scholarly journals Analysis of polymer-flood performance including viscoelastic effects of polymer solution. Part 2. Experiments on one-dimensional polymer flood.

1991 ◽  
Vol 56 (1) ◽  
pp. 1-11
Author(s):  
Yoshihiro MASUDA
Keyword(s):  
Polymer Solution ◽  
One Dimensional ◽  
Polymer Flood ◽  
Viscoelastic Effects

Polymer in-Situ Rheology in Carbonate Reservoirs

2021 ◽  
Author(s):  
Tormod Skauge ◽  
Kenneth Sorbie ◽  
Ali Al-Sumaiti ◽  
Shehadeh Masalmeh ◽  
Arne Skauge
Keyword(s):  
Polymer Solution ◽  
Carbonate Rock ◽  
High Salinity ◽  
Polymer Flooding ◽  
Resistance Factor ◽  
Carbonate Reservoirs ◽  
Permeability Reduction ◽  
Polymer Flood ◽  
Core Flood

Abstract A large, untapped EOR potential may be extracted by extending polymer flooding to carbonate reservoirs. However, several challenges are encountered in carbonates due to generally more heterogeneous rock and lower permeability. In addition, high salinity may lead to high polymer retention. Here we show how in-situ viscosity varies with permeability and heterogeneity in carbonate rock from analysis of core flood results and combined with review of data available in literature. In-situ rheology experiments were performed on both carbonate outcrop and reservoir cores with a range in permeabilities. The polymer used was a high ATBS content polyacrylamide (SAV10) which tolerates high temperature and high salinity. Some cores were aged with crude oil to generate non-water-wet, reservoir representative wettability conditions. These results are compared to a compilation of literature data on in-situ rheology for predominantly synthetic polymers in various carbonate rock. A systematic approach was utilized to derive correlations for resistance factor, permeability reduction and in-situ viscosity as a function of rock and polymer properties. Polymer flooding is applied to improve sweep efficiency that may occur due to reservoir heterogeneities (large permeability contrasts, anisotropy, thief zones) or adverse mobility ratio (high mobility contrast oil-brine). In flooding design, the viscosity of the polymer solution in the reservoir, the in-situ viscosity, is an essential parameter as this is tuned to correct the mobility difference and to improve sweep. The viscosity is estimated from rheometer/viscometer measurements or, better, measured in laboratory core flood experiments. However, upscaling core flood experiments to field is challenging. Core flood experiments measure differential pressure, which is the basis for the resistance factor, RF, that describes the increased resistance to flow for polymer relative to brine. However, the pressure is also influenced by several other factors such as the permeability reduction caused by adsorption and retention of polymer in the rock, the tortuosity of the rock and the viscosity of the flowing polymer solution. Deduction of in-situ viscosity is straight forward using Darcy's law but the capillary bundle model that is the basis for applying this law fails for non-Newtonian fluids. This is particularly evident in carbonate rock. Interpretation of in-situ rheology experiments can therefore be misleading if the wrong assumptions are made. Polymer flooding in carbonate reservoirs has a large potential for increased utilization of petroleum reserves at a reduced CO2 footprint. In this paper we apply learnings from an extensive core flood program for a polymer flood project in the UAE and combine this with reported literature data to generate a basis for interpretation of in-situ rheology experiments in carbonates. Most importantly, we suggest a methodology to screen experiments and select data to be used as basis for modelling polymer flooding. This improves polymer flood design, optimize the polymer consumption, and thereby improve project economy and energy efficiency.

pH-Sensitive Polymers for Novel Conformance-Control and Polymer-Flood Applications

2010 ◽  
Vol 13 (06) ◽  
pp. 926-939 ◽  
Author(s):  
Suk Kyoon Choi ◽  
Mukul M. Sharma ◽  
Steven L. Bryant ◽  
Chun Huh
Keyword(s):  
Polymer Solution ◽  
Polymer Concentration ◽  
Injection Pressure ◽  
Low Ph ◽  
Ph Sensitive ◽  
Solution Viscosity ◽  
Conformance Control ◽  
Polymer Flood ◽  
Geochemical Reactions ◽  
Acidic Conditions

Summary Novel conformance-control and polymer-flood applications that exploit the pH sensitivity of partially hydrolyzed polyacrylamide (HPAM) are proposed. The key feature of this process is the injection of the HPAM solution under acidic conditions. The low pH makes polymer molecules coil tightly, resulting in a very low polymer-solution viscosity. This allows the polymer solution to be injected into the reservoir at a substantially reduced injection pressure. Once injected, the acid reacts with the formation minerals to cause a spontaneous pH increase, uncoiling the polymer chains and causing a large increase in solution viscosity. Such a viscosity-control scheme can be exploited for placement of a concentrated polymer solution in high-permeability zones, where it later viscosifies to divert subsequently injected fluids (in-depth conformance control), or to reduce the high pressure drop near the wellbore during polymer injection (injectivity improvement). Extensive laboratory experiments were systematically performed and interpreted to evaluate the novel applications of pH-sensitive HPAM. The evaluations require (a) quantification of steady-shear viscosities, (b) characterization of geochemical reactions with acids, and (c) transport evaluation of HPAM solutions in cores. Rheological measurements show that shear viscosities of HPAM solution have a pronounced, but reversible, dependence on pH. The peak pHs observed in several shut-ins guarantee that spontaneous geochemical reactions can return the polymer solution to its original high viscosity. The use of a weak acid is the key. Coreflood results show that the HPAM solution under acidic conditions can be propagated through cores with much higher mobility than at neutral pH. However, low-pH conditions increase adsorption (polymer loss) and require additional chemical cost (for acid). The optimum injection formulation (polymer concentration, injection pH) will depend on the specific reservoir mineralogy, permeability, salinity, and injection conditions.

Can 25-cp Polymer Solution Efficiently Displace 1,600-cp Oil During Polymer Flooding?

SPE Journal ◽  
2018 ◽  
Vol 23 (06) ◽  
pp. 2260-2278 ◽  
Author(s):  
R. S. Seright ◽  
Dongmei Wang ◽  
Nolan Lerner ◽  
Anh Nguyen ◽  
Jason Sabid ◽  
...  
Keyword(s):  
Crude Oil ◽  
Polymer Solution ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Polymer Solutions ◽  
Water Saturation ◽  
Field Application ◽  
Polymer Flooding ◽  
Solution Viscosity ◽  
Polymer Flood

Summary This paper examines oil displacement as a function of polymer-solution viscosity during laboratory studies in support of a polymer flood in Canada's Cactus Lake Reservoir. When displacing 1,610-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 seconds−1). No significant benefit was noted from injecting polymer solutions more viscous than 25 cp. Much of this paper explores why this result occurred. 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 1,000 cp. In field cores, relative permeability to water (krw) remained low, less than 0.03 for most corefloods. After extended polymer flooding to water saturations up to 0.865, krw values were less than 0.04 for six of seven corefloods. Relative permeability to oil remained reasonably high (greater than 0.05) for most of the flooding process. These observations help explain why 25-cp polymer solutions were effective in recovering 1,610-cp oil. The low relative permeability to water allowed a 25-cp polymer solution to provide a nearly favorable mobility ratio. At a given water saturation, krw values for 1,000-cp crude oil were approximately 10 times lower than for 1,000-cp refined oil. In contrast to results found for the Daqing polymer flood (Wang et al. 2000, 2011), no evidence was found in our application that high-molecular-weight (MW) hydrolyzed polyacrylamide (HPAM) solutions mobilized trapped residual oil. 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 corefloods, the choice of polymer viscosity for a field application must consider reservoir heterogeneity and the risk of channeling in a reservoir.

Prediction of Polymer Flood Performance

1971 ◽  
Vol 11 (01) ◽  
pp. 72-84 ◽  
Author(s):  
J.T. Patton ◽  
K.H. Coats ◽  
G.T. Colegrove
Keyword(s):  
Numerical Model ◽  
Polymer Solution ◽  
Oil Recovery ◽  
Single Layer ◽  
Polymer Flooding ◽  
Solution Viscosity ◽  
Flood Water ◽  
Polymer Flood ◽  
Member Aime ◽  
Quick Estimate

Patton, J.T., Member AIME, Patton, J.T., Member AIME, Computer/Bioengineering Institute, Inc., Houston, Tex. Coats, K.H., Member AIME, International Computer Applications Ltd., Houston, Tex. Colegrove, G.T., Kelco Co., Houston, Tex. Abstract This experimental and numerical study was performed to estimate the incremental oil recovery performed to estimate the incremental oil recovery by pattern polymer flooding in a California viscous-oil reservoir. Results indicate that adding 270-ppm Kelzan to the normal flood water will boost oil production by 42 percent (at 1 PV injected) and production by 42 percent (at 1 PV injected) and will reduce water handling costs sharply. This corresponds to $8.35 incremental oil/$1.00 polymer injected, taking into account the 30 percent pore volume bank of polymer solution. The 28.6 percent additional oil recovery predicted at 0.5 PV injected yields a return of $4.60 incremental oil/$1.00 polymer injected. polymer injected. The field predictions are based onlaboratory measurements of polymer solution viscosity, adsorption and dispersion upon displacement by normal water in a sand representative of the reservoir,linear laboratory oil displacement experiments using brine and polymer solution, anda numerical model developed to simulate linear or five-spot polymer floods in single-layer or stratified reservoirs. The paper presents an analytical solution to the linear polymer flood problem, which provides a check on accuracy of the numerical model and a quick estimate of additional oil recovery by line-drive polymer floods. The numerical model developed indicates that additional oil recovery by polymer flooding is sensitive to polymer bank size polymer flooding is sensitive to polymer bank size and adsorption level and is insensitive to the extent of dispersion active at the trailing edge of the polymer slug. polymer slug Introduction The benefits of improving the mobility ratio, lambda o/lambda w, on waterflood performance is well documented and research on how best to effect this improvement has been considerable. Both producers and chemical manufacturers, spurred on producers and chemical manufacturers, spurred on by the vast reserves of oil which will be otherwise abandoned, have sought to resolve the problem. Currently, two types of additives are being marketed and field tested with promising results. Both additives increase oil recovery by lowering the mobility of the flood water, lambda w. However, they effect this lowering by distinctly different mechanisms. Mobility of the flood water is given by: lambdaw = kw/ w . Hence, one may elect to either increase viscosity, mu w, or decrease effective permeability, kw. Viscosity can be increased by adding small amounts of a water-soluble polymer. To be effective at the flood front this additive should exhibit minimum adsorption on the pore surfaces. Polymers showing minimal adsorption are generally a combination nonionic-anionic type. The negative charge repels the clay platelets to reduce adsorption and the nonionic portion provides the brine tolerance required for reservoir applications. A polymer of this type, Kelzan M, was chosen for the study. The alternate method of lowering mobility is equally well known. It consists of adding to the flood water a polymer designed to adsorb on the pore surfaces, thereby physically reducing the available flow area. This study was performed to estimate the additional oil recovery by pattern polymer flooding using Kelzan in a California viscous-oil reservoir. Laboratory experiments were performed to estimate polymer solution viscosity, adsorption and polymer solution viscosity, adsorption and dispersion upon displacement by normal injection water. Waterflood and polymer flood oil recovery curves were obtained for a laboratory core packed with sand representative of the reservoir. A numerical model was developed to simulate polymer floods in linear or five-spot patterns in single-layer or stratified reservoirs. An analytical solution to the linear polymer flood problem was developed to provide a quick estimate of incremental oil provide a quick estimate of incremental oil obtainable by polymer flooding and to provide a check on the accuracy of the numerical model. SPEJ P. 72

Sign in / Sign up

Export Citation Format

Share Document