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Placement of conformance improvement gels

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Proper placement of conformance improvement gels is key to achieving the desired results within the reservoir. 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.[1][2] 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.[1][2]

Gel treatments when matrix

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.[1][3] 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).[3] 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
  • 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.[4] 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 is discussed in the next section. 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. Chromium(III)-carboxylate/acrylamide-polymer (CC/AP) fracture-problem polymer gels that are placed in such a manner are capable of selectively plugging the treated fracture volume effectively.[4]

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.[5] [6] [7] 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.[6] 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.[6] [7] [8] 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:


where wf is the fracture width.[7] [8] (See Fig. 1.) The data of Fig. 1 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.

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.[7] [8] 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, μl in ft/D (or alternatively ft3/ft2/D), has been described, as Fig. 2 shows, by the empirical equation:


where t is time in days.[7] During the laboratory flooding-experiment study of Fig. 2, 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.

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.[9] [10] [11] As normally used in conjunction with gel treatments and gel injection, Σptf Δt is plotted vs. cumulative gel volume injected Wi, where ptf is the flowing wellhead pressure in psi, Δt is time in days, and Wi is cumulative injection volume in barrels. Under steady-state conditions, the slope of the Hall plot is


where μ is viscosity in cp, re is the external reservoir radius in feet, rw 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. 3 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.[11]

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.[12][13][14] 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.[15]

Dual injection of two fluids to impart selective gel placement has been suggested and applied in pilot tests. It is not yet a routine practice, except in the case of 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:


MH = Hall plot slope
s = skin factor
t = time, t, days
wf = fracture width/aperture, L
khi = high permeability, L2
μ = viscosity
μi = viscosity of phase i


  1. 1.0 1.1 1.2 Seright, R.S., Lane, R.H., and Sydansk, R.D. 2001. A Strategy for Attacking Excess Water Production. Presented at the SPE Permian Basin Oil and Gas Recovery Conference, Midland, Texas, 15-17 May 2001. SPE-70067-MS.
  2. 2.0 2.1 Seright, R.S. 1988. Placement of Gels to Modify Injection Profiles. Presented at the SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, Oklahoma, 16–21 April. SPE-17332-MS.
  3. 3.0 3.1 Sorbie, K.S. and Seright, R.S. 1992. Gel Placement in Heterogeneous Systems With Crossflow. Presented at the SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, Oklahoma, 22–24 April. SPE-24192-MS.
  4. 4.0 4.1 Seright, R.S. 1995. Gel Placement in Fractured Systems. SPE Prod & Oper 10 (4): 241-248. SPE-27740-PA.
  5. Sydansk, R.D. and Moore, P.E. 1992. Gel Conformance Treatments Increase Oil Production in Wyoming. Oil & Gas J. (20 January): 40.
  6. 6.0 6.1 6.2 Seright, R.S. 1997. Use of Preformed Gels for Conformance Control in Fractured Systems. SPE Prod & Oper 12 (1): 59-65. SPE-35351-PA.
  7. 7.0 7.1 7.2 7.3 7.4 Seright, R.S. 2001. Gel Propagation Through Fractures. SPE Prod & Fac 16 (4): 225-231. SPE-74602-PA.
  8. 8.0 8.1 8.2 Seright, R.S. 1999. Mechanism for Gel Propagation Through Fractures. Presented at the SPE Rocky Mountain Regional Meeting, Gillette, Wyoming, 15–18 May. SPE-55628-MS.
  9. Hall, H.N. 1963. How to Analyze Waterflood Injection Well Performance. World Oil (October): 128.
  10. Earlougher, R.C. Jr. 1997. Advances in Well Test Analysis, 85-87. Richardson, Texas: SPE.
  11. 11.0 11.1 Seright, R.S. 1993. First Annual Technical Progress Report—Improved Techniques for Fluid Diversion in Oil Recovery, DOE/BC/14880-5, Ch. 6. Bartlesville, Oklahoma: US DOE.
  12. Denys, K., Fichen, C., and Zaitoun, A. 2001. Bridging Adsorption of Cationic Polyacrylamides in Porous Media. Presented at the SPE International Symposium on Oilfield Chemistry, Houston, Texas, 13-16 February 2001. SPE-64984-MS.
  13. Chauveteau, G., Denys, K., and Zaitoun, A. 2002. New Insight on Polymer Adsorption Under High Flow Rates. Presented at the SPE/DOE Improved Oil Recovery Symposium, Tulsa, Oklahoma, 13–17 April. SPE-75183-MS.
  14. Zitha, P.L.J. and Botermans, C.W. 1998. Bridging Adsorption of Flexible Polymers in Low-Permeability Porous Media. SPE Prod & Oper 13 (1): 15-20. SPE-36665-PA.
  15. Thompson, K.E. and Fogler, H.S. 1995. A Study of Diversion Mechanisms by Reactive Water-Diverting Agents. SPE Prod & Oper 10 (2): 130-136. SPE-25222-PA.

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See also


Types of gels used for conformance improvement

Evaluation of conformance improvement gels

Conformance improvement gel treatment design

Field applications of conformance improvement gel treatments