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Polymer waterflooding design and implementation
When conducting a polymer waterflood, a high-molecular-weight and viscosity-enhancing polymer is added to the water of the waterflood to decrease the mobility of the flood water and, as a consequence, improve the sweep efficiency of the waterflood (See Polymer waterflooding). This articles focuses on the design and field implementation of a polymer waterflood.
- 1 Flood design
- 2 Polymer injection
- 3 Pilot testing
- 4 Issues regarding manufacturing of polymers
- 5 Quality control
- 6 References
- 7 Noteworthy papers in OnePetro
- 8 External links
- 9 See also
Working up a flood design is one of the first steps when implementing a polymer-waterflooding project.
Selecting a polymer
When selecting a polymer for a polymer waterflooding project, one should try to maximize, as best as possible, all the following polymer attributes. The polymer should
- Maximize the amount of viscosity enhancement and/or mobility reduction per unit cost
- Readily dissolve
- Propagate well and have low retention as transported through the reservoir
- Exhibit good shear stability
- Possess good chemical stability
- Have good biological stability
- Be thermally stable at reservoir temperature
- Possess acceptable injectivity properties
The optimum concentration of the polymer to be injected is a critical parameter in the design of an effective polymer waterflooding project. The concentration of the injected polymer profoundly affects the cost, economics, and performance of a polymer-flooding project. The optimum concentration is a function of reservoir properties, the nature of the reservoir’s conformance problems, and the business objective of the polymer flood. Business objectives of a polymer flood can include maximizing oil recovery, maximizing the rate of return on the cost of the polymer-flooding project, and minimizing the cost of the polymer flood.
De Bons and Braun provide a literature review of 12 international polymer-flooding projects conducted between 1975 and 1992. The projects included both pilot and fieldwide projects. Ten of the polymer-flooding projects involved the use of acrylamide polymers, and two projects involved the use of xanthan polymers. All the flooding projects were conducted in reservoirs with temperatures less than 140°F. For the 12 international polymer-flooding projects, the median incremental oil recovery, as calculated from data in the paper, was 13% original oil in place (OOIP), and the range of incremental oil recoveries was reported to be 6 to 52% OOIP. The average pore volume (PV) of the polymer slug injected was calculated to be 51%, with the range of PVs being 21 to 100%.
These flooding parameter values are noteworthy when viewed in terms of comparable values reported in the paper, or calculated from data presented in the paper, for 128 polymer floods performed in the US between 1980 and 1993. The median incremental oil production for the US polymer floods was 4.9% OOIP. The average concentration of polymer injected in the US projects was 460 ppm vs. 920 ppm for the international polymer floods. De Bons and Braun state that it appears the amount of incremental oil production for the 12 international projects best correlates with the numerical value that is obtained from multiplying the PV of the polymer slug injected by the average concentration of the polymer injected during the polymer flooding project.
On the basis of the 12 international polymer flooding projects, 900-ppm polymer concentration in the polymer slug would be a good starting value in designing a polymer waterflooding project. Working from this initial concentration, it should be determined, using appropriate engineering and evaluation tools, whether the optimum polymer concentration for the proposed polymer flood is actually higher or lower.
Sizing volume injected
At this writing, optimum sizing of the polymer-solution slug to be injected was one of the most controversial aspects of designing a polymer waterflooding project. This design parameter profoundly affects the cost, economics, and performance of a polymer-flooding project. Underdesigning the size of the polymer slug injected has been thought to be a major cause for the disappointing performance of many polymer floods conducted in the US. Using the general arguments made in previous subsections, the optimum size of the polymer-solution slug during polymer flooding is a function of reservoir properties, nature of the reservoirs conformance problems, and the business objective of the polymer flood. Business objectives of a polymer flood can include maximizing oil recovery, maximizing the rate of return on the cost of the polymer flooding project, or minimizing the cost of the polymer flood.
On the basis of 12 international polymer-flooding projects, a 50% PV slug of polymer solution would be a good starting value to use in designing a polymer waterflooding project. Working from this initial polymer solution slug size, it should be determined, using appropriate engineering and evaluation tools, whether the optimum polymer solution slug size for the proposed polymer flood is actually higher or lower. When attempting to design the optimum size of the polymer solution slug, two important parameters that need to be accounted for are polymer retention and the rate and nature of the viscous fingering of the polymer slug chase drive water into the polymer solution slug.
Grading of polymer concentration
To overcome, or substantially reduce, the problem of viscous fingering of the polymer slug chase drive water into the polymer slug, most polymer floods are designed with a tapered, decreasing polymer concentration chase slug beginning at or near the end of the design volume of the primary polymer-solution slug.
There is general agreement that, when all other factors are held constant, the earlier in the life of a waterflood that a polymer flood is initiated, the relatively more effective the polymer flood will be. Two factors offset the benefits of an early start.
- It is more difficult to definitively assess the oil-recovery potential and economic effectiveness of a polymer flood until definitive waterflood performance has been established
- Reservoir description and associated reservoir conformance problems are often less well defined, especially in a new reservoir
Suggested steps for designing a polymer flood
- Screen the candidate reservoirs for both the technical and economic feasibility of performing a successful polymer waterflooding project
- If appropriate and needed, improve the reservoir description
- Select the polymer that should be used in the flooding project
- When and where cost-effective, conduct laboratory studies under reservoir conditions to perform screening and compatibility tests on the polymer and polymer-solution core-flooding tests to determine polymer-solution flow properties and to estimate incremental oil recovery (on the scale of the core size used)
- Estimate the amount of polymer that will be required for the polymer flood
- Design the polymer-injection facilities
- When and where cost-effective, conduct a polymer-injectivity test and a field polymer flood pilot test
- If feasible and cost-effective, conduct reservoir simulation studies
- Optimize the reservoir, operational, and economic performance of the polymer waterflooding project, such as optimizing well and pattern spacing, completion strategies, and injection rates
One of the primary causes of failure for polymer flood projects is that the reservoir description used was inaccurate.
The polymer-injection facilities and the actual injection of the polymer solution are important aspects of a successful polymer waterflooding operation.
If the polymer is allowed to become mechanically shear degraded during surface mixing and pumping operations or during injection into the reservoir, the polymer will have lost a substantial amount, if not most, of its viscosity enhancing and mobility reducing power before leaving the injection well near-wellbore region. The higher the rate that a polymer solution is injected across a unit area of injection surface, the greater the propensity for mechanical shear degradation of the polymer. It is most often the goal to inject the polymer solution as rapidly as possible without exceeding reservoir parting pressure. The strategy usually implemented is to use injection equipment and well completions that permit desired injection rates without substantial mechanical degradation.
To minimize mechanical shear degradation, the operator needs to use specialized pumping equipment, be sure that the polymer solution is not passed through any valves or orifices that cause high and damaging shear fields, and use special mixing and dilution equipment, such as the use of static mixers, to not shear degrade the polymer during mixing and dilution operations.
Injection wells of polymer floods are often openhole or gravel-packed completions. Hydraulically fracturing the injection well with short, wide fractures has been reported to have been used successfully to aid in injecting hydrolyzed polyacrylamide (HPAM) without excessive shear degradation. The injection of polymer solutions through mandril completions, with associated flow of the polymer solution through mandril orifices, has proved to be detrimental in several instances.
Historically, the polymer, as supplied to (or near) the final wellsite, must be dissolved and/or diluted to some degree. The polymer dissolution or dilution process needs to be implemented so that the polymer is fully dissolved, at the proper concentration before injection into the reservoir, and dissolved or diluted in a manner that does not mechanically shear degrade the polymer. The dissolution or dilution process can range from a fairly simple process for broths of xanthan polymer to a quite difficult and technically challenging process for ultra-high- molecular weight (MW) solid HPAM. A long dissolution time is an economic determent for a polymer flood, because it requires extra equipment and extra polymer-solution holding tanks.
The polymer solution normally should be filtered before injection to ensure that it is readily injectable and does not unduly damage injectivity. This is a particularly critical and challenging issue when injecting biopolymer solutions, such as xanthan solutions, that are notorious for containing substantial amounts of cell debris from the polymer’s fermentation process and cell debris that are difficult to remove fully with filters.
HPAM polymer, when obtained in the solid form and then dissolved in the field, should normally be filtered to remove microgels or undissolved “fisheyes.” The amount of microgel and fisheye material in a given hydrolyzed acrylamide polymer varies from manufacturer to manufacturer and even with manufacturing lots from the same polymer manufacturer. These microgels and fisheyes of partially hydrated solid HPAM in solution often largely result from the final drying process in the manufacturing of the polymer, in which overheating, overdrying, and other factors cause some of the polymer molecules to crosslink together chemically during the drying process.
Downhole injection pressure should normally be kept below formation fracturing and parting pressures. If injection-well fracturing is required to obtain adequate polymer solution injectivity or to eliminate mechanical shear degradation, the injection wells are normally appropriately hydraulically fractured during a separate hydraulic fracturing operation.
It is recommended that a pilot test of a polymer waterflooding design be implemented in one or several injection wells before a polymer waterflooding project is implemented field wide and/or before implementing an expensive polymer flood project. The primary objective of a pilot test is to assure that there will be adequate injectivity and that there will be no substantial injectivity issues. The polymer solution injectivity trial can be as short as several days. Proper interpretation of a single-well polymer injectivity test can be difficult. If time and economics permit, a secondary objective of the pilot test is to demonstrate that the polymer flood will perform in the reservoir as expected in terms of mobilizing and recovering incremental oil. If it proves to be cost-effective, observation wells can be drilled near the injection well to observe, in a relatively short time frame, how the polymer flood can be expected to perform in the reservoir.
Issues regarding manufacturing of polymers
Polymers used in polymer waterflooding can be manufactured and provided to the end user in one of four forms. #Polymers in solid particle form, the oldest form, are readily transported and stored. Polymers supplied in solid particles are a challenge to dissolve properly and fully. In addition, the polymer of solid particle polymers can be damaged in the drying process during polymer manufacturing, may contain undesirable chemicals that coat the polymer particles, and often contain undissolvable microgels that are not injectable into matrix reservoir rock and that damage the injectivity of the polymer solution injection wells.
- Concentrated (~10%) broths of aqueous polymer (especially biopolymers), is more easily dissolved in the field, but is more costly per pound of polymer to transport to the field.
- Either aqueous emulsions that contain up to 35% or more active polymer or hydrocarbon-fluid suspensions/dispersions that contain ~50% active polymer. The challenge in using polymers supplied in this form is to routinely and consistently fully invert the emulsion/suspension in the field to permit the polymer to be dissolved fully in the flood water and to be fully effective during the polymer waterflood.
- Where economic and project scale permit, field-manufactured polymer, especially field-manufactured partially hydrolyzed polyacrylamide, can be an attractive option for providing polymer of high quality and exceptional performance characteristics. 
Quality control is an essential element for the successful implementation of a polymer-waterflooding project. A quality control program should include, but not be limited to, the following elements:
- Routine verification of the polymer concentration in the polymer as supplied and in the polymer solution injected
- Routine determination of the viscosity and SFs of the injected polymer solution
- Check of the filterability of the polymer solution to be injected
- Check of the dissolution-rate properties of the polymer as supplied
- Check of the polymer to be injected for complete dissolution
- Periodical check of the thermal and chemical stability of the polymer by measuring the viscosity and SF of wellhead polymer samples that have been aged for appropriate periods of time at reservoir temperature under scrupulous anaerobic conditions in sealed glass ampoules (See the recommended polymer solution sample deoxygenation procedure discussed in Polymer waterflooding.)
- Lake, L.W. 1989. Enhanced Oil Recovery, 314-353. Englewood Cliffs, New Jersey: Prentice Hall.
- De Bons, F.E. and Braun, R.W. 1995. Polymer Flooding: Still Viable IOR Technique. Paper presented at the 1995 European IOR Symposium, Vienna, Austria, 15–17 May, 57–65.
- Sorbie, K.S. 1991. Polymer-Improved Oil Recovery. Glasgow and London: Blackie.
- DeHekker, T.G., Bowzer, J.L., Coleman, R.V. et al. 1986. A Progress Report on Polymer-Augmented Waterflooding in Wyoming's North Oregon Basin and Byron Fields. Presented at the SPE Enhanced Oil Recovery Symposium, Tulsa, Oklahoma, 20-23 April 1986. SPE-14953-MS. http://dx.doi.org/10.2118/14953-MS
- Argabright, P.A., Rhudy, J.S., and Phillips, B.L. 1982. Partially Hydrolyzed Polyacrylamides with Superior Flooding and Injection Properties. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 26-29 September 1982. SPE-11208-MS. http://dx.doi.org/10.2118/11208-MS
Noteworthy papers in OnePetro
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