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Collaborating Authors
Improved and Enhanced Recovery
Abstract Polymer flood improves the sweep efficiency of viscous oil recovery over water flood. The low-tension polymer (LTP) flood has the potential to improve the displacement efficiency due to low interfacial tension without sacrificing sweep efficiency. The objective of this research is to evaluate the performance of LTP floods as a function of IFT for a viscous oil in a 2D sand pack. Over 20 non-ionic surfactants/co-solvents were tested. A series of sandpack flooding experiments were conducted in a custom-designed 2D visualization cell. The results show that short-hydrophobic surfactants 2EH-xPO-yEO can reduce the IFT to as low as 0.05 dynes/cm. Flooding experiments were performed in sandpacks with and without connate water saturation. For the experiments with connate water saturation, the sandpack was water-wet/intermediate-wet. A base-case polymer flood (without any surfactant) with a viscosity ratio of 10 showed a stable displacement and 82% OOIP oil recovery at the first pore volume injected (PVI).LTP flood with an IFT of 0.1 dynes/cm also showed stable displacement front, but ahigher oil recovery at 1 PVI (90% OOIP).Further reduction in IFT to 0.05 dynes/cm resulted in an unstable displacement and a lower recovery of 65% OOIP. For the experiments without connate water saturation, sandpack was oil-wet, the base-case polymer flood at a viscosity ratio of 10 showed severe fingering and a low oil recovery at 1 PVI (58% OOIP). Adding the nonionic surfactants did not improve displacement efficiency nor oil recovery in oil-wet sandpacks.
- North America > Canada > Alberta (0.46)
- North America > United States > Texas (0.28)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline (0.66)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Mooney Field > Bluesky Formation (0.99)
- North America > Canada > Alberta > Flood Field > Adamant Masters Flood 6-6-85-24 Well (0.99)
A New Logistically Simple Solution for Implementing ASP/ACP in Difficult Environments – Evaluation of Concept with High TAN Viscous Crude Oil
Southwick, Jeffrey George (JSouth Energy LLC) | Upamali, Karasinghe Nadeeka (Ultimate EOR Services, LLC) | Fazelalavi, Mina (Ultimate EOR Services, LLC) | Weerasooriya, Upali Peter (Ultimate EOR Services, LLC) | Britton, Chris James (Ultimate EOR Services, LLC) | Dean, Robert Matthew (Ultimate EOR Services, LLC)
Abstract Research on alkali assisted chemical EOR technology with high TAN crude oils have led to developments with liquid organic alkalis and co-solvents (Southwick J., et al., 2020) (Fortenberry, et al., 2015) (Schumi, et al., 2019) (Upamali, et al., 2018). Both concepts afford potential significant cost reduction in field operations but to date it has not been demonstrated that these two concepts can work together. Monoethanolamine (MEA) alkali and a wide variety of liquid co-solvents are evaluated with high TAN (total acid number) crude oil. Formulations are found that give ultra-low interfacial tension (IFT) at a specified injection salinity. Fine tuning the formulation to different injection salinities can be done by choosing alternate co-solvents (or a co-solvent blend). A formulation comprising 1% MEA and a novel high molecular weight (3,152 g/gmol) co-solvent, 0.5% Glycerin alkoxylate with 30 moles propylene-oxide and 35 moles ethylene-oxide (Glycerin-30PO-35EO), gave ultra-low IFT in 21,000 TDS injection brine and gave 100% oil recovery in Bentheimer sandstone with 3500 ppm FP 3630 as mobility control agent. All oil was produced clean, no separation of emulsion was needed to measure oil recovery. Alkali consumption tests were also performedwith a high permeability reservoir sandstone. Results confirmed earlier data published with Boise outcrop sandstone (Southwick J., et al., 2020) showing low alkali consumption with MEA. On a mass basis, only 12% of the amount of MEA is consumed relative to sodium carbonate. This reduces the logistical challenges of shipping chemicals to remote locations. MEA is also a low viscosity liquid which further simplifies field handling.
- Asia (1.00)
- North America > United States > Idaho > Ada County > Boise (0.25)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Central Basin > Salymskoye Field > Zapadno Salymskoye Field (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (0.95)
Novel Application of Polyethylene Oxide Polymer for EOR from Oil-Wet Carbonates
Trine, Eric Brandon (Ultimate EOR Services, LLC) | Pope, Gary Arnold (Ultimate EOR Services, LLC) | Britton, Chris James (Ultimate EOR Services, LLC) | Dean, Robert Matthew (Ultimate EOR Services, LLC) | Driver, Jonathan William (Ultimate EOR Services, LLC)
Abstract The objective of this study was to test the performance of high-molecular weight polyethylene oxide (PEO) polymer in a low-permeability, oil-wet carbonate reservoir rock. Conventional HPAM polymers of similar molecular weight did not exhibit acceptable transport in the same rock, so PEO was explored as an alternative polymer. Viscosity, pressure drop across each section of the core, oil recovery, and polymer retention were measured. The PEO polymer showed good transport in the 23 mD reservoir carbonate core and reduced the residual saturation from 0.29 to 0.17. The reduction of residual oil saturation after polymer flooding using PEO was unexpected and potentially significant.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.88)
- 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)
Improved Amott Cell Procedure for Predictive Modeling of Oil Recovery Dynamics from Mixed-Wet Carbonates
Kaprielova, Ksenia (King Abdullah University of Science and Technology) | Yutkin, Maxim (King Abdullah University of Science and Technology) | Gmira, Ahmed (Saudi Aramco) | Ayirala, Subhash (Saudi Aramco) | Radke, Clayton (University of California, Berkeley) | Patzek, Tadeusz W. (King Abdullah University of Science and Technology)
Abstract Spontaneous counter-current imbibition in Amott cell experiments is a convenient laboratory method of studying oil recovery from oil-saturated rock samples in secondary or tertiary oil recovery by waterflood of adjustable composition. Classical Amott cell experiment estimates ultimate oil recovery. It is not designed, however, for studying the dynamics of oil recovery. In this work we identify a flaw in the classical Amott cell imbibition experiments that hinders the development of predictive recovery models for mixed-wet carbonates. We revise the standard Amott procedure in order to produce smoother experimental production curves, which then can be described by a mathematical model more accurately. We apply Generalized Extreme Value distribution to model the cumulative oil production. We start with the Amott imbibition experiments and scaling analysis for Indiana limestone core plugs saturated with mineral oil. The knowledge gained from this study will allow us to develop a predictive model of water-oil displacement for reservoir carbonate rock and crude oil recovery systems.
- North America > United States > California (0.28)
- Asia > Middle East > Saudi Arabia (0.28)
- North America > United States > Indiana (0.25)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.94)
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 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)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
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 The goal of this work is to develop alkaline-surfactant-polymer (ASP) formulations for a shallow, clayey sandstone reservoir. Commercially available surfactants were used in the phase behavior study. The gas-oil-ratio (GOR) was low; the phase behavior and coreflood study was conducted with the dead oil. The surfactant formulation systems were tested in tertiary ASP core floods in reservoir rocks. Many surfactant formulations were identified which gave ultralow IFT, but the formulation with only one surfactant (at 0.5 wt% concentration) in presence of one co-solvent was selected for corefloods. The cumulative oil recovery was in the range of 94-96% original oil in place (OOIP) in the corefloods. The surfactant retention was low (0.15 mg/gm of rock) in spite of the high clay content. The study showed that 0.5 PV of ASP slug and 2700 ppm of the polymer were required to make the flood effective. The use of alkali and preflush of the soft brine helped minimize surfactant retention.
- Asia > Middle East (1.00)
- Asia > China > Heilongjiang Province (0.28)
- North America > United States > Missouri (0.28)
- Geology > Mineral (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.55)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff D Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff C Formation (0.99)
- (6 more...)
Re-Injection of Produced Polymer in EOR Projects to Improve Economics and Reduce Carbon Footprint
Ghosh, Pinaki (SNF Holding Company) | Wilton, Ryan R (SNF Holding Company) | Bowers, Annalise (SNF Holding Company) | O’Brien, Thomas (SNF Holding Company) | Cao, Yu (SNF Holding Company) | Wilson, Clayton (SNF Holding Company) | Metidji, Mahmoud Ould (SNF SA) | Dupuis, Guillaume (SNF SA) | Ravikiran, Ravi (SNF Holding Company)
Abstract Chemical Enhanced Oil Recovery (cEOR) flooding is one of the more attractive methods to improve oil recovery. However, during times of instability in the oil market, cost of specialized chemicals and necessary facilities for alkali-surfactant-polymer (ASP) or surfactant-polymer (SP) make this technology very expensive and challenging to implement in the field. In majority of cases, polymer flooding alone has proven to be the most cost-effective solution that has resulted in attractive and predictable return on investment. In recent times, challenging economic environment has operators looking for added economic and sustainable savings. The possibility of re-injection of produced polymer to offset injection concentration requirements can lead to reduced cost and longer sustainability of oil recovery; thus, offering a subsequent reduction in produced water treatment and a reduced full-cycle carbon footprint. This innovative approach is subject to conditions experienced in the surface facilities, as well as in the reservoir. As part of this study, different polymer chemistries were investigated for their mobility control in porous media and comparative effect on oil recovery trends in presence of produced fluid containing residual polymer. The initial fluid-fluid testing and lab characterization results were validated against a mature field EOR project for reduction in polymer requirement to achieve target viscosity. Monophasic flow behavior experiments were performed in Bentheimer and Berea outcrop cores, while oil recovery experiments were performed in Bentheimer outcrops with different polymer solutions – freshly made and combinations with residual produced polymer. In addition, comparative injectivity experiments with field and lab prepared solutions were performed in Bentheimer outcrop cores. Based on field observations and lab measurements, a 10-15% reduction in fresh polymer loading could be achieved through the re-utilization of water containing residual polymer in these specific field conditions. Similar screen factor measurements were obtained with increasing concentration of residual polymer solution. This agreed with the monophasic injectivity experiments in both outcrop cores that resulted in similar resistance factors for fresh polymer and blends with produced water containing residual polymer solution. Oil recovery experiments also resulted in similar oil displacement behavior (approximately 30-40% OOIP after 0.5 PV waterflood) for fresh and blends with sheared polymer solutions, validating no loss in recovery potential, with the added benefit of 10-15% polymer loading reduction.
- North America > United States (1.00)
- Asia (1.00)
- North America > Canada (0.93)
- Europe (0.68)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.47)
- Geology > Rock Type (0.46)
- Water & Waste Management > Water Management > Lifecycle > Treatment (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Lloydminster Field (0.99)
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- Europe > Netherlands > North Sea > Dutch Sector > P09C License > Horizon Field > Vlieland Sandstone Formation (0.98)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Reaction Kinetics Determined from Core Flooding and Steady State Principles for Stevns Klint and Kansas Chalk Injected with MgCl2 Brine at Reservoir Temperature
Andersen, Pål Østebø (Department of Energy Resources, University of Stavanger, 4021 Norway) | Korsnes, Reidar Inge (Department of Energy and Petroleum Engineering, University of Stavanger, 4021 Norway) | Olsen, Andre Tvedt (Department of Energy Resources, University of Stavanger, 4021 Norway) | Bukkholm, Erik (Department of Energy Resources, University of Stavanger, 4021 Norway)
Abstract A methodology is presented for determining reaction kinetics from core flooding: A core is flooded with reactive brine at different compositions with injection rates varied systematically. Each combination is performed until steady state, when effluent concentrations no longer change significantly with time. Lower injection rate gives the brine more time to react. We also propose shut-in tests where brine reacts statically with the core a defined period and then is flushed out. The residence time and produced brine composition is compared with the flooding experiments. This design allows characterization of the reaction kinetics from a single core. Efficient modeling and matching of the experiments can be performed as the steady state data are directly comparable to equilibrating the injected brine gradually with time and does not require spatial and temporal modeling of the entire dynamic experiments. Each steady state data point represents different information that helps constrain parameter selection. The reaction kinetics can predict equilibrium states and time needed to reach equilibrium. Accounting for dispersion increases the complexity by needing to find a spatial distribution of coupled solutions and is recommended as a second step when a first estimate of the kinetics has been obtained. It is still much more efficient than simulating the full dynamic experiment. Experiments were performed injecting 0.0445 and 0.219 mol/L MgCl2 into Stevns Klint chalk from Denmark, and Kansas chalk from USA. The reaction kinetics of chalk are important as oil-bearing chalk reservoirs are chemically sensitive to injected seawater. The reactions can alter wettability and weaken rock strength which has implications for reservoir compaction, oil recovery and reservoir management. The temperature was 100 and 130°C (North Sea reservoir temperature). The rates during flooding were varied from 0.25 to 16 PV/d while shut-in tests provided equivalent rates down to 1/28 PV/d. The results showed that Ca ions were produced and Mg ions retained (associated with calcite dissolution and magnesite precipitation, respectively). This occurred in a substitution-like manner, where the gain of Ca was similar to the loss of Mg. A simple reaction kinetic model based on this substitution with three independent tuning parameters (rate coefficient, reaction order and equilibrium constant) was implemented together with advection to analytically calculate steady state effluent concentrations when injected composition, injection rate and reaction kinetic parameters were stated. By tuning reaction kinetic parameters, the experimental steady state data could be fitted efficiently. From data trends, the parameters were determined relatively accurate for each core. The roles of reaction parameters, pore velocity and dispersion were illustrated with sensitivity analyses. The steady state method allows computationally efficient matching even with complex reaction kinetics. Using a comprehensive geochemical description in the software PHREEQC, the kinetics of calcite and magnesite mineral reactions were determined by matching the steady state concentration changes as function of (residence) time. The simulator predicted close to identical production of Ca as loss of Mg. The geochemical software predicted much higher calcite solubility in MgCl2 than observed at 100 and 130°C for Stevns Klint and Kansas.
- Europe (1.00)
- North America > United States > Kansas (0.91)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Mineral > Carbonate Mineral > Calcite (0.66)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.34)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Nebraska > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Kansas > Laramie Basin > Niobrara Formation (0.99)
- (7 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Integration of geomechanics in models (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- (2 more...)