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Results
Abstract As the unconventional shale development matures, the industry has been actively seeking new ways to unlock incremental value beyond primary depletion. In particular, the miscible gas injection EOR via huff-and-puff technique has garnered interest in recent years. However, the pilot tests in the field have shown lower recoveries than initially predicted by laboratory and simulation studies. The objective of this study was to develop a systematic approach to upscale the EOR results from laboratory scale to field scale and better predict recoveries. One of the issues with existing laboratory and modeling studies is the assumption of constant-pressure or constant-rate boundary conditions at the fracture interface during the soaking stage, which is rarely achieved. A mathematical model is developed to represent this scenario better by modeling mass diffusion of a limited volume of well-stirred fluid in a non-porous body (remaining injected gas in the fracture network at the end of injection phase as compressed gas) into a porous medium (matrix). The matrix is characterized as an ensemble of rock pillars separated by fracture discontinuities to represent field conditions better. The rock pillars are of different thicknesses, with their thickness gradually increasing, moving away from the main fracture cluster. And finally, the concept of Dynamic Penetration Volume, which controls the amount of contacted oil by the EOR agent, is explored further as a function of the micro-fracture distribution function. Ultimately, this information was used to derive an updated a priori equation to better predict recovery factors of EOR processes in the field. For upscaling, we integrated concepts from both geomechanics and fluid flow. We used an existing correlation relating the fracture frequency & distribution observed in the lab-scale experiments to the fracture density in the field. By doing so, we can upscale the micro-fracture distribution to their field-scale counterparts. Although diffusion is the main transport & recovery mechanism, this study found that the fracture geometry created near-wellbore, i.e., fracture spacing & distribution, has a first-order effect on the efficacy of the huff-and-puff process in the field. It was also observed that by varying the soaking times of each cycle, the issue of penetration length could be resolved (as it increases as a function of √time). Additionally, focusing on understanding the near-wellbore fracture geometry would help operators optimize their gas injection schemes. The updated upscaling equation will help understand the huff-and-puff process better and predict the expected recoveries in the field more accurately. Additionally, it would help operators adjust and optimize soaking times for the process using a mechanistic approach.
- North America > United States > Texas (1.00)
- North America > Canada (0.93)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.73)
- 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)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (4 more...)
Abstract During miscible gas injection for enhanced oil recovery, the composition of the fluids can change throughout the reservoir as the oil and gas phases develop miscibility. Measuring and modeling relative permeability as compositional regions are traversed creates many challenges. In simulators, the association of each phase with a relative permeability curve sometimes creates discontinuities when phases disappear across miscibility boundaries. Some newer relative permeability models attempt to resolve these issues by changing the standard "oil" and "gas" method of phase labeling and instead labeling phases according to a physical property that is continuous and tied to composition, most notably the fluid density or Gibbs free energy (GFE). Ideally, a relative permeability model will be based on experimental measurements. A handful of all relative permeability experiments focus on studying changes in relative permeability brought about by changes in fluid composition with increasing capillary number. However, there is also evidence to suggest that composition can impact relative permeability even at capillary numbers well below the capillary desaturation threshold. In this research, two-phase gas/oil core flood experiments were performed with ethane as the gas phase and equilibrated octane as the oil phase. Pressure was varied so that the composition (density and GFE) of the gas and oil were changing. The capillary numbers were kept low and constant to prevent capillary desaturation of the oil phase. The experiments were then repeated with an added residual brine phase to test the effect of composition with a third phase present. The results show that changing the density and GFE of the oil and gas phases in either two-phase or three-phase flow had no impact on the relative permeability curves. However, significant changes were observed when comparing two-phase to three-phase oil and gas relative permeabilities. When only gas and oil were flowing in the core, the oil phase formed a continuous layer on the pore surfaces. The addition of residual brine caused the oil to form droplets, reducing the relative permeability of both the oil and gas phases in the absence of a continuous layer of oil. These findings verify previous history-matched relative permeabilities in literature and show that the oil phase connectivity is more important than compositional parameters.
- Research Report > New Finding (0.67)
- Research Report > Experimental Study (0.48)
Fast Screening of LSW Brines Using QCM-D and Crude Oil-Brine Interface Analogs
Yutkin, M. P. (King Abdullah University of Science and Technology) | Kaprielova, K. M. (King Abdullah University of Science and Technology) | Kamireddy, S. (King Abdullah University of Science and Technology) | Gmira, A. (Saudi Aramco) | Ayirala, S. C. (Saudi Aramco) | Radke, C. J. (University of California – Berkeley) | Patzek, T. W. (KAUST)
Abstract This work focuses on a potentially economic incremental oil-recovery process, where a brine amended with inexpensive salts (in contrast to expensive surfactants and other chemicals) is injected into a reservoir to increase oil production. Historically, this process received the name of low salinity waterflooding (LSW) although the salinity is not always low(er). Nevertheless, we keep using this terminology for historical reasons. The idea of LSW has been known for three decades, but to the best of our knowledge no specific brine recipes that guarantee success have been presented so far. The reasons hide in the problem's complexity, disagreements in the scientific community, and a race to publish rather than to understand the fundamental principles behind the process. In this paper, we present an experimental model system that captures many of the important fundamental features of the natural process of crude oil attachment to mineral surfaces, but at the same time decomposes this complex process into simpler parts that can be more precisely controlled and understood. We systematically investigate the first-order chemical interactions contributing to the well-known strong attachment of crude oil to minerals using SiO2 as a mineral for its surface chemistry simplicity. Our preliminary results suggest that magnesium and sulfate ions are potent in detaching amino/ammonium-based linkages of crude oil with a SiO2 surface. However, when used together in the form of MgSO4, they lose part of their activity to the formation of a MgSO4 ion pairs. We also find that sulfate-detachment propensity stems not from the interaction with prototype mineral surface, but rather from the interactions with the crude oil-brine interface analog. We continue the systematic study of the ion effects on crude oil detachment, with and more results following in the future.
- Research Report > New Finding (0.66)
- Research Report > Experimental Study (0.48)
Abstract Many conventional surfactant-brine-oil phase behavior tests are conducted under ambient pressure conditions without the solution gas. It is known that the solution gas lowers the optimum salinity. Researchers often mix toluene (or cyclohexane) with the dead oil and form a surrogate oil to mimic the live oil. The objective of our work is to study the effect of gas and toluene on phase behavior, and to provide the proper amount of toluene to be mixed to mimic the live oil. Effects of toluene in surrogate oil and solution gas in live oil are examined by hydrophilic-lipophilic difference and net average curvature (HLD-NAC) structural model simulation and the equivalent alkane carbon number (EACN). Experimental values from literature and our experiments are also examined to compare those with the simulation results. For the simulation, both the mole fraction and mass fraction were used to calculate mixture EACN and examine the effect of additional components. HLD-NAC simulation results showed that the mass fraction-based simulation is more accurate (~7% error) than mole fraction-based simulation (~19% error) with a toluene EACN of 1. For larger molecules like toluene in surrogate oil, EACN using mole fraction also works with a toluene EACN of 5.2. The EACN of the surrogate oil should match the EACN of the live oil to determine the proper amount of toluene in the surrogate oil.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Polymer Injectivity Enhancement Using Chemical Stimulation: A Multi-Dimensional Study
Chandrasekhar, Sriram (Chevron Technical Center, a division of Chevron USA Inc.) | Alexis, Dennis Arun (Chevron Technical Center, a division of Chevron USA Inc.) | Jin, Julia (Chevron Technical Center, a division of Chevron USA Inc.) | Malik, Taimur (Chevron Technical Center, a division of Chevron USA Inc.) | Dwarakanath, Varadarajan (Chevron Technical Center, a division of Chevron USA Inc.)
Abstract Chevron injected emulsion polymer in the Captain field, offshore UK in the last decade at various scales (Poulsen et al., 2018). Pilot horizontal wells had exhibited faster than designed injectivity decline and Jackson et al. (2019) documented the causes to include oleic phase damage from a) injection of produced water containing crude oil after imperfect separation, and b) entrainment of injected emulsion polymer’s carrier oil. The wells were remediated with a surfactant stimulation package (Alexis et al., 2021; Dwarakanath et al., 2016). The remediation boosted the water relative permeability near wellbore which enhanced injectivity and allowed higher processing rates for subsequent continuous polymer injection. In this work, we conducted a set of core floods in slabs of surrogate rock of varying dimension and patterns to demonstrate the beneficial effect of near wellbore stimulation in the general case. 0.04 PV of the remediation package was injected and we show consistent injectivity enhancement across the experiments. We demonstrate the dominant effect of well skin treatment on the pressure drop profile compared to flow resistance from a) residual oil saturation and b) viscous fingering. The result is an important reminder for injectivity maintenance for high polymer flood processing rates for the life of the project. Clean injection fluids were demonstrated to maintain injectivity. We show applicability of stimulation for injectors into viscous oil reservoirs with adverse viscosity ratio. The robust nature of the remediation package developed by Alexis et al. (2021) is also shown, working to efficacy on viscous oil, as well as in situ phase separated polymer. We estimated skin and stimulation depth for a line drive case with low chemical dosage finding that 0.04 pore volumes of surfactant injection at 0.33 oil saturation units gave injectivity improvement of 31%. Surfactant stimulation is thus broadly applicable to wells with oleic phase skin.
Abstract Wettability alteration considered as the principal mechanism has attracted more attention for low salinity waterflooding effect. It was significantly affected by electrokinetic interactions, which occurred at the interfaces of rock/brine and crude oil/brine. The mineral impurities of natural carbonate releasing ions have an important impact on the electrokinetics, which could lead to wettability shift subsequently. In this study, the effect of dolomite and anhydrite as the main impurities in natural carbonate, which caused wettability alteration, was evaluated using triple-layer surface complexation and thermodynamic equilibrium models coupled with extended Derjaguin-Landau-Verwey-Overbeek (DLVO) theory. The electrokinetics of crude oil and carbonate in brines were predicted by the triple-layer surface complexation model (TLM) based on zeta potential, while thermodynamic equilibrium model was mainly used for analyzing the carbonate impurities on wettability alteration. The equilibrium constants of reactions were determined by successfully fitting the calculated zeta potentials with measured ones for crude oil and carbonate in different solutions, which were validated for zeta potential prediction in smartwater. The disjoining pressure results show that there is a repulsion between crude oil and carbonate in Na2SO4 brine (Brine3) or smartwater (Brine4) equilibrating with calcite when comparing to that in MgCl2 (Brine1) and CaCl2 (Brine2), indicating the water-wet condition caused by the presence of sulphate ions. Moreover, the equilibrium of carbonate impurities with smartwater increases the repulsion between oil and carbonate. When the sulphate ion concentration in the adjusted smartwater exceeds a certain value, the effect of carbonate impurities on wettability alteration is not significant. Finally, the influence of smartwater pH on the interaction between oil and carbonate was evaluated with or without considering the equilibrium of carbonate impurities.
- North America > United States (0.68)
- Europe (0.46)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Mineral > Sulfate (0.79)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.51)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
Impact of Brine Chemistry on Waterflood Oil Recovery: Experimental Evaluation and Recovery Mechanisms
Aminzadeh, Behdad (Chevron CTC) | Chandrasekhar, Sriram (Chevron CTC) | Srivastava, Mayank (Chevron CTC) | Tang, Tom (Chevron CTC) | Inouye, Art (Chevron CTC) | Villegas, Mauricio (Chevron GOM) | Valjak, Monika (Chevron GOM) | Dwarakanath, Varadarajan (Chevron CTC)
Abstract Water floods are typically conducted using the least expensive, easily available, non-damaging brine. Very little attention is given to the possibility of changing brine composition to improve oil recovery. Over the last 20 years, there has been laboratory and field trial evidence that shows changing brine chemistry, especially to low salinity, can sometimes increase the recovery. The various mechanisms of additional oil recovery from changing brine chemistry are not entirely clear. We report here on the effect of using low salinity and divalent altered brines on oil recovery through a variety of laboratory methods and materials. More than twenty corefloods were conducted to evaluate the effect of brine chemistry and initial wettability on incremental oil recovery. We also performed phase behavior tests, contact angle measurements, and wettability index measurements to evaluate recovery mechanisms. Initial wettability of the core was altered by ageing it with different crude oil containing wide range of asphaltene content. The core flood with lowest wettability index (least water-wet) produced about 12% incremental recovery while the most water-wet core only produced ∼ 4% during the secondary low salinity waterflood.
- Asia (0.93)
- North America > United States > Texas (0.47)
- North America > United States > Alaska > North Slope Basin > Duck Island Field > Endicott Field > Kekiktuk Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Berea Sandstone Formation (0.98)
- North America > United States > Pennsylvania > Appalachian Basin > Berea Sandstone Formation (0.98)
- (2 more...)
Abstract Polyacrylamide-based friction reducer is commonly used in well completion for unconventional reservoirs. However, residual polymer trapped in the near well-bore region could create unintended flow restrictions and could negatively impact oil production. An eco-friendly approach to regain conductivity was developed by stimulating indigenous bacteria for residual polymer biodegradation. In this work, a series of laboratory experiments were conducted using produced water and oil from Permian Basin, polyacrylamide-based polymer, and a modified nutrient recipe that contained 100 to 300 ppm of inorganic salts. The sealed sample vials containing water, oil, and polymer were prepared in a sterilized anaerobic chamber and then kept in a 160° F incubator to simulate the reservoir condition. Feasibility tests of bacteria growth and biodegradation evaluation of polymer were conducted using an optical laser microscopic system with bacteria tagged with fluorescent dye. Size regression was calculated and applied to a mathematical model based on actual fracture aperture distribution data from shale formation. The indigenous bacteria were successfully stimulated with and without the existence of the friction reducer. It was observed that the size of polymer particles decreased from over 300 µm to less than 20 µm after 15 days. Under the condition of produced water injection, 140° F reservoir temperature, and anaerobic environment, about 30% of the natural fractures in shale were calculated to be damaged and remediated within 15 days. This work is a pioneer research on microbial EOR application in unconventional reservoirs with only indigenous bacteria involved. In field applications, only an extremely low amount of nutrient is required in this process which provides great economic potential. Additionally, the nutrients introduced into the reservoirs will be fully consumed by bacteria during treatment, and the bacteria will be decomposed into organic molecules soon after the treatment. Thus, this technique is environmental- and economical- friendly for the purpose of polymer damage remediation to maximize the recoverable.
- North America > United States > Texas (0.25)
- North America > United States > New Mexico (0.25)
- 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)
- (21 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (0.96)
- Health, Safety, Environment & Sustainability > Environment > Remediation and land reclamation (0.89)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (0.75)
- (2 more...)
Abstract Most chemical EOR formulations are surfactant mixtures, but these mixtures are usually modeled as a single pseudo-component in reservoir simulators. However, the composition of an injected surfactant mixture changes as it flows through a reservoir. For example, as the mixture is diluted, the CMC changes, which changes both the adsorption of each surfactant component and the microemulsion phase behavior. Modeling the physical chemistry of surfactant mixtures in a reservoir simulator was found to be more significant than anticipated and is needed to make accurate reservoir-scale predictions of both chemical floods and the use of surfactants to stimulate shale wells.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)
- Geology > Mineral (0.46)
- Reservoir Description and Dynamics > Reservoir Simulation (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)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Improved Oil Recovery Techniques and Their Role in Energy Efficiency and Reducing CO2 Footprint of Oil Production
Farajzadeh, R. (Shell Global Solutions International, Delft University of Technology) | Glasbergen, G. (Shell Global Solutions International) | Karpan, V. (Shell Development Oman) | Mjeni, R. (Petroleum Development Oman) | Boersma, D. (Shell Global Solutions International) | Eftekhari, A. A. (Technical University of Denmark) | Casquera García, A. (Delft University of Technology) | Bruining, J. (Delft University of Technology)
Abstract The energy intensity (and potentially CO2 intensity) of the production of hydrocarbons increases with the lifetime of the oil fields. This is related to the large volumes of gas and water that need to be handled for producing the oil. There are two potential methods to reduce CO2 emissions from the aging fields: (1) use a low-carbon energy source and/or (2) reduce the volumes of the non-hydrocarbon produced/injected fluids. The first solution requires detailed analysis considering the availability of the infrastructure and carbon tax/credit economics and is largely influenced by the cost of the CO2 capture technologies and renewable power. The second solution utilizes improved/enhanced oil recovery methods (I/EOR) aimed at injecting materials to increase the fraction of oil in the producers. In this paper, we use the production data from a field in the Middle East and show the high-level economics associated with switching the field operating energy demand to solar energy. We begin the analysis by first investigating the energy requirement of different stages in the life cycle of oil production and quantifying the CO2 emission and energy loss that can be avoided in each stage. We also utilize the concept of exergy to identify process steps that require lower energy quality and thus are the main targets for optimization. The analysis indicates that preventing CO2 emission is economically more attractive than utilizing mitigation methods, i.e., to capture the emitted CO2 and store it at later stages. Moreover, we show quantitatively how I/EOR techniques can be designed to reduce the CO2 intensity (kgCO2/bbl oil) of oil production. The energy efficiency of any oil production system depends on the injectant utilization factor, i.e., the volume of produced oil per mass or volume of the injectant.
- Asia > Middle East (0.49)
- North America > United States (0.46)
- Europe > United Kingdom (0.46)