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Polymer and Polymer-Gel Water
Shutoff Treatments, What It Takes To Be Successful and Illustrative Field
Application
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Based on a workshop co-sponsored by PTTC's Texas Region, held on August 25, 2004 in Houston, TX.
Polymer-gel water-shutoff (WSO) treatments are highly reservoir-, well- and problem-specific. In order to successfully apply a polymer-gel WSO treatment, the underlying problem must be correctly identified (or deduced) and be amenable to polymer-gel WSO treatments. Then an appropriate polymer-gel system must be properly selected, sized and applied. Diagnosing whether flow of the excess water production is linear (e.g., fractures) or radial (matrix rock) is critical since the flow regime greatly influences the required gel composition, volume and placement method. Extensive case study data exist on application of CC/AP gel technologies in WSO treatments. Through experience, the industry has learned that reservoir-channeling flow paths tend to actually have higher permeabilities than are normally initially anticipated. Success rate for experienced operators in fields with a track record of polymer-gel WSO treatments can exceed 90%, whereas inexperienced operators first performing treatments should only expect a 60% success rate. This latter success rate can be greatly improved upon by applying guidelines presented in the workshop. Success is often proportional to operator involvement. Good teamwork among the producer, service provider and technology provider is essential.
Excessive, unproductive water production is a major problem throughout the world. One study indicates that in the U.S. we produce 7 barrels of water for every barrel of oil produced. Polymer-gel water-shutoff treatments are one solution. Although widely applied in some areas, their use is rare in other areas where they appear to be an attractive option. So what does it take to apply this technology that can lower water production and associated lifting/handling costs and, in many cases, increase oil recovery and reserves? Material in this workshop, presented by two well-respected experts in the field, directly addresses that question.
Candidate screening/diagnostics, Linear versus radial flow, Polymer-gel water-shutoff, treatments, Treatment design and sizing
Introduction to Polymer and Polymer-Gel Water-Shutoff (WSO)
Treatments;
Overview of the CC/AP Gel WSO Technology & Illustrative Field Applications;
High Temperature Applications of Polymer Gels;
What Experience Has Taught Us;
Latest Advances & What Is Coming and Needed,
Bob Sydansk
What Polymers, Gelants and Gels Can and Cannot Do;
Placement Concepts;
Strategy for Attacking Excess Water Production Problems,
Randy Seright
There are a multitude of high permeability anomalies responsible for excess water production, including: fractures, solution channels, faults and joints, conductive vugular porosity, karsting, rubbelized zones, cobble packs, unconsolidated coarse sand, multi-Darcy matrix reservoir rock, channeling behind pipe, and casing leaks. Multiple solutions could be appropriate and are available. These include mechanical procedures, cement, downhole water separation, and chemical (of which polymer-gel water-shutoff (WSO) treatments are most common). The challenge is to correctly identify or deduce the nature of the excess water production problem at the well to be treated, and then to select an appropriate WSO technology to apply.
One must recognize that polymer-gel water shutoff treatments are highly reservoir-, well- and problem-specific. The underlying problem leading to excess water production must be correctly diagnosed and be amenable to polymer-gel WSO treatments, then the appropriate polymer-gel system must be properly designed, sized and executed. For an experienced operator in a field where polymer-gel treatments have been previously applied successfully, success rates can exceed 90%. There is a learning curve—an inexperienced operator applying polymer-gel WSO treatments for the first time in a new field should only expect a 60% success rate. However, this latter success rate can be greatly improved upon by employing the guidelines presented in the workshop.
Polymer solutions and crosslinking agents are mixed together in order to form a gelant solution. Gelants can flow into porous matrix rock. With time and chemical crosslinking, gelants develop 3-D structures that will not enter into, or flow through, porous rock of normal permeabilities (less than 10 Darcys). Gelation time determines how far a gelant can penetrate into porous rock. Gelation times for most commercial gelants are fairly short even at moderate temperatures. There are several methods to increase gelation time. Higher molecular weight polymers that are incorporated into gel formulations used to treat reservoir high-permeability anomalies, such as fractures, require lower concentrations for 3-D gel formation.
In small volume applications often applied to treat matrix reservoir rock in the near-wellbore region, gel formulations exist as fluid gelants during most of the placement process, while with larger volume applications used to treat fracture problems, the formulations exist as partially- or fully-formed gels during most of the placement process in the reservoir. A minimum pressure gradient must be met before a formed gel will extrude through a fracture. Once the minimum pressure gradient is met, the pressure gradient during gel extension is not sensitive to injection rate. Gels, while propagating through a fracture, dehydrate or lose water to the formation with the amount of dehydration depending on injection rate and time. Gels injected at high rate achieve maximum penetration with minimum dehydration. More concentrated rigid gels can be formed by injecting slower, decreasing the possibility of gel washout. For example, this might be done at the end of a treatment to form more rigid gels in near-wellbore vicinity.
Polymer-gel technology developed by Marathon, MARCITSM or CC/AP gel technology, has proven to be a robust technology broadly applied in the U.S. There are other polymer-gel systems that are available that can be applied for WSO purposes. There is more case study information on MARCITSM applications than on other systems. For most gelants the gelation reaction is sensitive to pH. That is one reason why CC/AP gels, which are highly insensitive to pH, are well suited for use in CO2 floods that can be quite acidic.
There have been more than 2,000 CC/AP treatments worldwide. Data were presented for 43 injection-well treatments in Wyoming. Incremental oil from these treatments was 4.9 million barrels, costing on average less than $1 per incremental bbl of oil. For producer WSO treatments applied through May 1998, data on 252 Marathon treatments indicated an average oil production increase of 32 bopd per well along with an average decrease in water production of nearly 2,000 bwpd per well. In looking at more than 300 Arbuckle water shutoff treatments in Kansas, treatments paid out in 3 to 7 months on the basis of incremental oil only, making true economics with water reductions quite attractive.
High Temperature Applications of Polymer Gels
To achieve performance comparable to gels at lower temperature, high temperature CC/AP gels require (1) higher chemical (polymer and/or crosslinker) loadings and (2) slightly higher chemical loadings when employing carboxylate gelation-rate retarding agents. For higher temperatures there is a variety of gelation delay mechanisms that can be employed, individually or in combination. Combinations can be synergistic.
Selected higher temperature gel systems that are available include:
• Lignosulfonate gels (> 300°F; simple, inexpensive and environmentally friendly, SPE 37458)
Placement Concepts
When performing polymer-gel WSO treatments in producing wells, the objective is to shut off water without seriously damaging hydrocarbon-producing zones. Thus one wants to maximize blocking agent penetration into water-source pathways, while minimizing (or eliminating) penetration into hydrocarbon zones. One must understand the distinction between blocking agents (polymer gel) and mobility-control agents (simple viscous polymer solutions). For a blocking agent, penetration into low permeability zones should be minimized or at times eliminated.
Gelants can penetrate into all open zones. An acceptable placement of a gel is much easier to achieve in linear flow (e.g., fractured wells) than in radial flow (matrix reservoir rock). In radial flow there should be a permeability barrier between the oil- and water-producing zones and the oil-producing zone should be isolated from gelant injection. In radial flow without a barrier, heterogeneity alone does not ensure effective placement of water shutoff materials. In radial flow from a single zone, a gelant treatment would not be expected to improve water:oil ratio (WOR). One cannot overstress the importance of knowing in advance whether one has linear flow through fractures or other voids versus radial flow through matrix rock since gelant composition, volume and placement method are different for linear versus radial flow problems.
Strategy For Attacking Excess Water Production
Operators often do not adequately diagnose the cause of their water production problems because diagnosis requires money and time, they are uncertain about what methods are cost-effective for diagnosing specific problems, or they have a preconception (often incorrect) about what the reservoir problem is. In diagnosing problems a primary focus must be to determine whether it is a linear (e.g., fractured) or matrix (radial) flow problem. Applying the concept of using information one already has first, such as analyzing injectivity/ productivity data, often provides strong clues about the flow environment. If pressure buildup/falloff data of appropriate quality and relevance are available, modern pressure transient analysis techniques are good at identifying linear versus radial flow environments. Production logs, conventional well logs and understanding the geological environment are helpful for determining the flow environment. When tracers are used, transit times are valuable indicators.
The speakers used a four-category system to help understand where polymer-gel WSO treatments are appropriate. These categories and examples of associated problems fitting within each category are listed below:
Category A: Conventional treatments (bridge plugs, packers, cement, etc.) are an effective choice. Examples: casing leaks without flow restrictions (having moderate to large holes); flow behind pipe (having large flow-channel apertures); unfractured wells with effective barriers to crossflow.
Category B: Gelant treatments normally are an effective choice. Examples: casing leaks with flow restrictions (pinhole and thread leaks); flow behind pipe with flow restrictions (narrow flow channels); 2-D coning through a hydraulic fracture from an aquifer; natural fracture system connected to an aquifer.
Category C: Treatments with preformed gels are an effective choice. Examples: faults or fractures crossing a deviated or horizontal well; single fracture causing channeling between wells; natural fracture system allowing channeling between wells - and can also be applied to a natural fracture system that is connected to an aquifer.
Category D: Difficult problems where gel treatments should not be used. Examples: 3-D coning through matrix reservoir rock; cusping; channeling through matrix rock strata (no fractures) with crossflow.
What Experience Has Taught Industry
Reservoir-channeling flow paths invariably tend to have higher permeabilities than are initially anticipated. Success rate is often proportional to operator involvement. Good teamwork among the producer, service provider and technology provider is essential. Quality control strongly influences success rate, and complete polymer dissolution prior to injection is strongly recommended. That is, fully hydrate the polymer at the surface prior to adding the crosslinker and injecting the gelant solution.
The term "treatments" means that in order to be successful, there must be a treatable conformance (excess water production) problem. Problems where polymer-gel treatments are an attractive option (also see categories above) include:
Good producing well candidates have at least one of the following:
Successful treatments require:
Selection of the over-displacement fluid following gel fluid injection and its volume are critical. Fluids that are used include produced oil, water (usually produced water), and polymer solution without crosslinker. During treatment of fracture problems, the over-displacement fluid volume should be large enough to displace polymer gel far enough from the wellbore so that the critical pressure gradient for gel flow is not exceeded. It also must be large enough to permit acceptable and required oil inflow. However, it must not be so large as to permit excessive water inflow. Unfortunately, choosing the over-displacement volume is still largely empirical, being as much art as science.
Performance of polymer-gel WSO treatments, when treating many naturally fractured reservoirs, tends to improve with increasing gel volume (recent experience in Kansas Arbuckle treatments & other documented instances), but the trend does not extend infinitely. There is an optimum treatment volume, which is still often much greater than the treatment volumes that are typically being pumped.
Latest Advances & What Is Coming/Needed
Stronger gels are coming/needed for treating exceptionally large fractures or for when encountering large drawdown pressures. Solids addition, when judiciously added and/or exploited, can greatly increase gel compressive strength, thereby allowing gels to be effectively used for treating very large fractures, large vugs and small caverns, and sizable solution channels.
Disproportionate permeability reduction (DPR) technologies are an area receiving strong industry interest and are being promoted by several technology providers (www.pttc.org/news/4qtr2003/v9n4p5.htm#1). Mechanisms of polymer-gel DPR are being intensely studied (SPE 89389). With DPR technology, DPR has its greatest applicability and potential in treating fractures (both natural and hydraulically-induced) that cut through at least one water zone and at least one hydrocarbon zone. In these cases, the polymer or gelant leaks off from the fracture faces into the matrix in both water and hydrocarbon zones. After placement, the polymer or gel restricts water flow into the fracture while causing relatively small resistance to oil flow from the matrix into the fracture. Engineering-based designs are available for these situations. DPR polymer-alone and polymer-gel treatments may be applicable in some matrix situations (that have no fractures) where dry oil production occurs through one flow path and water production occurs via another flow path. Realistically for these matrix treatments, Kw should be reduced by a factor of 10 - 100 while Ko needs to be reduced by a factor of less than 2. There is still much to be learned about DPR treatments, so they should be considered a somewhat high-risk undertaking in wells that do not intersect fractures. Reasons for this assessment were presented in the workshop.
An emerging trend is to combine WSO treatments with stimulation. Case history data were included in the workshop handout material for combined WSO-acid stimulation treatments in wells producing from the Madison Carbonate in Wyoming's Big Horn Basin (see American Oil and Gas Reporter, February 1998). WOR decreased, water production dropped significantly, oil production increased, and significant incremental reserves were developed. In optimum designs, reserve development cost averaged $1.11 per barrel.
Additional areas where technology advances are coming/needed include:
Resources (online and print)
Randy Seright
Petroleum Recovery
Research Center
New Mexico Tech
801 Leroy Place, Campus Station
Socorro, NM 87801
Website:
http://baervan.nmt.edu/randy/
Phone: 505-835-5571
E-mail:
randy@prrc.nmt.edu
Robert (Bob) Sydansk
Sydansk Consulting
Services, LLC
4605 E. Peakview Ave
Centennial, CO 80121
Phone: 303-770-2196
E-mail:
RDSydansk@msn.com
For information on PTTC’s Texas Region and its activities contact:
Scott Tinker
Bureau of Economic Geology, University of Texas at Austin,
University Station, Box X, Austin, TX 78713-2924
512-471-0209, fax 512-471-0140,
Scott.Tinker@beg.utexas.edu
Disclaimer: No specific application of products or services is endorsed by PTTC. Reasonable steps are taken to ensure the reliability of sources for information that PTTC disseminates; individuals and institutions are solely responsible for the consequences of its use.
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