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Resin treatment for conformance improvement
The term “resin,” as used in this page, 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. This page discusses resin types and the use of resin treatments for conformance improvement.
- 1 Oilfield resins and resin treatments
- 2 Problem identification and temperature issues
- 3 Well selection
- 4 Placement
- 5 Wellbore and injection-string condition
- 6 Advantages and disadvantages
- 7 Do's and Don’ts
- 8 References
- 9 Noteworthy papers in OnePetro
- 10 External links
- 11 See also
- 12 Category
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, or 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
- 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. Resin fluid-shutoff treatments are available from relatively few oilfield service companies.
Resin conformance fluid-shutoff treatments had been somewhat widely applied in previous years but the popularity of resin fluid-shutoff treatments has declined.
Resin 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.
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.
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 are 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:
- Behind pipe channels
- Gravel packs
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.
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. 1 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.
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.
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).
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:
- 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.
- 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.
- 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.
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.
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.
- 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.
- Corroded placement equipment or injection tubular strings can play havoc with the kinetics of the resin polymerization reaction, especially for epoxy resins.
- An oil-coated injection string can be detrimental to the polymerization reaction product of some resin formulas.
- 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.
- 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.
To their advantage, resins possess:
- Good mechanical strength
- Good bonding strength
- Good thermal stability
- Good chemical inertness (e.g., can acidize over resins)
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
- Are considered to be a niche conformance-treatment technology
Do's and Don’ts
The following items are a partial list of “do’s” and “don’ts” as they apply to resin fluid-shutoff treatments.
- 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.
- 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.
- Kabir, A.H. 2001. Chemical Water and Gas Shutoff Technology—An Overview. Presented at the SPE Asia Pacific Improved Oil Recovery Conference, Kuala Lumpur, 8–9 October. SPE-72119-MS. http://dx.doi.org/10.2118/72119-MS.
- Barnes, R.M. 1922. Notes on the Use of Resin for Excluding Water From Oil Wells. Annual Report of the State Oil and Gas Supervisor of California, California Division of Oil and Gas, Vol. 12, 3.
- Littlefield, B.A., Fader, P.D., and Surles, B.W. 1992. Case Histories of New Low-Cost Fluid Isolation Technology. Presented at the SPE Annual Technical Conference and Exhibition, Washington, D.C., 4-7 October 1992. SPE-24802-MS. http://dx.doi.org/10.2118/24802-MS.
- Fader, P.D., Surles, B.W., Shotts, N.J. et al. 1992. New Low-Cost Resin System for Sand and Water Control. Presented at the SPE Western Regional Meeting, Bakersfield, California, 30 March-1 April 1992. SPE-24051-MS. http://dx.doi.org/10.2118/24051-MS.
- Hess, P.H. 1980. One-Step Furfuryl Alcohol Process for Formation Plugging. J Pet Technol 32 (10): 1834-1842. SPE-8213-PA. http://dx.doi.org/10.2118/8213-PA.
- Morgenthaler, L.N. and Schultz, H.A. 1994. A Novel Process for Profile Control in Thermal Recovery Projects. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 25-28 September 1994. SPE-28504-MS. http://dx.doi.org/10.2118/28504-MS.
- Coiled-Tubing Resin Squeeze to Mitigate Water Production. 1998. J Pet Tech (June): 41.
Noteworthy papers in OnePetro
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