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Results
Investigation of Carbonate Matrix Damage and Remediation Methods for Preformed Particle Gel Conformance Control Treatments
Almakimi, Abdulaziz A. (Kuwait Institute for Scientific Research) | Liu, Junchen (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology) | Hussein, Ibnelwaleed A. (Missouri University of Science and Technology (Corresponding author))
Summary Preformed particle gels (PPGs) have been widely applied to control excessive water production in mature oil fields with fractures or fracture-like features, especially in sandstones, but with limited attention to carbonates. However, a vital concern arises regarding the potential damage of PPGs on the adjacent matrix that might promote negative results. This paper comprehensively evaluates PPGsโ potential damage to the carbonate matrix and seeks design optimization solutions. Filtration tests were applied to compare PPGsโ penetration into the matrix under different sets of conditions. The filtration regimes were defined by filtration curves, and the gel damage on the matrix was determined by permeability measurement results. Experiments were conducted to investigate the efficiency of an oxidizer as a remediation method to remove the damage. The qualitative description of gel particlesโ invasion and plugging behavior in the carbonate matrix was presented based on the analysis of filtration test results and permeability measurements. The results show that the swollen gel filtration curves can be divided into three regions: prior-filter-cake, filter-cake-building, and stable stages according to the gel particlesโ response to the injection pressure and effluent flow rates. PPGs can form cakes on the rock surface to prevent particlesโ further penetration into the carbonate matrix, and the penetration was only limited to less than a few millimeters. The smallest gel particles (50โ70 US mesh size) were more likely to form external and internal filter cakes at higher pressure values (700 psi) and result in more damage to the matrix. To restore the matrix permeability after filtration tests, oxidizer soaking proved to be a reliable solution. In all, the results indicated that unintentional matrix permeability damage induced by gel injection is generally unavoidable but conditionally treatable.
- Asia > Middle East (0.68)
- North America > United States > Oklahoma (0.28)
- North America > United States > Texas (0.28)
- Research Report > New Finding (0.88)
- Research Report > Experimental Study (0.66)
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 microgelsโ 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 dispersionsโ 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)
Comparative Study of Proppant Transport in the Vertical Fracture for High Viscosity Friction Reducers and Slickwater Fracturing with High-TDS Marcellus Shale Formation Water
Ge, Xiaojing (Missouri University of Science and Technology) | Imqam, Abdulmohsin (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology)
ABSTRACT High viscosity friction reducers (HVFRs) have been gaining more attention and increasing in use as proppant carriers. Reusing of produced water has also been driven by both environmental and economic benefits. However, high total dissolved solids (TDS) of produced water and high reservoir temperature significantly decrease the viscoelastic properties of HVFRs even for the cationic ones, which further reduce their proppant transport capabilities. Increasing loadings of HVFRs also has very limited effects on improving their proppant transport performances under high-TDS and high-Temperature conditions. The ultimate objective of this experimental study is to investigate the injection rate effects on the proppant transport performance of HVFRs, especially under high-TDS conditions. 1 gallon per thousand gallons (GPT) slickwater and 4 GPT HVFRs were comparatively analyzed by conducting rheology measurements and dynamic proppant transport experiments with both deionized (DI) water and 30,000 mg/L TDS Marcellus formation water at 60ยฐC. The 1 GPT slickwater was injected at a rate of 1.5 gal/min, whereas the 4 GPT HVFR was injected at a lower rate of 0.75 gal/min. The results showed that HVFRs with low injection rates were preferred when using fresh water. In contrast, slickwater with high pumping rates was preferred during produced water fracturing. INTRODUCTION Over the past few years, the use of HVFRs in hydraulic fracturing has been increasing as they offer operational and economic benefits compared to traditional fracturing fluids such as slickwater and guar (Hu et al. 2018; Johnson et al. 2018; Biheri and Imqam 2021a). HVFRs have been found to lower operational costs, require less equipment, exhibit better conductivity in fractured formations, and lead to production improvements (Johnson et al. 2018; Ba Geri et al. 2019; Biheri and Imqam 2021b, 2022). However, hydraulic fracturing fluids are usually prepared using fresh water, which can be costly and present challenges when freshwater resources are scarce. As a result, the industry has been exploring the use of produced or formation water, which typically has high levels of salinity and hardness. Currently, most high TDS applications are focused on the Marcellus shale formation. The Marcellus shale is a Middle Devonian source rock and reservoir that spans over multiple states in the Appalachian Basin, including Kentucky, West Virginia, Ohio, Pennsylvania, and New York. This formation has an average temperature of around 140ยฐF (60ยฐC) and can reach bottom hole pressures up to 6000 psi. The produced and flowback water in this area has high levels of TDS, with a typical concentration range of 30,000 ppm to 50,000 ppm. (Williams et al. 2011; Johnson et al. 2018).
- North America > United States > West Virginia (1.00)
- North America > United States > Virginia (1.00)
- North America > United States > Pennsylvania (1.00)
- (2 more...)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline (1.00)
Prediction of Single Proppant Terminal Settling Velocity in High Viscosity Friction Reducers by Using Artificial Neural Networks and XGBoost
Ge, Xiaojing (Missouri University of Science and Technology) | Lu, Rong (bp) | Biheri, Ghith (Missouri University of Science and Technology) | Imqam, Abdulmohsin (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology)
Abstract High viscosity friction reducers (HVFRs) have been recently gaining more attention and increasing in use, not only as friction-reducing agents but also as proppant carriers. The settling velocity of the proppant is one of the key outputs to describe their proppant transport capability. However, it is influenced by many factors such as fluid properties, proppant properties, and fracture properties. Many empirical/physics-based models and correlations to predict particle settling velocity have been developed. However, they are usually based on certain assumptions and have applicable limits. In contrast, machine learning models can be considered as a black box. The objective of this study is to use machine learning models to find the relationship between the multiple factors mentioned above and particle settling velocity in order to correctly predict it. Two of the most popular and powerful machine learning algorithms, Artificial neural networks (ANN) and XGBoost, were comparatively investigated with standard data processing and training procedures. Mean Absolute Errors (MAEs) for ANNs and XGBoost were 0.010379 and 0.004253 respectively. The XGBoost learning algorithm had overall better prediction performance than the ANN model in terms of the data sets used for this study and had the potential to properly handle missing values by itself.
- North America > United States > West Virginia (0.28)
- North America > United States > New York (0.28)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Ohio > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > New York > Appalachian Basin > Marcellus Shale Formation (0.99)
Experimental Study: Investigating the Anions and Cationsโ Effects on the Elasticity of the Anionic and Cationic High Viscosity Friction Reducers
Ge, Xiaojing (Missouri University of Science and Technology) | Biheri, Ghith (Missouri University of Science and Technology) | Imqam, Abdulmohsin (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology) | Zhang, Yuwei (Missouri University of Science and Technology)
Abstract High viscosity friction reducers (HVFRs) are widely used as friction-reducing agents and proppant carriers during hydraulic fracturing. The reuse of produced water has gained popularity due to environmental and economic benefits. Currently, the fieldโs most commonly used friction reducers are anionic and cationic HVFRs. Anionic HVFRs are typically pumped with freshwater, while cationic HVFRs are used with high Total Dissolved Solids (TDS) produced water. Cationic friction reducers are believed to have better TDS tolerance, friction reduction performance, and proppant transport capabilities compared to anionic friction reducers under high TDS conditions due to their superior viscoelastic properties. In addition, the impact of different anions and cations on the viscosity of HVFRs has been thoroughly studied, and viscosity reduction mechanisms include charge shielding, increasing the degree of hydrolysis, and forming coordination complexes. However, anions and cationsโ effects on the elasticity of HVFRs still remain to be investigated. Besides, most previous experimental studies either do not specify experimental procedures or control the experimental variables well. Therefore, the ultimate objective of this experimental study is to analyze various cations and anionsโ effects on the elasticity of anionic and cationic HVFRs comparably and precisely with experimental variables well controlled. Two hypotheses based on anions and cationsโ effects on the viscosity of HVFRs are proposed and will be tested in this study. First, the elasticity reduction of anionic HVFRs is mainly due to cations, whereas the elasticity reduction of cationic HVFRs is mainly due to anions. Second, the saltsโ effects on the elasticity reduction of HVFRs should follow the same trend as the saltsโ effects on the viscosity reduction of HVFRs. For anionic HVFRs, monovalent Alkali metals should have a similar effect; divalent Alkaline earth metals should have a similar effect; transition metals should have the most severe effect. For cationic HVFRs, SO4 should have more pronounced effects than Cl. To demonstrate both hypotheses, an anionic and a cationic HVFR at 4 gallons per thousand gallons (GPT) were selected and analyzed. The elasticity measurements of both anionic and cationic HVFRs were conducted with deionized (DI) water and various salts respectively. Fe and H (or pH) effects were specifically investigated. The results showed both hypotheses were accepted.
- North America > United States > Pennsylvania (0.47)
- North America > United States > Ohio (0.46)
- North America > United States > West Virginia (0.28)
- North America > United States > New York (0.28)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.90)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (4 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well Intervention (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (0.89)
The Success Story of First Ever Polymer Flood Field Pilot to Enhance the Recovery of Heavy Oils on Alaska's North Slope
Dandekar, Abhijit (University of Alaska Fairbanks) | Bai, Baojun (Missouri University of Science and Technology) | Barnes, John (Hilcorp Alaska LLC) | Cercone, Dave (DOE-National Energy Technology Laboratory) | Edwards, Reid (Hilcorp Alaska LLC) | Ning, Samson (Reservoir Experts, LLC/Hilcorp Alaska, LLC) | Seright, Randy (New Mexico Institute of Mining and Technology) | Sheets, Brent (University of Alaska Fairbanks) | Wang, Dongmei (University of North Dakota) | Zhang, Yin (University of Alaska Fairbanks)
Abstract The primary goal of the first ever polymer flood field pilot at Milne Point is to validate the use of polymers for heavy oil Enhanced Oil Recovery (EOR) on Alaska North Slope (ANS). The specific objectives are systematic evaluation of advanced technology that integrates polymer flooding, low salinity water flooding, horizontal wells, and numerical simulation based on polymer flood performance data. Accordingly, under the co-sponsorship of the US Department of Energy and Hilcorp Alaska LLC the first ever polymer field pilot commenced on August 28, 2018 in the Schrader Bluff heavy oil reservoir at the Milne Point Unit (MPU) on ANS. The pilot started injecting hydrolyzed polyacrylamide (HPAM), at a concentration of 1,750 ppm to achieve a target viscosity of 45 cP, into the two horizontal injectors in the J-pad flood pattern. Since July 2020, HPAM concentration was reduced to 1,200 ppm to control injectivity and optimize polymer utilization. Filter ratio tests conducted on site ensure uniform polymer solution properties. Injectivity is assessed by Hall plots, whereas production is monitored via oil and water rates from the two producers. Water samples are analyzed to determine the produced polymer concentration. Supporting laboratory corefloods on polymer retention, injection water salinity, polymer loading, and their combinations on oil recovery, match rock, fluid and test conditions. A calibrated and validated numerical multiphase reservoir model was developed for long-term reservoir performance prediction and for evaluating the project's economic performance in conjunction with an economic model. Concerns related to handling of produced fluids containing polymer are addressed by specialized experiments. As would be expected in a field experiment of this scale, barring some operational and hydration issues, continuous polymer injection has been achieved. As of September 30, 2022, a total of 1.41 million lbs of polymer or 2.99 million bbls of polymer solution (~18.8% of total pore volume), placed in the pattern serves as an effective indicator of polymer injectivity. During the first half of the pilot period, water cut (WC) drastically reduced in both producers and over the entire duration, the deemed EOR benefit over waterflood was in the range of 700-1,000 bopd, and that too at a low polymer utilization of 1.7 lbs/bbl. Low concentration polymer breakthrough was observed after 26-28 months, which is now stabilized at 600โ800 ppm in congruence with the WC. Although as indicated by laboratory experiments, polymer retention in core material is high; ~70% of the injected polymer propagates without any delay, while the remaining 30% tails over several PVs. History matched simulation models consistently forecasts polymer recovery of 1.5โ2 times that of waterflood, and when integrated with the economic modeling tool, establish the economic profitability of the first ever polymer flood field pilot. Produced fluid experiments provide operational guidance for treating emulsions and heater-treater operating temperature. Over a duration of ~4.5 years important outstanding technical issues that entail polymer flooding of heavy oils have been resolved, which forms the basis of the success story summarized in the paper. The first ever polymer pilot is deemed as a technical and economic success in significantly improving the heavy oil recovery on ANS. The pilot has provided impetus to not only apply polymer EOR throughout the Milne Point Field, but has paved the way for additional state-funded research targeting even heavier oils on the ANS. The combined success of this work and the future work will contribute to the longevity of the Trans Alaska Pipeline System (TAPS).
- Europe > United Kingdom > North Sea > Central North Sea (1.00)
- North America > United States > Alaska > North Slope Borough > Prudhoe Bay (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.87)
- North America > United States > Alaska > Schrader Bluff Formation (0.99)
- North America > United States > Alaska > North Slope Basin > Milne Point Field > Kuparuk Formation (0.99)
- North America > Canada > Alberta > Flood Field > Adamant Masters Flood 6-6-85-24 Well (0.99)
Coreflooding Evaluation of Fiber-Assisted Recrosslinkable Preformed Particle Gel Using an Open Fracture Model
Zhao, Shuda (Department of Petroleum Engineering, Missouri University of Science and Technology) | Al Brahim, Ali (Department of Petroleum Engineering, Missouri University of Science and Technology) | Liu, Junchen (Department of Petroleum Engineering, Missouri University of Science and Technology) | Bai, Baojun (Department of Petroleum Engineering, Missouri University of Science and Technology (Corresponding author)) | Schuman, Thomas (Department of Chemistry, Missouri University of Science and Technology)
Summary Recrosslinkable preformed particle gels (RPPGs) have been used to treat the problem of void space conduits (VSC) and repair the โshort-circuitedโ waterflood in Alaskaโs West Sak field. Field results showed a 23% increase in success rates over typical preformed particle gel (PPG) treatments. In this paper, we evaluated whether adding fiber into RPPGs can increase the RPPG plugging efficiency and thus further improve the success rate. We designed open fracture models to represent VSC and investigated the effect of swelling ratio (SR), fracture size, and fiber concentration on gel injection pressure, water breakthrough pressure, and permeability reduction. Results show that fiber can increase RPPG strength and delay its initial swelling rate, but an optimized fiber concentration exists. Beyond that, the fiber entangling problem can result in the recrosslinked bulk gel inhomogeneously and impact gel quality. The injection pressure of fiber-assisted RPPGs increased with the SR and fracture width. During post-injection water process, the breakthrough pressure and residual resistance factor increased when the RPPG SR and fracture width decreased. Fiber-assisted RPPGs can dramatically reduce the permeability of the fractured core up to 1.8ร10 times. It is observed that the fiber-assisted RPPGs used in the experiment remain in a bulk form in the fracture when we open the fracture after water injection. Not only does the addition of fiber improve the plugging efficiency, but it also prevents particle precipitation along vertical fractures or conduits.
- North America > United States > Texas (1.00)
- North America > United States > Alaska > North Slope Borough (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.34)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
Evaluation of Ultrahigh-Temperature-Resistant Preformed Particle Gels for Conformance Control in North Sea Reservoirs
Schuman, Thomas (Missouri University of Science and Technology (Corresponding author) | Salunkhe, Buddhabhushan (equal contributor)) | Al Brahim, Ali (Missouri University of Science and Technology (Equal contributor)) | Bai, Baojun (Missouri University of Science and Technology)
Summary Preformed particle gels (PPGs) are 3D, crosslinked, dried polymer particles that can swell to several hundred times on contact with formation water. PPGs have been used extensively to control water production problems in reservoirs with conformance problems. The current state-of-the-art PPGs are polyacrylamide-based hydrogel compositions which lack long-term thermal stability under high-temperature and -salinity conditions. There are many oil reservoirs across the globe exhibiting conditions of temperatures higher than 120ยฐC with high salinity. A novel ultrahigh-temperature-resistant PPG composition (DMA-SSS PPG) was designed to fill up the technology gap between existing polyacrylamide-based PPG technology that degrades readily over 110ยฐC temperatures. DMA-SSS PPG exhibited excellent thermal stability for greater than 18 months in North Sea formation and formation water environments at 130ยฐC. DMA-SSS PPG described herein showed swelling capacities of up to 30 times in different salinity North Sea brines. DMA-SSS PPGโs physiochemical properties like swelling, swelling rate, and rheological behavior were studied as a function of temperature and salinity. DMA-SSS PPGs showed excellent elastic modulus (Gโ) of about 3200 Pa in formation water of 90% water content. Thermostability of DMA-SSS PPGs was assessed at 130 and 150ยฐC in North Sea brines with different salinity conditions. DMA-SSS PPGs proved to be stable for more than 18 months without losing molecular integrity. Thermostability was further confirmed through different metrics such as cross-polarization magic angle spinning carbon-13 nuclear magnetic resonance (CPMAS C NMR), thermogravimetric analysis (TGA), and morphology. Laboratory coreflood experiments were performed to demonstrate the plugging efficiency of open fractures and effectiveness in reducing the permeability. DMA-SSS PPG comprehensive evaluation confirms its novelty for excellent hydrothermal stability, thus can be used to control water production problems for mature reservoirs exhibiting conditions of high salinity and high temperature.
- North America > United States (1.00)
- Europe > United Kingdom > North Sea (1.00)
- Europe > Norway > North Sea (1.00)
- (3 more...)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
Evaluation of a Novel Recrosslinkable Hyperbranched Preformed Particle Gel for the Conformance Control of High-Temperature Reservoirs with Fractures
Song, Tao (Missouri University of Science and Technology) | Ahdaya, Mohamed (Missouri University of Science and Technology) | Zhao, Shuda (Missouri University of Science and Technology) | Zhao, Yang (Missouri University of Science and Technology) | Schuman, Thomas (Department of Chemistry, Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology (Corresponding author))
Summary The existence of high conductivity features such as fractures, karst zones, and void space conduits can severely restrict the sweep efficiency of waterflooding or polymer flooding. Preformed particle gel (PPG), as a cost-effective technology, has been applied to control excessive water production. However, conventional PPG has limited plugging efficiency in high-temperature reservoirs with large fractures or void space conduits. After water breakthrough, gel particles can easily be washed out from the fractures because of the lack of particle-particle association and particle-rock adhesion. This paper presents a comprehensive laboratory evaluation of a novel water-swellable high-temperature resistant hyperbranched recrosslinkable PPG (HT-BRPPG) designed for North Sea high-temperature sandstone reservoirs (130ยฐC), which can recrosslink to form a rubber-like bulk gel to plug such high conductivity features. This paper systematically evaluated the swelling kinetics, long-term thermal stability, and plugging performance of the HT-BRPPG. Bottle tests were used to test the swelling kinetic and recrosslinking behavior. High-pressure-resistant glass tubes were used to test the long-term thermal stability of the HT-BRPPG at different temperatures, and the testing lasted for more than 1 year. The plugging efficiency was evaluated by using a fractured model. Results showed that this novel HT-BRPPG could recrosslink and form a rubber-like bulky gel with temperature ranges from 80 to 130ยฐC. The elastic modulus of the recrosslinked gel can reach up to 830 Pa with a swelling ratio (SR) of 10. In addition, the HT-BRPPG with an SR of 10 has been stable for over 15 months at 130ยฐC. The core flooding test proved that the HT-BRPPG could efficiently plug the open fractures, and the breakthrough pressure is 388 psi/ft. Therefore, this novel HT-BRPPG could provide a solution to improve the conformance of high-temperature reservoirs with large fractures or void space conduits.
- Europe > Norway > North Sea (0.34)
- North America > United States > Oklahoma (0.29)
- North America > United States > Texas (0.28)
- (3 more...)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.93)
- Europe > United Kingdom > North Sea > Central North Sea > Utsira High > PL 006 > Ekofisk Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (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)
Feasibility Study of Recrosslinkable Preformed Particle Gels for Natural Gas Injection Profile Control
Al Brahim, Ali (Petroleum Engineering, Missouri University of Science and Technology) | Eriyagama, Yugandhara (Chemistry, Missouri University of Science and Technology) | Bai, Baojun (Petroleum Engineering, Missouri University of Science and Technology (Corresponding author)) | Schuman, Thomas (Chemistry, Missouri University of Science and Technology)
Summary Recrosslinkable preformed particle gel (RPPG), a preformed particle gel (PPG) of which particles can bond together to form a strong bulk gel system after being placed inside the target formation, has been successfully applied to control conformance problems for waterflooding projects. However, no research has been conducted about whether RPPG is feasible in improving gasflooding performance in mature reservoirs. The study presents a systematic evaluation of acrylamide (AM) and 2-acrylamide-2-methylpropane sulfonate acid (AMPS)-based RPPG including phase stability under different gel-gas kinetics and plugging performance to natural gas and water. Different experimental apparatuses were designed to quantify and visualize the RPPG phase stability under static and dynamic gel-gas interactions. The RPPG phase stability was evaluated under a different range of injection pressure, gas exposure time, and swelling ratio (SR). Also, the RPPG stability was compared to the in-situ gel system hydrolyzed polyacrylamide crosslinked with chromium acetate [HPAM/Cr(III)], which has been applied in oil fields to control gas injection conformance. The RPPG plugging efficiency was evaluated using open fractured cores with different apertures. The results showed that the RPPG was stable under both static and dynamic gel-natural gas interactions and was stable when being exposed to an acidic environment with an insignificant total percentage weight loss (<3%). Additionally, the strength of the RPPG was further improved with the longevity of the gas exposure. Furthermore, different from the in-situ gel system HPAM/Cr(III), which exhibited a high degree of dehydration under natural gas and exhibited substantial syneresis under acidic conditions, the microstructure of the RPPG remained stable after the dynamic gas exposure. The results of the coreflooding experiments demonstrated that the RPPG had excellent plugging efficiency, which was closely related to the SR and the fracture aperture. This is the first study where a polymer gel system has been systematically assessed through varied testing methodologies using natural gas as opposed to other studies where nitrogen (N2) was used to simulate natural gas behavior. The robustness of the RPPG system makes it a viable candidate for improving the gasflooding processes in mature reservoirs dominated by conformance problems such as void space conduits (VSCs), fractures, and high-permeability channels.
- Europe (0.94)
- Asia (0.68)
- North America > United States > Alaska > North Slope Borough (0.28)
- North America > United States > Texas (0.28)
- North America > United States > Alaska > North Slope Basin > Kuparuk River Field > West Sak Field (0.99)
- South America > Venezuela (0.89)
- Europe > United Kingdom > North Sea (0.89)
- (3 more...)