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Collaborating Authors
Unconventional and Complex Reservoirs
Comprehensive Evaluation of a Novel Recrosslinkable Hyper Branched Preformed Particle Gels for the Conformance Control of High Temperature Reservoirs
Song, Tao (Missouri University of S & T) | Ahdaya, Mohamed (Missouri University of S & T) | Zhao, Shuda (Missouri University of S & T) | Zhao, Yang (Missouri University of S & T) | Schuman, Thomas (Missouri University of S & T) | Bai, Baojun (Missouri University of S & T)
Abstract The existence of high conductivity features such as fractures, karst zones, and void space conduits can severely restrict the sweep efficiency of water 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 due to 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 hyper-branched re-crosslinkable preformed particle gel (HT-BRPPG) designed for North Sea high-temperature reservoirs (130 °C), which can re-crosslink 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 employed to test the swelling kinetic and re-crosslinking 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 over one year. The plugging efficiency was evaluated by using a fractured model. Results showed that this novel HT-BRPPG could re-crosslink and form a rubber-like bulky gel with temperature ranges from 80 to 130 °C. The elastic modulus of the re-crosslinked gel can reach up to 830 Pa with a swelling ratio of 10. In addition, the HT-BRPPG with a swelling ratio of 10 has been stable for over 15 months at 130 °C so far. The core flooding test proved that the HT-BRPPG could efficiently plug the open fractures, and the breakthrough pressure is 387.9 psi/ft. Therefore, this novel 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)
- Europe > United Kingdom > North Sea (0.25)
- Europe > North Sea (0.25)
- (2 more...)
- Geology > Rock Type > Sedimentary Rock (0.88)
- Geology > Geological Subdiscipline (0.88)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- 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 > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (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)
Enhancing Heavy-Oil-Recovery Efficiency by Combining Low-Salinity-Water and Polymer Flooding
Zhao, Yang (Missouri University of Science and Technology) | Yin, Shize (Missouri University of Science and Technology) | Seright, Randall S. (New Mexico Petroleum Recovery Research Center) | Ning, Samson (Reservoir Experts, LLC and Hilcorp Alaska, LLC) | Zhang, Yin (University of Alaska Fairbanks) | Bai, Baojun (Missouri University of Science and Technology (Corresponding author)
Summary Combining low-salinity-water (LSW) and polymer flooding was proposed to unlock the tremendous heavy-oil resources on the Alaska North Slope (ANS). The synergy of LSW and polymer flooding was demonstrated through coreflooding experiments at various conditions. The results indicate that the high-salinity polymer (HSP) (salinity = 27,500 ppm) requires nearly two-thirds more polymer than the low-salinity polymer (LSP) (salinity = 2,500 ppm) to achieve the target viscosity at the condition of this study. Additional oil was recovered from LSW flooding after extensive high-salinity-water (HSW) flooding [3 to 9% of original oil in place (OOIP)]. LSW flooding performed in secondary mode achieved higher recovery than that in tertiary mode. Also, the occurrence of water breakthrough can be delayed in the LSW flooding compared with the HSW flooding. Strikingly, after extensive LSW flooding and HSP flooding, incremental oil recovery (approximately 8% of OOIP) was still achieved by LSP flooding with the same viscosity as the HSP. The pH increase of the effluent during LSW/LSP flooding was significantly greater than that during HSW/HSP flooding, indicating the presence of the low-salinity effect (LSE). The residual-oil-saturation (Sor) reduction induced by the LSE in the area unswept during the LSW flooding (mainly smaller pores) would contribute to the increased oil recovery. LSP flooding performed directly after waterflooding recovered more incremental oil (approximately 10% of OOIP) compared with HSP flooding performed in the same scheme. Apart from the improved sweep efficiency by polymer, the low-salinity-induced Sor reduction also would contribute to the increased oil recovery by the LSP. A nearly 2-year pilot test in the Milne Point Field on the ANS has shown impressive success of the proposed hybrid enhanced-oil-recovery (EOR) process: water-cut reduction (70 to less than 15%), increasing oil rate, and no polymer breakthrough so far. This work has demonstrated the remarkable economical and technical benefits of combining LSW and polymer flooding in enhancing heavy-oil recovery.
- North America > United States > Texas (1.00)
- North America > United States > Alaska > North Slope Borough > Prudhoe Bay (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- 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)
- North America > United States > Alaska > Schrader Bluff Formation (0.98)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
First Ever Polymer Flood Field Pilot to Enhance the Recovery of Heavy Oils on Alaska's North Slope Pushing Ahead One Year Later
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) | Ciferno, Jared (DOE National Energy Technology Laboratory) | Edwards, Reid (Hilcorp Alaska LLC) | Ning, Samson (Reservoir Experts, LLC/Hilcorp Alaska, LLC) | Schulpen, Walbert (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 In June 2018 the team embarked on an ambitious project to address the slow development pace of Alaska's 20+ billion barrels heavy oil resource via the first ever polymer flood pilot. Following the successful commencement of the pilot in August 2018, the field demonstration, supporting laboratory experiments and numerical simulation have steadily progressed. A significant amount of valuable data and lessons learned have been collected, and are reported in this paper. The ongoing pilot and the research activities is making headway toward the primary objective of validating the use of polymer flooding for extracting heavy oil in Alaska's challenging environment. The pilot is conducted in two pre-existing pairs of horizontal injectors and producers in an isolated fault block of the Schrader Bluff heavy oil reservoir at the Milne Point Field. A customized polymer blending and pumping unit injects HPAM polymer at a concentration of 1,750 ppm to achieve a target viscosity of 45 cP. Supporting coreflood laboratory experiments have focused on quantification of polymer retention in the rock, and effect of injection water salinity, polymer, and their combinations on oil recovery. The injection and production response of the pilot flood pattern is utilized to develop a history matched reservoir simulation model for forecasting oil recovery beyond the pilot. Finally, specially designed laboratory experiments address anticipated operating concerns regarding post-polymer breakthrough such as oil-water separation efficiency and polymer induced fouling of heater tubes. Polymer has been injected continuously since startup except for two short equipment modification shutdowns, and more recently a prolonged disruption due to polymer hydration issues at the J-pad field site. Cumulatively, over 600,000 lbs. of polymer has been injected, corresponding to ∼7%PV. The two producers show significant decrease in the water cut, gradually increasing oil rate, and no polymer breakthrough. Two main observations from the coreflood are a significant uncertainty in polymer retention values, and positive oil recovery response to low salinity water (2,600 mg/liter TDS). The heterogeneity in the flood pattern presents some challenges in obtaining a robust history matched simulation model. Experimental results on produced fluids treatment indicate the formation of a dense polymer deposit, at certain conditions, on heating tubes that can negatively impact the heat transfer efficiency. The scientific knowledge, including the lessons learned during unanticipated shutdowns, quality control, logistics and field data that is being acquired from this effort has referential value for other planned EOR projects. Finally, by all indications, the polymer field pilot is steadily progressing toward achieving the ultimate goal of unlocking the massive heavy oil resources on Alaska North Slope (ANS).
- Europe > United Kingdom > North Sea > Central North Sea (0.72)
- North America > United States > Alaska > North Slope Borough > Prudhoe Bay (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.70)
- 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)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Confinement Effect on the Fluid Phase Behavior and Flow in Shale Oil Reservoirs
Song, Yilei (China University of Petroleum) | Song, Zhaojie (China University of Petroleum) | Guo, Jia (China University of Petroleum) | Feng, Dong (China University of Petroleum) | Bai, Baojun (Missouri University of Science & Tech) | Liu, Yueliang (China University of Petroleum)
Abstract The nanopore confinement plays an important role in fluid phase behavior and transport. However, investigation of the confinement effect on fluid phase behavior and production performance is lacking in the petroleum industry. Conventional models need to be adjusted to account for nanopore confinement in both phase equilibrium and fluid transport. The objective of this study is to put forward an efficient model to fill this gap and to evaluate the production performance of shale oil reservoir. In this work, the phase equilibrium of Bakken oil is investigated using an adsorption-dependent Peng-Robinson equation of state (A-PR-EOS) coupled with fugacity calculation, capillary pressure calculation, and shifted critical properties. The shifted critical properties can be described by the A-PR-EOS. The bubble point pressure and black-oil properties at different pore sizes are calculated and compared. In addition, the phase behavior calculation results are coupled with the reservoir simulator to evaluate the nanopore confinement effect on the production performance in the Bakken shale reservoir. Results in nanopores show that the bubble point pressure is depressed due to the confinement effect. In the two-phase region, solution gas-oil ratio and oil formation volume factor increase, and oil viscosity decreases as the pore size reduces. In the single-phase region, solution gas-oil ratio and oil formation volume factor in nanopores is the same as those in bulk, while the oil viscosity still decreases as the pore size decreases. The cumulative oil and gas recovery in Bakken reservoir will be enhanced if considering the nanopore confinement. This work provides an improved understanding of the confinement effect on the fluid phase equilibrium and production performance in shale oil reservoirs. Introduction As unconventional hydrocarbons, shale oil and gas are enormous energy resources (EIA, 2016). Great success has been achieved to produce shale reservoirs. However, our understanding of the phase and flow behavior of shale reservoir fluids is still very limited (Salahshoor et al. 2018). Phase behaviors and properties of reservoir fluid and their effects on flow behavior play a key role in the production processes of both conventional and unconventional reservoirs (Song et al. 2020c). Thus, more efforts may be needed to better understand the phase and flow behavior of confined fluids in shale reservoirs.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.70)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- North America > United States > New Mexico > Permian Basin > Wolfcamp Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.98)
- (5 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Performance of Low Salinity Polymer Flood in Enhancing Heavy Oil Recovery on the Alaska North Slope
Zhao, Yang (Missouri University of Science and Technoology) | Yin, Shize (Missouri University of Science and Technoology) | Seright, Randall S. (New Mexico Petroleum Recovery Research Center) | Ning, Samson (Reservoir Experts, LLC/Hilcorp Alaska, LLC) | Zhang, Yin (University of Alaska Fairbanks) | Bai, Baojun (Missouri University of Science and Technoology)
Abstract Combining low-salinity water (LSW) and polymer flooding was proposed to unlock the tremendous heavy oil resources (20–25 billion barrels) on the Alaska North Slope (ANS). The synergy effect of LSW and polymer flooding was demonstrated through coreflooding experiments carried out on representative rock and fluid systems. The results indicate that the high-salinity polymer solution (HSP, 2,300 ppm, salinity=27,500 ppm) requires nearly two thirds more polymer than the low-salinity polymer (LSP, 1,400 ppm, salinity=2,500 ppm) to achieve the same target viscosity of 45 cp measured from viscometer. Additional oil (5–9%) can be recovered from LSW flooding after extensive high-salinity water (HSW) flooding. LSW flooding performed in secondary mode can achieve higher recovery than in tertiary mode. Strikingly, LSP flooding can further improve the oil recovery by ∼8% even after extensive HSP flooding with the same viscosity. LSP flooding performed directly after waterflooding can achieve ∼10% more incremental oil recovery. The pH increase of the effluent during LSW/LSP flooding was significantly greater than that during HSW/HSP flooding, indicating the occurrence of ion exchange which might contribute to the improved oil recovery. Also, the water breakthrough was delayed in a low-salinity flood compared with a high-salinity flood. The idea of combining LSW and polymer flooding has been put into practice on a pattern-scale field pilot test in the target Milne Point field. Nearly two-year observation has shown impressive success: water cut reduction (70% to below 15%), increasing oil rate, and no polymer breakthrough so far. This work has demonstrated remarkable economical and technical benefits of combination of LSW and polymer flooding in enhancing heavy oil recovery. Introduction Heavy oil resources are abundant and account for a large portion of the total oil reserves around the world. Thermal methods, like steam flooding, are effective techniques to develop the heavy oil resources. However, in some areas the thermal methods are not feasible. For example, the Milne Point heavy oil reservoir on the Alaska North Slope (ANS) is thin and covered with thick permafrost. Heat loss and environmental concerns make thermal recovery methods unacceptable. Waterflooding can maintain the production at the early stage, but it soon shows premature breakthrough and fast rise of water cut. Polymer flooding is believed an effective method to unlock the heavy oil resources in this area. Successful field applications of polymer flooding in heavy oil reservoirs have been reported around the world, like in Canada (e.g. Pelican Lake, Seal, Cactus Lake), China (e.g. Bohai Bay), Middle East, Suriname (e.g. Tambaredjo), and Trinidad and Tobago (Delamaide et al., 2014, 2018; Saboorian-Jooybari et al., 2016; Saleh et al., 2017; Zhang et al., 2016).
- North America > United States > Louisiana > Pelican Lake Field (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)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Combining Preformed Particle Gel and Curable Resin-Coated Particles To Control Water Production from High-Temperature and High-Salinity Fractured Producers
Sun, Lin (Southwest Petroleum University) | Li, Daibo (Southwest Petroleum University) | Pu, Wanfen (Southwest Petroleum University) | Li, Liang (Northwest Oilfield Company) | Bai, Baojun (Missouri University of Science and Technology) | Han, Qi (Southwest Petroleum University) | Zhang, Yongchang (Southwest Petroleum University) | Tang, Ximing (Southwest Petroleum University)
Summary Preformed‐particle‐gel (PPG) treatments have been successfully used in injection wells to reduce excessive water production from high‐temperature, high‐salinity fractured reservoirs. However, PPG itself cannot be used in fractured producers because it tends to wash out after the wells resume production. Therefore, we proposed to combine curable resin‐coated particles (CRPs) with PPG to control water production from fractured producers. In this paper, millimeter‐sized tubes and fractured carbonate cores were designed to comprehensively investigate water‐plugging behaviors of the combined system under the conditions of various fracture parameters and PPG/CRP sizes. Particular attention was given to control the PPG washout after production was resumed. The results showed the cured CRPs could generate immobile packs in fractures and dramatically mitigate the PPG washout. The small size of the CRPs and the small ratio of CRP size to tube diameter contributed low permeability and homogeneity to CRP packs. Meanwhile, the less‐permeable and more‐homogeneous CRP pack, as well as the larger‐sized PPGs, contributed to a higher PPG breakthrough pressure gradient. Moreover, some of the PPG particles blocked in the CRP packs could be released through high‐speed brine injection from producers, which indicated the recoverability of the water plugging. This study provides a promising approach to reduce the high‐water‐cut problem in fractured producers.
- Asia (1.00)
- North America > United States > Oklahoma (0.47)
- North America > United States > Texas (0.28)
- North America > United States > Texas > Fort Worth Basin > Northwest Field (0.99)
- Asia > China > Henan > North China Basin > Zhongyuan Field (0.99)
- North America > United States > Louisiana > China Field (0.98)
A Critical Review of CO2 Enhanced Oil Recovery in Tight Oil Reservoirs of North America and China
Song, Zhaojie (China University of Petroleum, Beijing) | Li, Yuzhen (China University of Petroleum, Beijing) | Song, Yilei (China University of Petroleum, Beijing) | Bai, Baojun (Missouri University of Science and Technology) | Hou, Jirui (China University of Petroleum, Beijing) | Song, Kaoping (China University of Petroleum, Beijing) | Jiang, Ajiao (China University of Petroleum, Beijing) | Su, Shan (China University of Petroleum, Beijing)
Abstract Primary oil recovery remains less than 10% in tight oil reservoirs, even after expensive multistage horizontal well hydraulic fracturing stimulation. Substantial experiments and pilot tests have been performed to investigate CO2-EOR potential in tight reservoirs; however, some results conflict with each other. The objective of this paper is to diagnose how these conflicting results occurred and to identify a way to narrow the gap between experimental results and field performance through a comprehensive literature review and data analysis. Peer-reviewed journal papers, technical reports, and SPE publications were collected, and three key steps were taken to reach our goal. First, rock and fluid properties of tight reservoirs in North America and China were compared, and their potential effect on tight oil production was analyzed. Afterward, based on published experimental studies and simulation works, the CO2-EOR mechanisms were discussed, including molecular diffusion, CO2-oil interaction considering nanopore confinement, and CO2-fluid-rock minerals interaction. Subsequently, pilot projects were examined to understand the gap between laboratory works and field tests, and the challenges faced in China's tight oil exploitation were rigorously analyzed. Compared with Bakken and Eagle Ford formation, China's tight oil reservoirs feature higher mud content and oil viscosity while they have a lower brittleness index and formation pressure, leading to confined stimulated reservoir volume and further limited CO2-oil contact. The effect of CO2 molecular diffusion was relatively exaggerated in experimental results, which could be attributed to the dual restrictions of exposure time and oil-CO2 area in field scale. Numerical modeling showed that the improved phase properties in nanopores led to enhanced oil recovery. The development of nano-scale chips withholding high pressure/temperature may advance the experimental study on nano-confinement's effect. Oil recovery can be further enhanced through wettability alteration due to CO2 adsorption on nanopores and reaction with rock minerals. CO2 huff-n-puff operations were more commonly applied in North America than China, and the huff time is in the order of 10 days, but the soaking time is less. Conformance control was essential during CO2 flooding in order to delay gas breakthrough and promote CO2-oil interaction. There is less than 5% of tight oil reserve surrounded by CO2 reservoirs in China, limiting the application of CO2-EOR technologies. An economic incentive from the government is necessary to consider the application of CO2 from power plants, refineries, etc. This work provides an explanation of conflicting results from different research methods and pilot tests, and helps researchers and oil operators understand where and when the CO2-EOR can be best applied in unconventional reservoirs. New directions for future work on CO2-EOR in tight formations are also recommended.
- North America > United States > Texas (1.00)
- North America > United States > Montana (1.00)
- Asia > China (1.00)
- (2 more...)
- Research Report > New Finding (0.86)
- Research Report > Experimental Study (0.86)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- (3 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Performance Improvement of Thickened Liquid CO2 by Introducing a Philic-CO2 Silicone Polymer
Li, Qiang (China University of Petroleum, East China) | Wang, Yanling (China University of Petroleum, East China) | Li, Qingchao (China University of Petroleum, East China) | Wang, Fuling (China University of Petroleum, East China) | Bernardo, Jennifer (China University of Petroleum, East China) | Zhang, Ye (Chongqing Geology and Mineral Research Institute) | Bai, Baojun (Missouri University of Science and Technology) | Liu, Fei (Shengli College)
Abstract As an excellent stimulation treatment for the shale reservoir, CO2 fracturing liquid is injected into the reservoir to increase crude oil production due to the high mobility and high backflow. Nevertheless, many disadvantages in fracturing process, including high fluid loss volume, short fracture length and low viscosity of pure CO2, hinders its application and development. In this investigation, a novel silicone thickener consisted of CO2-Phobic Phenyl and CO2-Philic Ester group is prepared. The thickening performance of a thickener in liquid CO2 is measured by capillary viscosity measurement system at different conditions. Molecular simulation presents that a mesh structure can be formed among CO2, solvent and silicone, and the density of mesh structure affects the viscosity of thickened liquid CO2 Meanwhile, the filtration property and fracturing simulation are compared between pure CO2 and thickened CO2. With the capillary viscometer, the viscosity of thickened liquid CO2 can be increased to 2 mPa·s at 3 wt% thickener at 303 K and pressure of 12 MPa. An increasing CO2 viscosity was displayed as the thickener content and pressure increased, but a decrease of viscosity is shown as temperature and flow velocity rise. The elevated viscosity leads to a significantly reduced filtration volume. Fracturing simulation displays that the increased viscosity results in a longer fracturing time and length. By analyzing the fracturing simulation data, the thickener CO2 can involve a farther reservoir which the pure CO2 cannot reach. Compared to pure CO2, a 55m fracture is revealed during the fracturing simulation while it is only 6m for pure CO2. For the fracturing and filtration performance, the thickened CO2 is obviously better than the pure CO2. The addition of thickener can not only obviously improve the CO2 viscosity to some degree, but also the excellent fracturing and filtration performance according to the extended finite element simulation and the thickened CO2 is considered as an applicable fracturing fluid to develop the shale reservoir.
- Geology > Geological Subdiscipline > Geomechanics (0.72)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.49)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (0.88)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (0.88)
Evaluation of Terpolymer-Gel Systems Crosslinked by Polyethylenimine for Conformance Improvement in High-Temperature Reservoirs
Zhu, Daoyi (China University of Petroleum, Beijing) | Hou, Jirui (China University of Petroleum, Beijing) | Chen, Yuguang (China University of Petroleum, Beijing) | Wei, Qi (China University of Petroleum, Beijing) | Zhao, Shuda (Missouri University of Science and Technology) | Bai, Baojun (China University of Petroleum, Beijing, at Karamay, and Missouri University of Science and Technology)
Summary A terpolymer-gel system using low toxic polyethylenimine (PEI) as the crosslinker was developed for conformance improvement in high-temperature reservoirs. Suitable gelation time (GT), gel strength, and thermal stability could be obtained by selecting PEI molecular weight and adjusting terpolymer concentrations. With the increase of terpolymer concentration, GT decreases and the gel strength increases. However, in this research, the effect of PEI concentration on the gelation performance was much less obvious than that of the polymer concentration. Very low concentrations of sodium chloride (NaCl) can slightly shorten the GT. After critical concentrations were reached, the authors determined that the ions will delay the crosslinking reaction. Moreover, the addition of sodium carbonate (Na2CO3) can also lengthen GT. The gel systems were able to maintain thermal stability at 150°C. Uniformly distributed 3D network microstructures and the small size of the gel-grid pores made the network structure maintain thermal stability. The use of the terpolymer-gel-system gelation mechanism crosslinked by PEI can help petroleum engineers better understand and apply this terpolymer-gel system.
- Asia > China (1.00)
- North America > United States > Texas (0.67)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > China Government (0.46)
- 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...)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
First Ever Polymer Flood Field Pilot - A Game Changer 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) | Ciferno, Jared (DOE-National Energy Technology Laboratory) | 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 development pace of Alaska's vast, 20-25 billion barrels, heavy oil resources has been very slow due to high development costs and low oil recovery using conventional waterflood, and the impracticality of deploying thermal methods due to the presence of continuous permafrost. Although, polymer flooding has attracted attention and has become a promising EOR technique in heavy oil reservoirs due to the extensive application of horizontal wells and advancement of polymer flooding technology, no field tests have been performed to date in Alaska's underdeveloped heavy oil reservoirs. The overall objective of this research is to perform a field experiment to validate the use of polymer flooding for extracting heavy oil in Alaska's challenging environment. Two pre-existing pairs of horizontal injection and production wells in an isolated fault block of the Schrader Bluff heavy oil reservoir at the Milne Point Field are currently being used for the field experiment. Hydrolyzed polyacrylamide (HPAM) polymer injection started on August 28, 2018 at 600 ppm (4 cP viscosity) concentration ramping up to 1,800 ppm (45 cP viscosity) over a three week time period, and has been maintained at an average concentration of ~1,800 ppm. Current injection rates in the two horizontal injectors are ~2,200 and 600 bwpd. Laboratory experiments to determine the polymer retention, optimum water salinity, synergistic effects of water salinity and polymer, and handling of produced fluids, in support of the field experiment, are currently ongoing. Similarly, reservoir simulation of coreflood behavior and history match of previous waterfloods to predict polymer flood performance in the project area are also conducted in parallel. The field data and scientific knowledge that have been collected since the start of the injection indicates that the field pilot is performing as predicted. To date, no unexpected injectivity issues or polymer breakthrough have been encountered, and the two horizontal producers are showing positive response to the polymer injection, resulting in incremental increase in oil production rate. Since the research is still in its early stages, selected field, laboratory and simulation results are presented and discussed to highlight the integrative approach adopted in this first ever polymer flood field pilot in Alaska.
- Europe > United Kingdom > North Sea > Central North Sea (0.82)
- 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 (0.95)
- South America > Suriname > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- North America > United States > Alaska > North Slope Basin > Milne Point Field > Kuparuk Formation (0.99)
- (8 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)