bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Unconventional Approach to Model a Polymer Flood in the Kalamkas Oilfield
Authors: Sagyndikov Marat , Seright Randall , Tuyakov Nauryzbek 
Published: April 2022

Abstract
This article describes the main features of an unconventional approach to model a polymer flood in the Kalamkas oilfield. This non-standard simulation method is based on specially performed inter-well tracer tests, step-rate tests, pressure fall-off tests, dedicated field studies, well monitoring, and lab analysis. Our approach excludes permeability reduction as a mechanism to provide more mobility reduction than expected from rheology measurements (resistance factor) and by improving the recovery during post-polymer water flooding (residual resistance factor). Evidence is presented to support this exclusion for real field applications. Additionally, our approach places a significant emphasis on history matching bottomhole pressures. Our effort accounts well for the decreased mobility of the injected polymer solution and increased rock permeability during a polymer flood. In contrast to most other simulation approaches to polymer flooding, our method incorporates open fractures during polymer injection and their impact on injectivity and sweep efficiency. A literature review (lab tests and field cases) and our laboratory and field studies confirm the validity of our approach and its advantages over other modern simulator modeling of polymer flooding. From viscosity measurements of back-produced polymer solutions from injectors and well tests (inter-well tracer tests, pressure fall-off tests, step rate tests), we proved that polymer flooding induces fractures or fracture-like features and consequently, the polymer solution flows through the fracture with increased injectivity proportional to a resistance factor. Also, incorporated are expectations during a brine post-flush and the absence of the residual resistance factor (i.e., equal to 1). Implementation of these concepts brings our model closer to reality for simulating polymer floods.
Modelling the Impact of Surface Charge on Wettability Alteration in Low Salinity Waterflooding
Authors: Elakneswaran Yogarajah 
Published: April 2022

Abstract
The wettability alteration is the most prominent mechanism for a favorable effect of low salinity water flooding in enhanced oil recovery. It has been accepted that the surface charge at crude oil/brine and rock/brine interfaces significantly influences the interaction of the crude oil with rock surface and thus wettability changes. In this study, the interface characteristics were coupled with a solute transport model to simulate low salinity waterflooding in carbonate and sandstone reservoirs. The ionic transport and two- phase flow of oil and water equations were solved and coupled with IPhreeqc for geochemical calculations. The dissolution and precipitation of minerals were considered thorough thermodynamic equilibrium reactions in IPhreeqc. In addition, a triple layer surface complexation model was employed in IPhreeqc to predict electrokinetic properties of crude oil/brine and rock/brine interfaces. The wettability alteration was calculated based the adsorbed polar components of crude oil on minerals’ surface, which changes the relative permeability. The coupled model able to predict the spatiotemporal variation of ionic profiles, surface and zeta potentials, dissolution and precipitation of minerals, total disjoining pressure, and wettability index in addition to oil recovery for the injection of brines. The validity of the coupled model results was tested against PHREEQC in a single-phase flow without the presence of oil. Moreover, the modelling results were compared with the published experimental data for a single-phase flow in carbonate cores. A very good agreement between experimental data and modelling results was obtained. Furthermore, the coupled model was applied to predict ionic concentration, pH profile, and oil recovery in both carbonate and sandstone cores and verified with experimental data. The modelling results reproduce well the experimental data, suggesting that model captures the geochemical and interface reactions. Finally, the coupled model can be used to optimize brine composition for improved oil recovery in carbonate and sandstone reservoirs.
A Comparative Study of the Impact of the CO2 Properties on the Thermal Output of a Geothermal Well
Authors: Ratnakar Ram , Dindoruk Birol , Livescu Silviu , Gautam Sandarbh 
Published: April 2022

Abstract
The problem of growing carbon footprint calls for the exploitation of cleaner and sustainable energy resources. Geothermal energy is clean, renewable, and in abundant supply underneath the surface of the earth, which makes it one of the most optimum solutions to this problem. With the depletion of hydrocarbon resources, geothermal energy also helps to close the gap between demand and supply of cleaner energy resources reliably, although several problems need to be solved before producing geothermal energy globally. In this study, an effort is made to understand and improve the reservoir heat extraction through a geothermal well.
There are approximately 3 million abandoned wells within the U.S. and this number will only increase in the future. Producing electricity from these abandoned hydrocarbon wells, as the source of geothermal energy, have intrinsic importance in the context of extending the life of the well in the context of energy production and as well as generation of future options for new wells. Whether the costs are sunken or not (for the existing wells), incremental costs for the new potential wells can be minimum to redesign them to fit for future geothermal energy production. Not only the design/retrofitting the wells, but also the selection of right power fluid is crucial to effectively produce the geothermal energy. Using CO2 as the power fluid to generate electricity from low temperature abandoned hydrocarbon wells while sequestering it will help in reducing the well costs to a minimum as well as optimizing the energy production to lower temperature thresholds.
In this paper, a previously developed coupled well-reservoir model (Livescu and Dindoruk, 2022a, for fixed reservoir delivery as successions of steady state) is extended to study the effects of the fluid properties on the thermal output. Specifically, the previous model considered fluids with constant properties. Several correlations and look-up tables are used in this study for pressure- and temperature-dependent fluid properties (i.e., density and viscosity) to explicitly quantify their effect on the thermal balance of the geothermal system. These results are important for understanding the effects of the fluid PVT properties on the physics and economics of the entire geothermal project.
This study is important for the design of closed-loop systems and can be extended to enhanced geothermal systems. For a given reservoir intake conditions, it can also be used to perform economic evaluation for abandoned oil and gas wells to assess their feasibility for geothermal energy production while reducing the overall CO2 footprint. In particular, the novelty and importance lie in
Impact of choice of fluid/fluid PVT properties on the physics and economics of the entire geothermal project. Parametric study of using CO2 as the power fluid to generate electricity from relatively lower temperature abandoned hydrocarbon wells and variants in terms of P&T ranges.
Water Alternating Alkane Injection: A Molecular Dynamics Simulation Study
Authors: Coskuner Yakup Berk , Dean Elio , Yin Xiaolong , Ozkan Erdal 
Published: April 2022

Abstract
In a recent study, we observed that the diffusion coefficient of common hydrocarbons in crude oils are more affected by the presence of different hydrocarbon components than the effect of confinement. Based on our previous observations, in this study, we investigated the efficiency of smaller-chain alkane injection into oil-soaked sandstone pores to dilute the oil with alkane. We used molecular dynamics simulations of C2, C3, C4 and C5 as well as a mixture of C3 and C4 to rank the effects of different alkanes on the diffusion and distribution of oil molecules in pore. As water-alternating-alkane injection would bring water into the pores, our simulations included water. Our results indicate that alkane injection into sandstone reservoirs has a significant potential due to the fact that it effectively dilutes the oil. Water always wets quartz surface relative to the oils. Injection of water therefore should be effective in detaching oil molecules on the surface. Presence of water layers did not affect the diffusion coefficients of oil molecules.
Lab and Pilot-Scale Evaluation of Stable Foam for Drilling in High Temperature Environment
Authors: Griffith Christopher , Linnemeyer Harry , Kim Do Hoon , Hahn Ruth , Zhou Jimin , Upchurch Eric , Malik Taimur , Wileman Angel , Beck Griffin , Bhagwat Swanand , Gutierrez Luis 
Published: April 2022

Abstract
Using foams to drill in low pore pressure reservoirs is attractive because of their low density, high viscosity, and ability to transport cuttings. However, in high temperature reservoirs (240 °F) with H2S gas present, there are concerns with the long-term stability of a foam drilling fluid. In this work, we highlight a lab program to develop a stable drilling foam for drilling in a low pore pressure, high temperature reservoir. The work also includes pilot-scale experiments to evaluate foam performance.
Aqueous nitrogen-in-water foams were stabilized with a preferred foaming surfactant formulation, and the rheology and stability of the foams were measured at representative drilling conditions (temperature and pressure) at the lab and pilot-scale. The foams were also evaluated for their compatibility with current drilling fluids used on site and for stability in the presence of H2S gas (at 1900 psi and 140 °F). The drilling foam was also evaluated using a pilot-scale flow loop comprised of a rheology flow loop and a model drilling wellbore. The experiments included measuring the foam rheology, foam stability in the model wellbore, and gas migration tests to understand how the foam suppresses upwardly migrating gas bubbles.
We successfully developed a surfactant stabilized foam designed for a high-temperature reservoir with H2S gas present. We found that H2S can negatively impact foam stability if proper surfactants are not selected. Our foam showed less than 10% liquid drainage after 12 hours at 240 °F and showed no significant degradation upon contact with 17 mol% H2S gas. Additionally, the foam was compatible with all drilling fluids (both water-based and oil-based) currently used at the drill site and demonstrated good stability in a model pilot-scale drilling wellbore. Interestingly, when the wellbore was angled at 30 degrees from vertical with the eccentric drill pipe rotating at 100 RPM, the foams were susceptible to degradation compared to an equivalent scenario of a vertical wellbore with concentric rotating drill pipe. The gas migration tests at the pilot-scale showed the foam was capable of significantly slowing down an upwardly moving gas bubble with and without pipe rotation.
Enabling Increased Oil Recovery from Deep-Water Viscous Oil Reservoirs by Improved Performance Prediction of Multiphase Viscous Pumps
Authors: De Raeve Karel , Gaillard Xavier , Bibet Pierre-Jean 
Published: April 2022

Summary
Typical seawater depths for deep-water oil fields range from 1000m to 4000m. For these deep-water oil fields, the most popular and cost-effective technologies for increased oil recovery are water injection and subsea boosting with a multiphase helico-axial pump on the seabed. By installing a pump on the seabed, the well head pressure and thus the bottom hole pressure can be reduced, which will result in an increased well lifetime and thus an increased oil recovery. This contributes to a reduction in CAPEX per produced barrel and hence make the field development economically more interesting.
Viscous multiphase production fluids occur in case of a viscous oil or in case of water-oil emulsions with a high apparent viscosity close to the inversion point. It is known that for viscous fluids the required power and size of the pump are significantly larger than for water-like products, such as low viscous oils. On top of this, due to the poor accuracy of the existing performance prediction models available in literature for viscous conditions, the pumps and the corresponding utility systems have to be significantly over-dimensioned to compensate for the uncertainties. This has a large negative impact on the CAPEX requirements for such field developments up to the point that it becomes economically unattractive to develop the field.
For this reason, TotalEnergies (Operator), Sulzer (OEM) and TechnipFMC (EPC contractor) have launched real-size pump test campaigns in 2012 and 2014 with viscosities up to 3,000 cP in hot fluid and 10,000 cP in cold start-up conditions.
The data obtained from those measurement campaigns have been used to develop a performance prediction model, which allows for accurate sizing of the pumps and corresponding topside utility system.
This model allows for a reduction of the uncertainties and risks related to subsea boosting for viscous deep-water field developments and related to this the overall CAPEX requirements. This enables subsea boosting as a viable solution for increased oil recovery for deep-water fields with viscous multiphase fluids.
This paper presents the test campaign and acquired measurement data. It explains how the effect of viscosity is modeled. It illustrates the match between the pump performance prediction model and the viscous multiphase test data. This allows for a reduction of the uncertainties and thus a more accurate pump selection.
Bioremediation by Indigenous Microbes: A Green Approach to Degrade Polymer Residue
Authors: Liu Songyuan , Lu Bo , Sie Chao-yu , Li Yifan 
Published: April 2022

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.
Impact of Brine Chemistry on Waterflood Oil Recovery: Experimental Evaluation and Recovery Mechanisms
Authors: Aminzadeh Behdad , Chandrasekhar Sriram , Srivastava Mayank , Tang Tom , Inouye Art , Villegas Mauricio , Valjak Monika , Dwarakanath Varadarajan 
Published: April 2022

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.
Energy Efficient Steam-Based Hybrid Technologies: Modeling Approach of Laboratory Experiments
Authors: Pérez Romel Antonio , García Hugo Alejandro , Gutiérrez Dubert , Rodríguez Hector Arnoldo , Mehta Sudarshan , Moore Robert Gordon , Ursenbach Matthew , Sequera-Dalton Belenitza , Manrique Eduardo Jose 
Published: April 2022

Abstract
Colombia is evaluating different steam-based hybrid oil recovery technologies as a strategy to face current challenges in the development of heavy oil reservoirs. Oil price volatility, the need for an energy transition, and carbon footprint reduction are factors limiting the commercial deployment of conventional steam injection projects. Ecopetrol evaluates the hybrid steam methods at laboratory scale as one of the different options to overcome current constraints developing heavy oil resources. The ongoing experimental program is supported by numerical modeling as a prior step to upscale the results at the pilot-scale.
This study aims to present history match results and describe the numerical modeling approach of hybrid steam experiments (50 mm diameter × 1.1 m long assembly) and compare it against the baseline steam injection simulation. The first hybrid test involved the injection of steam and flue gas considering consecutive floods that included a saturated steam flood (SSF), a flue gas slug injection, and a second saturated steam flood. The second test was a steam and solvent injection following the same experimental protocol (SSF + solvent + SSF).
The variables matched included produced fluids, pressures, produced gas compositions, and temperature profiles. One important feature is that all three models use the same set of water-oil relative permeability curves obtained from an independent experiment. Also, it was assumed those curves are not a function of temperature, which simplifies the modeling and allows focusing on the physical mechanisms relevant to each experiment. For instance, for the hybrid steam-flue gas test, it was necessary to include an additional set of gas-oil relative permeability curves to account for the presence of the flue gas in the gas phase. The hybrid steam-solvent test was focused on modeling the mixing of the native oil with the injected solvent. The proposed workflow led to a good history match of all variables, particularly total produced fluids, temperature profiles, and injection pressures. Additional recommendations are provided based on laboratory observations to understand important mechanisms such as trapped gas, relative permeability hysteresis, and solvent characteristics.
A new methodology to simulate hybrid steam methods is provided. The proposed numerical approach incorporates novel energy efficiency and carbon intensity indexes to guide the decision-making and identify recovery strategies driven by its efficiency and reduce carbon footprint. Both hybrid tests led to energy efficiency improvements and reduction in carbon intensity up to 20%. These indexes combined with experimental results will be key input parameters for designing and commissioning future pilot tests using numerical simulations at the field scale.
Comprehensive Evaluation of a Novel Recrosslinkable Hyper Branched Preformed Particle Gels for the Conformance Control of High Temperature Reservoirs
Authors: Song Tao , Ahdaya Mohamed , Zhao Shuda , Zhao Yang , Schuman Thomas , Bai Baojun 
Published: April 2022

Abstract
The existence of high conductivity features such as fractures, karst zones, and void space conduits can severely restrict the sweep efficiency of water or polymer flooding. Preformed particle gel (PPG), as a cost-effective technology, has been applied to control excessive water production. However, conventional PPG has limited plugging efficiency in high-temperature reservoirs with large fractures or void space conduits. After water breakthrough, gel particles can easily be washed out from the fractures due to the lack of particle-particle association and particle-rock adhesion. This paper presents a comprehensive laboratory evaluation of a novel water-swellable high-temperature resistant hyper-branched re-crosslinkable preformed particle gel (HT-BRPPG) designed for North Sea high-temperature reservoirs (130 °C), which can re-crosslink to form a rubber-like bulk gel to plug such high conductivity features. This paper systematically evaluated the swelling kinetics, long-term thermal stability and plugging performance of the HT-BRPPG. Bottle tests were employed to test the swelling kinetic and re-crosslinking behavior. High-pressure resistant glass tubes were used to test the long-term thermal stability of the HT-BRPPG at different temperatures, and the testing lasted for over one year. The plugging efficiency was evaluated by using a fractured model. Results showed that this novel HT-BRPPG could re-crosslink and form a rubber-like bulky gel with temperature ranges from 80 to 130 °C. The elastic modulus of the re-crosslinked gel can reach up to 830 Pa with a swelling ratio of 10. In addition, the HT-BRPPG with a swelling ratio of 10 has been stable for over 15 months at 130 °C so far. The core flooding test proved that the HT-BRPPG could efficiently plug the open fractures, and the breakthrough pressure is 387.9 psi/ft. Therefore, this novel BRPPG could provide a solution to improve the conformance of high-temperature reservoirs with large fractures or void space conduits.