Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Transport and Plugging Performance Evaluation of a Novel Re-Crosslinkable Microgel Used for Conformance Control in Mature Oilfields with Super-Permeable Channels
Alotibi, Adel (Kuwait Institute for Scientific Research / Department of Geosciences and Geological and Petroleum Engineering, Missouri University of Science and Technology) | Song, T. (Department of Geosciences and Geological and Petroleum Engineering, Missouri University of Science and Technology) | Bai, Baojun (Department of Geosciences and Geological and Petroleum Engineering, Missouri University of Science and Technology) | Schuman, T. P. (Department of Chemistry, Missouri University of Science and Technology)
Abstract Preformed particle gels (PPG) have been widely applied in oilfields to control excessive water production. However, PPG has limited success in treating opening features because the particles can be flushed readily during post-water flooding. We have developed a novel micro-sized Re-crosslinkable PPG (micro-RPPG) to solve the problem. The microgel can re-crosslink to form a bulk gel, avoiding being washed out easily. This paper evaluates the novel microgels’ transport and plugging performance through super-permeable channels. Micro-RPPG was synthesized and evaluated for this study. Its storage moduli after fully swelling are approximately 82 Pa. The microgel characterization, self-healing process, transportation behavior, and plugging performance were investigated. A sandpack model with multi-pressure taps was utilized to assess the microgel dispersions’ transport behavior and plugging efficiency. In addition, micro-optical visualization of the gel particles was deployed to study the particle size changes before and after the swelling process. Tube tests showed that micro-RPPG could be dispersed and remain as separate particles in water with a concentration below 8,000 ppm, which is a favorable concentration for gel treatment. However, during the flooding test, the amount of microgel can be entrapped in the sandpack, resulting in a higher microgel concentration (higher than 8,000 ppm), endowing the gel particles with re-crosslinking ability even with excessive water. The microgel could propagate through the sandpack model, and the required pressure gradient mainly depends on the average particle/pore ratio and gel concentration. The gel dispersion significantly reduced channel permeability, providing sufficient resistance to post-water flooding (more than 99.97 % permeability reduction). In addition, the evaluation of micro-RPPG retention revealed that it is primarily affected by both gel concentration particle/pore ratios. We have demonstrated that the novel re-crosslinkable microgel can transport through large channels, but it can provide effective plugging due to its unique re-crosslinking property. However, by this property, the new microgel exhibits enhanced stability and demonstrates resistance to being flushed out in such high-permeability environments. Furthermore, with the help of novel technology, it is possible to overcome the inherited problems commonly associated with in-situ gel treatments, including chromatographic issues, low-quality control, and shearing degradation.
- North America > United States (0.46)
- Asia > China (0.28)
Deep Reservoir Conformance Control for the Wara Formation of the Greater Burgan Field: Lab Evaluation, Numerical Simulation and Field Implementation Design
Al-Murayri, Mohammed Taha (Kuwait Oil Company, KOC) | Hayat, Laila (Kuwait Oil Company, KOC) | Al-Qattan, Abrar (Kuwait Oil Company, KOC) | Al-Kharji, Anfal (Kuwait Oil Company, KOC) | Bouillot, Jerome (Poweltec) | Omonte, German (Poweltec) | Salehi, Nazanin (Poweltec) | Zaitoun, Alain (Poweltec)
Abstract Improving water-flood efficiency in heterogeneous reservoirs with high permeability contrast is of high strategic importance to maximize oil gains, debottleneck production facilities and alleviate water-handling constraints. This paper presents key lab, simulation and field design insights to implement Deep Reservoir Conformance Control (DRCC) in the Wara formation of the Greater Burgan Field. Prior technical assessment and high-resolution streamline modelling are covered in other technical publications. Full-field high-resolution streamline reservoir simulations have been used to identify 23 candidate injectors for DRCC. The wells having one layer taking more than 50% of the total water injected were considered as good candidates for DRCC to mitigate water channeling challenges and increase sweep efficiency accordingly. Mechanical water shut-off options were considered, but it was confirmed that near-wellbore solutions do not adequately address deep reservoir conformance issues and can compromise water accessibility to unswept oil zones. Furthermore, mechanical water shut-off options require recompletion and can be expensive and difficult to deploy. To overcome these drawbacks, DRCC has been evaluated in an integrated laboratory and simulation study to design a field implementation plan. The recommended DRCC approach involves injecting a microgel followed by a gel. The microgel enables deep treatment while the gel strengthen Permeability Reduction near the well. Laboratory evaluation qualified a microgel having a size of around 2 µm and a gel combining water-soluble polymer with an organic crosslinker. Gelation time was 2 days and full gel consistency was obtained after two weeks, under the form of a strong and slightly deformable gel (E-F on Sydansk scale). Permeability reduction post gelation was as high as 10,000 times. Reservoir simulations were executed to validate this approach, size-up the treatment and forecast performance. A pattern involving an injector and a producer well was selected. Laboratory coreflood data were used as input for the simulations. The combination of microgel followed by gel with a total volume of around 6000 bbl, pumped in two days, induces a gain in oil production of around 20 to 50% in 10 years. Simulation shows improvement of both vertical and areal sweep efficiency. Moreover, the gain appears very early after chemical injection. The combination of microgel and gel gives an efficient in-depth conformance system that can increase waterflood efficiency in formations such as Wara. This innovative approach has high potential in multi-layer high-permeability heterogeneous sandstone reservoirs.
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- (6 more...)
Design of In-Depth Conformance Treatment in the Mangala Polymer Flood Project
Zaitoun, Alain (Poweltec) | Omonte, German (Poweltec) | Bouillot, Jerome (Poweltec) | Salehi, Nazanin (Poweltec) | Bellin, Stephan (Cairn India) | Das, Joyjit (Cairn India) | Kumar, Ritesh (Cairn India) | Shekhar, Sunit (Cairn India) | Horn, Brian (Cairn India) | Ahmed, Abaan (Cairn India) | Kumar, Alok (Cairn India) | Sharma, Gaurav (Cairn India) | Kumar, Suresh (Cairn India)
Abstract The Mangala Field is located in the Barmer Basin in north-west of India (Fig. 1). The field has oil in-place volumes of 1.3 billion barrels, with an estimated recovery factor of 43% with polymer flood. Production began in 2009 and water injection in 2010. Polymer flooding started in 2015 in all layers at field scale. A successful ASP pilot was conducted in 201012 and it envisaged to roll it out gradually to full field in due course of time. The main reservoir units in the Mangala Field are the fluvial sandstones of the Fatehgarh Formation. The targeted reservoir horizon (FM1), is quite heterogeneous. The permeability range varies from 200 mD to several Darcies (4-5 Darcies) and sandbody connectivity is complex in the reservoir that is interpreted as a fluvial to lacustrine environment. This heterogeneity affects polymer sweep efficiency and calls for an in-Depth Conformance solution. Two candidate patterns were selected for further evaluation of conformance technologies. The selection criteria were based on early breakthrough, non-uniform injection profiles, cross-section analysis to check connectivities and low recovery factor with higher remaining oil. Several chemical conformance options were considered. Injection of gels are constrained by the gelation time, which does not typically exceed a few days. Injection of Microgels is preferred since the single component product acts by simple adsorption and can thus propagate deep in the reservoir. Moreover, the Microgel size which is above 2 μm, prevents the invasion of low-permeability intervals by a size-exclusion process. The product has thus a natural tendency to invade high permeability sandbodies (already swept). Different Microgel species have been submitted to lab tests. SMG Microgels keep their original size, while EMG Microgels expand with time and temperature. A major challenge to overcome is the existence of a polymer layer adsorbed on pore walls, which creates a barrier to Microgel adsorption. Finally, an EMG species whose chemistry induces high adsorption level has been qualified. The adsorption level is as high as 200 μg/g and the product induces a permeability reduction to water of around 8.5. Reservoir simulations were conducted afterwards to optimize the injection design (volume and duration) and draw performance forecasts. The reservoir simulation software used for the study can perform a dual polymer simulation, so two different species of polymers can be simulated. The sector model was made of two inverted contiguous 5-spot patterns with central injectors. The best scenario consisted in injecting the EMG at a concentration of 0.3% for 15-30 days. The deployment is simple since the product (delivered as liquid emulsion) can be injected with a volumetric pump of the water injection line directly. Additional oil production is expected to be as high as 95,500 bbls in 4.5 years. Microgel technology, has been successfully applied in waterflood projects in heterogeneous sandstone reservoirs and is shown to be applicable in ongoing polymer flood as remedial injection to solve conformance problems as well as produce significant incremental oil currently by-passed.
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Fatehgarh Formation (0.99)
- (4 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Summary Gel treatment is an effective way to attack excessive water production during oil development. The transport behavior of gel materials in reservoirs is of crucial importance to the effectiveness of gel treatments. The aim of this paper is investigating the transport behavior of swellable micrometer-sized preformed particle gels (PPGs, or microgels) through superpermeable (super-K) channels. Sandpacks with permeabilities ranging from 27 to 221 darcies were used to mimic the super-K channels. Multiple pressure sensors were applied along the sandpack models to monitor the propagation behavior of the microgels. The tested microgel particles could transport through the super-K channels, and a higher driving pressure gradient was required when the particle/pore size ratio was larger. The pressure gradient distribution along the super-K channels was relatively uniform when the particle/pore ratio was low (less than 1.3). However, the inlet section would show increasingly higher pressure gradients as the particle/pore ratio was increased, indicating increased difficulty in propagation. The propagation of the gel particles was significantly slower compared with the carrying fluid. The delayed propagation behavior was more pronounced when the particle/pore ratio was higher. The injection pressure was much less sensitive to the injection flow rate compared with a Newtonian fluid. The gel dispersion exhibited an apparent shear thinning (pseudoplastic) behavior when transporting through the porous channels. Breakage of the gel particles was observed especially at high superficial velocities. The particle breakage was partially responsible for the apparent shear thinning behavior. The breakage phenomenon was in favor of deep placement of the gel particles. The channel permeabilities were significantly reduced by the microgels, bringing sufficient resistance to subsequent waterflooding (more than 99.5%). At given matching size conditions, softer gels were more likely to establish in-depth placement and uniform water blocking capacity in the channels. The microgel particles exhibited salinity-responsive behavior to the post-brine flush. The gel particles could shrink and reswell according to the salinity of the injected water. Possibilities were discussed to use this salinity-responsive behavior. Also, the microgels exhibited a particular disproportionate permeability reduction (DPR) effect. After gel injection, the channel permeability to water flow was reduced by more than 20 to 92 times of the permeability to oil flow. This work provides important support to understand the transport behavior of gel particles in super-K channels. The achievements are helpful for gel product selection and gel treatment design.
- North America > United States > Texas (1.00)
- Asia (0.93)
- North America > United States > Alaska > North Slope Borough (0.46)
- Research Report > New Finding (0.82)
- Research Report > Experimental Study (0.50)
- North America > United States > Alaska > North Slope Basin > Milne Point Field > Kuparuk Formation (0.99)
- North America > United States > Alaska > North Slope Basin > Kuparuk River Field > West Sak Field (0.99)
- North America > Canada > Alberta > Flood Field > Adamant Masters Flood 6-6-85-24 Well (0.99)
- North America > United States > Louisiana > China Field (0.98)
- Well Drilling > Formation Damage (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (2 more...)
Summary Gel treatment is an effective way to attack excessive water production during oil development. The transport behavior of gel materials in reservoirs is of crucial importance to the effectiveness of gel treatments. The aim of this paper is investigating the transport behavior of swellable micrometer-sized preformed particle gels (PPGs, or microgels) through superpermeable (super-K) channels. Sandpacks with permeabilities ranging from 27 to 221 darcies were used to mimic the super-K channels. Multiple pressure sensors were applied along the sandpack models to monitor the propagation behavior of the microgels. The tested microgel particles could transport through the super-K channels, and a higher driving pressure gradient was required when the particle/pore size ratio was larger. The pressure gradient distribution along the super-K channels was relatively uniform when the particle/pore ratio was low (less than 1.3). However, the inlet section would show increasingly higher pressure gradients as the particle/pore ratio was increased, indicating increased difficulty in propagation. The propagation of the gel particles was significantly slower compared with the carrying fluid. The delayed propagation behavior was more pronounced when the particle/pore ratio was higher. The injection pressure was much less sensitive to the injection flow rate compared with a Newtonian fluid. The gel dispersion exhibited an apparent shear thinning (pseudoplastic) behavior when transporting through the porous channels. Breakage of the gel particles was observed especially at high superficial velocities. The particle breakage was partially responsible for the apparent shear thinning behavior. The breakage phenomenon was in favor of deep placement of the gel particles. The channel permeabilities were significantly reduced by the microgels, bringing sufficient resistance to subsequent waterflooding (more than 99.5%). At given matching size conditions, softer gels were more likely to establish in-depth placement and uniform water blocking capacity in the channels. The microgel particles exhibited salinity-responsive behavior to the post-brine flush. The gel particles could shrink and reswell according to the salinity of the injected water. Possibilities were discussed to use this salinity-responsive behavior. Also, the microgels exhibited a particular disproportionate permeability reduction (DPR) effect. After gel injection, the channel permeability to water flow was reduced by more than 20 to 92 times of the permeability to oil flow. This work provides important support to understand the transport behavior of gel particles in super-K channels. The achievements are helpful for gel product selection and gel treatment design.
- North America > United States > Texas (1.00)
- Asia (0.93)
- North America > United States > Alaska > North Slope Borough (0.46)
- Research Report > New Finding (0.82)
- Research Report > Experimental Study (0.50)
- North America > United States > Alaska > North Slope Basin > Milne Point Field > Kuparuk Formation (0.99)
- North America > United States > Alaska > North Slope Basin > Kuparuk River Field > West Sak Field (0.99)
- North America > Canada > Alberta > Flood Field > Adamant Masters Flood 6-6-85-24 Well (0.99)
- North America > United States > Louisiana > China Field (0.98)
- Well Drilling > Formation Damage (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (2 more...)
Deformable Microgel for Enhanced Oil Recovery in High-Temperature and Ultrahigh-Salinity Reservoirs: How to Design the Particle Size of Microgel to Achieve Its Optimal Match with Pore Throat of Porous Media
Yuan, Chengdong (Southwest Petroleum University and Kazan Federal University) | Pu, Wanfen (Southwest Petroleum University and Kazan Federal University) | Varfolomeev, Mikhail A. (Southwest Petroleum University and Kazan Federal University) | Wei, Junnan (PetroChina Tarim Oilfield Company) | Zhao, Shuai (Southwest Petroleum University) | Cao, Li-Na (China ZhenHua Oil Co., Ltd)
Summary Conformance control treatment in high-temperature and ultrahigh-salinity reservoirs for easing water/gas channeling through high-permeability zones has been a great challenge. In this work, we propose a deformable microgel that can be used at more than 373.15 K and ultrahigh-salinity conditions (total dissolved solids > 200 kg/m, Ca + Mg > 10 kg/m) and present a method for choosing the suitable particle size of the microgel to achieve an optimal match with the pore throat of the core. First, the particle size distribution of the microgel was analyzed to decide d50, d10, and d90 (diameter when cumulative frequency is 50, 10, and 90%, respectively). Coreflooding experiments were conducted under different permeability conditions from 20 to 900 md to investigate the migration and plugging patterns of the microgel by analyzing and fitting injection pressure curves together with the change in the morphology of the produced microgel analyzed by a microscope. The migration and plugging patterns were divided into three patterns: complete plugging; plugging—passing through in a deformation or broken state—deep migration; and inefficient plugging—smoothly passing through—stable flow. The second pattern can be further divided into three subpatterns as strong plugging, general plugging, and weak plugging. Finally, on the basis of five patterns, we build a quantitative matching relation between the particle size distribution of microgel and the pore-throat size of cores by defining three matching coefficients α = d10/d, β = d50/d, γ = d90/d (d is the average pore-throat diameter). The effectiveness of this quantitative matching relation was verified by evaluating the plugging ability (residual resistance factor) in a post-waterflooding process after the injection of 1.5 pore volume (PV) of microgel. For a strong permeability heterogeneity, the strong plugging is believed to be the expected pattern. The particles size and the pore-throat size should meet the following relationship: 1 < α < 2, 2 < β < 4, 4 < γ < 6. In this scenario, the deformable microgel particles could achieve both an effective plugging and a deep migration. The quantitative matching relation with multiple matching coefficients determined based on the particle size distribution might help to choose suitable particles more precisely in comparison to the method based on one matching coefficient (mostly, the ratio of the average diameter of particles to the average pore-throat diameter). In addition, the method itself to build a quantitative matching relation according to particle size distribution can be used for designing different particle-type conformance control agents for profile control and water shutoff treatment in field applications.
- North America > United States (0.68)
- Asia (0.68)
- Well Drilling > Formation Damage (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (2 more...)
Successful Water Shutoff Treatment of Fractured Carbonate Horizontal Well Under Aquifer Pressure Support
Hernando, Louis (Poweltec) | Martin, Nicolas (Poweltec) | Zaitoun, Alain (Poweltec) | Al Mufargi, Hilal (Daleel Petroleum LLC) | Al Harthi, Hamood (Daleel Petroleum LLC) | Al Naabi, Ahmed (Daleel Petroleum LLC) | Al Subhi, Khamis (Daleel Petroleum LLC) | Al Harrasi, Mohammed Talib (Daleel Petroleum LLC)
Abstract Many horizontal wells in GCC (Gulf Cooperation Council) are producing from fractured carbonate reservoirs under aquifer pressure support. After water breakthrough, these wells suffer from high water cut rise due to water channeling through the fractures, inducing a strong and quick loss of well productivity. The wells being completed horizontal open hole, zonal isolation is very difficult to isolate the water producing zone. Moreover, mechanical water shut off like using liners or open hole packers is normally costly and challenging as well. Therefore, bullheading chemicals is often the only remaining option. The fractures being producing mixture of both oil and water, water shutoff in this type of well is very challenging. To solve this problem, an original method was used consisting of microgel and gel injections. The strategy is to create a flow barrier deep in the fracture while preserving oil production from the matrix. The optimized procedure enables control of chemical placement by bullhead injection. Laboratory tests were conducted to optimize Microgel and gel chemistry (injectivity, gelation time and gel consistency/stability, return oil permeability). The treated candidate was 530m long horizontal well and produced at around 600 bpd with water cut of 92%. Temperature and salinity were 62°C and around 100,000ppm respectively. Well behavior indicated existence of fractures along the wellbore. The treatment consisted of 230m3 of successive Microgel/Gel injection at an average rate of 2.5 BPM. The treatment proceeded bullhead through annulus. WHP remained low throughout injection (150 psi). After curing time of 10 days for gel set, production was released with ramp up rate. The well, which was facing strong production decline, stopped declining, with a water cut drop of around 10%. Incremental daily oil rate was around 50 bopd with cumulative oil for the first 4 months of around 4500 bbls of oil. This technology may have many applications in fractured carbonate fields and may lead to better oil potential from such high water cut highly fractured reservoir wells, with strong aquifer.
- Asia > Middle East > UAE (0.48)
- Asia > Middle East > Oman (0.34)
Integrating Microgels and Low Salinity Waterflooding to Improve Conformance Control in Fractured Reservoirs
Alhuraishawy, Ali (Missouri University of Science and Technology, Missan Oil Company) | Wei, Mingzhen (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology) | Almansour, Abdullah (King Abdulaziz City for Science and Technology)
Abstract The recovery from fractured reservoirs is usually low. The areal heterogeneity is one result of the fractured reservoir. Low-salinity waterflooding (LSWF) and preformed particle gel (PPG) have recently investigated by some reserchers. The main objective of this study was to determine whether the combining technologies can improve conformance control in fractured sandstone reservoirs. Semi-transparent five-spot models made of sandstone cores and acrylic plates were built. The effect of low-salinity waterflooding on oil recovery was studied. Models were designed with three parallel open fractures. Sodium chloride (1.0, 0.1, 0.01, and 0.001 wt. % NaCl) were used for brine flooding and 1.0 wt. % NaCl for preparing swollen PPG. Two microgel concentrations, 2000 PPM and 5000 PPM, with 850 micrometer particle size were used. Three cycles of low-salinity water were injected after the second conventional brine injection was completed. Oil recovery factor, water cut, injection pressure, microgel extruded pressure, fracture pressure (Pf), monitoring pressure (P1 and P2), and water residual resistance (Frrw) were measured. The interwell connectivity also was investigated. Laboratory experiments showed that the oil recovery factor, injection pressure, and the Frrw increased when the concentration of injected brine changed from conventional salinity to low salinity and the areal sweep efficiency was improved. The tortuous wormholes resulted highrer oil recovery than the straight wormholes and the oil recovery decreased as number of fratures and fracture width increased. The microgel concentration had a signicicant effect on plugging effeciecny; therefore, the 5000 PPM Microgel showed higher plugging efficiency than 2000 PPM. The result showed the interwell connectivity between the injector and producer decreased when low salinity waterflooding applied and increased the interwell connectivity between the injector and the monitoring points. The plugging efficiency, stabilized injection pressure, fracture pressure, monitoring pressure, and water residual resistance factor—all increased when the salinity of injected water decreased. Furthermore, the microgel strength decreased as brine concentration decreased. However, lower salinity water caused the incremental oil recovery factor to increase. Thus, there is a limitation in increasing the plugging efficiency under low salinity water. This limitation occurred when the brine injection pressure was less than the PPG’s extruded pressure. Combining two different EOR technologies can improve displacement and sweep efficiency and, in turn, enhance conformance control.
- Asia > Middle East (0.93)
- Europe (0.68)
- North America > United States > Oklahoma (0.47)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.91)
- Geology > Mineral (0.66)
- North America > United States > Alaska > North Slope Basin > Duck Island Field > Endicott Field > Kekiktuk Formation (0.99)
- North America > United States > Louisiana > Chatham Field (0.93)
Abstract Water and gas shutoff in naturally fractured reservoirs is traditionally achieved with cross-linked gels. Low sweep efficiency is also an important problem in waterflooding such reservoirs which can be treated with gel. In-depth placement of gels is the key to success, and this requires careful control of the cross-linking chemistry. This work examines the feasibility of an alternative gelation mechanism in fractured rock: pH-triggered polymer microgels. The microgel particles are small enough to pass through fractures but not pore throats in a matrix. The pH change occurs naturally and inevitably; it thus offers a simpler means of obtaining deep placement. When an acidic polymer solution is injected into the formation, several factors affect the pH: rock mineralogy, reactive surface area of the minerals, temperature and dilution due to mixing with residual water. The viscosity of the solution depends strongly on pH and upon polymer concentration and salinity of the polymer solution. The rate of pH increase relative to the rate of fluid advance determines the depth of placement. We used commercially available polymers which exhibit low viscosity at a pH below 3 but transform to gels at pH > 4. Polymer solutions were injected through artificial fractures in outcrop cores. Both sandstone and carbonate rocks raise the polymer solution pH. The presence of acid-soluble minerals containing cations such as calcium can independently trigger viscosification by precipitating the polymer. After polymer injection, a shut-in time allows further reaction to increase the pH and thus affects the Permeability Reduction Factor (PRF), the ratio of original fractured core permeability to treated core permeability. The PRF was measured to be in the range of 200 to 5 during the various experiments. The gelation is faster and PRF is higher in carbonates than in sandstones. Because the neutralization capacity of a core is large, it is possible to approximate reactive transport in a reservoir by continuously re-circulating the polymer effluent. Experiments showed gel-like characteristics after 30 pore volumes of recirculation in Berea sandstone. Introduction There are large reserves of mobile oil in reservoirs around the world that cannot be produced due to problems such as low reservoir pressure and thief zones. Water injection is commonly employed to increase the average reservoir pressure and push out the oil. However, water flooding is not always successful. The most important problem is channeling of the injected water into high permeability zones which occur in heterogeneous reservoirs. In this situation, the water breakthrough time decreases, and significant portions of the reservoir remain untouched by the injected water. This reduces the sweep efficiency and oil recovery. In addition, the water oil ratio (WOR) increase which increases the cost of the water flood process. One of the methods to overcome the channeling problem is to block the high permeability zones with a specific kind of polymer or gel. By blocking the areas already swept by the water, subsequently injected water can sweep an unswept area of the reservoir and thereby increase the oil recovery. The polymer should be very viscous to be able to block the high permeability zones and ideally, these polymers should be economical and easy to prepare. However, injecting a viscous polymer into the reservoir at reasonable rates requires high injection pressures. The limitation imposed by the local fracture gradient greatly restricts the depth to which such a solution can be placed. Therefore, we are looking for a polymer that can be injected easily to the reservoir, yet offers large resistance to flow once placed in the reservoir.