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Collaborating Authors
Results
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...)
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)
Abstract In this paper, we evaluate the idea of adding nanoparticles (NPs) in fracturing water to enhance its wetting affinity to oil-wet pores and to mobilize part of the oil during the extended shut-in periods. We analyzed the performance of two different nanoparticle additives (NP1 and NP2) on core plugs collected from the Montney Formation. Additive 1 is a colloidal dispersion with highly surface-modified NPs and additive 2 is a micellar dispersion with highly surface-modified silicon dioxide NPs, solvents and surfactants. The proposed methodology consists of the following steps: 1) Characterizing wettability of the candidate rock samples under different conditions of brine salinity and NP concentrations through dynamic contact-angle measurements, 2) Evaluating NP-assisted imbibition oil recovery during the shut-in period by conducting systematic counter-current imbibition tests, and 3) Evaluating pore accessibility by comparing the mean size of the particles formed in the NP solutions measured by dynamic light scattering (DLS) method with pore-throat size distribution of the core plugs obtained from scanning electron microscopy (SEM) and mercury injection capillary pressure (MICP) analyses. The dynamic contact-angle results show that the core plugs are oil-wet in the presence of reservoir brine and fresh water as base fluids, and water-wet in the presence of the NP solutions. Consistently, the measured oil recovery factor (RF) by the NP solutions is 5% to 10% higher than that by the base fluids, which can be explained by the wettability alteration by NPs. Comparing the mean particle size of the NP solutions with the pore-throat size distribution of the plugs evaluates pore accessibility of core plugs. From MICP and SEM analyses, most pores of the rock samples have pore-throat radius in the range of 4 to 100 nm. The mean particle size of NP1 in low-salinity water is less than 30 nm while that of NP2 in low-salinity water is around 40 nm. The NPs can pass through most of the pore throats under low-salinity conditions. This is supported by fast and spontaneous imbibition of the NP solutions into the oil-saturated core plugs, compared with the base cases without the NPs solutions. When salinity increases, the particle size for NP solutions increases to more than 200 nm. Therefore, fewer pores may be accessed by NPs under high-salinity conditions if the NP solutions are not optimized for such conditions.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.84)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.47)
Abstract Pilot testing results and economics from a novel electrochemical desalination technology for enhanced oil recovery (EOR) produced water are presented. The pilot objectives were: (1) economically desalt produced water to improve hydrocarbon recovery and lower polymer consumption costs for chemical flood EOR; (2) inform full scale plant development with a field pilot; and (3) optimize pre-filtration, chemical consumption, and energy use to realize a greater than 20% return on investment through reduced polymer consumption. The paper will present EOR operators with a novel option to reuse produced water as low salinity injection water and recycle polymer to reduce chemical EOR flood operating costs.
- Asia > Middle East (0.93)
- North America > United States > California (0.28)
- Europe > United Kingdom > North Sea > Central North Sea (0.24)
- Water & Waste Management > Water Management (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
Abstract This paper presents numerical modeling of low tension surfactant gas based EOR method. In this process, slugs of various surfactant solutions and gas are alternated injected to mobilize remained oil left from water flood. The objective of this paper is to model the mechanisms behind the process by history matching the experimental data and simulation of a field-scale reservoir pilot. A four-phase chemical flooding reservoir simulator (UTCHEM) was used to history match a published core flood experiment and simulate a pilot-scale case. The results from the history match reveale that interfacial tension (IFT) reduction between oil and water by surfactant, displacement of oil by gas, and the mobility control of gas are the main mechanims lead to a substantioal increase in oil recovery. Based on these key findings, modeling of the low-tension surfactant-gas flood shows that such a process is very positive for low permeability reservoirs with a 90% oil recovery of the initial oil saturation (Sio=0.56) in a coreflood experiment and a range of recovery factors between 50% to 70% of the water flood in large scale cases.
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract Alkaline-Surfactant-Foam flooding is a novel enhanced oil recovery process which increases oil recovery over water flooding by combining lowering of the oil-water interfacial tension by two to three orders of magnitude and foaming. We report an experimental study of the formation of the oil bank and its displacement by foam drives of varying qualities. Experiments include: (a) bulk phase behaviour and foam testing studies using n-hexadecane and a single internal olefin sulfonate surfactant which was found to lower the oil-water interfacial tension by at least two orders of magnitude and (b) series of CT scanned core-floods using Bentheimer sandstone cores. A major goal of this study was to investigate the effect of drive foam quality on oil bank displacement. Core-flood results, performed at under-optimum salinity conditions yielding an oil-water interfacial tension in the order of 10 mN/m, showed similar ultimate oil recovery factors for the range of drive foam qualities studied. Although the total oil recovery is not affected by drive foam quality, results indicate a more frontal oil bank displacement at lower foam qualities. The findings in this study suggest that a) a lower drive foam quality favours oil bank displacement and b) the amount of clean oil produced by the oil bank is not effected by drive foam quality.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract Previously proposed models of wettability change have not been tied to the chemistry that controls wettability but instead were driven by simplistic criteria such as salinity level or concentration of an adsorbed species. Such models do not adequately predict the impact of brine compositional change and therefore cannot be used to optimize brine composition. In this work, after testing proposed models in the literature on sandstones and carbonates, we propose a mechanistic surface-complexation-based model that quantitatively describes observations for ionically treated waterfloods. To the best of our knowledge this is the first surface-complexation-based model that fully describes ionic compositional dependence observed in ionically treated waterfloods in both sandstones and carbonates. We model wettability change by directly linking wettability to brine chemistry using detailed colloidal science. Brine has charged ions that interact with polar acidic/basic components at the oil-water interface and rock surface and therefore oil/brine and rock/brine interfaces are charged and exert both Van der Waals and electrostatic forces on each other. If the net result of the forces is repulsive, the thin water film between the two interfaces is stable (i.e., the rock is water-wet) otherwise, the thin water film is unstable and the rock becomes oil-wet. Based on Hirasaki (1991), we describe a ratio of electrostatic force to Van der Waals force with a dimensionless group, called "stability number," where rock wettability is water-wet for values greater than one and oil-wet for values less than one. For sandstones, the zeta potentials of oil/brine and rock/brine interfaces become more negative/less positive by diluting or softening the brine and/or increasing pH. Similarly, for carbonates, dilution and/or sulfate enrichment of brine makes surface potentials more negative. Such brine modification can therefore be used to improve oil recovery. We implemented the improved wettability change model in a comprehensive coupled reservoir simulator, UTCOMP-IPhreeqc, in which oil/brine and rock/brine zeta potentials are modeled using the IPhreeqc surface complexation module. We take into the account total acid number (TAN) and total base number (TBN) for the oil/brine interface and we use rock surface reactions for brine/rock surface potential modeling. Surface potentials obtained from the geochemical model are used to calculate the dimensionless group controlling wettability change, which is dynamically modeled in the transport simulator. The model is validated in sandstones and carbonates by simulating an inter-well test, and several corefloods and imbibition tests reported in the literature. For sandstones, we model Kozaki (2012) and BP's Endicott trial. For simple dilution in carbonates we model experiments by Shehata et al. (2014) and Yousef et al. (2010). For enrichment with sulfate we model Zhang and Austad (2006) and for increasing total ionic strength via sodium chloride enrichment, Fathi et al. (2010a).
- Asia > Middle East (0.67)
- North America > United States > Texas (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
Novel Surfactants without Hydrocarbon Chains for Chemical EOR
Sharma, Himanshu (The University of Texas at Austin) | Panthi, Krishna (The University of Texas at Austin) | Ghosh, Pinaki (The University of Texas at Austin) | Weerasooriya, Upali (The University of Texas at Austin) | Mohanty, Kishore (The University of Texas at Austin)
Abstract Enhanced oil recovery (EOR) techniques involving surfactants such as surfactant floods, foam floods, and wettability alteration have been studied to recover remaining oil after primary and secondary floods. In these processes, a surfactant solution is injected to promote one (or more) of the following: lowering of capillary forces, improvement in sweep efficiency, and wettability alteration. Although significant advances have been made in designing surfactant molecules to achieve the above mentioned objectives efficiently, surfactant price is often the key limiting factor for a field-scale operation. Most surfactant molecules have a hydrocarbon chain (for example alkyl chain) or an aromatic ring as the main hydrophobe. The hydrocarbon chain (or ring) imparts hydrophobicity (and surface activity) to the surfactant molecule. However, these hydrophobes also result in additional cost. In this study, we discuss low-cost surfactants developed without hydrocarbon chains (or rings) for chemical EOR processes in general. The focus of this paper, however, is on their application in surfactant floods. These novel surfactants were developed by using methanol as the starting material, followed by the addition of propylene oxide (PO) and ethylene oxide (EO) groups, and an anionic head group. The surface tension and critical micelle concentration (CMC) values of these surfactants were measured. A screening study was performed to identify promising candidates; which showed ultralow interfacial tension (IFT) with various crude oils as well as aqueous stability at reservoir conditions. A comparison between novel surfactants with traditional surfactants was made based on the screening study. Oil recovery corefloods were performed in Berea and Boise sandstone cores to test the ultralow IFT formulations. These surfactants were found to have very low CMC values, and lowered the surface tension to about 32 dynes/cm. Their aqueous stability at a given temperature was found to be dependent on the number of PO and EO groups. Phase behavior experiments showed low IFT formulations with different crude oils by using these surfactants by themselves as well as in combination with internal olefin sulfonates (IOS). Moderate oil recoveries were obtained in coreflood experiments using these surfactants.
- North America > United States > Texas (0.28)
- North America > United States > Idaho > Ada County > Boise (0.25)
- Geology > Mineral (0.34)
- Geology > Geological Subdiscipline (0.30)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- 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)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Barmer Hill Formation (0.99)
General Overview This paper describes a new chemical EOR numerical model capable of simulating surfactant and polymer floods. We present the highlights of a highly efficient and robust IMPES implementation within a legacy, in-house gas-oil-water compositional simulator. The additional computational overhead, over say a waterflood calculation, is on the order of only 20% for large scale (type pattern model) simulations. We present performance results both in serial as well as parallel (multi-processor) mode. Flow within all three Winsor Type environments is modeled, with the ability to transition between the different types. The effects of a separate microemulsion (ME) phase are accounted for. Temperature effects on surfactant phase behavior as well as on adsorption are also considered. Other important physical effects that are modeled include phase trapping and oil bypassed by surfactant, near wellbore polymer injectivity and the reduction of surfactant adsorption associated with a sacrificial agent such as alkali. Gas phase is included in the model. The model has been extensively benchmarked against another reservoir simulator. We also present some validation results at the laboratory as well as at the field scale.
Abstract While synthetic polymer floods are being deployed in mild temperature and low salinity fields, many oilfields (harsh conditions) remain inaccessible due to performance limitations, and concentration requirements, which adversely affect project economics. Historically, biopolymers have been considered in such reservoirs, with mixed results. Xanthan was used in the 1980's, while more recently schizophyllan polymer was tested in a pilot study. This study presents scleroglucan polymers as a class of viscosifiers that demonstrate excellent performance in harsh temperature and salinity reservoirs. Scleroglucan polymers do not suffer from catastrophic drop in viscosity in the presence of high concentration of divalent ions. This makes produced water re-injection projects without water treatment a reality. This work demonstrates that cost-effective, high purity EOR grade Scleroglucan polymers, show excellent performance in lab trials as related to excellent rheological properties, injectivity, bio and thermal stability and with minimal shear degradation. Injectivity tests demonstrated good propagation through cores without blockage or injectivity issues. Resistance factors and residual resistance factors are in the desirable range. Core floods carried out in sandstone and carbonate outcrop cores demonstrated that adsorption values and oil recoveries are consistently in the expected range for polymer recoveries. Shear degradation studies showed that recycling scleroglucan through a centrifugal pump causes less than 5% drop in viscosity after 100 passes while synthetic polymer showed substantial loss after a single pass and a 50% drop after 10 passes through the same pump. Capillary shear testing (API RP 63 method) of scleroglucan shows little change in viscosity upon multiple passes through shear regimes greater than 150,000 s. Scleroglucan polymer solution showed less than 25% drop in viscosity after exposure to 115 °C for six months. No change in viscosity was observed at 95 °C after one year. Scleroglucan has no compatibility issues through 6 months (at 37, 85, and 95 °C) with glutaraldehyde and tributyl tetradecyl phosphonium chloride (TTPC) biocides. Long term biostability studies at various temperatures and salinities are ongoing - current data will be presented. Scleroglucan has excellent stability in the presence of hydrogen sulfide (H2S) and ferrous species (Fe) under fully aerobic conditions! This work provides insight on the potential of using EOR grade scleroglucan for CEOR in harsh condition reservoirs. Currently, the program is moving towards pilot implementation of a scleroglucan formulation to demonstrate large scale hydration, long term injectivity and oil recovery.
- Asia (0.68)
- North America > United States > Texas (0.47)
- North America > United States > California (0.46)
- Geology > Geological Subdiscipline (0.46)
- Geology > Rock Type > Sedimentary Rock (0.34)