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Collaborating Authors
Hsu, Tzu-Ping
A Novel Enhanced Oil Recovery Approach to Water Flooding in Saskatchewan’s Tight Oil Plays
Kiani, Mojtaba (Nalco Champion, An Ecolab Company) | Hsu, Tzu-Ping (Nalco Champion, An Ecolab Company) | Roostapour, Alireza (Nalco Champion, An Ecolab Company) | Kazempour, Mahdi (Nalco Champion, An Ecolab Company) | Tudor, Eric (Nalco Champion, An Ecolab Company)
Abstract Fast production decline in Saskatchewan's tight oil assets has left behind billions of barrels of oil. In the past few years, waterflooding has been utilized to reduce the production decline rate to some extent, however, further optimization in waterflood performance is desired by operators. In this paper, we present our methodology to enhance waterflooding in Saskatchewan's Bakken field, reducing the rate of production decline. This methodology relies upon surfactant-based production enhancement formulations specifically designed to boost waterflood performance. Laboratory experiments and field design are presented to support the assertion that waterflood performance can be enhanced. This approach is one of the earliest of its kind that systematically utilizes the surfactant to enhance water floods in Saskatchewan's assets. In this paper, we cover the laboratory formulations, fluid-fluid and rock-fluid tests, and the pilot design process. Laboratory work includes formulation development and screening through stability, interfacial tension (IFT) measurement, emulsion tendency and imbibition tests to evaluate the rate of oil recovery against current waterflood. A correlation between IFT and oil recovery was observed and is also discussed. Using a spontaneous imbibition test and our optimized formulations resulted in an additional 35% of original oil in place (OOIP) recovery at 1000 ppm concentration compared to the 20% OOIP oil recovery when placed in brine only. As a result, wettability alteration and IFT reduction were identified as mechanisms that are effective at enhancing incremental oil recovery beyond the secondary brine mode. After promising laboratory observations, a pilot design area was selected in Saskatchewan. Through a detailed analysis of well communications, breakthroughs, cumulative injection and production volumes, numerical simulation, and economics, a slug size of surfactant solution was proposed. It was identified that our designed treatment could be ineffective to some well patterns with strong frac communications and very short breakthrough times; however, a conformance treatment has been designed for these specific areas. The preliminary laboratory work and design work support the requirements to proceed to the next step of a pilot. Successful results using this approach demonstrate the potential to increase the amount of recoverable resources in tight oil plays under waterflood.
- North America > United States > Montana (1.00)
- North America > Canada > Saskatchewan (1.00)
Understanding the Oil Recovery Mechanism in Mixed-Wet Unconventional Reservoirs: Uniqueness and Challenges of Developing Chemical Formulations
B. Alamdari, Baharak (Nalco Champion) | Hsu, Tzu-Ping (Nalco Champion) | Nguyen, Duy (Nalco Champion) | Kiani, Mojtaba (Nalco Champion) | Salehi, Mehdi (Nalco Champion)
Abstract Several surfactant formulations that had been tested successfully in oil-wet unconventional reservoirs were tested in mixed-wet to oil-wet unconventional reservoir cores and did not generate the expected results. To study the mechanisms of oil recovery and understand the uniqueness of these shale reservoirs, a series of studies were performed utilizing Eagle Ford (EF) and Canadian Bakken shale rocks and fluids. In this study customized chemical formulations for improving production from the EF and the Canadian Bakken were developed. Previously related formulation development for the Bakken and Permian basins relied upon wettability alteration as the oil recovery mechanism; however, no significant oil recovery compared to brine was seen from wettability-altering formulations using EF and Canadian Bakken shale rock and fluids. Several imbibition tests showed that baseline oil recovery by brine was 20-30% of original oil in place (OOIP) for both formations. High oil recovery by brine was attributed to the mixed to water-wet nature of the pore surface. A well-connected fracture system may have also contributed. Further, there was no correlation between oil recovery and contact angle measurements. Failure of wettability alteration as an oil recovery mechanism led to investigation of interfacial tension (IFT) reduction as an alternative mechanism. Testing this hypothesis, a change in the EF formulation reduced IFT to 0.03 dyne/cm and had oil recoveries above 60% OOIP. However, these formulations were not stable at 320 °F. Formulation KPIs were set as lowering IFT and being stable up to 320 °F. Out of many formulations tested, two containing multiple actives in a specific mixture of solvents passed the KPIs and were tested for imbibition oil recovery. A synergistic mixture had a final oil recovery above 56% OOIP as compared to 20-25% OOIP for brine alone. The imbibition oil recovery results indicate that although the ultimate oil recovery by brine alone is significant, the early oil production is significantly slower than by surfactant solutions. Upscaling the laboratory time to the field time emphasizes the value of implementing customized surfactant formulation in both early and late oil production. Similarly, there was no correlation between wettability contact angle measurements and oil recovery for the Canadian Bakken shale. Surfactant formulations which exhibited low IFT (~0.01 dyne/cm) significantly accelerated the oil production and recovered an additional 30-45% OOIP in the tertiary mode from the imbibition tests. Further laboratory studies via the Washburn method, imbibition tests, and zeta potential measurements validated lowering IFT, not altering the wettability, as a primary oil recovery mechanism in the mixed-wet EF and Canadian Bakken. Optimal formulations for EF and Canadian Bakken will be tested in the field by mid-2018.
- North America > United States > South Dakota (0.89)
- North America > United States > North Dakota (0.89)
- North America > United States > Montana (0.89)
- North America > United States > Texas (0.67)
- Research Report > Experimental Study (0.68)
- Research Report > New Finding (0.48)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.66)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- (31 more...)
Recovery of Oil from High Salinity Reservoir Using Chemical Flooding: From Laboratory to Field Tests
Shiau, Ben (University of Oklahoma) | Hsu, Tzu-Ping (University of Oklahoma) | Lohateeraparp, Prapas (University of Oklahoma) | Rojas, Mario (University of Oklahoma) | Budhathoki, Mahesh (University of Oklahoma) | Raj, Ajay (University of Oklahoma) | Wan, Wei (University of Oklahoma) | Bang, Sangho (University of Oklahoma) | Harwell, Jeffrey H. (University of Oklahoma)
Abstract Reservoirs containing very high total dissolved solids and high hardness make the design of a surfactant polymer (SP) flood extremely difficult because surfactant tends to precipitate and separate under these conditions. Beside divalent ions, Ca, Mg, presence of iron in the brine can be a challenging issue. Different surfactant formulations are evaluated and incorporate cosurfactants and co-solvents which minimize viscous macroemulsions, promote rapid coalescence under Winsor Type III conditions, and stabilize the chemical solution by reducing precipitation and phase separation. The optimal surfactant formulations were further evaluated in one-dimensional sand packs and coreflood tests using Berea sandstone, reservoir oils, and brines at reservoir temperatures. Using similar injection protocols, 3 pore volumes of surfactant-only system, experimental results show the oil recovery ranging from 45 % to 70% of the residual oil (Sor) after water flooding. The level of surfactant loading is less than 0.5 wt%. A single-well test was conducted to confirm laboratory results in situ in the presence of high-salinity formation water containing 102,300 mg/L total dissolved solids (TDS). The aim of ongoing test is to confirm the effectiveness of the high-salinity surfactant-only formulation (0.46 wt% of surfactant). In this effort, we plan to conduct multiple single-well tests at different wells to minimize the design risks involved for the surfactant pilot test. A pilot test at a sandstone reservoir is scheduled to be performed in July of 2013 to further evaluate the effectiveness of surfactant formulation and address technical issues related to scale-up.
- North America > United States > Texas (0.28)
- North America > United States > West Virginia (0.25)
- North America > United States > Pennsylvania (0.25)
- (2 more...)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Improved Oil Recovery by Chemical Flood from High Salinity Reservoirs-Single-Well Surfactant Injection Test
Hsu, Tzu-Ping (University of Oklahoma) | Prapas, Lohateeraparp (University of Oklahoma) | Roberts, Bruce L. (University of Oklahoma) | Wan, Wei (University of Oklahoma) | Lin, Zhixun (University of Oklahoma) | Wang, Xiaoguang (University of Oklahoma) | Budhathoki, Mahesh (University of Oklahoma) | Ben Shiau, B. J. (University of Oklahoma) | Harwell, Jeffrey H. (University of Oklahoma)
Abstract Reservoirs containing very high total dissolved solids and high hardness make the design of a surfactant polymer (SP) flood extremely difficult because surfactant tends to precipitate and separate under these conditions. Beside divalent ions, Caand Mg, the presence of iron in the brine can be a challenging issue. Different surfactant formulations incorporating cosurfactants and co-solvents are studied. These formulations minimize viscous macroemulsions, promote rapid coalescence under Winsor Type III conditions, and stabilize the chemical solution by reducing precipitation and phase separation. The optimal surfactant formulations are further studied in one-dimensional sand packs and coreflood tests using Berea sandstone, reservoir oils, and brines at 42°C. Using similar injection protocols, 0.5 PVs surfactant/polymer, oil recoveries ranging from 50 % to 70% of the residual oil (Sor) after waterflooding are observed. The level of surfactant loading is less than 0.6 wt%. A single-well test is conducted to confirm laboratory results in situ in the presence of high-salinity formation water containing 165,000 mg/L total dissolved solids (TDS). The test is considered to be a technical success and confirms the effectiveness of a high-salinity surfactant-polymer formulation composed of 0.23 wt% of surfactant and 1,800 ppm of polymer loading. Approximately 87% of the residual oil was mobilized.
- North America > United States > Pennsylvania (0.34)
- North America > United States > West Virginia (0.24)
- North America > United States > Ohio (0.24)
- North America > United States > Kentucky (0.24)
- Geology > Geological Subdiscipline (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.51)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Reduction of residual oil saturation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Improved Oil Recovery by Chemical Flood from High Salinity Reservoirs
Shiau, B. J. (Prapas, Lohateeraparp) | Hsu, Tzu-Ping (Prapas, Lohateeraparp) | Wan, Wei (University of Oklahoma) | Lin, Zhixun (University of Oklahoma) | Roberts, Bruce L. (University of Oklahoma) | Harwell, Jeffrey H. (University of Oklahoma)
Abstract Reservoirs containing very high total dissolved solids and high hardness make the design of a surfactant polymer (SP) flood extremely difficult because surfactant tends to precipitate and separate under these conditions. Beside divalent ions, Ca, Mg, presence of iron in the brine can be a challenging issue. Different surfactant formulations are evaluated and incorporate cosurfactants and co-solvents which minimize viscous macroemulsions, promote rapid coalescence under Winsor Type III conditions, and stabilize the chemical solution by reducing precipitation and phase separation. The optimal surfactant formulations were further evaluated in one-dimensional sand packs and coreflood tests using Berea sandstone, reservoir oils, and brines at reservoir temperatures. Using similar injection protocols, 0.5 pore volumes of surfactant/polymer + 0.5 pore volumes of polymer drive, experimental results show the oil recovery ranging from 46 % to 89% of the residual oil (Sor) after water flooding. The level of surfactant loading is less than 0.5 wt%. A single-well test was conducted to confirm laboratory results in situ in the presence of high-salinity formation water containing 185,000 mg/L total dissolved solids (TDS). The test is considered to be a technical success and confirms the effectiveness of the high-salinity surfactant-polymer formulation (0.4 wt% of surfactant and 1,800 ppm of polymer loading). The Sor was reduced from 25% to 7% resulting in approximately 72 % of the residual oil being mobilized. A pilot test at the same reservoir is scheduled to be performed in 2012 to further evaluate the effectiveness of surfactant formulation and address technical issues related to scale-up.
- North America > United States > Pennsylvania (0.34)
- North America > United States > West Virginia (0.24)
- North America > United States > Ohio (0.24)
- North America > United States > Kentucky (0.24)
- Research Report > New Finding (0.67)
- Research Report > Experimental Study (0.66)
- Geology > Geological Subdiscipline (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.69)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Reduction of residual oil saturation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract The purpose of this study is to investigate compounds that can generate carbon dioxide in situ, decrease the viscosity of oil and improve oil recovery. Several chemicals are studied for their potential to generate CO2 when exposed to elevated temperatures. Laboratory results show that ammonium carbamate can produce a significant amount of carbon dioxide when the temperature is elevated to 85° C. In contrast, negligible CO2 is detected while heating up the methyl carbamate to a similar temperature range. Ammonium carbamate is further studied in a one-dimensional sand pack column. Ammonium carbamate results in the production of CO2 in column studies at 80°C and 90° C and also results in a decrease in oil viscosity. The additional injection of a 0.5 PV of 3% ammonium carbamate solution with a polymer + surfactant chemical flood improved crude oil recovery by 9.7% OOIP compared to a polymer + surfactant chemical flood without carbamate. However, there is negligible oil recovery without the presence of surfactant for studies using light oils, decane and Arrow crude oil. The use of carbamate can have a positive impact on the mobility ratio for heavier oil, Elk Petroleum crude oil, by reducing crude oil viscosity. Instead of looking black, the crude oil exiting from the carbamate injected column appeared dark brown and less viscous. This suggests that a property of crude oil was changed by the CO2 generated in the column. Laboratory results also show that AMP (2-Amino-2-methyl-1-propanol) is also a promising candidate for generating carbon dioxide under high temperatures.
- North America > United States (0.70)
- Europe (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.31)
Designing Alcohol-Free Surfactant Chemical Flood for Oil Recovery
Shiau, B. J. (Prapas Lohateeraparp) | Harwell, Jeffrey H. (Prapas Lohateeraparp) | Dinh, Anh V. (University of Oklahoma) | Roberts, Bruce L. (University of Oklahoma) | Hsu, Tzu-Ping (University of Oklahoma) | Anwuri, Ovinuchi I. (University of Oklahoma)
Abstract This work shows a unique method for determining the composition of an aqueous solution for chemical EOR using surfactants, salts, and polymer without the addition of a co-solvent. Phase behavior studies composed of reservoir brine, alkali, surfactants, salts, polymer and reservoir crude oil are evaluated as a function of time for onset of phase equilibrium and middle phase formation at ambient temperature and pressure. The optimal surfactant formulation was confirmed by a fast coalescence rate of formation of middle-phase microemulsion and ultra-low interfacial tension. Optimum formulations from phase behavior studies are further evaluated in 1-D sand-pack using crushed sandstone, reservoir oil, and brine at reservoir temperature. One half of a pore volume (PV) of the selected surfactant/polymer (SP) or alkali/surfactant/polymer (ASP) solution is used to flood the column and is followed with reservoir brine until no more oil is produced. The optimum SP and ASP compositions for oil mobilization from the sand pack studies are then investigated in a core flood apparatus. Residual oil saturation was first established in a Berea core at the targeted reservoir temperature and pressure. The core is then flooded with 0.5 PV of the optimum SP or ASP formulation, followed by reservoir brine until no more oil is produced. A unique aspect of this work is that the packed column studies predict core flood results. Packed bed studies are much faster, the apparatus is much less complex and much less expensive, relative to a core flood apparatus. The level of surfactant loading is 0.51% to 0.55% with 2.1% salt. The alcohol-free surfactant loading is lower that previously reported levels. Core floods show oil recoveries ranging from 55% to 64% of the residual oil after waterflooding.
- North America > United States (0.45)
- Asia (0.28)