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Collaborating Authors
Results
Abstract Crosslinked polymers extrude through fractures during placement of many conformance improvement treatments, as well as during hydraulic fracturing. Dehydration of polymer gel during extrusion through fractures has often been observed, and was extensively investigated during the last decades. Injection of highly-viscous gel increases the pressure in a fracture, which promotes gel dehydration by solvent leakoff into the adjacent matrix. The present comprehension of gel behavior dictates that the rate of solvent leakoff will be controlled by the gel and fracture properties, and to a less extent impacted by the properties of an adjacent porous medium. However; several experimental results, presented in this work, indicate that solvent leakoff deviates from expected behavior when oil is present in the fracture-adjacent matrix. We investigated solvent leakoff from Cr(III)-Acetate-HPAM gels during extrusion through oil-saturated, fractured core plugs. The matrix properties were varied to evaluate the impact of pore size, permeability and heterogeneity on gel dehydration and solvent leakoff rate. A deviating leakoff behavior during gel propagation through fractured, oil-saturated core plugs was observed, associated with the formation of a capillary driven displacement front in the matrix. Magnetic Resonance Imaging (MRI) was used to image water leakoff in a fractured, oil-saturated carbonate core plug and verified the position and existence of a stable displacement front. The use of MRI also identified the presence of wormholes in the gel, during and after gel placement, which supports gel behavior similar to the previously proposed Seright filter-cake model. An explanation is offered for when the matrix impacts gel dehydration and supported by imaging. Our results show that the properties of a reservoir rock may impact gel dehydration; which, in turn, strongly impacts the depth of gel penetration into a fracture network, and the gel strength during chase floods.
- Europe (1.00)
- North America > United States > Texas (0.46)
- North America > United States > Oklahoma (0.46)
- Geology > Geological Subdiscipline (0.46)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.30)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract This paper examines oil displacement as a function of polymer solution viscosity during laboratory studies in support of a polymer flood in the Cactus Lake reservoir in Canada. When displacing 1610-cp crude oil from field cores (at 27°C and 1 ft/d), oil recovery efficiency increased with polymer solution viscosity up to 25 cp (7.3 s). No significant benefit was noted from injecting polymer solutions more viscous than 25 cp. Much of the paper explores why this result occurred. That is, was it due to the core, the oil, the saturation history, the relative permeability characteristics, emulsification, or simply the nature of the test? Floods in field cores examined relative permeability for different saturation histories—including native state, cleaned/water-saturated first, and cleaned/oil-saturated first. In addition to the field cores and crude oil, studies were performed using hydrophobic (oil-wet) polyethylene cores and refined oils with viscosities ranging from 2.9 to 1000 cp. In nine field cores, relative permeability to water (krw) remained low—less than 0.03 for water saturations up to 0.42. Relative permeability to oil (kro) remained reasonably high (greater than 0.05) for most of this range. At a given water saturation, krw values for 1000-cp crude oil were about ten times lower than for 1000-cp refined oil. These observations help explain why only 25- cp polymer solutions were effective in recovering the viscous crude oil. In contrast to results found for the Daqing polymer flood, no evidence was found that high-molecular-weight (Mw) HPAM solutions mobilized trapped residual oil in our application. The results are discussed in light of ideas expressed in recent publications. The relevance of the results to field applications is also examined. Although 25-cp polymer solutions were effective in displacing oil during our core floods, the choice of polymer viscosity for a field application must consider reservoir heterogeneity and the risk of channeling/viscous fingering in a reservoir.
- North America > Canada > Saskatchewan (0.93)
- North America > United States > North Dakota (0.68)
- Asia > China > Heilongjiang Province > Daqing (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
Abstract This paper addresses two questions for polymer flooding. First, what polymer solution viscosity should be injected? A base-case reservoir-engineering method is present for making that decision, which focuses on waterflood mobility ratios and the permeability contrast in the reservoir. However, some current field applications use injected polymer viscosities that deviate substantially from this methodology. At one end of the range, Canadian projects inject only 30-cp polymer solutions to displace 1000-3000-cp oil. Logic given to support this choice include (1) the mobility ratio in an unfavorable displacement is not as bad as indicated by the endpoint mobility ratio, (2) economics limit use of higher polymer concentrations, (3) some improvement in mobility ratio is better than a straight waterflood, (4) a belief that the polymer will provide a substantial residual resistance factor (permeability reduction), and (5) injectivity limits the allowable viscosity of the injected fluid. At the other end of the range, a project in Daqing, China, injected 150-300-cp polymer solutions to displace 10-cp oil. The primary reason given for this choice was a belief that high molecular weight viscoelastic HPAM polymers can reduce the residual oil saturation below that expected for a waterflood or for less viscous polymer floods. This paper will examine the validity of each of these beliefs. The second question is: when should polymer injection be stopped or reduced? For existing polymer floods, this question is particularly relevant in the current low oil-price environment. Should these projects be switched to water injection immediately? Should the polymer concentration be reduced or graded? Should the polymer concentration stay the same but reduce the injection rate? These questions are discussed.
- North America > United States > Texas (1.00)
- Europe (1.00)
- South America (0.93)
- (2 more...)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.68)
- Geology > Geological Subdiscipline > Geomechanics (0.67)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract This paper examines whether retention of partially hydrolyzed polyacrylamide (HPAM) is different under anaerobic versus aerobic conditions. Both static (mixing with loose sand) and dynamic methods (core floods) were used to determine HPAM retention. There are both advantages and disadvantages associated with determining polymer retention using static tests versus dynamic tests and using aerobic versus anaerobic conditions. From static retention measurements, polymer adsorption values on pure silica sand or Berea sandstone were small, and they showed little difference between experiments conducted aerobically or anaerobically. For both aerobic and anaerobic conditions, HPAM retention increased significantly with increased pyrite or siderite content. Static retention under anaerobic conditions ranged from 45-75 µg/g with 1% of either pyrite or siderite to 137-174 µg/g for 10% pyrite or siderite to 1161-1249 µg/g for 100% pyrite or siderite. If iron minerals are present, the most representative polymer retention results are obtained (for both static and dynamic tests) if conditions are anaerobic. Retention values (from static measurements) under aerobic conditions were commonly twice those determined under anaerobic conditions. If iron minerals are present and retention tests are performed under aerobic conditions, TOC or some similar method should be used for polymer detection. Viscosity detection of polymer may provide retention values that are too high (because oxidative degradation can be misinterpreted as polymer retention). For a broad range of siderite content, retention from static tests did not depend on whether dissolved oxygen was present. However, for a broad range of pyrite content, HPAM retention was significantly lower in the absence of dissolved oxygen than under aerobic conditions. Theses results may be tied to iron solubility. When polymer solutions were mixed with 100% pyrite over the course of 12 hours, 360–480-ppm iron dissolved into polymer solutions under both aerobic and anaerobic conditions, whereas with 100% siderite, only 0–0.6-ppm iron dissolved. If dynamic methods (i.e., corefloods) are used to determine polymer retention under aerobic conditions, flow rates should be representative of the field application. Rates that are too high lead to underestimation of polymer retention. With 10% pyrite, dynamic retention was 211 μg/g at 6 ft/d versus 43.2 μg/g at 30 ft/d. In contrast, retention values were fairly consistent (40.6 – 47.8 μg/g) between 6 ft/d and 33 ft/d under anaerobic conditions.
- North America > United States > West Virginia (0.25)
- North America > United States > Pennsylvania (0.25)
- North America > United States > Ohio (0.25)
- North America > United States > Kentucky (0.25)