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Collaborating Authors
Britton, Christopher
Geochemical Modeling to Evaluate the Performance of Polymer Flooding in a Highly Sour Sandstone Heavy Oil Reservoir
Al-Murayri, Mohammed Taha (Kuwait Oil Company) | Kamal, Dawood Sulaiman (Kuwait Oil Company) | Garcia, Jose Gregorio (Kuwait Oil Company) | Delshad, Mojdeh (UEORS) | Britton, Christopher (UEORS) | Fortenberry, Robert (UEORS)
Abstract The Umm Niqa Lower Fars (Heavy Oil Field) oil reservoir has very favorable properties of high permeability, low temperature, and moderate oil viscosity for polymer flooding and work is progressing towards implementing a polymer pilot in this target reservoir. Nonetheless, Heavy Oil Field contains high salinity water, it is shallow with concerns about injectivity limitations, and high concentrations of H2S (up to 5 mol% in reservoir fluids) which may adversely impact the effectiveness of the injected polymer solutions. A comprehensive laboratory and numerical modeling was initiated to address some of these issues. One potential concern is the degradation of polymer in the co-presence of H2S and possible oxygen introduced with polymer solution injection. This study is aimed at evaluating the impact of H2S on polymer performance in the Heavy Oil Field reservoir via geochemical simulations based on laboratory data. Previously performed polymer rheology and transport experiments were history matched and model parameters were developed for subsequent simulations. Transport behavior of both HPAM type and biopolymers was modeled incorporating two new features of viscous fingering and filtration models. This was then followed by a geochemical simulation study to assess and potentially de-risk the presence of H2S near the wellbore assuming that all oxygen in the injection water (if any) is rapidly consumed by reservoir rock minerals and oil. The parameters developed for the rheology of the polymers were very robust and represented the effects of salinity and polymer shear thinning over a wide range of polymer concentrations for each polymer. These parameters were then used to conduct simulation studies on waterflooding and polymer flooding in the presence of near wellbore H2S. Sensitivity simulations to relative permeability/wettability, oil viscosity, polymer concentration were also conducted to identify the impact on injectivity of polymer solution. The use of the newly added viscous fingering and filtration models was necessary in some cases to correctly model the transport behavior of unstable displacements. Geochemical evaluation showed that injecting H2S-free water over a period of ~3 months can significantly reduce H2S concentration in the near-wellbore region (~30 ft) due to stripping from the oil phase. This is advantageous for the injected polymer because even if small oxygen concentration is co-injected with the water, there would be no H2S present to cause polymer degradation. This study presents a practical approach to de-risk the deployment of polymer flooding in a highly sour shallow sandstone heavy oil reservoir. The findings of this study will be evaluated in a one-spot EOR pilot soon.
- North America > United States > Texas (0.46)
- Asia > Middle East > Kuwait (0.29)
- North America > United States > Oklahoma (0.28)
- North America > United States > Colorado (0.28)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.61)
- 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)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
Stability of Biopolymer and Partially Hydrolyzed Polyacrylamide in Presence of H2S and Oxygen
Al-Murayri, Mohammed Taha (KOC) | Kamal, Dawood Sulaiman (KOC) | Garcia, Jose Gregorio (KOC) | Al-Tameemi, Naser (KOC) | Driver, Jonathan (UEORS) | Hernandez, Richard (UEORS) | Fortenberry, Robert (UEORS) | Britton, Christopher (UEORS)
Abstract There are many oil reservoirs worldwide with substantial amount of H2S but otherwise very favorable conditions for polymer flooding such as low temperature, high permeability, and moderate to high oil viscosity. However, there is a legitimate concern about the chemical stability of polymers when there is dissolved oxygen in the injection water or injection facility and its high concentrations of H2S in the reservoir. Several synthetic polymers and biopolymers were selected for stability testing under a wide range of conditions. We focused on identifying the concentration limits for co-presence of H2S and oxygen for which the synthetic and biopolymers are stable for an extended period, using different, widely available brine compositions. Experiments were conducted with and without standard polymer protection packages to evaluate their effects on stability and degradation under sour conditions. Viscosity of polymer solutions with varying concentrations of H2S and oxygen were measured and compared with the oxygen free or H2S free solution viscosities for a period of 6 months. Several methods of safely introducing H2S to the polymer solution were investigated and compared. The laboratory results indicated that biopolymers were stable at all the concentrations of oxygen and H2S concentrations studied. Three synthetic polymers tested showed some degradation in the presence of oxygen and H2S but were stable when either species is absent. The results indicated that oxygen is the limiting reagent in the degradation reaction with partially hydrolyzed polyacrylamide (HPAM) polymers under normal reservoir conditions. We observed little-to-no difference in degradation between samples with 10 or 100 ppm H2S at 500 ppb oxygen concentration, so H2S is not the limiting reagent under these conditions. Additionally, HPAM exposed to 10 ppm H2S and intermediate levels of oxygen (~0.5 ppm) only partially degrades, while samples exposed to H2S and ambient oxygen completely degrade. We anticipate these results will be useful for operators evaluating the potential of polymer flooding in sour reservoirs to follow a stricter polymer preparation at the surface facility to minimize oxygen concenration.
- Geology > Geological Subdiscipline (0.67)
- Geology > Mineral > Sulfide (0.60)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.30)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.55)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
Novel Large-Hydrophobe Alkoxy Carboxylate Surfactants for Enhanced Oil Recovery
Lu, Jun (University of Texas at Austin) | Britton, Christopher (University of Texas at Austin) | Solairaj, Sriram (University of Texas at Austin) | Liyanage, Pathma J. (University of Texas at Austin) | Kim, Do Hoon (University of Texas at Austin) | Adkins, Stephanie (University of Texas at Austin) | Arachchilage, Gayani W. (University of Texas at Austin) | Weerasooriya, Upali (University of Texas at Austin) | Pope, Gary A. (University of Texas at Austin)
Summary A new class of surfactants has been developed and tested for chemical enhanced oil recovery (EOR) that shows excellent performance under harsh reservoir conditions. These novel Guerbet alkoxy carboxylate (GAC) surfactants fulfill this need by providing large, branched hydrophobes; flexibility in the number of alkoxylate groups; and stability in both alkaline and nonalkaline environments at temperatures up to at least 120ยฐC. The new carboxylate surfactants were recently manufactured at a cost comparable to other commercial EOR surfactants by use of commercially available feedstocks. A formulation containing the combination of a carboxylate surfactant and a sulfonate cosurfactant resulted in a synergistic interaction that has the potential to reduce the total chemical cost further. One can obtain both ultralow interfacial tension (IFT) with the oils and a clear aqueous solution (even under harsh conditions such as high salinity, high hardness, and high temperature with or without alkali) with these new large-hydrophobe alkoxy carboxylate surfactants. Both sandstone and carbonate corefloods were conducted, with excellent results. Formulations were developed for both active oils (contains naturally occurring carboxylic acids) and inactive oils (oils that do not produce sufficient amounts of soap/carboxylic acid), with excellent results.
- Geology > Mineral (0.69)
- Geology > Rock Type > Sedimentary Rock (0.50)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Recent Technology Developments in Surfactants and Polymers for Enhanced Oil Recovery
Lu, Jun (U. of Texas at Austin) | Liyanage, Pathma Jith (U. of Texas at Austin) | Solairaj, Sriram (Conocophillips) | Adkins, Stephanie (U. of Texas at Austin) | Arachchilage, Gayani Pinnawala (U. of Texas at Austin) | Kim, Do Hoon (U. of Texas at Austin) | Britton, Christopher (U. of Texas at Austin) | Weerasooriya, Upali (U. of Texas at Austin) | Pope, Gary A. (U. of Texas at Austin)
Abstract Several classes of new surfactants have recently been tested for enhanced oil recovery. These new surfactants were needed for oil field applications under reservoir conditions that made it difficult or impossible to find conventional surfactants with the desired behavior such as ultra-low interfacial tension, aqueous stability, thermal stability at high temperature, low retention, tolerance to high salinity and so forth. We illustrate results for several of these new surfactants and discuss under what conditions they are suitable, how we developed formulations using them and some of the general principles that can be applied to future applications. A common theme of this development is the need for surfactants with large hydrophobes (carbon numbers above 18) even for some light oils. A second common theme is the advantages and flexibility of propylene oxide and ethylene oxide linkages between these large hydrophobes and the sulfate or carboxylate end group. A third common theme is the advantages of highly branched hydrophobes regardless of the other characteristics of the surfactant structure help prevent undesirable viscous phases. Finally, a fourth common theme is the advantages of using surfactant mixtures with diverse structures and sizes. These common elements enable us find surfactant formulations that are highly effective and that can be made from available feedstocks at reasonable cost.
- North America > United States > Oklahoma (0.29)
- North America > United States > Texas (0.29)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Surfactant Enhanced Oil Recovery from Naturally Fractured Reservoirs
Lu, Jun (The University of Texas at Austin) | Goudarzi, Ali (The University of Texas at Austin) | Chen, Peila (The University of Texas at Austin) | Kim, Do Hoon (The University of Texas at Austin) | Britton, Christopher (The University of Texas at Austin) | Delshad, Mojdeh (The University of Texas at Austin) | Mohanty, Kishore K. (The University of Texas at Austin) | Weerasooriya, Upali P. (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin)
Abstract Large volumes of oil remain in naturally fractured carbonate oil reservoirs and water floods are often very inefficient because many of these reservoirs are mixed-wet or oil-wet as well as extremely heterogeneous. Naturally fractured reservoirs are challenging targets for chemical flooding because they typically have a high permeability contrast between the fractures and the matrix with low to extremely low matrix permeability. In addition, some of the world's largest oil reservoirs are fractured carbonates with high reservoir temperature and high salinity formation brine and some of them also have low API gravity oils, which also increases the difficulty of recovering the oil. We have developed a stable surfactant that shows promising results even when all of these conditions are present at the same time. Both static and dynamic imbibition experiments were done using a fractured carbonate core. These results were interpreted using a mechanistic chemical reservoir simulator.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
New Correlation to Predict the Optimum Surfactant Structure for EOR
Solairaj, Sriram (The University of Texas at Austin) | Britton, Christopher (The University of Texas at Austin) | Lu, Jun (The University of Texas at Austin) | Kim, Do Hoon (The University of Texas at Austin) | Weerasooriya, Upali (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin)
Abstract It is well known that the oil recovery efficiency of chemical EOR depends on microemulsion phase behavior and interfacial tension (IFT). The surfactants needed to obtain good phase behavior and ultra-low IFT vary greatly with oil characteristics and reservoir conditions. Hence, it is often necessary to test many surfactant formulations before finding a highly effective one. Based on both sound principles and extensive experience, one would expect to find a relationship between the optimum surfactant structure, the oil characteristics, the brine, and the temperature. Salager's equation (Salager et al., 1979, Anton et al., 2008) shows it is possible to correlate some of these variables to classical surfactant structure. We now have many new surfactants with widely different structures and many more good formulations with a wider range of oils, temperature and so forth. Thus, it becomes imperative to study the underlying trend and to identify the most important variables affecting the optimum surfactant structure. A new correlation has been developed using an extensive data set taking into account the effect of propylene oxide number (PON), ethylene oxide number (EON), temperature, brine salinity and the equivalent alkane carbon number (EACN) of the oil. The new correlation will help in identifying the most important variables and also to improve our understanding of the relationship among variables affecting optimum surfactant structure. In particular, the new equation can be used to predict the optimum carbon number of the surfactant hydrophobe. Results show that larger hydrophobes are needed as either the temperature or the equivalent alkane carbon number (EACN) of the oil increases. The surfactant formulations used for this study include mixtures of sulfate, sulfonate, carboxylate and non-ionic surfactants. This is a new and highly significant advance in the optimization of chemical EOR processes that will greatly reduce the time and cost of the effort required to develop a good formulation as well as to improve its performance.
- North America > United States > Oklahoma (0.29)
- North America > United States > Texas > Travis County > Austin (0.15)
- Research Report > New Finding (0.67)
- Research Report > Experimental Study (0.48)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Measurement and Analysis of Surfactant Retention
Solairaj, Sriram (The University of Texas at Austin) | Britton, Christopher (The University of Texas at Austin) | Kim, Do Hoon (The University of Texas at Austin) | Weerasooriya, Upali (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin)
Abstract Surfactant retention is one of the most important variables affecting the economics of chemical flooding and varies widely depending on the surfactant structure, mineralogy, salinity, pH, Eh, microemulsion viscosity, crude oil, co-solvent and mobility control among other variables. We have done a large number of dynamic surfactant retention measurements over a wide range of conditions using a variety of new-generation surfactants to recover crude oils from both sandstone and carbonate cores. Surfactant retention values for both surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) floods were measured and correlated with pH, total acid number (TAN) of the oil, temperature, co-solvent concentration, salinity of the polymer drive, mobility ratio, and molecular weight of the surfactant. Surfactant retention values ranged from about 0.01 to 0.37 mg/g of rock. SP and ASP formulations included mixtures of anionic and nonionic surfactants with and without co-solvents. The retention of anionic surfactants of all types was found to be similar on both sandstones and carbonate rocks.
- Research Report > New Finding (0.46)
- Research Report > Experimental Study (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.61)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.48)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Novel Large-Hydrophobe Alkoxy Carboxylate Surfactants for Enhanced Oil Recovery
Lu, Jun (The University of Texas at Austin) | Britton, Christopher (The University of Texas at Austin) | Solairaj, Sriram (The University of Texas at Austin) | Liyanage, Pathma J. (The University of Texas at Austin) | Kim, Do Hoon (The University of Texas at Austin) | Adkins, Stephanie (The University of Texas at Austin) | Arachchilage, Gayani W. (The University of Texas at Austin) | Weerasooriya, Upali (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin)
Abstract A new class of surfactants has been developed and tested for chemical enhanced oil recovery that shows excellent performance under harsh reservoir conditions. These novel Guerbet alkoxy carboxylate surfactants fulfill this need by providing large, branched hydrophobes, flexibility in the number of alkoxylate groups, and stability in both alkaline and non- alkaline environments at temperatures up to at least 120 ยฐC. The new carboxylate surfactants perform better than previously available commercial surfactants, they can be used under harsh reservoir conditions, and they can be manufactured at a lower cost from widely available feedstocks. A formulation containing the combination of a carboxylate surfactant and a sulfonate co-surfactant resulted in a synergistic interaction that has the potential to further reduce the total chemical cost. Both ultra- low interfacial tension with the oils and a clear aqueous solution even under harsh conditions such as high salinity, high hardness and high temperature with or without alkali can be obtained using these new large-hydrophobe alkoxy carboxylate surfactants. Both sandstone and carbonate corefloods were conducted with excellent results. Formulations have been developed for both active oils (contains naturally occurring carboxylic acids) and inactive oils (oils that do not produce soap/carboxylic acid) with excellent results. The new class of surfactants is a major breakthrough that greatly increases the commercial potential of chemical enhanced oil recovery.
- North America > United States > Texas (0.48)
- North America > United States > Oklahoma (0.29)
- Geology > Mineral (0.70)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.36)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
The Impact of Microemulsion Viscosity on Oil Recovery
Walker, Dustin L. (The University of Texas at Austin) | Britton, Christopher (The University of Texas at Austin) | Kim, Do Hoon (The University of Texas at Austin) | Dufour, Sophie (The University of Texas at Austin) | Weerasooriya, Upali (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin)
Abstract The physical structure of microemulsions and the degree to which ultra-low IFT is achieved is dependent on a number of parameters including the types and concentrations of surfactants, co-solvents and alkali, crude oil composition, brine composition, temperature and to a lesser extent, pressure. Modifying any one of these variables creates a microemulsion with different properties. The rheological properties of the microemulsion must be adjusted appropriately to achieve good performance under practical reservoir conditions. Two microemulsion properties of primary concern are undesirably high viscosity relative to oil viscosity and non-Newtonian behavior. The broader implications of injecting microemulsions with high viscosities or non-Newtonian behavior in the field include high surfactant retention, unsustainably high pressure gradients, reduced sweep efficiency and microemulsions that stagnate in the field due to high viscosity at low shear rates. The most common ways to reduce microemulsion viscosity are to optimize the surfactant formulation with a good co-solvent and/or by adding more branching to the surfactant hydrophobe. Adding co-solvent in appropriate concentrations makes a microemulsion much less viscous. However, co-solvents increase the cost and complexity and also tend to increase the IFT. A less conventional solution involves increasing the temperature of the injection water thereby lowering both the oil and microemulsion viscosity. This approach has been tested successfully in core floods using both surrogate and reservoir cores.
- North America > United States > Texas (0.29)
- North America > United States > Oklahoma (0.28)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Low-Cost, High-Performance Chemicals for Enhanced Oil Recovery
Yang, Hyuntae (Center for Petroleum and Geosystems Engineering, University of Texas) | Britton, Christopher (Center for Petroleum and Geosystems Engineering, University of Texas) | Liyanage, Pathma J. (Center for Petroleum and Geosystems Engineering, University of Texas) | Solairaj, Sriram (Center for Petroleum and Geosystems Engineering, University of Texas) | Kim, Do Hoon (Center for Petroleum and Geosystems Engineering, University of Texas) | Nguyen, Quoc (Center for Petroleum and Geosystems Engineering, University of Texas) | Weerasooriya, Upali (Center for Petroleum and Geosystems Engineering, University of Texas) | Pope, Gary A. (Center for Petroleum and Geosystems Engineering, University of Texas)
Abstract The ability to select low-cost, high-performance surfactants for a wide range of crude oils under a wide range of reservoir conditions has improved dramatically in recent years. We have developed surfactant formulations (surfactant, co-surfactant, co-solvent, alkali, polymer, electrolyte) using a refined phase behavior approach. Such formulations nearly always result in more than 90% oil recovery in both outcrop and reservoir cores when good surfactants with good mobility control are used. Chemical flood residual oil saturations are typically less than 0.04 and surfactant retention between 0.01 and 0.1 mg/g with these formulations using as little as 0.2% surfactant concentration and 30% pore volume ASP slugs. We describe some of the advances that have improved the performance, reduced the cost, increased the robustness, and extended the range of reservoir conditions for these formulations. There are thousands of possible combinations of the chemicals that could be tested for each oil and each chemical combination requires many observations over a long time period at reservoir temperature for proper evaluation, so it would take too long, cost too much and in many cases not even be feasible to test all combinations. In practice we use our scientific understanding of how to match up the surfactant/co-surfactant/co-solvent characteristics with the oil characteristics, temperature, salinity, hardness and so forth. We have synthesized and tested new surfactants with much larger hydrophobes and more branching than previously available. We have tested new classes of co-solvents and co-surfactants with superior performance. These new developments have enabled us to develop good formulations for both oils that react with alkali to make soap and oils that do not. We have significantly lowered the chemical cost needed for waxy crudes with very high equivalent alkane carbon numbers. We have good results for oils with API gravities as low as 17, high temperature, high salinity, and high hardness brines. Many of these developments are synergistic and taken together represent a breakthrough in reducing the cost of chemical flooding and thus its commercial potential in both sandstone and carbonate reservoirs.
- North America > United States > Texas (0.46)
- North America > United States > Oklahoma (0.28)
- Geology > Mineral (0.69)
- Geology > Geological Subdiscipline (0.54)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.35)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)