bluuebunny/crossref_metadata_2025_split huggingface dataset:
Slickwater Friction Reducer Performance Evaluation and Application
Authors: Matovic Gojko , Theriot Timothy , Linnemeyer Harold , Solano Marlon , Fuller Michael , Han Seung , Kim Amos , Nizamidin Nabijan , Kim Do Hoon , Malik Taimur , Dwarakanath Varadarajan 
Published: April 2022

Abstract
Friction reducers (FRs) are a vital component of slickwater fracturing fluids used in hydraulic fracturing operations. FRs, which are typically made up of high molecular weight polyacrylamide-based polymers, help decrease frictional pressure losses and improve the effectiveness of fracturing operations by allowing for higher fracturing (frac) injection rates at the same or lower surface pressures. By optimizing FR selection for field application, cost savings can be realized through reduction in chemical costs, reduction in equipment maintenance frequency, and rental savings. Furthermore, operations could be modified to use more produced water.
Evaluating FR performance in the laboratory typically consists of running flow-loop experiments to measure pressure reduction in tubing or pipe over time. However, there is no industry-standard method for evaluating FR performance and different labs have developed their unique protocols and loop designs. To mitigate this deficiency, the project team designed and installed a FR evaluation flow loop and developed a protocol that effectively evaluates FR performance. The team compared performance of various FRs from selected FR suppliers focusing on three attributes: hydration time, maximum pressure reduction, and sustainability of pressure reduction over time. For a given test water, all candidate FRs were tested in the same conditions to allow direct comparison of FR performance. This work showed that pipe size, Reynolds number, and shear rate all affect friction reduction performance; but if testing is done under the same conditions, performance can be compared and ranked directly.
Based on comprehensive testing to identify the best performing FRs for brackish, produced, and mixed water blends, a field test with the recommended candidates was conducted in support of a frac-chemical unbundling effort. FRs used in the field test were qualified using the in-house FR evaluation flow loop. Friction reducer performance in the field trial confirmed the FR lab evaluation protocol correctly ranks FR performance and enables scaling to field operation. There were no accepted methods to scale-up lab FR performance to predict field conditions and as accurate models continue to be developed, the main method for evaluating FR performance continues to rely on qualifying FRs based on lab-scale experiments. To bridge the gap, the project team developed an empirically based tool to improve FR selection using a comprehensive test matrix considering FR dosage, water salinity and water hardness. Development of this tool used constant test conditions so that consistent recommendations can be made.
Modeling of Chemical Tracers to Estimate Oil Volume Contacted and Sweep Efficiency in Porous Media Under Countercurrent Spontaneous Imbibition
Authors: Velasco-Lozano Moises , Balhoff Matthew Thomas 
Published: April 2022

Abstract
Modeling of chemical tracers is an important technique to estimate oil saturation in porous media. Although numerous models exist to analyze the flow of tracers in systems under dynamic conditions, modeling in capillarity-dominated systems has not been sufficiently examined. In tight porous media and the matrix of fractured reservoirs, spontaneous imbibition (SI) represents a key driving mechanism for fluid infiltration because the low permeability in these systems results in a negligible transport by advection. We present a new semi-analytical solution for the flow of tracers under countercurrent SI valid during the infinite-acting and boundary-dominated flow regimes.
The model presented is derived from the analysis of fluid imbibition driven by capillarity and numerically solved as a function of water distribution and initial tracer concentration. We model ideal and partitioning tracers to investigate the average oil saturation in the contacted region by tracer and sweep efficiency of countercurrent SI as a recovery mechanism in porous media. To verify the applicability of our solution, we compared it against numerical simulation cases under flow conditions with diverse solute and phase properties. The concentration profiles exhibit a significant delay in displacement behind the imbibition front when hydrodynamic dispersion is ignored and for high partitioning coefficients, demonstrating the importance of determining these properties before conducting a field test. The solution presented is the first to examine countercurrent SI for the modeling of oil volume contacted by tracers in porous media. We consider the model can be extended for the analysis of the flow of tracers in systems such as fractured reservoirs to estimate oil saturation in the matrix medium, and those using chemical solutions that promote SI by altering wettability and capillary pressure.
Oil and Gas Relative Permeability as a Function of Fluid Composition
Authors: Churchwell Lauren , DiCarlo David 
Published: April 2022

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.
Fast Screening of LSW Brines Using QCM-D and Crude Oil-Brine Interface Analogs
Authors: Yutkin M. P. , Kaprielova K. M. , Kamireddy S. , Gmira A. , Ayirala S. C. , Radke C. J. , Patzek T. W. 
Published: April 2022

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.
Comprehensive Fluid Compositional Analysis Program to Support the Interpretation of Chichimene Field In-Situ Combustion Pilot
Authors: Manrique Eduardo Jose , Trujillo Marta Liliana , Lizcano Juan Carlos , Cardenas Diego Alejandro , Vanegas Jose Walter , Portillo Fredy De Jesus , Salazar Helmut , Caicedo Nicolas 
Published: April 2022

Abstract
The evaluation of EOR methods in Colombia has been very active during the past decade. One of the most recent and promising pilots is the In-Situ Combustion (ISC) in Chichimene Field, starting in September 2019. Based on international ISC field experiences, this pilot represents a unique case study given the depth (≈8,000 ft.) of this heavy crude oil (9°API) reservoir.
The pilot project consists of one injector, seven producers, and two temperature observation wells between the injector and first-line wells. Production response shows encouraging results. Its interpretation is supported by a comprehensive fluid compositional analysis, which is the main objective of this paper.
This paper describes the compositional analysis of produced fluids (gas, oil, and water) and the influence of the current flow assurance program. Geochemical simulations support the evaluation of scaling tendencies, and possible corrosion trends are based on iron and manganese concentrations following the National Association of Corrosion Engineers (NACE) standards. Crude oil analysis is based on conventional techniques (i.e., acid number, distillation curves, etc.) and biomarkers to infer possible thermal maturation changes in the produced oil.
Results confirm predicted cycles of CO2 and H2S during the planning of the monitoring program. The solubility of both gases in water leads to its acidification and the formation of carbonate and sulfate scales characterized in production wells. The precipitation of solids was also influenced by the N2-based H2S scavenger decomposition downhole due to water pH increment observed with the dosage increases. The scaling tendencies did not impact the productivity due to the high reservoir permeability. The precipitation of iron species difficulted NACE standards interpretation to infer corrosion except for wells shut-in for more than two months showing a higher concentration of Fe and Mn. However, a recent casing inspection job at one of the first-line producers shows no corrosion signs. The analysis of heavy metals such as nickel and vanadium in water was also used to infer possible corrosion or thermal cracking of porphyrins present in the crude oil. Changes in the paraffinic fractions and biomarkers (i.e., methyl phenanthrene index, mono- and tri- aromatic steroids) also suggest increasing the thermal maturity of the produced oil. The robust monitoring program has provided important insights from the ISC process and flow assurance strategy supporting possible expansion plans.
This study provides valuable guidelines for monitoring programs based on compositional analysis of produced fluids, including the influence of production chemistry. Lessons learned through the Chichimene ISC monitoring program can be valuable in interpreting thermal and potentially non-thermal EOR projects.
Experimental and Simulation Based Interpretation of Characteristic Behavior During Forced and Spontaneous Imbibition in Strongly Water-Wet Sandstones
Authors: Andersen Pål Østebø , Salomonsen Liva , Sleveland Dagfinn 
Published: April 2022

Abstract
In this work we investigate forced and spontaneous imbibition of water to displace oil from strongly water-wet Gray Berea (~130 mD) and Bentheimer (~1900 mD) sandstone core plugs. Two nonpolar, nonvolatile oils (n-heptane and Marcol-82) and their mixtures were used as non-wetting phase, giving oil viscosities between 0.4 and 31 cP between experiments. Brine (1 M NaCl) was used as wetting phase with viscosity 1.1 cP. Recovery was measured for both imbibition modes, and pressure drop was also measured during forced imbibition. Forced imbibition (five tests) was conducted with same viscosities at low and high injection rate using two different viscosities. 17 spontaneous imbibition experiments were performed at four different oil viscosities, and on the two rock types, including tests at same conditions. By varying the oil viscosity, injection rate and imbibition modes we measured the system's response to displacing oil by water under different conditions where both capillary and advective forces were allowed to dominate. Our hypothesis is that such a combination of experiments allows us to determine some characteristics of water-wet systems.
Transient analytical solutions were derived accounting for low water mobility and inlet end effects, allowing theoretical predictions consistent with the observations. Full numerical simulations were also run to consistently match all the experimental observations. We find that, consistent with the literature, water has low mobility associated with its relative permeability. Thus, complete oil recovery was achieved at water breakthrough during the forced imbibition both at low and high oil viscosity tests. For the same reason, increasing oil viscosity by a factor of almost 100 did not increase the spontaneous imbibition time scale by more than 5 compared to the lowest oil viscosity. This was consistently matched by our models. Theoretical analysis indicates that pressure drop increases linearly with time until water breakthrough if capillary pressure is negligible and that the initial pressure drop correspond to the oil relative permeability end point. Positive capillary forces assist water in entering the core, and the pressure drop is reduced and possibly nonlinear with time. Using a high injection rate we could a linear trend more clear than at low rate, consistent with our predictions.
Experimental Investigation of Transient Foam Flow in a Long Heterogeneous Consolidated Sandstone
Authors: Almajid Muhammad Majid , Kovscek Anthony R. 
Published: April 2022

Abstract
Transient N2-foam flow experiments were conducted in a heterogeneous sandstone core to improve our understanding of how foam flows in these complex systems. An apparatus with an aluminum core holder and a medical x-ray CT scanner was built to measure the aqueous-phase saturation nondestructively. Pressure readings along the length of the core, were recorded using six pressure taps drilled into the core. We coinjected the foamer solution and the gas at the core's inlet and allowed foam generation to occur inside the core. Measurements of the aqueous-phase saturation and of the pressure at various times enabled us to track and analyze the transient foam behavior in the core. Three foam qualities were tested ranging from low quality (gas fractional flow) of 33% to high quality of 90%. Results show that gas initially drains the core and forms weak foam before crossing a permeability discontinuity present in the core. The travel distance from the inlet until the point of entrance into the permeability discontinuity was inversely proportional to the water content of the foam. Wetter foams required a shorter distance before the gas entered the low-permeability layer. Crossing the permeability discontinuity, the weak foam became stronger as evidenced by the drop in aqueous-phase saturation and the increase in the pressure gradient. Once strong foam was generated, it traveled to the outlet in a piston-like fashion. After it breaks through the outlet, a second front appears to be traveling backward toward the inlet against the direction of flow. Diversion to lower-permeability layers occurs during this second front movement. This observation was validated qualitatively by a simple pore network model that is equipped with the invasion percolation with memory algorithm. The results of the network show the diversion occurring once strong foam generates in the high-permeability zone and explain the discontinuous aqueous-phase saturation observed during the first foam front movement.
New Paradigm in the Understanding of In Situ Combustion: The Nature of the Fuel and the Important Role of Vapor Phase Combustion
Authors: Gutiérrez Dubert , Mallory Don , Moore Gord , Mehta Raj , Ursenbach Matt , Bernal Andrea 
Published: April 2022

Abstract
Historically, the air injection literature has stated that the main fuel for the in situ combustion (ISC) process is the carbon-rich, solid-like residue resulting from distillation, oxidation, and thermal cracking of the residual oil near the combustion front, commonly referred to as "coke". At first glance, that assumption may appear sound, since many combustion tube tests reveal a "coke bank" at the point of termination of the combustion front. However, when one examines both the laboratory results from tests conducted on various oils at reservoir conditions, and historical field data from different sources, the conclusion may be different than what has been assumed. For instance, combustion tube tests performed on light oils rarely display any significant sign of coke deposition, which would make them poor candidates for air injection; nevertheless, they have been some of the most successful ISC projects.
It is proposed that the main fuel consumed by the ISC process may not be the solid-like residue, but light hydrocarbon fractions that experience combustion reactions in the gas phase. This vapor fuel forms as a result of oxidative and thermal cracking of the original and oxidized oil fractions. An analysis of different oxidation experiments performed on oil samples ranging from 6.5 to 38.8°API, at reservoir pressures, indicates that this behavior is consistent across this wide density spectrum, even in the absence of coke. While coke will form as a result of the low temperature oxidation of heavy oil fractions, and while thermal cracking of those fractions on the pathway to coke may produce vapor components which may themselves burn, the coke itself is not likely the main fuel for the process, particularly for lighter oils.
This paper presents a new theory regarding the nature and formation of the main fuel utilized by the ISC process. It discusses the fundamental concepts associated with the proposed theory, and it summarizes the experimental laboratory evidence and the field evidence which support the concept. This new theory does still share much common ground with the current understanding of the ISC process, but with a twist. The new insights result from the analysis of laboratory tests performed on lighter oils at reservoir pressures; data which was not available at the time that the original ISC concepts were developed.
This material suggests a complete change to one of the most important paradigms related to the ISC process, which is the nature and source of the fuel. This affects the way we understand the process, but provides a unified and consistent theory, which is important for the modelling efforts and overall development of a technology that has the potential to unlock many reserves from conventional and unconventional reservoirs.
Improved Oil Recovery Techniques and Their Role in Energy Efficiency and Reducing CO2 Footprint of Oil Production
Authors: Farajzadeh R. , Glasbergen G. , Karpan V. , Mjeni R. , Boersma D. , Eftekhari A. A. , Casquera García A. , Bruining J. 
Published: April 2022

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.
Fundamental Improvements in Modeling Surfactant Behavior in Reservoir Simulators
Authors: Chang Leonard Yujya , Li Zhitao , Luo Haishan , Pope Gary Arnold 
Published: April 2022

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.