crosslinked polymer molecules to separate at the crosslinking sites. If the shear-rate flow or shear-stress conditions become exceptionally high, the gel’s polymer backbone begins to experience scissions caused by mechanical shear degradation, which results in irreversible shear damage and mechanical degradation of the polymer gel.

Injection Pressure. As a general rule, the reservoir facture and/or parting pressure should not be exceeded during the injection of the gel treatment fluid. If reservoir fracture or parting pressure is unexpectedly and/or inadvertently exceeded when performing a gel treatment involving a relatively strong gel, normal practice calls for going to water injection at the same rate and pressure until the gel solution is displaced from the tubing. At worst in this situation, a minifracture will be created in the reservoir. On cessation of gel injection, the fracture will close, the gel will mature and should seal the fracture, and there will be little damage to the reservoir.

Hall Plots. Hall plots are often generated and analyzed during real-time placement of gel conformance-improvement treatments. At times, Hall plots of gel treatment placement have been creatively and unscientifically interpreted. The Hall plot was originally developed to analyze steady-state injectivity data for waterflood injection wells that are injecting into a single zone. As normally used in conjunction with gel treatments and gel injection, Σp_tf Δt is plotted vs. cumulative gel volume injected W_i, where p_tf is the flowing wellhead pressure in psi, Δt is time in days, and W_i is cumulative injection volume in barrels. Under steady-state conditions, the slope of the Hall plot is

....................(13.19)

where μ is viscosity in cp, r_e is the external reservoir radius in feet, r_w is the wellbore radius in feet, s is the skin factor, k is permeability in md, and h is formation height in feet. If a change in slope occurs in a Hall plot, all that the slope change can indicate, in the absence of some other and independent data, is that there has been a change in the well’s injectivity. Without having other independent data, when a change occurs in the slope of a Hall plot, one cannot tell if the slope change was caused by a change in the well’s skin factor, a change in the mobility (k/μ), or a change in the effective height of the well interval accepting the injection fluid.

Fig. 13.25 is a Hall plot illustrating an injectivity reduction after 5,000 bbl cumulative injection. In themselves, Hall plots, and any changes in their slopes, do not indicate selective placement of the gel in high-permeability channels during a gel treatment.

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  Fig. 13.25 – Hall plot illustrating an injectivity decrease after 5,000 bbl cumulative injection.

Temperature Considerations and Limits. All gels, especially polymer gels, have a finite upper temperature limit above which the gels are not stable or functional. Significant progress has been made over the past two decades in increasing the upper temperature limit for the successful application of conformance-improvement gels. A continuation of this trend can be reasonably expected.

For CC/AP gel technology, the reservoir temperature limit for applying matrix-rock, near-wellbore total-shutoff treatments is reported to be 300°F. Sydansk and Southwell reported that the upper temperature limit for treating high-permeability-anomaly conformance problems (e.g., fractures) with this gel technology can be up to approximately 270°F. Sydansk and Southwell also discusses laboratory testing at 300°F that demonstrate how appropriately formulated CC/AP gels can essentially totally block flow to water in sandstone at high differential pressure conditions (1,000 psi per 3 in.) for an extended period of time (testing conducted for 23 days). Fig. 13.26 is a photo of a CC/AP gel that remained stable, rigid, and clear after aging for 2.5 years at 300°F. This CC/AP gel is used for near wellbore, total-fluid-shutoff purposes in high-temperature matrix-rock reservoirs. For most polymer-gel technologies, such as the CC/AP gel technology, it is necessary to increase the polymer concentration within a given formula as temperature increases to maintain gel stability, performance, and strength similar to that of the gel formula at lower temperatures.

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  Fig. 13.26 – CC/AP gel aged for 2.5 years at 300°F.

Conformance-improvement gels, consisting of an acrylamide polymer crosslinked with a set of organic crosslinking agents, have been reported to form strong and stable gels up to 350°F. This is an interesting observation because, in both this and the CC/AP conformance gel technology, it is believed that it is not the crosslinking chemistry that is limiting high-temperature gel stability, but limitations in the thermal stability of the gel’s organic polymer. Thus, one interpretation of these observations is that the acrylamide polymer used in the organic-crosslinked acrylamide-polymer gels was of a purer and more stable form.

The upper reservoir temperature limit, at which a given gel technology is stable and functional, is an interrelated function of polymer concentration and chemistry used in the gel, hardness divalent-ion concentrations within the gel’s makeup water, polymer purity, and, if used, the chemical stabilizer package. For organic polymer gels, stability is, in part, a function of the level of free-radical and free-radical-precursor chemical impurities in the polymer material itself. Free radicals cause organic-polymer backbone scission and associated polymer-gel degelation.

It is imperative to truly know what the upper reservoir temperature limit is for a conformance gel technology that is to be applied to a high-temperature reservoir and to not apply such a treatment at a temperature exceeding the temperature rating of the gel being used.

Treatable Conformance Problems. Table 13.3 provides guidelines as to which conformance problems are attractive and unattractive to treat with polymer gels.

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  Table 13.3

Gel Treatment Design. The first step in designing a gel treatment is to correctly identify the nature of the conformance problem to be treated. This includes, during water- or gas-shutoff treatments, identifying the flow path of excessive water or gas production from its source to the production wellbore.

Gel Technology Selection. The following procedure for gel technology selection is highly generalized, and the procedure should be modified as dictated by the actual reservoir conformance problem to be treated. If a service company or a company specializing in conformance-treatment gels is to be involved, they should be consulted during each step of the selection process. A prerequisite is to eliminate all gel technologies, if any, that are prohibited by locally applicable safety or environmental regulations.

First, determine the type of problem that is to be treated. That is, whether it is a matrix-rock problem or a high-permeability-anomaly problem, such as fractures. If treating a matrix-rock problem, decide if you need a gel for treating near-wellbore or deeply in the reservoir. Determine how strong the gel needs to be. If the gel must be placed deep in the reservoir, economic constraints on the unit volume cost of gel pumped need to be carefully factored into the gel technology selection process. If the gel treatment will require a shut-in time following gel placement, decide on the shut-in strategy (i.e., what shut-in time range is acceptable) and chose a gel technology accordingly. Then, begin to select a gel technology that will function as required at the reservoir temperature being treated.

Next, if treating a high-permeability-anomaly (> 2 Darcy) conformance problem, select a gel-treatment fluid that can be injected into the reservoir in a mature or partially mature state. If treating matrix-rock conformance problems for which all the permeabilities are less than approximately 2 Darcy, select a gel technology that can be injected in the gelant state. After completing these steps in the gel-selection process, decide what the initial and near-full gelation times should be. Depending on the exact needs of the treatment design so far, predict the thermal history that the gelant will experience as it is being injected. If a precise thermal history for the gelant as it is being injected is required, computer thermal-simulation work may be needed.

Based on the outcome of the gel technology selection process so far, numerous conformance gel technologies may have already been ruled out. If so, the remaining selection process may be simpler. Next, the remaining gel technologies, which fit all the gel technology selection criteria, should be sorted through to select the gel technology that will perform the most effectively in treating the reservoir conformance problem and will meet the specialized needs of the operator who is applying the gel treatment. At this point, if economically justified, comparative laboratory studies may be conducted to help select with more certainty which of several gel technologies will perform most effectively in treating the reservoir conformance problem that is to be remedied.

Treatment Sizing. At this writing, technical sophistication relating to the method used to size the volumes of various conformance-improvement gel treatments needs improvement. The encouraging news is that there are active R&D programs that are specifically pursuing the development of a more rigorous scientific and engineering basis for use in the sizing of conformance-improvement gel treatments. Seright, Liang, and Sedall reports on a sound engineering basis for the sizing of polymer-gel treatments, injected as gelants, for treating excessive water production that results when a hydraulic fracture inadvertently extends down into an aquifer or into some other type of water-bearing geological strata. Seright, Liang, and Sedall also references a user-friendly computer program for use in sizing such gelant treatments and provides information on how the computer program can be downloaded.

Unfortunately, sizing of gel treatments remains highly empirical and is often based on the experience of operators and gel service companies. There are a number of empirical guidelines for sizing conformance gel treatments. When conducting near-wellbore gel treatments in matrix-rock reservoirs for total shutoff purposes, such as when using a CC/AP gel treatment for zone-abandonment or squeeze-and-recompletion treatment purposes, the rule of thumb is to inject a gel treatment volume that extends, on the average, 6 to 9 ft radially from the wellbore. This is a good guideline when treating reservoirs with elevated temperatures (> 150°F) and large drawdown pressures (> 300 psi). For lower temperatures and lower drawdown pressures, this rule of thumb can be relaxed somewhat. The depth of gel placement must be increased for gel technologies that produce relatively weaker gel strengths. For any given gel treatment applied for total-fluid-shutoff application in the near-wellbore region in matrix reservoir rock, as the gel chemical loading is increased, the rule of thumb can again be relaxed (but do not treat, on the average, less than 3 ft radially). When using such higher chemical loadings in the gelant formula, the required depth of treatment penetration can be reduced, in part, because more chemical is available on the leading edge of gelant volume to be consumed and lost to the reservoir rock in the treated reservoir volume.

A series of CC/AP gel treatments were applied in an economically attractive manner as sweep-improvement treatments to waterflood injection wells of carbonate and sandstone reservoirs possessing fracture networks of intermediate intensity with directional trends. Gel treatment volumes ranged between 50 to 700 bbl of gel injected per perforated foot of reservoir pay zone. Fig. 13.27 shows how the incremental oil production for these treatments increased as the amount of gel injected per perforated foot increased. Gel treatment volumes for this series of treatments ranged up to 37,000 bbl of gel injected. The trend depicted in Fig. 13.27 cannot be extrapolated to an infinite volume of incremental oil production. This curve must eventually bend over and not exceed the recoverable amount of oil in any given reservoir. However, for the volumes of gel injected for this series of gel treatments, the volume of gel injected had not yet begun to approach the volume of gel required to cause the curve to bend over.

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  Fig. 13.27 – Incremental oil production vs. volume of gel injected for CC/AP gel treatments applied to a series of fractured injection wells.

Gel treatment volumes of 25 to 50 bbl (100 bbl in specialized cases) of gel injection per perforated foot of reservoir producing interval have been reported to have been injected during successful CC/AP gel water-shutoff treatments of production wells of naturally fractured reservoirs. One to two barrels of gel per foot of treated wellbore interval were injected during a series of total-shutoff CC/AP gel treatments that were successfully applied as chemical liner completions to the curved section of openhole short-radius horizontal wellbores. These gel chemical-liner treatments were applied during the drilling of short-radius horizontal wells in a thin oil column. The gel chemical-liner treatments were applied to the curved section of the openhole borehole. Without the application of these chemical-liner gel treatments, excessive and uneconomic volumes of gas would have been produced into the short interval of openhole curved section of the borehole that extended up into the gas cap. For gel water-shutoff treatments to be applied to a vertical fracture that intersects a horizontal wellbore, it has been suggested that the gel needs to be placed only deep enough so that the gel will be able to prevent direct water entry into the borehole at the point of the fracture intersection.

In general, an acceptable design strategy for sizing the volume of gel treatments applied to matrix rock (unfractured) reservoirs is to specify the radial distance that a gel treatment will extend, on the average, from the treated wellbore. The exact values of the required gel radial-penetration distance will be a strong function of, and vary widely with, the nature of the specific gel to be used, the nature of the reservoir-conformance problem, the nature of the reservoir properties, and the well’s drawdown pressure. When conducting a gel treatment in a reservoir with a significant amount of fracturing, discussing radial depth of gel penetration into the reservoir from the wellbore is near meaningless, unless the fracture reservoir plumbing is quantitatively well characterized.

Injection Rate. When injecting fracture-problem gels, especially polymer gels that undergo gel dehydration during placement, the gel should be injected as rapidly as practical (without exceeding parting or fracture pressure) if the objective is to place the gel as deeply as possible into the fracture or fracture network. If the objective is to maximize the strength of the placed fracture-problem gel, then the gel should be injected as slowly as is feasible.

In general, gel treatments should be injected as rapidly as feasible without exceeding reservoir parting or fracture pressure. For a gel with a given gelation onset time and gel that is to be injected into a matrix rock reservoir and for the situation of the gel-treatment pumping time possibly exceeding the gelation-onset time, maximizing the injection rate will maximize the amount of gel that can be injected within the gelation-onset-time constraint. Maximizing the injection rate will also reduce pumping time and costs.

A special word of caution needs to be made. If while pumping a gel treatment unexpectedly high or rapidly increasing injection pressure is encountered, normally a poor option to choose is to cut the pumping rate. When injecting a gel treatment, cutting the injection pump rate increases the residence time of the gel in the injection tubulars and results in a more structured gel being injected into the reservoir. Both of these outcomes are the opposite of what is needed if excessive injection pressure is being encountered. Also, many polymer-gel solutions are shear-thinning fluids. Thus, reducing the rate at which these gel solutions are being pumped results in a more viscous gel solution being pumped and injected. Again, this is the opposite of what is needed if excessive injection pressure is being encountered. The better options are to either stop gel injection and immediately clear the injection tubulars with water or reduce chemical loading in the injected gel.

Overdisplacement. The importance of the overdisplacement fluid itself and the volume of the overdisplacement fluid can range from negligible to profound. For example, the nature of the switch over to injecting water immediately following a large-volume weak gel treatment that is applied to an injection well as a sweep-improvement treatment is normally very straightforward and noncrucial. However, when applying a polymer-gel water-shutoff treatment to a naturally fractured reservoir surrounding a production well for which the excessive water production results from fracture channeling during a waterflood, the choice of the fluid and the volume injected of the overdisplacement fluid following gel injection is a crucial element of the treatment design and can have a major effect on treatment performance.

Balancing the following three (often opposing) requirements is critical to the success of this type of gel water-shutoff treatment. The first requirement is to displace the gel deep enough into the formation so that when the well is put back on normal production, the large near-wellbore drawdown differential pressure does not overlap some of the emplaced gel volume such that the large differential pressure will exceed the critical differential pressure for gel flow and, in turn, cause such emplaced gel to be back produced. The second requirement is that the gel is not excessively overdisplaced from the most offending and troublesome of fracture flow paths so as to permit undesired water production. The third requirement is that the gel is sufficiently overdisplaced so that the gel will not excessively block desired oil production through the fracture network to the production well. Many such successful polymer-gel water-shutoff treatments require post-treatment oil flow through fractures to the wellbore. At this writing, a lot of art is used in the selection of the overdisplacement fluid and its volume for this type of fracture-problem water-shutoff gel treatment.

The three basic varieties of overdisplacement fluids are water or brine (usually injection or produced water), a polymer solution (often the polymer solution of the gel without the addition of the crosslinking agent), and a hydrocarbon liquid (such as diesel or the reservoir crude oil). For water-shutoff gel treatments, the use of a liquid hydrocarbon has been advocated as a means to establish favorable relative permeability to oil flow in the near-wellbore environment. The pros and cons of the use of a hydrocarbon overdisplacement fluid during water-shutoff gel treatments have been vigorously debated among experts. The bottom line of these debates is that whether the use of a hydrocarbon fluid is favorable is reservoir specific and is relatively more advantageous when treating matrix-rock reservoirs. The use of a viscous polymer solution as the overdisplacement fluid helps to mitigate (or completely mitigates) the problem of a nonviscous brine overdisplacement fluid fingering into the gelant solution in the wellbore and near-wellbore environment, especially in a near-wellbore fracture environment. Additionally, there are numerous gel-treatment cases for which the use of a brine overdisplacement fluid is favored for functional, operational, safety, environmental, and/or economic reasons.

For total-fluid-flow-shutoff purposes in matrix rock, both the type of overdisplacement fluid used during a water- or gas-shutoff gel treatment and how much the gelant solution is over- or underdisplaced from the wellbore are critical. Gel will be left in the wellbore if underdisplaced. Overdisplacement can result in near-wellbore flow paths being opened to flow and essentially negating the value of the entire treatment. In general, the gel is underdisplaced, and some gel is left in the wellbore downhole near the production interval when treating matrix rock problems. Gel left in the wellbore will often spontaneously clean up during normal post-gel-treatment production, but, if not, can be cleaned/jetted out of the wellbore using coiled tubing.

Shut-in Time. After the placement of many gel treatments, the well needs to be shut in to allow the gelant solution to mature and set up. Post-treatment well shut in is mandatory following fluid-shutoff gel treatments applied to production wells in matrix rock reservoirs. Usually, the well needs to be shut in for the length of time it takes the gelant to reach near-full gel strength under the conditions encountered within the treated reservoir volume.

Returning a Well to Production. During the application of gel treatments to production wells for water- and gas-shutoff purposes, the manner in which the well is returned to production can have a major impact on the performance of the gel treatment. It is generally recommended to slowly return a gel-treated production well back to full production over a period of a day to several days. Obviously, the exact manner in which a production well should be slowly returned to full production is a strong function of the nature and the strength of the particular gel used and the nature of the reservoir being treated.

Injection Mode. There are two major modes of injecting conformance polymer-gel treatments. The single-fluid injection mode involves incorporating all the chemical components required to form the gel into a single gelant (pregel) solution. Essentially all modern conformance-improvement polymer-gel treatments are injected in this mode. As discussed in the Classification of Gel Treatment Types subsection of Sec. 13.6.1, many early polymer-gel treatments were pumped using the sequential-fluid injection mode.

Disproportionate Permeability Reduction. Sec. 13.4 reviewed the applicability, limitations, desirability, and fundamental concepts of DPR as it applies to conformance-improvement (including water and gas shutoff) treatments. It focused on the application of radial-flow DPR conformance-improvement treatments that are applied in matrix rock (unfractured) reservoirs. The development and successful application of conformance-improvement DPR gels is of substantial interest to the petroleum industry, as indicated in many sources. Gels that are used in matrix-rock radial-flow DPR gel treatments are typically characterized as being relatively weak gels.

A DPR gel treatment scheme exists that often favors the use of relatively strong DPR polymer gels, for treating excessive water or gas production problems that occur in wells producing from a fractured oil-bearing formation. Such DPR fracture-problem gel treatments, which are conducted for water-shutoff purposes, are applied in the situation in which the oil-producing layer (producing 100% oil) is underlain or overlain by a water-producing zone and the vertical fractures provide the conduit for the undesired water production. The scheme was originally developed for, and is most directly applicable to, a production well that has been hydraulically fractured, where the hydraulic fracture has inadvertently extended down into, or up into, a water zone. Such gel DPR water-shutoff treatments require that the gel be placed in the matrix reservoir rock that is adjacent to water-producing fracture. A publicly available computer program can help design and size such a DPR water-shutoff gel treatment. A strong CC/AP gel would be a good candidate for use in this type of DPR fluid-shutoff treatment. This DPR gel treatment scheme for imparting water-shutoff/reduction in fractured reservoirs is also applicable as production-well water-shutoff treatments that are applied to naturally fractured reservoirs in which the oil zone overlies or underlies a water zone or aquifer and when hydraulically fracturing through thin interbedded oil- and water-bearing geological strata.

Illustrative Field Results

The following examples illustrate field applications of various types of conformance-improvement gel treatments.

Fracture Problem Sweep-Improvements Treatments. Fig. 13.28 shows the type of production response that is possible when applying a polymer-gel treatment to a waterflood injection well to improve sweep efficiency. The sweep-improvement treatment involved the application of a CC/AP gel treatment. The figure shows the combined production-response of the four direct offsetting production wells to the gel-treated injection well. The gel treatment was applied for waterflood sweep-improvement purposes to the naturally fractured Embar carbonate formation surrounding Well O-7 of the highly mature SOB field in the Big Horn basin of Wyoming. The wide variations in WOR and oil production rate are quite common in many of the well patterns of this highly fractured reservoir. Sydansk and Moore provides more details regarding the 20,000 bbl gel treatment. The economics of applying this gel treatment were exceptionally good.

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  Fig. 13.28 – Production response to the CC/AP gel treatment applied to injector O-7 in the SOB field.

Fig. 13.29 shows seven years of incremental-oil-production response for the combined direct offset producing wells to CC/AP gel-treated injection well O-17 of the SOB field. This figure illustrates the type of treatment longevity that can be expected from CC/AP gel treatments. Well O-17 was treated in approximately the same manner and as part of the same gel treatment series cited for the Well O-7 gel treatment in Fig. 13.28.

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  Fig. 13.29 – Production response to the CC/AP gel treatment applied to injector O-17 in the SOB field (after Sydansk and Southwell).

Water Shutoff Treatments. Fig. 13.30 shows the production response type that can occur when a gel treatment is applied to a production well to reduce excessive water production. In this case, a CC/AP gel treatment was applied to a production well for water-shutoff purposes. The gel treatment was applied to the 145°F fractured carbonate reservoir surrounding production well LSD N-17P in a field in Wyoming’s Big Horn basin. The excessive water production, which was occurring during primary production, was thought to be edge water encroaching through fractures from a strong aquifer. Water production before the gel treatment was 5,000 BWPD. Following the treatment, the water production was reduced to 1,000 BWPD. There was a short-lived (several months) modest oil-production increase following the treatment that paid out the cost of the gel treatment. The primary objective and benefit was the water shutoff.

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  Fig. 13.30 – Production response to the CC/AP gel water-shutoff treatment applied to production well LSD N-17P.

More recently, a large number of CC/AP gel water-shutoff treatments have been successfully applied to often old and highly marginal production wells of the dolomitic Arbuckle formation in Kansas. The excessive and detrimental water production is believed to be aquifer water coning up to the production wells via fractures or some other type of high-permeability anomaly. Successful Kansas Arbuckle CC/AP gel water-shutoff treatments often reduce the water production rate by more than 90%.

Willhite and Pancake reported in 2004 that more than 250 CC/AP water-shutoff treatments had been applied to Kansas Arbuckle wells. Their paper reported that incremental oil production was, in general, the business driver for conducting these gel treatments. The focus of their paper was on seven of these gel treatments that were studied in detail, where downhole pressure data was obtained before, during, and after the gel treatments. Highlights relating to these seven Arbuckle gel water-shutoff treatments are as follows:

• Water production was reduced in every well by 53 to 90%.
• Incremental oil production was obtained for 5 out of the 6 wells that were produced for 6 months after the gel treatment.
• Oil productivity indexes increased following the gel treatments.
• Incremental oil production increased with increasing volume of the gel treatment for the wells that were completed open hole.
• The duration of the treatment response is expected to be a function of the volume of the gelant injected.

Rodney Reynolds reported on the performance of 300 CC/AP gel water-shutoff treatments that were applied in the Arbuckle formation of Kansas by more than 30 different operators. The 250 CC/AP gel water-shutoff treatments of Willhite and Pancake are likely a subset of these 300 gel treatments. The following analyses are based on performance data that were obtained from 95 of the 300 treatments and then factored/proportioned up to the 300 CC/AP gel water-shutoff treatments. Reynolds reported the following performance attributes for the 300 Arbuckle water-shutoff treatments (based on the 95 gel treatments analyzed):

• Shut off 110,000,000 bbl of excessive and undesirable water production.
• Generated 1,600,000 bbl of incremental oil from these, in general, old and marginal wells.
• Cost of the gel pumped ranged from approximately U.S. $10 to $15 per bbl.
• Average treatment size was 2,600 bbl of gel fluid injected.
• For gel treatments with "average performance," payout times ranged from 3 to 6 months (based on incremental oil production only).
• Average incremental oil production from these "marginal" production wells was 5,500 bbl of oil.
• Operators reported reserve development costs for the incremental oil of U.S. $2 to $7 per bbl.

Sanders, Chambers, and Lane reported on 37 CC/AP gel gas-shutoff treatments that were applied to 31 production wells in the 190 to 220°F reservoir of Alaska’s Prudhoe Bay field. It reported that these gas-shutoff gel squeeze treatments cost 75% of comparable Portland cement gas-shutoff squeeze treatments in this field and afforded a higher success rate. Sanders, Chambers, and Lane also reported that these gel gas-shutoff treatments had been credited with a gross initial (one month of production) incremental-oil-production rate of 22,000 BOPD and that these gel treatments reduced gas production to 213 MMscf/D. Sanders, Chambers, and Lane stated that "squeeze longevity has been greater than one year [to date] in some cases with drawdown pressures exceeding 1,500 psi."

Microgel Sweep-Improvement Treatments. Colloidal dispersion gels of acrylamide polymer crosslinked with aluminum citrate have been applied somewhat extensively in the U.S. Rocky Mountain region, especially in the Minnelusa sand formation. These large-volume gel treatments were applied to secondary and tertiary projects to promote in-depth permeability modification in highly heterogeneous "matrix" sandstone reservoirs. Mack and Smith reviews the recovery and economics of 29 such aluminum-citrate colloidal dispersion gel treatments. The polymer concentration of the aluminum-citrate colloidal dispersion gels was typically in the 200 to 1,200 ppm range. The mechanism by which these aluminum-citrate colloidal dispersion gel treatments function is not well understood, and technical issues relating to this technology are being debated.

Fractures Intersecting a Horizontal Well. Lane and Seright reviews the successful design and application of polymer-gel water-shutoff treatments that were applied using bullhead placement for treating excess water production from horizontal wellbores into which the excessive and competing water production was emanating from a "vertical" natural fracture that intersected the horizontal borehole and extended into an underlying aquifer. This is an emerging gel water-shutoff technology that is creating substantial interest because of the large number of expensive multilateral and/or subsea horizontal wells for which any water-shutoff treatments to be applied through these horizontal wells must be bullheaded due to their often openhole, multilateral, and/or subsea completions that do not readily permit the use of mechanical zone isolation.

Use During CO₂ Flooding. Borling reported on successful conformance-improvement CC/AP gel treatments that were applied at the Wertz field CO₂ tertiary water alternating gas (WAG) flooding project in Wyoming’s Wind River basin. He reviewed 10 injection-well gel treatments applied to a 165°F naturally fractured Tensleep sandstone reservoir. The following benefits were reported to have been derived from applying these gel treatments during the Wertz CO₂ flooding project in this naturally fractured reservoir. The gel treatments promoted incremental oil recoveries of up to 140,000 barrels per well pattern and increased oil production rates by 100 to 300 BOPD per well pattern. The gel treatments extended the economic lives of marginal well patterns by nearly two years. They reduced GORs and WORs, reduced gas and water cycling, reduced gas and water breakthrough times, and improved water and gas injection profiles. The CC/AP gel treatments reduced operating expenses, contributed substantially to the fieldwide decline-rate reduction in 1992 from 24 to 9%, were effective where conventional oilfield foams had failed, and had rapid payout times of often less than three months. The Wertz conformance-improvement gel treatments were responsible for recovering substantial reserves that would not have been otherwise recovered.

Hild and Wackowski reported on 44 injection-well CC/AP gel treatments that were applied during 1994 through 1997 at the CO₂ miscible WAG flooding project of the Rangely Weber Sand unit in northwestern Colorado. These injection well treatments (average size ~10,000 bbl) had an 80% success rate and rendered an economic rate of return of 365%.

Gas Shutoff in an Openhole Gravel-Pack Completion. A "successful and selective" gas-shutoff treatment, using an organically crosslinked acrylamide-polymer gel, has been documented. The gel treatment was applied to an offshore well in the Norwegian North Sea. The gel treatment was applied to a gravel-packed well penetrating a multilayer reservoir containing shaley sandstone strata. A temporary blocking gel of crosslinked hydroxypropyl guar was selectively placed to temporarily seal and protect the upper producing portion of the well, while the organically crosslinked acrylamide-polymer gel for shutting off the lower gas-producing strata was being injected.

Carbonate vs. Sandstone Reservoirs. Table 13.4 shows a comparison of the production response and the economic performance of a series of large-volume (4,000 to 37,000 bbl) CC/AP gel treatments that were applied, between 1985 and 1988, as sweep-improvement treatments to naturally fractured injection wells in Wyoming’s Big Horn basin. The averaged combined production responses of the four direct offsetting production wells to the treated injection wells are shown. For this set of treatments, 11 of the gel treatments were applied to the naturally fractured Embar carbonate formation and six of the gel treatments were applied to the naturally fractured Tensleep sandstone formation. The gel treatments performed well in both the carbonate and sandstone reservoirs. The difference in performance of the gel treatments in the two sets of reservoir mineralogies is believed to have resulted mostly from differences in fracture characteristics and not from differences in gel performance in the two types of mineralogical formations. The fracture network of the carbonate formation in this instance is believed to be more conducive to being successfully treated with gel sweep-improvement treatments.

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  Table 13.4

Chemical Liner Completions. More than 100 successful CC/AP gel gas-shutoff treatments were applied as chemical liner completions and were performed during a drilling program involving the drilling of short-radius horizontal wellbores in the Yates field of Pecos County, Texas. The gel chemical liner completions were applied to the openhole curved section of the horizontal wellbores. The lateral borehole of these wells penetrates a relatively thin oil column in a fractured dolomitic reservoir, where the oil column is overlain by a substantial gas cap. The openhole curved section of the short-radius borehole partially extended up into the gas cap. If the curved section of the boreholes were not sealed, the horizontal wells would produce excessive, and often uneconomic, high GORs. In 1995, the first 80 of these horizontal wellbores, which had been treated with the gel chemical liner treatments, were producing 12,500 BOPD and had recovered approximately six million cumulative barrels of crude oil.

Miscellaneous Gel-Treatment Issues

Gels Complement Portland Cement. A number of petroleum engineers believe that oilfield gel treatments are a competing technology to Portland cement. Gels of oilfield conformance-improvement treatments are, in reality, a complementary technology to Portland cement. Where Portland cement functions well, oilfield gels do not, and vice versa.

Gels are effective plugging agents for use in blocking fluid flow in flow channels with small apertures, such as pore-level flow paths in matrix reservoir rock and in microannulae behind pipe, where such microannulae often exist between a primary cement job and the adjacent geological formation material.

However, the solids contained within Portland cement prevent cement slurries from penetrating any significant distance into matrix reservoir rock or other similar small-channel flow paths. In fact, squeeze cement water-shutoff treatments function primarily by squeezing off perforations or by breaking down the formation rock and placing the cement into the newly formed reservoir partings. Even so-called microfine cement does not propagate any significant distance into oil-reservoir matrix rock of normal permeabilities, such as sandstone formations with permeabilities less than 1,000 md.

If the goal is to treat to any significant depth into matrix reservoir rock or other small flow channels such a microannulae behind pipe, the placement and maturation of a solids-free gelant solution of an appropriate gel is the preferred technique for shutting off fluid flow in such instances. However, if the goal is to plug large flow channels, such as a perforation, a large void space behind pipe, or oilfield tubulars, then the use of cement is the preferred technology. Oilfield gels, in general, simply do not have the favorable compressive strength characteristics of Portland cement that are required to plug such large flow channels, especially if there is any significant differential pressure involved in the fluid flow to be blocked. However, if solids are incorporated into the gelant solution of an oilfield gel, especially a polymer gel, the compressive strength of the resultant gel can be dramatically increased. When the solids loading is significantly increased in the gel or a local volume of the gel, the compressive strength of the gel can approach that of Portland cement.

A problem faced by petroleum engineers is determining the size of the fluid-flow channels to be plugged and whether they should pump an appropriate gel treatment or a Portland cement squeeze job. When conducting a gel production-well water- or gas-shutoff treatment for which there may be a significant distribution in the size of the offending flow channels, there may be uncertainty in the size of the problematic flow channels or significant drawdown pressures involved. In these instances, a good strategy is to cap off a gel treatment with Portland cement. The reverse order of first injecting cement and then gel is not recommended. The cement cap should not be pumped at rates that will exceed the downhole reservoir parting or fracture pressure.

Historical Trends. Part of the explanation for the historically low success rate of gel treatments applied for the first time in a new field by inexperienced petroleum engineers is that the permeability of offending reservoir flow channels tend to have permeabilities higher than initially anticipated. Several reasons for this are the tendency to average permeabilities over relatively long logging intervals, ignoring what unrecovered core intervals might be suggesting during coring operations, and incomplete core, borehole, and reservoir volumetric sampling.

The success of gel-conformance treatments tends to be proportional to the involvement of the field operator in the well-candidate selection, the treatment design, execution, and quality control. This is especially true for first-time treatments in a new field by an operator who is not highly familiar with oilfield gel treatments. An important aspect in explaining this observation is that the success of conformance-improvement and fluid-shutoff treatments is highly dependent on properly understanding and diagnosing the conformance and excess-fluid coproduction problems. These conformance problems are often best addressed and determined by the operator; however, the experience and capabilities of an oilfield-gel service company in determining and deducing the reservoir conformance problems for an operator should not be overlooked and underused.

Gel Treatment Elements That Must Be Successfully Executed. The successful application and execution of a sweep-improvement or fluid-shutoff gel treatment requires that all five of the following treatment elements be simultaneously implemented, otherwise, there is a high probability of failure.

• The conformance problem must be correctly identified.
• A proper and effective gel system must be selected.
• The gel treatment must be properly designed and sized.
• The gelant solution and/or gel must be properly applied and placed.
• The gel must function as intended downhole.

The success rate of any given gel sweep-improvement or fluid-shutoff treatment is often directly proportional to the operator’s involvement in all the gel treatment elements. The implementation of successful gel treatments for sweep-improvement and fluid-shutoff purposes requires a high degree of teamwork between the field’s operator and the service and technology providers.

Prerequisites of Good Candidate Wells and Well Patterns. Because polymer-gel conformance treatments that are applied during oil-recovery production operations are, in fact, just treatment s , the well or well pattern to be treated must be suffering from a treatable conformance sweep problem or suffering from a treatable excessive fluid coproduction problem. Because gel treatments alone do not reduce microscopic-displacement residual oil saturation, any well pattern to be treated successfully must contain sufficient remaining recoverable oil to make the treatment economical. When performing a fluid-shutoff treatment, the production well must be producing an excessive amount of unproductive competing water or gas.

Attributes of Good Well Candidates. Good well candidates for the application of gel conformance-improvement treatments during oil-recovery operations have the following attributes. Good injection-well candidates have some combination of early injectant breakthrough, an excessive injection capacity, a substantial movable oil saturation within the well pattern, and unexpectedly low oil recovery within the well pattern. Good production well candidates are characterized by some combination of high WOR or gas/oil ratio (GOR), excessive competing water or gas coproduction, a substantial movable oil saturation within the well pattern, unexpectedly low oil recovery, early water or gas breakthrough, and high producing levels within wells that are being pumped.

Quality Control Is Critical. There is a strong correlation between service companies and operators who conduct and/or insist on a strong quality control and quality assurance program during the application of conformance-improvement gel treatments and the success rate and the degree of benefits derived from the applied gel treatments.

It is important for the operator to request, and to closely monitor and/or actually participate in, the quality control program for polymer-gel conformance treatments (or for any gel technology) if the operator expects to enjoy a high success rate for such chemical treatments. This is especially true for the first application of a gel treatment in any given field. The quality control program should include, but not necessarily be limited to, assuring that the proper chemicals are being used in the actual gel formula of the treatment; before pumping the gel, formulating and testing the gel with the actual chemicals and water to be used; assuring complete dissolution of the gel chemicals before injection; when conducting matrix rock treatments, assuring that the gelant solution is injectable into the matrix reservoir rock without face plugging occurring; and taking gelant/gel solution samples regularly at or near the wellhead as the treatment is being pumped.

When performing nonroutine gel treatments using any gel, particularly for a new application or during a first-time treatment in a field, properly executed bottle testing, which is conducted in the field or at a nearby laboratory using actual field gel-formula chemicals and gel make-up water and which is conducted at reservoir temperature, is an especially powerful and effective quality control and quality assurance tool. Such testing provides a semiquantitative check on gelation rate, a semiquantitative check on final gel strength, and an indication of gel stability. In addition, such testing provides a degree of assurance that the proper chemicals are being used in the actual field gel formula, and that there are no chemical interferences involving the field make-up water that will interfere with the gel. Furthermore, such testing can provide a degree of assurance that the actual field recipe being used is the correct formula.

When conducting "bottle testing" of polymer gels at high temperatures (greater than ~180°F), the use of glass-blown sealed glass ampoules and appropriate associated safety procedures are recommended for both short-term and long-term testing. For such high-temperature gel ampoule testing, the gelant solution needs to be scrupulously deoxygenated (described in the Gel Bottle Testing subsection of Sec. 13.6.1) before placing the gel samples in the oven.

Limitations, Constraints, Pitfalls, and Risks. Polymer-gel treatments are not a panacea for rendering conformance improvement, but polymer gel treatments for sweep improvement and water and gas shutoff are a relatively new, emerging, and promising technology that should be added to the petroleum engineer’s toolbox. An important constraint is that, unfortunately, gel sweep-improvement and fluid-shutoff treatments tend to be highly well, well pattern, and reservoir specific. An improperly designed or executed gel conformance-improvement treatment can reduce oil or gas production rates, reduce ultimate oil or gas recovery from the treated well or well pattern, cause injection or production operational problems, and, following poorly designed producing-well treatments, result in excessive back production of gel.

Common pitfalls of oilfield sweep-improvement and fluid-shutoff treatments include improper diagnosis of the conformance problem to be treated with gel; applying a gel treatment to a radial-flow matrix rock reservoir suffering from a vertical conformance problem without selectively placing the gel in only the high-permeability geological strata; inadequate and improper quality control; applying a gel treatment designed for matrix rock application to a high-permeability anomaly conformance problem, such as a fracture problem; and failure to use a chemically robust and adequately thermally stable gel technology or a sufficiently strong gel formula. Additional pitfalls include the use of too small of a gel-treatment volume, insufficient involvement by the technical staff of the field operator in the well-candidate selection and in the design and execution of the gel treatment, overexpectations of what DPR and RPM gel treatments can do, an incomplete understanding of how microgels function, incomplete dissolution of all the gel’s makeup chemicals before gel-fluid injection, and failure to properly design production-well gel treatments, thereby encountering excessive back-production of the fluid-shutoff gel.

Guidelines for Most Effective Application. In general, gel sweep-improvement treatments for promoting incremental oil production are most advantageously applied to injection wells. Water coning through vertical fractures is a problem that often can be treated successfully with polymer gels. On the other hand, water coning through matrix reservoir rock is very difficult to treat successfully with gels. Generally, gel treatments that are applied for water and gas shutoff purposes are usually most advantageously applied to production wells, except as noted below. When applying gel-conformance treatments in conjunction with gas flooding (e.g., CO₂ flooding) in naturally fractured reservoirs, whether for sweep improvement or fluid shutoff, they are usually more advantageously applied to injection wells. When treating naturally fractured reservoirs with gels for sweep improvement or water shutoff, the best reservoir candidates are found when a fracture network exists of intermediate intensity (fracture spacing) with a directional trend for the most problematic fractures.

List of Water Shutoff Problems By Increasing Difficulty to Treat. Seright, Lane, and Sydansk proposed a straightforward strategy for the use of polymer-gel treatments to solve excess water-production problems. The strategy advocates that the easiest excess water-production problems to remedy should normally be attacked first. The paper advocates that conventional water-shutoff methods (e.g., cement and mechanical devices) should normally be applied first, where applicable. Table 13.5 provides a general ranking of water-production problems and treatment categories in order of increasing difficulty to treat successfully.

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  Table 13.5

Emerging Trends and Issues

At this writing, there are a number of significant emerging trends and issues relating to gel treatments. An important emerging trend is the attempt to effectively exploit and capitalize on the DPR and RPM properties exhibited by many polymer gels. This emerging trend was discussed in a previous section and, in general terms, early in the chapter. Five other important emerging trends are discussed next.

Selective Placement. High on the oil industry wish list in the area of conformance-improvement treatments is to be able to bullhead treatments during gel injection, especially polymer-gel treatments when treating matrix-rock-strata (unfractured) radial-flow conformance problems, particularly when fluid crossflow between the strata does not occur. To do this, the gelant must be injected into and/or function selectively in only the high-permeability and/or water-bearing strata. Three of the more promising selective placement strategies under study are described here.

The use of bridging-adsorption and/or flow-induced-adsorption properties of certain water-soluble polymer macromolecules are being studied as a means to promote the selective placement of conformance-improvement gels into high-permeability reservoir geological strata and selectively into water-producing strata. This scheme involves the pretreatment injection, under appropriate conditions, of a solution containing such polymers. The use of water-reactive diverting agents has been suggested as a means to selectively plug water-bearing strata.

Dual injection of two fluids to impart selective gel placement has been suggested and applied in pilot tests; however, it is not yet a routine practice, except possibly by a few large service companies. The dual-injection scheme is as follows. One of the injected fluids is a nongel, nonreactive, and nondamaging fluid that is injected into the low-permeability geological strata. The second fluid is the gelant solution that is simultaneously injected into the strata to be treated. The two fluids must be pumped down the well via isolated flow conduits, such as being pumped down two separate tubing stings or being pumped down a tubing string and the tubing annulus. When mechanical zone isolation can be used effectively (e.g., a mechanical packer), this version of the dual injection scheme is readily applicable with existing technology. The real "plum" and emerging technology in this area is to be able to dual inject the gelant and the protecting fluid without the use of mechanical-zone isolation and without performing a well-workover operation. The fluid-injection rates must be precisely controlled and selected so that the two fluids are injected only into the targeted strata. In this case, the nongelant and protective fluid that is being injected into the high-oil-saturation geological strata is often a hydrocarbon fluid, such as diesel or crude oil. The application of dual injection of fluids, which is to be applied without the use of mechanical-zone isolation, is an advanced and sophisticated technique. Such dual injection is custom designed for the well to be treated and often requires substantial computer simulation during the design phase. In addition, sophisticated downhole-pressure monitoring and computer-aided fluid-injection control will likely be required.

Selective Stimulation of Low-Permeability Strata. Another strategy being developed for treating matrix-rock vertical conformance problems is to conduct a bullhead treatment followed by selective stimulation of the damaged high-oil-saturation strata. Methods of stimulation being considered and developed are ultradeep perforation techniques, hydraulic fracturing, and, in certain and limited instances, the use of a gel chemical breaker.

Foamed Gels. Foamed gels provide the possibility of reducing the unit-volume cost of a given oilfield gel by replacing the bulk of the volume of the relatively expensive liquid phase of a gel with a relatively inexpensive gas phase. Foamed gels, in principal, would combine desirable features of foam-blocking agents and classical gels for use in conformance-improvement treatments, especially for use in the far-wellbore environment in which differential pressures are relatively low. The low density of foamed gels provides a driving force during placement in the reservoir for foamed gels to seek out different and, at times, more favorable flow paths than denser fluids, such as conventional aqueous gel fluids. This would be especially true when foamed gels are placed in highly conductive vertical fractures. Such selective placement could be particularly effective in reducing gas override, as occurs during CO₂ flooding in naturally fractured reservoirs of the U.S. Permian Basin and the Rocky Mountain region. Two countervailing issues relating to conformance foamed gels are that foamed gels are relatively more complex chemically and operationally compared with conventional gels, and their low density requires more pump horsepower to be expended during injection than conventional aqueous-based gelants of the same viscosity. Foamed gel has been applied as a conformance-improvement technology at the Rangely field CO₂ flooding project.

Solids Addition. One of the drawbacks of many gels is their low compressive strengths that prevent effective use when encountering large differential pressures in large-aperture reservoir fluid-flow conduits, such as centimeter aperture fractures or solution channels. When solids are added to polymer gels, the compressive strength of the gel can be greatly increased and increased up to that of Portland cement when the gel is fully loaded with an appropriate solid.

There are numerous near-wellbore conformance problems that are best treated with gel. A small minority of these wells randomly and "unpredictably" require a plugging material with more compressive strength than the gel alone can provide. Previously when such unexpected well and conformance problems were encountered and detected during a gel treatment, a separate cement job had to be called out after, or during, the gel job. When an unexpected well and conformance problem is now encountered, appropriate solids can be added to the gel fluid as it is being pumped and only needs to be added near the end of gel fluid injection to be able to cost effectively plug the flow conduits that have unexpectedly wide apertures. This can be done cost effectively on the fly without the need to subsequently conduct an additional cement squeeze treatment. One of the keys to the effective addition of solids to conformance-improvement gels is to know how to precisely control the screen out of such solids addition during the placement of the gel treatment.

Gels Functional Only in the Presence of Water. Attempts have been made in the past to develop conformance-improvement gel technologies that are functional and active only in the presence of water, but inactive or inactivated in the presence of oil. There has been revived interest in developing such a gel technology. One of the technical challenges that has to be overcome is that even when there is 100% oil flow in a matrix-rock, connate water also exists.

Gel Breakers

When an aqueous gel is contacted under appropriate conditions, chemical breakers can degrade the gel back to a low-viscosity and watery solution. Two possible reasons to use a breaker after a conformance-improvement gel treatment are to remove gel from the wellbore or perforations and to undo a gel treatment in the near-wellbore region if it was determined after its placement that the emplaced gel was not beneficial.

There are several reasons why a chemical breaker cannot be used to successfully and fully degrade a gel that has been placed deeply in either a matrix-rock or a fractured reservoir. First, successfully delivering the chemically reactive gel-breaker solution deeply in an oil reservoir is a daunting task. Second, and more fundamentally problematic, even if a chemical breaker solution could be 100% effective in the reservoir during its entire gel-breaking life, once injected into the reservoir, the gel-breaker solution would tend to wormhole through the emplaced gel. Thus, the chemical breaker would only be able to regain a small fraction of the pregel-treatment fluid-flow capacity within the gel-treated reservoir volume.

Many biopolymer gels and freshly placed inorganic gels can be chemically broken and reversed by contacting them with a strong acid solution. However, acids are usually ineffective at chemically breaking down metal-crosslinked synthetic-organic-polymer gels, such as metal-crosslinked acrylamide-polymer gels. Acrylamide-polymer gels can be chemically degraded back to a watery solution by contacting them with a free-radical chemical breaker, such as hydrogen peroxide, sodium hypochlorite of bleach, and ammonium peroxide. Free radicals chemically degrade polymer gels by a polymer-backbone scission mechanism.

Hydrogen peroxide is, in many instances, the most chemically powerful of the gel chemical breakers commercially available. However, its decomposition is catalyzed by tubular rust and many other oilfield substances, such that the injected hydrogen peroxide can be rendered essentially spent before it can be delivered to the downhole gel. The use of hydrogen peroxide may be favored when plastic-coated well tubulars have been used. Hydrogen peroxide is an extremely reactive chemical. It is advised to not inject concentrations exceeding 10% hydrogen peroxide; however, a concentration of less than 5% is ill advised, because ineffectively low concentration of hydrogen peroxide will often result downhole. Hydrogen peroxide decomposes to water and free oxygen during the gel-degradation process. The creation of oxygen in the wellbore and/or the reservoir after the hydrogen peroxide is injected raises safety issues that need to be addressed as part of the hydrogen peroxide selection process.

Bleach (containing sodium hypochlorite) is probably the most widely used material to chemically breakdown acrylamide-polymer gels. It is more chemically robust downhole than hydrogen peroxide. A note of caution: when hydrogen peroxide or bleach is used to break gels crosslinked with a chromium (III)-containing crosslinking agent, some of the chromium (III) will be converted, at least temporarily, to chromium (VI). Because any Cr (VI) that might be formed in the chemically reducing reservoir environment is rapidly converted back to relatively nontoxic Cr (III), field experience has shown that this is often only a theoretical concern. Most oil reservoirs are characterized as having a chemically reducing environment. It should be noted that certain types of metal-crosslinked polymer gels, under certain conditions, can be degelled when contacted with an aqueous solution containing a high concentration of either a caustic chemical (e.g., sodium hydroxide) or a strong ligand (e.g., oxalate).

If an effective delayed and single-fluid reversible-gel technology, especially a reversible-polymer-gel technology, were to be developed in which the gel chemical breaker or gel-breaking mechanism were chemically built directly into the gel structure itself, there would be numerous oilfield applications for such reversible gels. The delayed gel reversal/degelation time would need to be controllable.

If a water-soluble chemical breaker (breaker not built into the gel structure itself) were incorporated into an aqueous gel formula and the gel were placed downhole under a differential pressure (as usually is the case), then as the chemical breaker begins to break down the gel, the differential pressure would begin to squeeze water, including the dissolved breaker, out of the gel. Unfortunately, increasing breaker concentration is required as the concentration of the polymer increases in the gel. When a water-soluble breaker is being squeezed out of the partially broken gel, the opposite trend is occurring. Thus, the use of water-soluble chemical breakers incorporated into a single-fluid aqueous gel under differential pressure always results in an incomplete gel break and always leaves a significant gel residue. To date, the addition of a water-soluble chemical breaker into a single-fluid aqueous gel formula has not proven effective in fully degrading a gel when the gel is broken under differential pressure.

Foams

Currently, the three major applications of conformance-improvement oilfield foams are as a mobility-control agent during steamflooding, a mobility-control agent during CO₂ flooding, and gas-blocking/plugging agents placed around production wells, often applied in conjunction with a gas-flooding project.

Although the use of foams for oil-recovery applications has been actively considered and studied for more than forty years, widespread application of foams for improving oil recovery has not occurred to date. In the pioneering work of the late 1950s and through the early 1970s, foam was identified to be a promising candidate for improving mobility control and sweep efficiency of oil-recovery drive fluids, especially gas-drive fluids. Early R&D personnel observed the following foam characteristics:

• Foams can be quite effective at reducing gas mobility.
• On the microscopic scale, the gas and liquid phases of foam flow separately through porous media with the liquid usually flowing as thin films or lamellae that are separated by gas bubbles.
• The pressure gradient during foam flow is proportional to the liquid flow rate, but quite independent of the gas flow rate.
• The macroscopic effective viscosity of foam during its flow in porous media is a function of the number and strength of the lamellae (alludes to the importance of foam texture and bubble size).
• Foams, at times, tend to promote larger mobility reductions in high-permeability porous media, as compared with lower-permeability porous media (an attractive property for improving conformance and reducing channeling).
• Foams might be good candidates for use as gas-flow blocking agents.

These early workers also noted that oil in porous media often tends to destabilize most aqueous foams and tends to harm oilfield foam performance. A number of the earliest oil-industry proponents of the use of foam hoped that foams would eventually lead to routine "air flooding" of reservoirs. This has not come to fruition.

The earliest study of foams for use during oil-recovery flooding operations attempted to capitalize on the ability of numerous aqueous-based foams to significantly reduce the mobility of gas flow during gas flooding and to be able to substantially improve oil-recovery flood sweep efficiency when flooding with a gas. In concept, foam flooding offers an alternative to polymer flooding. That is, foams can also provide mobility control during oil-recovery flooding operations. Early study and development focused on foam use for mobility-control purposes during oil-recovery flooding projects, especially during gas-flooding operations.

The focus of foam development and application has changed in more recent years. Two major factors have been largely responsible for promoting this change. First, it is unclear if foams (especially steam and natural gas foams) can be propagated distances of more than 100 ft in an oil reservoir because of the substantial minimum pressure gradient required for foam propagation and in view of the small pressure gradients that exist in most of the volume of matrix rock reservoirs. Second, economics now tend to favor small-volume chemical treatments (e.g., gel conformance-improvement treatments) over chemical-based improved oil-recovery flooding operations. Thus, the focus of oilfield foam development and application has shifted somewhat toward the use of foams as blocking/plugging agents that are part of relatively small volume treatments applied through production wells, especially for use as blocking agents to gas flow. The fluid-flow-blocking and permeability-reducing propensity of foams is one of the major factors hampering effective application of mobility-control foams (especially steam and natural gas foams) in the far-wellbore environment. The significant negative impact that crude oil often exerts on the desired performance of foams during mobility-control flooding also helped to shift the focus of oilfield foam use from mobility-control applications to fluid-flow-blocking treatments.

Conventional foams (i.e., not polymer-enhanced foams and foamed gels) are considered effective only when placed in matrix reservoir rock and are not applicable when placed in reservoir fracture channels with aperture widths on the order of greater than 0.5 mm. The application of foams for sweep-improvement and gas/water-blocking purposes is considered to be an advanced and nonroutine form of an oilfield conformance-improvement operation. It is recommended that the average petroleum engineer not undertake a foam conformance-improvement operation without in-house or commercially available technical support and/or without support from an organization that has expertise in conformance-improvement foam technologies. In addition, before implementing a foam conformance-improvement operation, it is usually necessary to perform a laboratory evaluation of the proposed foam formulation and the actual foam process to be used in the field.

Fundamentals and Science of Foams

General Nature of Foams. Bulk foam, as found in the head of a glass of beer or as found in association with cleaning solutions, is a metastable dispersion of a relatively large volume gas in a continuous liquid phase that constitutes a relatively small volume of the foam. An alternate definition of bulk foam is an "agglomeration of gas bubbles separated from each other by thin liquid films." In most classical foams, the gas content is quite high (often 60 to 97% volume). In bulk form, such as in oilfield surface facilities and piping, foams are formed when gas contacts a liquid in the presence of mechanical agitation. As used herein, bulk foams are foams that exist in a container (e.g., a bottle or pipe) for which the volume of the container is much larger than the size of the individual foam gas bubbles.

Capillary processes control the formation and properties of foams in porous media. Foams for use in conformance improvement are dispersions of microgas bubbles usually with diameters/lengths ranging between 50 and 1000 μm. Foam in porous media exists as individual microgas bubbles in direct contact with the wetting fluid of the pore walls. These microgas bubbles are separated by liquid lamellae that bridge the pore walls and form a liquid partition on the pore scale between gas bubbles. Foam propagates in most matrix reservoir rock as a bubble train in which each gas bubble is separated from the next by a liquid lamellae film. In many instances, individual foam bubbles in reservoir matrix rock can be many pore bodies in length. Gauglitz et al. have defined foam structure in porous media as "a dispersion of gas in a continuous liquid phase with at least some gas flow paths made discontinuous by thin liquid films called lamellae."

All foams discussed in this chapter and all foams that are used for conformance improvement have surfactants dissolved in the foam’s liquid phase to stabilize the gas dispersion in the liquid. The gas phase of a foam can include both a classical gas and a supercritical gas, such as supercritical/dense CO₂. Except as specially noted, all foams discussed in this chapter that are used to impart oilfield conformance improvement are aqueous-based foams. This chapter is limited primarily to the discussion of surfactant-stabilized aqueous-based foams for use in improving conformance during oil-recovery operations.

Fig. 13.31 shows a 2D slice of a generalized bulk foam system. The thin liquid films separating the foam gas bubbles are defined to be foam lamellae. The connection of the three lamellae of a gas bubble at a 120° angle is referred to as the Plateau border. In persistent bulk foams, spherical foam gas bubbles become transformed into foam cells, polyhedra separated by nearly flat thin liquid films. Such a foam is referred to as a dry foam. The polyhedra foam cells are almost, but not quite, regular dodecahedra. In three dimensions, four Plateau borders of a foam cell meet at a point at a tetrahedral angle of approximately 109°.

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  Fig. 13.31 – Generalized 2D slice of a bulk foam system.

Foams in porous media generally have bubbles that are as large as, or larger than, the pore bodies. Foam exists in reservoir-rock porous media as bubble trains where the Plateau border of the foam lamellae is formed at the pore wall and has, for static nonflowing foam in the pore body, an angle of about 90° between the liquid lamellae and the pore wall.

Foaming Agents. Surfactants are the necessary third ingredient required for the formation of the foams discussed in this chapter. An understanding of basic surfactant chemistry is essential when selecting a proper surfactant for a given oilfield foam application.

A surfactant molecule contains, within the same molecule, both a polar and nonpolar segment. The polar or hydrophilic segment of a surfactant molecule has a strong chemical affinity for water. The nonpolar or lipophilic segment has a strong chemical affinity for nonpolar hydrocarbon molecules. When water and oil or water and gas are in contact, surfactant molecules tend to partition to the oil/water or gas/water interface and reduce the interfacial tension of the interface. Fig. 13.32 depicts a surfactant molecule residing at an oil/water interface. The partitioning of the surfactant molecule to the gas/water interface and the ensuing reduction of the interfacial tension is the primary mechanism through which surfactants stabilize dispersions of gas in water to form metastable foam.

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  Fig. 13.32 – Depiction of a polymer molecule residing at an oil/water interface.

Surfactants are classified into four types that are distinguished by the chemistry of the surfactant molecule’s polar group.

• Anionics—The polar group of an anionic surfactant is a salt (or possibly an acid) where the polar anionic group is directly attached to the surfactant molecule and the counter and surface-inactive cation (often sodium) is strongly partitioned into the aqueous side of an oil/water or gas/water interface. Anionic surfactants are often used in oilfield foams because they are relatively good surfactants, generally resistant to retention, quite chemically stable, available on a commercial scale, and fairly inexpensive.
• Cationics—The polar group of a cationic surfactant is a salt where the polar cationic group is directly attached to the surfactant molecule and the counter and surface-inactive anion is strongly partitioned into the aqueous side of an oil/water or gas/water interface. Cationic surfactants are infrequently used in oilfield foams because they tend to strongly adsorb on the surfaces of clays and sand and are relatively expensive.
• Nonionics—The polar group of a nonionic surfactant is not a salt, but rather a chemical specie, such as an alcohol, ether, or epoxy group, which promotes surfactant properties by imposing electronegativity contrast. Nonionic surfactants are less sensitive to high salinities and can be relatively inexpensive.
• Amphoterics—Amphoteric surfactants contain two or more characteristics of the previously listed chemical types of surfactants.

Fig. 13.33 illustrates the chemical structure of selected surfactants. Within any of the surfactant types, there can be substantial variations in their chemistries and performance. The chemistry, size, and degree of branching of the lipophilic segment of a surfactant molecule can have a major impact on foam-surfactant performance, just as the chemistry of the hydrophilic portion of a surfactant molecule can have. Even small and subtle differences in the lipophilic segment can alter surfactant properties dramatically. Most commercial surfactant products contain a distribution of surfactant types and sizes that adds further complexity of the surfactants used in conformance-improvement foams.

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  Fig. 13.33 – Surfactant chemistry types.

When using foam in conjunction with steam flooding or any elevated-reservoir-temperature application, it is important to choose a surfactant that will be thermally stable over the needed life of the foam in the reservoir. Historically, alpha-olefin surfactants and petroleum sulfonate surfactants have been most widely used in foams applied to high-temperature (> 170°F) reservoirs. Sulfate surfactants have been used at times in low-temperature (< 120°F) reservoirs.

Alpha-olefin sulfonates have emerged to be one of the most popular and widely employed surfactant chemistries for use in foams. This has resulted in large part because of their combined good foaming characteristics, relatively good salt tolerance, good thermal stability, availability, and relatively low cost. Mixtures of different surfactant chemistries have been suggested to provide advantages when formulating conformance foams.

The use of fluorinated surfactants in foam formulas has shown some promise. Fluorinated surfactants used with other surfactants have been reported to often improve the tolerance of the foam to oil. Fluorinated surfactants have not been widely used in field applications of oilfield foams largely because of their relatively high cost.

Foam Properties. Several properties important to the characterization of bulk foam, as might exist in a bottle, are foam quality, foam texture, bubble size distribution, foam stability, and foam density. Foam quality is the volume percent gas within foam at a specified pressure and temperature. Foam qualities can exceed 97%. Bulk foams, having sufficiently high foam quality such that the foam cells are made of polyhedra liquid films, are referred to as dry foams. Oilfield conformance-improvement foams typically have foam qualities in the range of 75 to 90%. When propagated through porous media, the mobility of many foams decreases as foam quality increases up to the upper limit of foam stability in terms of foam quality (an upper limit of often > 93% foam quality). When dealing with oilfield steam foams, steam quality refers to the mass fraction of water that is converted to steam.

Foam texture is a measure of the average gas bubble size. In general, as a foam texture becomes finer, the foam will have greater resistance to flow in matrix rock.

Bubble size distribution is a measure of the gas bubble size distribution in a foam. When holding all other variables constant, a bulk foam with a broad gas-bubble size distribution will be less stable because of gas diffusion from small to large gas bubbles. The imparted resistance to fluid flow in porous media by a foam will be higher when the bubble size is relatively homogeneous.

Stability of an aqueous-based foam is dependent on the chemical and physical properties of the surfactant-stabilized water film separating the foam’s gas bubbles. Foams are metastable entities; therefore, all foams will eventually break down. Foam breakdown is a result of the foam liquid films excessively thinning and rupturing with time and a result of gas diffusing from smaller bubbles into the larger bubbles, thus coarsening the foam’s bubble size. External effects, such as contact with a foam breaker (e.g., oil or adverse salinities), contact with a hydrophobic surface, and local heating can break foam structure.

Factors affecting foam lamellae stability include gravity drainage, capillary suction, surface elasticity, viscosity (bulk and surface), electric double-layer repulsion, and steric repulsion. The stability of foam residing in porous media evokes a whole series of additional considerations that are addressed in the next subsection of this chapter.

One of the attractive features of foams for use with gas-flooding operations is the relatively low effective density of foams. (As a countervailing note of reference, conformance-improvement foams formulated with supercritical CO₂ can attain densities exceeding the density of some crude oils.) The low-density feature has positive ramifications for foams used in both mobility-control flooding and for blocking fluid-flow. The low effective density causes the foam to be selectively placed higher in the reservoir interval where gas-flooding flow or gas production is most likely occurring.

For technical clarification, foam flow in porous media actually occurs as bubble trains of gas bubbles separated by liquid lamellae. Thus, strictly speaking, foam flow in porous media occurs as two phase flow—namely, gas bubble flow and liquid lamellae flow. In this more technically correct view, it is really the low density of the gas phase that promotes favored placement of the foam higher in the reservoir. During gas flooding, such as steam or CO₂ flooding, low-density foams used for mobility control are well suited to address and reduce the common problem of gas override that often precludes injectant oil-recovery gas from contacting the oil saturation lower in the reservoir vertical interval. Selective mobility-control by low-density foams in the upper portion of the reservoir will force more displacing fluid gas to contact oil-saturated sections lower in the reservoir.

The low density of foam used during a gas-blocking treatment will tend to drive the placement of the foam higher up in the reservoir interval where the offensive gas flow and production is most likely occurring. In this respect, foams for use in blocking-agent treatments are well suited to treat gas coning and gas cusping problems occurring at production wells. Also, gas override in a relative homogeneous reservoir with good vertical permeability causes excessive gas production in the upper interval of production wells. Low density gas-blocking foam helps favorable placement around such problem wells.

When considering the potential benefit of low density during foam placement of a conformance-improvement operation, the relative effects of gravity forces vs. viscous forces that are operating during the foam placement need to be carefully considered. That is, the horizontal differential pressure gradient vs. vertical differential pressure gradient that the foam will experience during its flow and/or placement in the reservoir needs to be evaluated.

Foams in Porous Media. Understanding how foams behave and perform in porous media is critical to the effective application of foams for conformance-improvement applications in matrix-rock reservoirs. How foam exists and functions in porous media is not always intuitively obvious on the basis of how foam behaves in bulk form (e.g., when existing in a bottle).

Properties. In addition to the properties of bulk foams, which for the most part, are applicable to foam that resides in porous media, there are two specialized properties of foams that reside in porous media.

In general, foams in matrix rock pores do not exist as a continuous interconnected liquid/film structure that contains gas bubbles, as is the case for a bulk foam. Foam in porous media exists as individual gas bubbles that are in direct contact with the wetting fluid of the pore walls. These in-situ microgas bubbles are separated by liquid lamellae that bridge the pore walls and form a liquid partition on the pore scale between the in-situ foam gas bubbles. Foam propagates in most matrix reservoir rock as a bubble train, where each gas bubble is separated from the next gas bubble by a liquid lamellae film. The length of a foam gas bubble in porous media is on the order of, or exceeds, one pore length.

See the subsection on General Nature of Foams in Sec. 13.7.1 for additional discussion of the nature of foams in porous media. Foam stability and performance in porous media is strongly influenced by lamellae/pore-wall interactions. Foam texture in porous media is believed to most often be controlled by the porous media.

Mobility Reduction. Compared with the mobility of the gas phase from which a foam is formulated, the mobility of the resultant foam is dramatically reduced. Often, the mobility of the foam in foam-saturated reservoir matrix rock is less that the mobility of the aqueous phase alone that is used in the foam formula. For a given foam formula, there often is a general trend of decreasing foam mobility with increasing foam quality (gas content) up to the upper foam-quality stability limit.

Foam mobility reduction results from a combination of foam-induced permeability reduction and, on the macro scale, apparent foam-induced viscosity enhancement. Foam-induced mobility reduction is caused by at least two different mechanisms: the formation of, or an increase in, the trapped residual gas saturation; and increased resistance to flow of the gas phase resulting from the drag of propagating the foam-lamellae aqueous films through constricting pore bodies and, especially, through constricted pore throats.

As the texture of a foam becomes finer, the apparent viscosity of the foam increases, and the foam mobility decreases. This occurs because the number of foam lamellae films within a given volume of the porous rock has increased; thus, foam texture is an important variable in determining the amount of mobility reduction that will occur during foam flow.

Rheology, Flow, and Transport. The apparent viscosity of foam (on the macro scale), as it is being propagated through porous media, frequently exhibits shear-thinning behavior. Such foams on the macro scale are a pseudoplastic fluid in porous media. Foams used in oilfield conformance treatments usually exhibit a yield stress. That is, the shear rate remains zero until a threshold stress and/or pressure gradient is reached, and, thereafter, foam flow begins.

Foam placement and saturation in water-wet reservoir matrix rock with normal permeabilities greatly reduces permeability to subsequent flow of gas. The reduction in gas permeability can be on the order of several hundred-fold. Following such foam placement in matrix reservoir rock, the relative permeability to water has often experienced little change. The substantial selective reduction of the gas permeability has been attributed, in part, to a higher trapped gas saturation than occurred before foam flooding. Such foam trapped gas saturations have been reported to range between 10 and 70% PV, depending on surfactant type and the presence of oil during the foam flood.

It is the drag and the resistance to flow of the lamellae through the pore structure that imparts much of the mobility reduction of foam flow. Fig. 13.34 shows a schematic drawing of a flowing train of foam gas bubbles and the trapped gas saturation during foam flow through a foam-saturated porous media. Only a small percentage, typically 1 to 15%, of the foam gas saturation actually flows. The stationary portion of the foam blocks gas flow in intermediate and small-sized flow paths and lowers the effective permeability to gas flow. In the flowing portion of the foam, interactions of the foam gas bubbles and the interspaced lamellae determine the effective foam viscosity of the foam that flows in the largest pore flow paths. The resultant effective foam viscosity is most often larger than the effective viscosity of the water when water alone saturates the same flow channels.

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  Fig. 13.34 – Pore level schematic of a flowing gas-bubble train and the trapped gas saturation during foam flooding in porous media. Flowing gas bubbles are unshaded; trapped gas is darkly shaded; liquid phase is dotted; and solid phase is hatched.

The rheology of flowing foam in porous media is controlled by the dynamics of foam generation and decay, in combination with the resulting foam texture and bubble size distribution of the equilibrium in-situ foam. Foam flow in porous media is a complex process that involves a number of interacting microscopic foam events. Macroscopic manifestations of foam flow in porous media are the result of the combination of many pore-scale events that involve foam bubble evolution and foam bubble/lamellae pore-wall interactions during multiphase flow. Fully understanding the macroscopic manifestation of foam flow in porous media requires understanding the pore-level phenomena of foam flow.

Foam lamellae formation during foam flow in porous media results from a combination of three foam-generation mechanisms: snap off, division, and leave behind. The snap-off mechanism is believed to be the dominant foam-generation mechanism during foam flow and transport in porous media.

During foam flow through porous media, foam destruction (decay and coalescence) is primarily brought on by capillary suction and gas diffusion. In certain instances, gravity can also contribute to foam decay when there is a significant density difference between the gas and liquid phases of the foam. The gas diffusion mechanism leads to coursing of the flowing foam and is normally of minor consequence for foam flow in porous media. Capillary suction coalescence is the dominant mechanism for lamellae breakage during foam flow in porous media and is strongly affected by the surfactant used in the foam. If the lamellae of a foam can withstand the imposed capillary suction pressure, such a foam is termed a "strong foam."

Coalescence of flowing foam bubbles in porous media is more complicated than the coalescence of static bulk foam. A limiting capillary pressure, P_c*, exists above which foam coalescence is significant and below which coalescence in minimal. Limiting capillary pressure varies with gas flow rate, absolute permeability, and the surfactant used in the foam. The limiting capillary pressure of flowing foam in porous media is typically on the order of 0.44 psi (3 kPa).

Many foams flowing in matrix sand-reservoir rock do so under steady flow at, or near, P_c*. Such foam flow occurs when the gas fractional flow rate is in the high range (i.e., high foam quality) and when the gas and liquid flow rates are fixed. In the P_c* foam-flow regime, the wetting-liquid (usually water) saturation is nearly constant and is independent of gas and liquid velocities over a wide range. This limiting wetting-phase saturation is thought to result from the constant P_c*.

Foam flow in the limiting capillary pressure (P_c*) regime is quite interesting. When the liquid (water) velocity is held constant and the gas velocity is varied, the pressure drop is highly independent of the gas flow rate. Increasing the liquid velocity while holding the gas velocity constant usually results in a linearly increasing pressure drop. Increasing both the liquid and gas velocities, while holding the fractional flow constant, produces a linear response of pressure drop vs. total flow rate. Steady-state liquid and gas saturations are independent of gas fractional flow.

Foam flow in the P_c* regime has a number of important ramifications. Under such foam-flow conditions, the aqueous phase saturation remains constant, as does the relative permeability of the water phase.

However, not all foam flow occurs under the limiting-capillary-pressure regime. The P_c* regime for foam flow does not necessarily apply for low gas fractional flow (i.e., flow of low-quality foams). Osterloh and Jante studied a wide range of flow rates and fractional flows (foam qualities) for foam flow in a 6,200 md sand pack at 302°F. During their flooding experiments involving a nitrogen foam and an alpha olefin-sulfonate-surfactant foam formula, they observed two foam-flow regimes when varying the foam quality. During flow of foam with foam qualities exceeding 94%, the pressure gradient was quite independent of gas velocity at a fixed liquid velocity and varied with liquid velocity to approximately the 0.33 power. The liquid saturation remained nearly constant. During flow of foam with lower foam qualities (< 94%), the opposite behavior was noted. The pressure gradient increased little with increased liquid velocities, but increased with gas velocity to the 0.31 power. It was suggested that the transition between these two foam flow regimes occurred at the point where the limiting capillary pressure was attained. Subsequently, Alvarez et al. reported on what is described to be a unified model for steady-state foam flow at both high and low foam qualities and a model that helps reconcile apparently contradictory foam flow data for foam flow occurring in reservoir-rock porous media. The unified model is predicated on the contention that, in the high-foam-quality flow regime of Osterloh and Jante, foam flow behavior is dominated by capillary pressure and coalescence and that, in the low-foam-quality flow regime, foam flow behavior is dominated by bubble trapping and mobilization.

Steady-state foam flow refers to foam flow in a given length of porous media after foam has been propagated and formed throughout the entire length of the porous media in question, and the liquid saturation profile is nearly uniform throughout the entire length of the porous media. Transient foam flow in a given length of porous media refers to foam flow as foam is progressively being formed and propagated along the length of the porous media and, as the liquid saturation profile varies from low to high along the length of the porous media, in the direction of flow.

An alternative definition for "strong foam" to the one given previously is based on the continuity of foam within porous media. For a given volume of porous media that contains foam, a "continuous gas foam" exists when there is at least one continuous flow path along the length of the porous media that is uninterrupted by the existence a foam lamellae. A "discontinuous gas foam" exits when there is at least one foam lamellae along all the gas flow paths over the entire length of the porous media volume. Thus, when gas must flow through a discontinuous gas foam in a given porous media, the gas must mobilize and propagate (or possibly rupture) at least one foam lamellae. A strong foam is said to exist when a discontinuous gas foam occurs. A weak foam is said to exist when a continuous gas foam occurs.

Chang and Grigg have studied and reported on the effect of foam quality and flow rate on the imparted mobility reduction resulting from the steady state flow of dense CO₂ foam in porous media at reservoir-like temperature and pressure conditions. Over the range of foam qualities normally used in oil reservoirs and for the studied conditions and foam formula, CO₂ foam mobility was observed to increase with increasing flow rate and to decrease with increasing foam quality.

Magnetic resonance imaging has been reported to be a useful tool for high-resolution viewing of foam flow in selected porous media.

Foams have been reported to have the very desirable feature, under certain conditions, of being able to reduce mobility to a greater extent in high-permeability porous media, as compared with lower-permeability porous media.

Questions persist about the ability to propagate and place foams deep within matrix rock. One aspect of this concern is the often destabilizing effect of oil on foam transport. The next subsection discusses the effect of the presence of oil. Another aspect of this concern is the pressure gradient that is normally required for initiating and maintaining foam flow. Can foam flow be maintained in the far-wellbore regime where pressure gradients are inherently low?

As a result, in part, of the low surface tension of CO₂, CO₂ foam is more easily propagated (than nitrogen, steam, and natural-gas foams) at the relatively small pressure gradients that exist in the far-wellbore region of most reservoirs. Gauglitz, et al. reports on laboratory results and literature references indicating that for dense/supercritical CO₂ foams, minimum pressure gradients in porous media of less than 1 psi/ft can exist for foam flow when flooding with strong CO₂ foams. However, under similar conditions, the minimum pressure gradients for the formation and flow of strong nitrogen foams are reported to be a factor of 20 psi/ft or greater. Viewed conversely, the relatively high minimum pressure gradient for foam flow in many instances can be advantageously used as the basis for foam treatments to block gas flow.

Another important aspect of the problem of deep foam placement is surfactant adsorption/retention. The upcoming subsection Surfactant Adsorption/Retention discusses adsorption and retention of surfactant during foam transport through matrix reservoir rock.

Effects of Oil and Wetting. Much has been published on the interaction of crude oil and foam within porous media—with much of this literature discussing negative interactions. When oil contacts a foam, the oil often has a destabilizing effect. The probability that oil will destabilize foams has been a major impediment to the widespread use of foams for oilfield conformance-improvement applications. The destabilizing effects of oil can range from minor to very deleterious. Schramm reviews the mechanisms by which crude oil can destabilize foam in porous media. Foams are more stable in the presence of some crude oils as compared to others. In general, foams are more highly destabilized when contacted with lighter, lower viscosity crude oils.

The degree of sensitivity of foam to oil as foam flows through matrix reservoir rock depends on both the nature of the foam and the nature of the crude oil. Although many conformance-improvement foams are sensitive to oil contact, some foam formulas are quite resistant to destabilization by crude oil.

It has been suggested that even foams sensitive to crude oil can still be effective in matrix reservoir rock if the residual oil saturation is < 10%. On the other hand, oil-sensitive foams will be significantly destabilized by the contact with the crude oil at higher oil saturations (e.g., 20% oil saturation). It has also been suggested that foam sensitivity to oil might be advantageously exploited. That is, by using foams to selectively reduce gas or water mobility in high-gas or water-saturation flow paths within an oil reservoir where the oil saturation is low, while the foam is simultaneously being destabilized and unable to reduce the oil mobility and productivity in the high-oil-saturation flow paths within the reservoir.

The general consensus of several investigators is that oil wetting is detrimental to foam stability and propagation in matrix reservoir rock; however, there is not universal agreement on this point.

Surfactant Adsorption/Retention. The degree of surfactant adsorption/retention often can "make or break" the oil-recovery performance and the economics of a foam application. "Retention" is the combination of all other mechanisms, other than adsorption, that retards surfactant propagation during foam propagation through reservoir matrix rock.

Surfactant adsorption/retention under reservoir conditions should be one of the key factors considered and is one of the first parameters that should be examined and/or estimated when considering the application of foam injection for mobility-control purposes during a gas flooding operation.

The use of low-cost adsorption/retention sacrificial agents in the foam or such agents injected before the foam have been proposed as a means to alleviate the adsorption/retention problem. Surfactant adsorption is often lower when foam is transported though an oil-wet reservoir.

Injection Mode. One of three distinctly different modes is used for injecting conformance-improvement foams: sequential injection, coinjection, or preformed foam created on the surface before injection. Sequential injection involves the alternate injection into the oil reservoir of the foam’s gas and aqueous phases. Coinjection involves the coinjection into the reservoir of the foam’s gas and liquid phases. Because of the substantial effective viscosities of foams and the associated poor injectivity of preformed foams, early applications of conformance-improvement foams tended to involve the sequential-injection or coinjection mode. Also, sequential-injection and coinjection are substantially simpler to implement in the field. Sequential injection also avoids tubular corrosion problems if the gas and the foaming-solution form a corrosive mixture, such as found in CO₂ foams.

The concept, which is supported by laboratory evidence, is that during the sequential or coinjection mode, foam will form in situ in the matrix reservoir rock. Supporting this contention is the expectation that low-viscosity and high-mobility gas will tend to finger into the aqueous foaming solution and generate the foam in situ.

However, there are two significant countering concerns. First, as the gas begins to finger into the aqueous solution and form foam in situ, the newly formed foam will substantially reduce subsequent gas fingering and divert subsequent gas flow away from the remaining aqueous foaming solution residing just ahead of the initially formed foam. This phenomenon results in ineffective and inefficient use of the injected foam chemicals and fluids in generating foam. Second, in intermediate and far wellbore locations, there may not be enough mechanical energy and/or differential pressure to generate foam in situ when using common foaming solutions. This is especially of concern for steam, nitrogen, and natural-gas foams.

Krause et al. reported on relatively near-wellbore production-well foam treatments that were applied at the Prudhoe Bay field to reduce excessive GOR emanating from the production of reinjected natural gas. The first treatment involved the injection of the foaming solution into the reservoir, followed by a series of overflushes. It was thought that the subsequent production of gas through the emplaced foaming solution, in a similar manner to the sequential injection mode, would cause the generation of a gas-blocking foam in situ. The second foam gas-blocking treatment involved the sequential injection of the foaming solution and a slug of nitrogen. Neither of these first two foam gas-blocking treatments showed any post-treatment GOR decline. The third foam gas-blocking treatment was a nitrogen foam of 65% quality that was preformed at the surface before injection. This treatment significantly reduced GOR at the treated production well for several weeks. These results suggest that, for many applications of natural-gas and nitrogen conformance-improvement foams, foam injection using the preformed mode, as compared to the sequential injection or coinjection mode, will result in superior performance of the foam within the oil reservoir when conducting "near-wellbore" treatments. Unless compelling arguments for a specific application can be made to the contrary, foams for most applications of near and intermediate wellbore conformance-improvement treatments should be preformed at the surface before injection.

The sequential process, alternately known as the WAG process, of injecting sequentially and repeatedly alternating slugs of CO₂ and aqueous foaming solution is often favored when using CO₂ foam for mobility-control purposes during CO₂ flooding. This is because CO₂ dissolved in an aqueous surfactant solution forms carbonic acid that is corrosive to steel tubulars. Because of the low surface tension of CO₂, foam generation and propagation is much more feasible (than steam, nitrogen, or natural-gas foams) at realistic field pressure gradients that occur throughout the reservoir.

Computer simulation studies have been reported to show that the optimal injection strategy for overcoming gas override during gas-flooding operations is the alternate/sequential injection of separate large slugs of gas and the foaming liquid at the maximum allowable fixed injection pressure. This study was limited to foam injection into a homogeneous reservoir and did not account for any foam interactions with oil. The surfactant-alternating-gas-ameliorated (SAGA) injection mode for forming in situ mobility-control foam has been proposed for use when conducting large-volume WAG flooding projects in North Sea reservoirs.

When, Where, and Why to Use Foams

The use of foams is most advantageously applied during gas flooding or for reducing gas coning and cusping in one of two manners. First, foams can be used to improve sweep efficiency and improve oil recovery during gas flooding (e.g., steam, CO₂, and hydrocarbon-miscible flooding). Such mobility-control foam is usually injected from the injection well side. Second, foams can be used as gas-blocking agents to reduce excessive, deleterious, and competing gas production. Such gas-blocking foam is most often placed from the production well side. Foams for use as both mobility-control and gas-blocking agents are attractive because they are relatively inexpensive on a unit-volume basis. The low unit-volume cost results from the combination of the bulk of the foam volume usually being a relatively low-cost gas, and the surfactant chemicals for the foaming solution are relatively inexpensive and used at relatively low concentrations.

Advantages and Disadvantages of Foams

There are a number of somewhat contrasting advantages and disadvantages for the use of foams for improving conformance during oil-recovery operations.

Advantages. The following is a list of the advantages of the use of foams.

• Foams are exceptionally effective in reducing gas mobility during gas flooding.
• Foams can be an effective gas-blocking agent.
• Foams are a conformance-improvement material that has the tendency, in numerous instances, to reduce permeability and mobility to a greater degree in higher permeability matrix reservoir rock.
• Foams are shear-thinning fluids resulting in relatively good injectivity and in more effective mobility control in the far-wellbore region where such mobility control is most needed.
• Foams possess low effective density that can often be exploited to help selectively place foams high in a reservoir thereby impeding problematic gas flow where it is most likely to occur.
• Foams are considered, in general, to be an environmentally friendly material for use in conformance-improvement operations.

Disadvantages. The following is a list of the disadvantages of the use of foams.

• Foams are a relatively complex technology, both chemically and operationally, to apply successfully.
• Oil tends to destabilize and deactivate many conformance-improvement foams.
• Many mobility-control foams (e.g., steam and natural gas foams) are difficult or impossible to propagate in the intermediate- to far-wellbore environment under the differential-pressure conditions encountered in most reservoirs.
• Surfactant adsorption/retention has a substantial negative impact on the performance and economics of mobility-control foams.
• Fluid-blocking (e.g., gas-blocking) foams used in production-well treatments have limited strength under high differential pressure conditions.
• Fluid-blocking (e.g., gas-blocking) foams are also limited by the inherent lack of long-term stability and the associated lack of long-term treatment effectiveness.
• The high viscosity and poor injectivity of preformed foams limit the application of this otherwise often favored foam-injection mode.
• The limited and sometimes poor ability to effectively form foam in situ in matrix reservoir rock during the coinjection or sequential injection of the foam’s gas and liquid phases limit the effectiveness and the efficiency of the coinjection and sequential-injection modes for foam formation and placement in a reservoir.

Foams for Mobility Control

Foams, as a conformance-improvement technology for use during gas flooding (e.g., steam, CO₂, and miscible-gas flooding), have historically been most widely studied and applied when the foams are to be used in the form of a "viscosity-enhancing" mobility-control agent that is injected from the injection-well side. Because relatively large volumes of foam are required and because the foam must be propagated significant distances in the reservoir, applying foams for mobility control have proved technically and economically challenging.

Reducing Gas Channeling and Override. As initially discussed in the Foam Properties subsection of Sec. 13.7.1, the low effective density of most mobility-control foams, which are used during a gas flood such as a steam or CO₂ flood, provides a driving force for the foam to flow and be desirably placed in the upper reservoir vertical interval where the offending gas override is occurring and where the foam will be most effective at countering the negative impact of the gas override. Shi and Rossen describes an "improved" surfactant-alternating-gas foam injection process to control gravity override during gas flooding projects.

Applications. CO₂ Flooding. CO₂ foams are considered to be an effective mobility-control agent candidate for use during CO₂ flooding to improve CO₂ sweep efficiency. This includes the use of "foams" formulated with supercritical and dense CO₂. Surfactant selection and surfactant adsorption/retention losses are particularly critical parameters to the successful economic application of CO₂ foams during CO₂ flooding operations. The exploitation of relatively low-cost CO₂ foams formulated with surfactant concentrations below the critical micelle concentration has been suggested. As discussed in the Injection Mode subsection of Sec. 13.7.1, the sequential or WAG injection of the CO₂ and the foaming solution is often preferred for the injection of mobility-control CO₂ foam.

Steam Flooding. Use of steam foams has been studied extensively and has been reduced to field practice as a technique to improve vertical and areal sweep efficiency and to reduce steam channeling and override during steam flooding that is being applied to shallow heavy-oil reservoirs. The steam foam process consists of adding surfactant, with and without the addition of a noncondensable gas, to the injected steam. Based on the combined findings of theory, laboratory studies, and field performance, it has been determined that steam foams are normally more effective when a small amount of a noncondensable gas, such as nitrogen, is incorporated into a steam-foam formula. Steam foams have been used in conjunction with both continuous and cyclic steam injection.

As with foams for CO₂ flooding, the effectiveness and the economics of the steam-foam process are critically dependent on surfactant adsorption and retention. Unlike CO₂ foams, surfactant thermal stability is also a critical issue. Alpha-olefin sulfonates, along with petroleum sulfonates, are the surfactants that have been favored for use in conformance-improvement steam foams. Borchardt and Strycker have studied commercial olefin sulfonate surfactants to determine what the optimum chemistry should be in terms of favorable surfactant performance in foams for steam-flooding applications.

To mitigate the destabilizing effect of oil on steam foam, one proposed strategy is to inject a prefoam surfactant slug to mobilize the residual oil ahead of the steam foam. Steam foams have been extensively applied in conjunction with the heavy-oil production operations in Kern County, California. The application of steam foam in Kern County, California has been considered a technical success, but its economic success is suspect.

Miscible Gas Flooding. Although it would appear that foams would be well suited to impart mobility control and to improve sweep efficiency during miscible gas flooding (in a similar manner as during CO₂ and steam flooding), relatively few papers have appeared in the literature about this application of conformance-improvement foams, especially the actual field application of foams for use in conjunction with miscible-gas flooding. Mannhardt and Novosad studied the adsorption of foaming surfactants to be used with hydrocarbon-miscible flooding in reservoirs with high salinities. Two Sources discuss the application of foams for use during hydrocarbon-miscible flooding in Canada.

Sizing Volume Injected. The volume of foam that should be injected during application, as a mobility-control agent in conjunction with gas flooding, is a subject that lacks good and sound engineering guidelines. Thus, the sizing of such foam applications must be a custom design based on previous experience with similar applications, and/or be based on empirical guidelines. It does not make sense to design the depth of foam placement to be greater than the distance the foam can propagate through the reservoir.

Polymer-Enhanced Foams. The addition of a water-soluble polymer to the foaming solution has been suggested as a means to increase stability of the foam, increase the effective viscosity and structure of foams, and improve the oil tolerance of foams. The possible use of polymer-enhanced foams to treat fracture conformance problems has been suggested. Polymer-enhanced foams formulated with high-MW acrylamide polymers have been noted to be rheologically shear-thinning fluids that substantially aid in the injectivity of preformed polymer-enhanced foams.

Potential disadvantages of the use of polymer-enhanced foams are reduced injectivity of preformed polymer-enhanced foams as compared with conventional foams, possible increased difficulty in propagating the polymer-enhanced foam through matrix reservoir rock, and somewhat increased operational and chemical complexity in applying polymer-enhanced foams as compared with conventional foams.

Foam as Blocking Agents

Because foam applications for mobility-control during gas flooding have proven technically challenging and marginally attractive, the recent focus has shifted somewhat to the application of relatively small volumes of foam that are placed as gas-blocking agents from the production well side. The application of foams as gas-blocking agents has been discussed and reviewed numerous times in the literature.

Concept. Because foams are exceptionally effective at reducing gas permeability, they are good candidates for use in gas-blocking treatments that are placed relatively near to producing wellbores. The foam’s low effective density results in the tendency for selective placement in the upper sections of the reservoir where gas, especially coning and cusping, is entering the wellbore. The obvious and major challenges that must be overcome to successfully apply foams as a gas-blocking agents are to assure that the emplaced blocking foam will have adequate strength and that the metastable foam will be stable long enough to result in attractive economics.

Laboratory Studies and Treatment Design. Treatment design and laboratory studies in support of applying foam gas-blocking treatments need to assure the following.

• The foam has adequate strength to function as intended under actual reservoir conditions, including adequate strength within the maximum permeability rock to be blocked/sealed and adequate strength to withstand the maximum differential pressure that will be encountered.
• The foam has adequate durability and stability to function as intended under actual reservoir conditions for at least the minimum intended economic life of the foam gas-blocking treatment, including adequate thermal stability, adequate stability to the reservoir oil and to the salinity of the reservoir brine, and adequate stability in the presence of the reservoir minerals and lithologies to be encountered.
• The foam can be emplaced and/or generated in the desired reservoir volume to be treated.

Foams for Reducing Gas Coning. The use of foams as blocking agents to reduce or eliminate gas coning in matrix-rock reservoirs has long been studied. One concept is to inject a foaming solution at, or near, the gas/oil contact (GOC). As gas cones down through the foaming solution, it is proposed that gas-blocking foam will form in situ and reduce or eliminate gas coning. More recently, it has been proposed that the foaming solution in this case should be a hydrocarbon solution. For a properly designed treatment, gravity forces will tend to promote the selective placement of the hydrocarbon foaming solution at the GOC, just as desired. Dalland and Hanssen reported on a laboratory study of this concept.

Sizing Volume Injected. The volume of the emplaced foam required to successfully function as a gas-blocking treatment is smaller than the foam volume required for mobility-control purposes. In concept, the volume of the foam placed through a production well needs only be large enough to provide sufficient strength and durability to assure effective gas blockage. The volume and depth of foam placement for such a treatment will vary substantially with the foam formula used, the permeability and mineralogical nature of the reservoir volume being treated, and the drawdown pressure that the foam gas-blocking treatment will experience. At this writing, no exact treatment size guidelines for foam gas-blocking treatments can be provided. The sizing of such foam treatments needs to be determined on a well-by-well and treatment-by-treatment basis.

Polymer-Enhanced Foams and Foamed Gels. A trend, which has often occurred when applying foams as gas- or water-blocking treatments from the production well side, is that the initial application of a conventional foam resulted in some blocking of gas or water flow that lasted for only a relatively short time. Encouraged by the initial favorable gas- or water-blocking performance of conventional foam treatments, but pursuing and needing longer-term gas- or water-blocking performance, the application and exploitation of polymer-enhanced foams were next pursued. Again encouraged by the improved gas- and water-flow blocking performance of the polymer-enhanced foam treatments, but still pursuing and needing even longer-term gas- and water-blocking performance, foamed gels were subsequently pursued. The application of foamed gels as a blocking-agent material for use across a broad spectrum of conformance treatments has been suggested and studied.

Hughes, et al. reports on three large-volume (~40,000 res bbl) foamed-gel treatments that were applied for conformance-improvement purposes to injection wells of the Rangely field miscible CO₂ WAG project in northwestern Colorado. The three foamed-gel treatments were reported to have generated an incremental oil production rate of 155 BOPD. Each of the foamed-gel treatments induced stabilization in the pattern oil rate. The cost of the foamed-gel treatments was said to be 40 to 50% below that of comparable polymer-gel treatments that would have been conducted at the Rangely field.

Design Strategies for Field Application

Rossen suggests the following design strategies for the field application of conformance-improvement foams. The initial steps are to characterize the field and its conformance problem; determine that there is sufficient recoverable oil to render the foam process economic; determine process goals (e.g., increase oil recovery or recovery rate, or reduce operating costs); and perform a preliminary economic evaluation of the foam project. Next, the surfactant to be used should be chosen by conducting wet-chemistry testing, conduct foam-property testing in porous media, and determining surfactant retention with reservoir core material, if possible. Finally, determine the injection strategy to be used.

Outlook

At this writing, the outlook for the use of foams extensively and routinely is not as encouraging as it was during the past two decades. Petroleum industry R&D was diminishing. The original interest in foams as mobility control agents has faded somewhat and interest in the use of conventional foams as fluid-flow blocking agents was also fading because foam fluid-flow blocking treatments are operationally and chemically relatively complex and polymer gels are considered by many petroleum engineers to be more effective, durable, and stronger.

Illustrative Field Results

The following are a series of illustrative field applications of foams for conformance-improvement purposes and/or a series of references to papers discussing such foam applications.

Foams Used During Steamflooding. In 1989, Hirasaki reviewed early steam-foam-drive projects. In 1996, Patzek reviewed the performance of seven steam-foam pilots conducted in California. Early and delayed production responses were discussed for these pilots. Gauglitz, et al. reviews a steam-foam trial conducted at the Midway-Sunset field of California.

Foams Used During CO₂ Flooding. The design, results, and analysis of a two-year CO₂ foam field trial at the North Ward-Estes field in Texas have been documented. The alternate injection of CO₂ and surfactant foaming solution was reported to have reduced injectivities by 40 to 85%. Gas production at an offset problematic production well decreased dramatically, while gas and oil production at the other offset producers increased, indicating favorable areal diversion. CO₂ foam application during this field trial was reported to have significantly improved CO₂ sweep efficiency and to have been economically successful.

Stephenson et al. reported that a foam bank could only be propagated several meters from the wellbore during an extended foam test at the Joffre Viking miscible CO₂ flood in Canada, where the foaming aqueous solution and the CO₂ were coinjected.

Hoefner and Evans reviewed four pattern-scale CO₂ -foam field trials to determine the technical and economic potential for reducing channeling during CO₂ flooding. The field trials involved two different foaming surfactants, alternating and coinjection of the CO₂ and the aqueous foaming solution, and two field trials each in a San Andres carbonate reservoir of West Texas and one trial in a platform carbonate formation in southeast Utah. In all, 161,000 lbm of active foaming surfactant were injected, with one of the field trials lasting 18 months. The CO₂ foam treatments resulted in reduced CO₂ production and indications of increased oil production.

Henry, et al. reports on a 3,000-reservoir-bbl CO₂ foam treatment that was applied to reduce CO₂ channeling in the Wasson ODC Unit in Texas. The foam treatment was reported to have been a technical success, but an economic failure. Foam performance was noted to decrease with time and to be a treatment success issue.

Martin, Stevens, and Harpole provides a review of a four-year CO₂ foam mobility-control pilot test conducted in a dolomitic carbonate reservoir of the East Vacuum Grayburg/San-Andres Unit in New Mexico. During the CO₂ foam pilot, CO₂ mobility of the ongoing CO₂ WAG flooding operation was reduced, incremental oil production was noted at three of the eight offsetting producers, and gas cycling was significantly reduced.

Foam Gas-Blocking Treatments. Eight production wells in Nigeria were treated with foam gas-blocking treatments to reduce gas coning or cusping and to reduce excessive GOR. The producing formation was thin and overlain by a gas gap. The reported set of applied nitrogen foam gas-blocking treatments included the use of polymer-enhanced foams, sequential and coinjection of the gas and foamer solution, and fluorosurfactants. The treatments were designed to place the foam barrier 5 to10 m radially from the wellbore. A volume of 600 to 800 bbl of foam solution was injected per treatment. The success rate of the foam gas-blocking treatments was reported to be 50+%. Results ranged from significant reductions in GOR that lasted for twelve months (reduced GOR from 7,000 to 2,000 scf/bbl and increased the oil production rate from 340 to 450 BOPD) to minor reductions in GOR that lasted only for a few weeks. The foam treatments were said to be easy to apply and relatively inexpensive. The preliminary conclusion based on this set of foam gas-blocking treatments is that for this type of foam treatment, the sequential injection mode is preferred over the coinjection mode. Four out of six foam gas-blocking treatments that used the polymer-enhanced foam formulas were successful, while neither of the foam gas-blocking treatments using the fluoro-surfactant foam formula were successful.

Surguchev and Hanssen presents a review of the application of two foam gas-blocking treatments that were applied to high GOR problems occurring at production wells in the North Sea. The first foam pilot test was applied to a sandstone formation of a production well in the Oseberg field in the Norwegian North Sea, where the high GOR production problem involved gas coning. The upper producing interval was selectively treated with a strong and "oil-resistant" foam. This Norwegian foam pilot was reported to have been successful (at a minimum, technically successful) and delayed the onset of gas coning by several months.

Foam ASP. The reported use in China of foamed alkaline-surfactant-polymer (ASP) flooding is noteworthy for several reasons. First, the field trial of foam flooding in this manner was reported to be both a technical and economic success with the reported economics being quite attractive. Second, definitive positive reservoir and flooding responses were noted during this foam pilot test. Positive responses included substantial incremental oil production; substantial increases in the injection pressure; significantly lower GOR indicating reduced gas mobility, fingering, and channeling; and favorable changes in the produced water salinity which indicated improved sweep efficiency. Third (and of significant importance), substantial increases in injection pressure occurred during the pilot test.

The implications of the higher injection pressures are three fold. First, for an older waterflood operation in a mature field, this situation may require installing relatively expensive high-pressure injection equipment, injection lines, and wellheads. Second, even if the foam should happen to have an effective viscosity identical to water, it will require substantially more horsepower to inject the foam at the same rate as compared to waterflooding because of the lower density and lower wellbore hydrostatic pressure of the foam. Third, if the previous waterflood injection pressure was just below reservoir parting pressure, any increase in injection pressure would require lower injection rates that might pose a possible negative impact on the economics of the project.

On the positive side (although. at first, a foam-ASP flood may appear to be quite complex), if an oil operator is conducting either an ASP or a WAG flood and if the operator has excess natural gas being produced in the field, then flooding in the WAG mode, using the ASP solution as the water phase of the WAG flood, could prove to be relatively easy to implement and relatively attractive if the conformance of the flooding operation could be improved in a similar fashion as reported for the Chinese foam-ASP pilot test.

Suggested Additional Reading

The subject of foam use in the petroleum industry is covered in depth in more than one source. Nguyen, et al. provides a more recent review of experimental and modeling studies of conformance-improvement foam flow through porous media. Hanssen, Holt, and Surguchev provides a review of published field experience relating to 30 applications of foam for conformance improvement in North Sea reservoirs. Isaacs, et al. presents an overview of the field application of foam for improved sweep efficiency and control of produced gas in the United States, the North Sea, and the Former Soviet Union.

Resins

The term "resin," as used in this chapter, refers to an organic, polymer-based, solid plastic material. Resins do not contain a significant amount of a solvent phase (as do gels), and resins are placed downhole in a liquid monomeric (or oligomeric) state and polymerized in situ to the mature solid state.

Oilfield Resins and Resin Treatments

Oilfield resins are exceptionally strong materials for use in blocking and plugging fluid flow in the wellbore and/or the very near-wellbore region. The three classical oilfield resins discussed here have exceptionally good compressive strengths. Also, these three resins usually have good bonding strength to oil-free rock surfaces. Resins for fluid-shutoff purposes during squeeze treatments can normally only be placed in the wellbore, perforations, gravel packs, and other near-wellbore multi-Darcy flow channels.

Solid fillers, such as silica flour and calcium carbonate, are sometimes added to fluid-shutoff resin formulas to reduce cost, increase resin specific gravity, and/or provide higher temperature stability. If solid fillers are added to a fluid-shutoff resin formula, the solids should normally be added at the wellsite just before resin placement. The exception to this is solids addition to epoxy resins that is often conducted at the resin manufacturing facility. This is done because of the need for a high level of agitation while mixing the solids into the viscous immature epoxy-resin fluid.

In addition to resin treatments applied during a well’s production phase, resin treatments have been successfully used as part of well completion strategies to improve conformance during the subsequent oil-recovery production phase of the well’s later life. The use of resins for water control dates back at least to 1922. The vast majority of the resin field applications, involving the use of the fluid-shutoff resins technologies that are described next, have used treatment volumes on the order of one to five barrels. At this writing, resin fluid-shutoff treatments were available from relatively few oilfield service companies.

Types and Chemistries. There are three resin chemistry types that have been studied and applied for use as fluid-shutoff treatments in wellbores and the very near-wellbore region. A fourth fluid-shutoff "resin" technology involves a blocking agent that is a cross between a resin and a gel.

Epoxies. Epoxy resins have been favored for use in conjunction with CO₂ flooding. Many of the early epoxy resin technologies were extremely sensitive to water and were "deactivated" while being placed. Wiper plugs are often placed in the tubing at the beginning and the end of the injected resin material. Some of the newer oilfield epoxy resin technologies are much less sensitive to water contact. In general, epoxy resins are the strongest (especially in terms of bonding strength) of the three oilfield resins discussed here. The kinetic rate of maturation of epoxy resins is somewhat touchy and subject to numerous possible interferences during resin placement as a consequence of the epoxy-resin maturation chemistry being based on free-radical chemistries.

Oilfield epoxy resins commercially available are applicable over a downhole temperature range (downhole temperature possibly attained by cooling) of 80 to 130°F and have an ultimate temperature stability of up to 400°F. Placement outside the wellbore is limited to fractures, behind-pipe channels, large vugs, and multi-Darcy matrix rock. Epoxy resins are applicable for shutting off fluid flow involving water, CO₂, and hydrocarbon gases. Epoxy resins are also applied for casing repair purposes. In general, epoxy resins have better bonding properties and strengths than phenolic or furan resins. The relatively fast curing times of epoxy resins result in more restrictive placement times than those of the other two fluid-shutoff resins.

Phenolics. Phenolic resins are well suited for use during steamflooding operations because of their good thermal stability. Phenolic resin treatments have been used to improve steam injection profiles by blocking near-wellbore steam thief zones. During resin treatment placement, immature phenolic resins are not highly sensitive to water and will not be deactivated by limited contact with water. The high viscosity of immature phenolic resins suppresses excessive mixing with water in the wellbore. The maturation chemical kinetics of phenolic resins is not highly subject to interferences during resin placement. Two types of catalysts/activators, caustic and acid, can be used to initiate the polymerization reaction. The maturation chemical kinetics for the more commonly used base-catalyzed phenolic resins is primarily a function of the amount of hydroxide ion incorporated into the resin formula. Phenolic resin maturation involves a chemical condensation polymerization reaction. Commercial base-catalyzed phenolic resins that were available at this writing were applicable over a downhole temperature range (downhole temperature possibly attained by cooling) of 90 to 170°F and applicable to an ultimate downhole temperature of up to 450°F. Acid-catalyzed phenolic resins are considered to be most ideally applied over a downhole temperature range of 100 to 130°F.

Primary uses of phenolic resins are for near-wellbore applications involve the plugging of perforations, behind pipe channels, gravel packs, and fractures. Phenolic resins are applicable for shutting-off fluid flow involving water, steam, CO₂, and hydrocarbon gases. In general, fluid-shutoff phenolic resins have slower maturation chemical-reaction (polymerization) rates than fluid-shutoff epoxy resins have. The bonding properties of phenolic resins are not as good as those of cement or epoxy resin.

Toxicity, safety, and environmental issues and regulations need to be carefully considered and reviewed before applying a phenolic resin treatment. The fundamental chemistry of phenolic resins is based on phenol/formaldehyde chemistry. Phenol and formaldehyde are both toxic. The use of phenolic resin treatments for oilfield fluid-shutoff purposes goes back to the 1960s.

Furans. Oilfield furan resins are, in general, weaker resins than epoxy and phenolic resins. Commonly available commercial furan resins are applicable over a downhole temperature range (downhole temperature possibly attained by cooling) of 60 to 350°F and are applicable to an ultimate downhole temperature of up to 700°F. The penetration of furan resins into an oil reservoir is limited to fracture channels, vugs, and multi-Darcy matrix rock. Furan resins are applicable for shutting off fluid flow involving water, steam, CO₂, and hydrocarbon gases. Furan resins are also applicable for casing repair purposes. Primary uses of furan resins are for near-wellbore plugging of perforations, behind pipe channels, and fractures, along with their use for casing repairs. The use of furan resins is reported to be environmentally friendly.

Oilfield furan resins are derived from the condensation polymerization reaction of furfuryl alcohol, as Fig. 13.35 shows. The polymerization reaction of furfuryl alcohol is acid catalyzed. Typically, furfuryl alcohol is obtained from the destructive distillation of corncobs. Furfuryl alcohol polymerizes to form a hard, black, chemically resistant, and thermally stable polymer resin. Hardened furan resins have, in general, lower compressive strengths than epoxy and phenolic resins.

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  Fig. 13.35 – Polymerization of furfuryl alcohol.

Modern oilfield furan resin treatments start with use and placement of furan oligomers or prepolymer chemical species (not the monomer specie). Use of oligomers of furfuryl alcohol reduces the reactivity of the polymerization reaction and greatly increases the controllability of the furan resin polymerization reaction. Modern furan resin fluid-shutoff treatments are a single-fluid process in which an organic acid and an ester have been included in the resin formula. The ester reacts with, and absorbs, the water formed during the condensation reaction of the furan resin polymerization process. The uptake of the water rendered by the condensation reaction drives the polymerization reaction further to completion and, thus, renders a more effective and stronger final furan resin. Some of the currently used furan resin fluid-shutoff formulas contain a small amount of a water-swelling polymer to prevent shrinkage of the furan resin after it is polymerized.

In general, furan resins provide better control over the resin maturation time and do so over a larger temperature range compared with the epoxy resin technology. The lower viscosity, in general, of immature furan resins, as compared with epoxy and phenolic resins, permits better penetration of furan resins, especially into reservoir matrix rock. Although not common, furan resins have been placed using coiled tubing.

Common Properties. The three resin technologies discussed previously have a number of features in common. They are all thermosetting and applicable to both sandstone and carbonate reservoirs. None of the three resin technologies are highly sensitive to the pH in the wellbore during resin placement or sensitive to H₂S. All three are not substantially degraded by conventional acid treatments performed after resin treatment placement. The three resins are more stable to acid than conventional Portland cement. Resins without solid fillers can flow into small flow channels where conventional Portland cement cannot.

All three resins types have good mechanical, bonding, and compressive strengths. Most fluid-shutoff resins have compressive strengths exceeding 1,000 psi, with some of these resins possessing compressive strengths up to, and exceeding, 20,000 psi.

The treatment volume of a high percentage of resin fluid-shutoff treatments placed downhole has only been in the range of one to five barrels (and most of these in the one to two barrel range). For all three of these resin technologies, the immature resin solution, as it is being placed downhole, is quite viscous (often qualitatively described as having approximately the consistency of molasses).

Crosslinked Styrene-Butadiene Block Copolymers. There is a conformance-improvement technology that involves a fluid-shutoff plugging agent that is a cross between a resin and a gel. The mature plugging agent contains approximately 10 to 20% styrene-butadiene block copolymer dissolved in an aromatic solvent, such as xylene, and the polymer has been chemically crosslinked using a peroxide free-radical crosslinking agent.

This plugging-agent material is an example of a crosslinked polymer gel in which the gel solvent is an organic fluid. However, this plugging-agent technology also has the attributes of a resin that contains a substantial amount of added organic solvent. Because this plugging technology has many of the functional attributes of a resin (both in terms of application and final physical form) and because, like the three resins described previously, the crosslinked styrene-butadiene block copolymer gel technology is essentially an organic and nonaqueous blocking-agent technology, it is included in this resin technology section.

Crosslinked styrene-butadiene block copolymer gels/resins, as reported in the petroleum literature, are not a fully rigid material. However, crosslinked styrene-butadiene block copolymer gels/resins are an effective "resin" material for use in correcting steam injection profiles during steamflooding. This blocking-agent material is reportedly stable to 500°F. The thermally activated chemical crosslinking of the styrene-butadiene block copolymer is imparted by a peroxide agent that starts a free-radical crosslinking chemical chain reaction. Control of the gelation onset time at various temperatures is achieved by the proper selection of the chemistry of the peroxide crosslinking agent such that the chosen peroxide chemical decomposes to free radicals in an appropriate time frame at a specified temperature.

Problem Identification and Temperature Issues

Because of the limited and relatively small volumes of resin that are placed during a typical resin fluid-shutoff treatment, the correct identification of both the nature and location of the fluid-flow path to be shut off are critical to the successful application of resin conformance-improvement treatments.

There are three reasons that resin jobs are inherently small-volume treatments. First, the immature resin fluid as it is being placed downhole is quite viscous, so that, at best, the immature resin can only be placed very slowly into matrix reservoir rock. This situation is compounded by the fact that the resin fluid has a relatively short maturation time. Second, because of the highly reactive nature of the immature resin solutions, they cannot be propagated any significant distance into or through porous reservoir rock or any other type of restricted flow path without encountering serious chemical interferences to the resin polymerization reaction. Third, the high unit-volume cost usually precludes the application of large-volume resin treatments.

Temperature issues and the thermal history that a resin experiences during its placement to the final downhole location are critical to the successful application of resin fluid-shutoff treatments. Thermosetting resins have maturation/polymerization rates that are highly sensitive to temperature. If a resin were to inadvertently set up (as has occurred at times) in the dump bailer during placement or in an injection tubing string, this will be a costly outcome. If the resin sets up in an injection string, normally that injection string will have to be decommissioned.

Thus, it is critical that the temperature of the reservoir volume to be treated at the time of initial resin placement be known. It is also critical to know how the temperature of the resin will change with time during its placement downhole. Not correctly identifying the downhole temperature where the resin is to be placed and not knowing the thermal history of the resin while it is being placed are major causes of resin treatment failures.

Well Selection

The process of well-candidate selection for resin squeeze treatments is an important aspect of successfully applying resin fluid-shutoff treatments, and a resin treatment aspect that needs careful attention. In particular, the conformance problem of the well to be treated must be a problem for which only a few barrels of successfully placed resin will be sufficient to create the necessary flow barrier.

Placement

Originally, because of the small-volume of resin treatments, wireline dump bailers were widely used for placement. More recently, the majority of resin treatments have been placed through clean, uncorroded injection tubing. The advantages of using injection tubing are faster placement and the ability to attain large differential pressures during placement.

When treating reservoirs with elevated temperatures, the downhole target zone is often precooled. For phenolic and furan resin treatments, the injected cooling fluid is usually water. However, when performing a water-intolerant epoxy resin treatment, the bulk of the injected cooling fluid is usually water that is followed by a hydrocarbon fluid spacer (often xylene). If preresin-treatment cooling-fluid injection is conducted, it is critical to accurately know to what degree the downhole target zone has been cooled and how rapidly the downhole treatment volume will heat back up. The determination of such thermal information often requires the running of appropriate computer thermal-simulation programs and/or a high degree of experience with applying resins to the well type to be treated.

When placing fluid-shutoff resins using an injection string, wiper plugs are usually placed in the injection tubing at the beginning and the end of the resin injection. Historically, clean, uncorroded production or drill strings have been used. The use of such a relatively large internal-diameter injection string during resin injection has often been considered necessary because of the high viscosity of the resin material being injected. More recently, the use of coiled tubing has been successfully used in limited instances.

It is mandatory that the resin be placed only in the wellbore interval intended for the resin treatment. As a result, the resin must normally be place with the use of mechanical zone isolation (e.g., use of mechanical packers). In the event any resin left in the wellbore needs to be removed, the resin material is usually drilled out using special drill bits. A major cause of failures for resin fluid-shutoff treatments is the improper placement downhole.

Wellbore and Injection-String Condition

For several reasons, the condition of the wellbore and the injection string is a critical parameter to the success of resin fluid-shutoff treatments.

First, if the surfaces of the wellbore or the near-wellbore reservoir material to be contacted with the resin have a substantial oil-coating film, the resin will fail to bond to the reservoir material or wellbore hardware, and much of the resin treatment effectiveness is lost. For this reason, if oily solid surfaces are expected, a hydrocarbon-wash preflush is often performed. The hydrocarbon fluid used in such a preflush is usually xylene.

Second, corroded placement equipment or injection tubular strings can play havoc with the kinetics of the resin polymerization reaction, especially for epoxy resins.

Third, an oil-coated injection string can be detrimental to the polymerization reaction product of some resin formulas.

Fourth, when placing the resin through liners, screens, or course sands where these flow paths have previously become partially plugged with organic debris (e.g., asphaltenes) and inorganic debris (e.g., formation fines and scale), such previous plugging can prevent the resin from being fully placed into the desired treatment volume. These plugging materials should be removed before placing the resin treatment material. Jet washing is a common technique used to remove plugging material.

Fifth, in addition to water interfering with the maturation chemistry of certain oilfield resins, water in the injection string can cause physical problems during resin placement. Water can lead to "clumping" in which water becomes interspersed between blobs of resin material. The resulting course emulsion will often not flow readily and the ultimate strength of the placed resin will be decreased.

Advantages and Disadvantages

The advantages and disadvantages of the use of resins as small-volume fluid-shutoff treatments to remedy oilfield conformance problems are as follows.

Advantages. Resins possess good mechanical strength, good bonding strength, good thermal stability, and good chemical inertness (e.g., can acidize over resins).

Disadvantages. Resin fluid-shutoff treatments are constrained by limited resin penetration distances into the reservoir formation (because of a combination of high viscosity, being highly chemically reactive, and cost issues); are operationally and chemically relatively complicated; are somewhat tricky to successfully apply; are constrained by placement techniques and issues; are costly on a unit volume basis; have, in practice, usually been limited to shallow reservoir applications; and are considered to be a niche conformance-treatment technology.

Dos and Don’ts

The following items are a partial list of "do’s" and "don’ts" as they apply to resin fluid-shutoff treatments.

Dos

• Test the resin maturation and hardening rate onsite using the actual resin chemicals to be used and simulating the thermal history that the resin will experience during its placement.
• Before initiating a resin treatment, understand and be able to fully predict how the rate of resin maturation and hardening varies with the amount of catalyst and/or activator that is added to the resin formula.
• Know the age of the resin as it is received from the supplier. Older resins will often react faster than fresh ones because of an increased level of "self-polymerization" that occurs while the resin sits on the shelf during storage. (This is largely a concern for phenolic and furan resins.)
• Know, with a high degree of certainty, the thermal history that the resin will experience as it is placed and the rate at which the resin will mature and harden under this thermal history.
• Know, with a high degree of certainty, the exact location of the problem to be treated. (This is important because of the limited volume of resin that is to be placed.)
• Ensure that the injection tubing and placement equipment are free of rust and oil.
• Clean oil from the wellbore and reservoir location where the resin is to be placed and function.
• If economics permit, perform laboratory testing in reservoir or gravel-pack sandpacks if the resin is to be placed in such sands. Such testing, among other purposes, assures that the sands will not chemically interfere with the expected performance of the emplaced resin.
• Conduct, or have conducted, a good quality control and quality assurance program in conjunction with the application of resin squeeze treatments.

Don’ts

• For most common epoxy resins, make sure water does not contact the epoxy resin while it is being placed and matured.
• For most common epoxy resins, don’t inject the epoxy resin through injection tubing without the use of wiper plugs.
• Don’t store the resin material above the recommended storage temperature before its use.
• Don’t use aged resin material—always use fresh resin material.

Illustrative Field Results

Water-Encroachment Treatments. Littlefield, Fader, and Surles reports on 26 production wells of the Kern River and San Ardo fields that were treated in 1990 and 1991 with furan resin jobs in which the treated production wells were suffering from water-encroachment problems. Most (24) of the wells were in the heavy-oil Kern River field of the Lower San Joaquin Valley in California. When the furan resin treatments were applied, the Kern River field was undergoing steamflooding. Of the production wells treated, 79% showed significant reductions in water production after the treatments. After drilling out the resin plug in the wellbore, the resin remaining in the treated perforations and in the treated formation was of a sufficient amount and strength to prevent water entry into the production wells.

Gravel Pack Resin Treatments. Phenolic-resin plugback treatments were applied to 32 wells with openhole gravel pack completions in the Midway-Sunset field in 1987. These resin treatments were reported to have decreased water production by 5,900 BWPD and increased oil production by 256 BOPD. Total revenue and savings from the resin treatments were estimated to be U.S. $1 million, and the resin treatment project was reported to have paid out in 120 days. The phenolic resin treatments were applied successfully to downhole temperatures ranging from 100 to 200°F at this California cyclic-steam injection project.

Furan Resin Treatments in California. In 1980, Hess provided a brief review of 36 small-volume (1 to 5 bbl) furan resin treatments applied for a variety of purposes in California. Of these 36 furan resin treatments, 27 were reported to have achieved "permanent" downhole plugging. The furan resin treatments were applied for a variety of purposes, including shutting off undesirable steam breakthrough in production wells, plugging thief zones in water and steam injection wells, shutting off bottomwater entry, and repairing casing and liner damage. The furan resin used in treating steam-stimulated and steamflood injection wells was reported to have held up through two years of service.

Epoxy Resin Treatment. A three-barrel epoxy resin treatment was applied to a Green Canyon production well in the Gulf of Mexico. The objective of this treatment was to shut off the lower perforated interval of the gravel-packed well. The temperature of the sand to be treated was 139°F. The wellbore had a deviation angle of 60° across the treated interval. The epoxy resin formula used was designed for a 4- to 6-hour pump time through coiled tubing and required a 24- to 48-hour shut-in time. Following the epoxy resin fluid-shutoff treatment, oil production increased from 240 BOPD before the resin job to 470 BOPD following the resin job. Following the resin treatment, the flowing tubing head pressure was reported to have increased dramatically.

Steam Injector Profile Correction. More than 40 crosslinked styrene-butadiene block copolymer resin/gel treatments of approximately four-barrel volume have been successfully applied as injection-well profile correction treatments in conjunction with the steamflood conducted at the Kern River field in California. It was reported that none of the resin/gel treatments showed any steam entry into the treated wellbore intervals after the steam-shutoff resin treatments. Payout times for these resin steam-shutoff treatments, based on steam cost savings alone, were reported to have averaged less than two months. These resin/gel treatments were applied with conventional oilfield surface and downhole equipment.

Historical Trend

Resin conformance fluid-shutoff treatments had been somewhat widely applied in previous years and had been relatively popular at that time. However, at the time of writing this chapter, relatively few resin fluid-shutoff treatments were being applied.

Summary

Conformance improvement encompasses improving drive-fluid sweep efficiency during oil-recovery flooding operations and the shutting off of excessive, deleterious, and competing coproduction of an extraneous fluid, such as water or gas. Conformance problems occur because of heterogeneity of reservoir permeability and/or viscosity and mobility-control attributes of the oil-recovery drive and reservoir fluids. A number of conformance problems and a number of key distinctions relating to conformance problems were discussed. Failure to correctly identify/diagnose the nature of an offending oilfield conformance problem and failure to adequately account for the key distinctions relating to the various conformance problems are major contributors to failures of conformance-improvement floods and treatments.

DPR is a phenomenon whereby a substantial number of, respectively, polymers and polymer gels of conformance-improvement treatments reduce the permeability to water flow to a greater extent than they reduce the permeability to oil and gas flow. The application of DPR technologies for water-shutoff purposes is not a panacea. The successful application of bullheaded DPR water-shutoff/reduction treatments (which are to be applied through production wells, involve radial flow in matrix rock, and for which the well’s drawdown pressure is not increased post-treatment) is limited to the following conditions:

• A conformance problem exists in a matrix rock reservoir involving differing geological strata.
• No fluid crossflow exists within the reservoir between the water and the oil or gas producing geological strata.
• The water strata are producing at an uneconomically high water cut.
• The oil or gas strata is producing and will produce for the economic life of the water-shutoff treatment at 100% oil or gas cut.

Early use of water-soluble and viscosity-enhancing polymers during conformance-improvement operations was primarily for improving mobility control during waterflooding. Such polymer flooding was, and is, applied to improve the flood volumetric sweep efficiency of a waterflood by increasing the viscosity of the oil-recovery drive fluid. More recently, polymer application during conformance-improvement operations has additionally been used extensively in polymer-gel treatments and DPR polymer treatments for water-shutoff/reduction purposes. The science, technology, engineering, historical trends, and field application of polymers used in conformance improvement were reviewed.

Gels are a fluid-based system (usually relatively inexpensive) to which solid-like structural properties have been imparted. Gels, especially crosslinked-polymer gels, are effective, widely applied permeability-reducing and blocking/plugging agents for use in conformance-improvement treatments. Conformance-improvement gels are used to reduce or eliminate the fluid-flow capacity of high-permeability and/or water-producing flow paths within an oil or gas reservoir. Organic- and inorganic-based gels and the when, where, and how of successfully applying gel treatments were reviewed. The economics of polymer-gel treatments can be exceptionally attractive.

The use of conformance-improvement foams as mobility-control agents and as gas-flow blocking/plugging agents was reviewed. Foams are primarily used as mobility-control agents during gas-flooding operations or as gas-shutoff treatments. The fundamentals, history, science, technology, engineering, trends, and field application and performance of foams for conformance improvement were reviewed. There are some significant distinctions between foam properties and performance as they exist in bulk foam (e.g., foam in a bottle) and foam as it exists in reservoir-rock porous media. Foam flow in porous media tends to occur as gas-bubble trains, in which the individual gas bubbles are separated by thin-film liquid lamellae. An important aspect of foams in porous reservoir rock is the increased trapped gas saturation that the foams impart. Polymer-enhanced foams and foamed gels for conformance improvement were briefly discussed.

Resins for use in conformance-improvement treatments are an organic polymer-based plastic solid material. Such resin material normally does not contain a significant amount of a solvent phase. Resins are placed downhole in a liquid monomeric (or oligomeric) state and then polymerized to the mature solid resin state. Resins are an exceptionally strong material and an exceptionally chemically and thermally stable material for use in blocking and plugging fluid flow in the wellbore and/or the very near-wellbore region. The chemistry, technology, engineering, limitations, trends, cost concerns, special issues, and field applications of resins for use in conformance-improvement treatments were reviewed. Resin treatments have been used successfully in conjunction with steam flooding. Volumes of resin placed during a conformance treatment are typically on the order of one to five barrels.

Nomenclature

a	=	polymer-specific constant of the Mark-Houwink equation
Af	=	area contacted by oil recovery displacement fluid, L2
At	=	total reservoir area under consideration, L2
AV	=	reservoir vertical cross section contacted by oil recovery displacement fluid, L2
AtV	=	total reservoir vertical cross section, L2
c	=	polymer concentration
dp	=	mean end-to-end distance or size of a polymer molecule dissolved in solution, L
EA	=	areal sweep efficiency
EI	=	vertical sweep efficiency
EP	=	pattern sweep efficiency
EV	=	volumetric sweep efficiency
h	=	formation height, L, ft
k	=	permeability, L2, md
K	=	power-law coefficient
K′	=	polymer-specific constant of the Mark-Houwink equation
ka	=	permeability measured after polymer flooding, L2
kav	=	average permeability, L2
kb	=	permeability measured before polymer flooding, L2
khi	=	high permeability, L2
ki	=	permeability of phase i
M	=	mobility ratio
MP	=	polymer molecular weight
MH	=	Hall plot slope
n	=	power-law exponent
Pc*	=	limiting capillary pressure, m/Lt2
ptf	=	flowing wellhead pressure, m/Lt2, psi
Rf	=	resistance factor
Rrf	=	residual resistance factor
re	=	external radius, L, ft
rw	=	wellbore radius, L, ft
s	=	skin factor
t	=	time, t, days
wf	=	fracture width/aperture, L
Wi	=	cumulative volume injected, bbl
ϕ	=	porosity
Γ	=	polymer retention in μg/g
Γv	=	polymer retention in lbm/AF
	=	shear rate
η	=	viscosity of the polymer solution
ηs	=	viscosity of the solvent
[η]	=	intrinsic viscosity
ρRG	=	density of reservoir rock (no porosity included)
μ	=	viscosity
μeff	=	effective viscosity of a polymer solution
μi	=	viscosity of phase i
μl	=	average rate of gel dehydration
μw	=	viscosity of the brine into which polymer is dissolved
λD	=	mobility of the displacement phase
λd	=	mobility of the displaced phase
λi	=	mobility of phase i
λp	=	mobility of the polymer solution
λw	=	mobility of the brine solution
τ	=	shear stress

Abbreviations and Acronyms

AMPS	=	2-acrylamido-2-methyl-propanesulfonic acid
ASP	=	alkaline surfactant polymer
BOPD	=	barrels oil per day
BWPD	=	barrels water per day
CC/AP	=	chromium (III)-carboxylate/acrylamide-polymer
CDG	=	colloidal dispersion gels
EOR	=	enhanced oil recovery
GOC	=	gas/oil contact
HPAM	=	hydrolyzed polycacrylamide
IPV	=	inaccessible pore volume
MW	=	molecular weight
OOIP	=	original oil in place
PAM	=	polyacrylamide
PV	=	pore volume
RPM	=	relative permeability modification
SF	=	screen factor
WAG	=	water alternating gas
WOR	=	water/oil ratio

Acknowlegdements

Special thanks to Craig Phelps, who provided much of the information on which the Resins section is based. The following individuals contributed significantly to the writing of this chapter by providing reviews of the chapter or selected sections of the chapter: Randy Seright, Paul Willhite, Malcolm Pitts, Bill Rossen, Jim Mack, Dwyann Dalrymple, Craig Phelps, Reid Grigg, Larry Eoff, and Ed Holstein.

References

SI Metric Conversion Factors

acre-ft	×	1.233 489	E + 03	=	m3
Å	×	1.0*	E − 01	=	nm
bbl	×	1.589 873	E − 01	=	m3
cp	×	1.0*	E − 03	=	Pa•s
ft	×	3.048*	E − 01	=	m
ft2	×	9.290 304*	E − 02	=	m2
ft3	×	2.831 685	E − 02	=	m3
°F		(°F − 32)/1.8		=	°C
in.	×	2.54*	E + 00	=	cm
in.3	×	1.638 706	E + 01	=	cm3
lbm	×	4.535 924	E − 01	=	kg
psi	×	6.894 757	E + 00	=	kPa

*

Conversion factor is exact.