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Conformance improvement 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.
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. 1 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. 1 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.
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.
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.
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)
- Polymer solution (often the polymer solution of the gel without the addition of the crosslinking agent)
- 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.
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.
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. Many early polymer-gel treatments were pumped using the sequential-fluid injection mode.
Disproportionate permeability reduction
Disproportionate permeability reduction (DPR) 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.
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 treatments, the well or well pattern to be treated must be suffering from a treatable conformance sweep problem or suffering from a treatable excessive fluid co-production 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
- Substantial movable oil saturation within the well pattern
- Unexpectedly low oil recovery within the well pattern
Good production well candidates are characterized by some combination of:
- High water/oil ratio (WOR) or gas/oil ratio (GOR)
- Excessive competing water or gas coproduction
- Substantial movable oil saturation within the well pattern
- Unexpectedly low oil recovery, early water or gas breakthrough
- 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
- Assuring that the gelant solution is injectable into the matrix reservoir rock without face plugging occurring(when conducting matrix rock treatments)
- 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(conducted in the field or at a nearby laboratory using actual field gel-formula chemicals) and gel make-up water(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 section of Evaluation of conformance improvement gels) 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 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
- Result in excessive back production of gel(following poorly designed producing-well treatments)
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
- Failure to use a chemically robust and adequately thermally stable gel technology or a sufficiently strong gel formula
Additional pitfalls include:
- 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
- Incomplete understanding of how microgels function
- Incomplete dissolution of all the gel’s makeup chemicals before gel-fluid injection
- 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 1 provides a general ranking of water-production problems and treatment categories in order of increasing difficulty to treat successfully.
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.1 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 success rates of gel treatments
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:
- Tendency to average permeabilities over relatively long logging intervals
- Ignoring what unrecovered core intervals might be suggesting during coring operations
- 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 co-production 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.
- Conformance problem must be correctly identified
- Proper and effective gel system must be selected
- Gel treatment must be properly designed and sized
- Gelant solution and/or gel must be properly applied and placed
- 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.
- Seright, R.S., Liang, J., and Seldal, M. 1998. Sizing Gelant Treatments in Hydraulically Fractured Production Wells. SPE Prod & Fac 13 (4): 223–229. SPE-52398-PA. http://dx.doi.org/10.2118/52398-PA
- Sydansk, R.D. and Moore, P.E. 1992. Gel Conformance Treatments Increase Oil Production in Wyoming. Oil & Gas J. (20 January): 40.
- Sydansk, R.D. and Southwell, G.P. 2000. More Than 12 Years of Experience with a Successful Conformance-Control Polymer Gel Technology. SPE Prod & Fac. 15 (4): 270. SPE-66558-PA. http://dx.doi.org/10.2118/66558-PA
- Southwell, G.P. and Posey, S.M. 1994. Applications and Results of Acrylamide-Polymer/Chrnmium (III) Carboxylate Gels. Presented at the SPE/DOE Improved Oil Recovery Symposium, Tulsa, Oklahoma, 17-20 April 1994. SPE-27779-MS. http://dx.doi.org/10.2118/27779-MS
- OBrien, W.J., Jr., J.J.S., and Lane, R.H. 1999. Mechanistic Reservoir Modeling Improves Fissure Treatment Gel Design in Horizontal Injectors, Idd El Shargi North Dome Field, Qatar. Presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 3-6 October 1999. SPE-56743-MS. http://dx.doi.org/10.2118/56743-MS
- Lane, R.H. and Seright, R.S. 2000. Gel Water Shutoff in Fractured or Faulted Horizontal Wells. Presented at the SPE/CIM International Conference on Horizontal Well Technology, Calgary, Alberta, Canada, 6-8 November 2000. SPE-65527-MS. http://dx.doi.org/10.2118/65527-MS
- 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
- Kohler, N., Rahbari, R., Han, M. et al. 1993. Weak Gel Formulations for Selective Control of Water Production in High-Permeability and High-Temperature Production Wells. Presented at the SPE International Symposium on Oilfield Chemistry, New Orleans, Louisiana, 2-5 March 1993. SPE-25225-MS. http://dx.doi.org/10.2118/25225-MS
- Dovan, H.T. and Hutchins, R.D. 1994. New Polymer Technology for Water Control in Gas Wells. SPE Prod & Oper 9 (4): 280-286. SPE-26653-PA. http://dx.doi.org/10.2118/26653-PA
- Seright, R.S. 1995. Reduction of Gas and Water Permeabilities Using Gels. SPE Prod & Fac 10 (2): 103–108. SPE-25855-PA. http://dx.doi.org/10.2118/25855-PA
- Thompson, K.E. and Fogler, H.S. 1997. Pore-Level Mechanisms for Altering Multiphase Permeability with Gels. SPE J. 2 (3): 350-362. SPE-38433-PA. http://dx.doi.org/10.2118/38433-PA
- Liang, J.-T., Sun, H., and Seright, R.S. 1995. Why Do Gels Reduce Water Permeability More Than Oil Permeability? SPE Res Eng 10 (4): 282–286. SPE-27829-PA. http://dx.doi.org/10.2118/27829-PA
- Grattoni, C.A., Jing, X.D., and Zimmerman, R.W. 2001. Disproportionate Permeability Reduction When a Silicate Gel is Formed In-Situ to Control Water Production. Presented at the SPE Latin American and Caribbean Petroleum Engineering Conference, Buenos Aires, Argentina, 25–28 March. SPE-69534-MS. http://dx.doi.org/10.2118/69534-MS
- Seright, R.S., Lane, R.H., and Sydansk, R.D. 2001. A Strategy for Attacking Excess Water Production. Presented at the SPE Permian Basin Oil and Gas Recovery Conference, Midland, Texas, 15-17 May 2001. SPE-70067-MS. http://dx.doi.org/10.2118/70067-MS
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