bluuebunny/crossref_metadata_2025 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

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

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

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

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

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

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

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

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.
Mobility Of Microemulsions: A New Method to Improve Understanding and Performances of Surfactant EOR
Authors: Rousseau David , Le Gallo Clémence , Wartenberg Nicolas , Courtaud Tiphaine
Published: April 2022

The mobility of Winsor III microemulsions, which can form in reservoirs when a surfactant formulation contacts oil, has become a critical parameter for feasibility evaluations of surfactant flooding EOR. The reason is that these bicontinous phases with low mobility are likely to impair the sweep efficiency of the remobilized oil. The common procedures to evaluate microemulsion's mobility are based on viscosity measurements. As they involve rheometers, namely pure shear flows, and conditions where microemulsions are separated from the water and oil phases they should remain equilibrated with, they are not satisfactory. We present a new method to directly determine the mobility of microemulsions at equilibrium and in-situ, namely when flowing in porous media.

The method consists in preforming the Winsor III microemulsion in a buffer cell and then injecting it in a small sized core plug. The bicontinous phase stays at equilibrium because the oil and water phases, present in the buffer cell, remain in contact with it. The mobility is assessed through the resistance factor (or mobility reduction factor), relative to the water phase injected first. This observable accounts for both viscosity and potential permeability impairment effect. As it directly represents the reduction of the mobility of the water phase, it is representative of phenomena taking place in the reservoir. During a typical experiment, the same microemulsion is also injected in a capillary tube, in order to determine its viscosity in a pure shear flow.

Winsor III microemulsions were injected in sandstone plugs of three different permeabilities (1700 to 45 mD), and in a 170 mD carbonate plug. The first outcomes are that the resistance factors in the porous media and capillary relative viscosities have a marked shear-thinning behavior but are always of the same order of magnitude. This indicates that the flow of microemulsions entails no or little permeability impairment.

Based on the experimental determination of the porous media's shape factors, the resistance factors and capillary viscosity data were also plotted against the equivalent wall shear rate. For the highest permeability sandstone, the capillary and porous medium data scaled almost perfectly, showing that, in this case, the microemulsion's transport properties are that of an ideal non-Newtonian fluid. However, increasing deviations were observed when decreasing the sandstone permeability as well as for the carbonate porous medium. This suggests that microemulsions are strongly affected by the composite deformations taking place in complex microscopic pore structures.

These outcomes show the importance of determining the microemulsion-induced resistance factor in representative conditions in order to forecast for the impact of microemulsion's mobility in reservoirs. Furthermore, the method proposed can be applied to investigate close to optimum conditions as well as to study the propagation of microemulsions.
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

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

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.
Aquifer Influx Versus Water Injection in GoM
Authors: Fassihi Mohammad Reza , Blangy J. P.
Published: April 2022

When developing new deep-water fields in locations such as the Gulf of Mexico (GoM), understanding the aquifer's size and its connectivity are two important variables that dictate the presence or absence of any future water injection project. Because of the substantial scale of thelarge size of investment associated with developing fields in deep offshore environments, it is important to identify the key factorsdrivers drivingthat would help with decisions onaround optimizing the development optimization, and thus, preventing the operators from incurring unnecessary expenses. The first such factordriver is the assessment of the aquifer's potential size and connectivity of the aquifer. The second factordriver is the understanding of the aquifer's strength. TWe do not feel that this second parameter has not been sufficientadequately assessquantified in the literature, so we propose a new aAquifer iInflux iIndex (AII) in order to address this gapfor that purpose.

Prior to any petroleum field startup of any petroleum field, it is important to plan for waterflooding, especially if there is uncertainty around the aquifer's strength is uncertain. We use data from several GoM fields in GoM as examples, as well as their corresponding AII, so as to provide guidance on designing an effective conceptual water injection project prior to startup.
Evaluation of Environmentally Friendly Green Solvents for the Recovery of Heavy Oils
Authors: Mathews Tanya Ann , Cortes Jairo , Hascakir Berna
Published: April 2022

Solvent injection recovery processes were introduced as a more energy-efficient and environmentally friendly alternative to Steam injection processes. However, BTX chemicals (Benzene, Toluene, and Xylene), commonly used for crude oil recovery due to their strong solvency and low asphaltene precipitation, are acutely toxic and harmful to the environment. These chemicals are easily soluble in water causing groundwater contamination. This paper evaluates the recovery efficiency of two green solvents, Limonene, and beta-pinene, on two samples of Californian heavy oil (C1 has an 874.8 cP viscosity and C2 has 178500 cP viscosity).

On both C1 and C2, 5 core flood experiments were conducted, in total 10 experiments were run. CO2, limonene, and Beta-pinene were tested as solvents on both oils. Limonene and beta-pinene were both chosen due to their ready availability in the State of California. Both these solvents are plant-derived, non-toxic, and biodegradable. They also have much higher flash points than BTX solvents allowing for safer handling. They have been either injected as sole solvents or co-injected with CO2 during the experiments. Limonene and beta-pinene were injected at 2 mL/min while CO2 was injected at 2000 ml/min with a back pressure of 45-55 psi. Core packs were prepared by filling the pore space of Ottawa sand with 60% PV oil samples and 40% PV water by volume. Produced oil and water samples were collected every 20 min during the experiments. Thermogravimetric analyses (TGA/DSC) were conducted on these samples to identify oil, water, and solvent percentages.

Because CO2 is insoluble in these types of high viscosity crude oils, CO2 flooding resulted in immiscibility with almost no oil production. Since both limonene and beta-pinene are aromatic solvents, by sole limonene or beta-pinene injection miscible flooding was achieved. Limonene achieved 35 and 23 vol. % oil recovery from a total of 60% oil for C1 and C2 respectively while Pinene achieved 31 and 27 vol. %. Co-injections of green solvents with CO2 are expected to yield higher recovery due to the presence of two active drive mechanisms namely miscible and immiscible. Co-injection of limonene and CO2 provided the greatest recovery with 45 vol. %, however, recovery efficiencies of pinene and CO2 had comparable recoveries with that of pinene possibly due to phase trapping. Produced samples analysis showed that oil percentages in produced samples were higher for Limonene than Pinene.

Our results indicated that limonene and beta-pinene are very promising solvents for heavy oil recovery. Because these solvents are citrus-based, they are both easy to handle and non-toxic. Hence, we believe that our study can be a breakthrough for many heavy oil and bitumen reservoirs all around the world.
Optimizing Waterflooding EOR Through Cyclic Injection: A Case Study on the Hoople Field, Midland Basin, West Texas
Authors: Farias Mario Jose , Liu Xijin CJ
Published: April 2022

This paper presents a case study of implementation and results of cyclic injection EOR technique in Hoople field. It is located in Crosby and Lubbock Counties, west Texas and sits on the Eastern Shelf of the Midland Basin. The Hoople oil field, discovered in 1970's, is in its depletion stage with water cut greater than 95%. The reservoir rock consists of tidal flat dolomite and limestone interbedded with shale in Lower Permian Clear Fork Formation. Severe reservoir heterogeneity with low porosity and permeability are observed through core examination. This type of reservoir is suitable for cyclic injection.

Cyclic injection consists of two stages for water injection: pressurization (or injection) and depressurization (injection shut-in). Cyclic injection was initiated in part of the Hoople field in 2020. We selected two sections in the field for pilot testing and completed a full cycle in each section. After encouraging results, the cyclic injection technique was deployed over the whole field. The large-scale operation consists dividing the field in four sectors to maximize water handling and optimize cyclic injection operations.

Cyclic water injection has generated positive results. During depressurizing (or shut-in) half cycle, water production decreased dramatically with increasing oil-cut. Water production decreased 10% in each area while oil-cut improvement ranges from 13% to 33%. During the pressurizing (or injection) half cycle, oil production increases with total fluid production. The observed increase in total production ranges between 10% to 19%. The most significant finding is the consistent reservoir oil production and oil-cut response. Overall oil production has been kept at a stable level, countering the expected natural decline, suggesting that the cyclic injection led to enhanced oil recovery. Overall water production dropped significantly, reducing the cost associated with lifting from and injecting back to the reservoir. Cyclic injection has a very positive impact on the financial performance of the field development.

The cyclic injection methodology, an alternative EOR technique, can be applied to other mature fields with similar reservoir properties.
Nanoparticle Stabilized Strong Foam for EOR in High Salinity Fractured Carbonate Reservoirs
Authors: Xuezhen Wang , Kishore Mohanty K
Published: April 2022

Foam flooding can minimize bypassing in gas floods in fractured reservoirs. Finding a good foam formulation to apply in high salinity reservoirs is challenging, especially with divalent cations, e.g., API brine (8% NaCl with 2% CaCl2). When formulating with nanoparticles, the colloidal dispersion stability is difficult due to the dramatic reduction of the Debye length at high salinity. The aim of this work was to develop a strong foam in API brine, using nonionic surfactant (SF) and ethyl cellulose nanoparticles (ECNP), for gas flooding in fractured carbonate reservoirs. ECNP particles were synthesized and dispersed in API brine using a nonionic surfactant (SF). SF and SF/ECNP foams were created and their stability was studied at atmospheric pressure and 950 psi. Foam mobility was measured in a sand pack at the high pressure. Foam flood experiments were conducted in oil saturated fractured carbonate cores. The nonionic surfactant was proven to be a good dispersion agent for ECNP in API brine. Moreover, the SF-ECNP stabilized foam in API brine, even in the presence of oil. The foam was found to be shear-thinning during flow through sand packs. Core floods showed that SF/ECNP foam recovered 81.6% of the oil from the matrix, 13.8% more oil than the surfactant only foam, indicating the synergy between ECNP and surfactant. ECNP accumulates in the foam lamella and induces larger pressure gradients in the fracture to divert more gas into the matrix for oil displacement.
Discussion of the Effect of Shut-In After Fracturing on Oil Recovery
Authors: Sheng James J , Zeng Fanhua
Published: April 2022

Water is accumulated near the fracture surface after fracturing, which will block oil flow out. The water blockage can be mitigated through the immediate well flow back or through shutting in the well before flow back. Which method is more effective? There are mixed results in the literature from field reports and experimental or simulation studies.

This paper discussed the literature results and simulation data obtained from this study. It is found that the oil recovery mainly depends on the magnitude of pressure drawdown and the strength of imbibition. When the pressure drawdown is high, immediate flow back may lead to higher oil recovery than shutting in a well before flow back. When imbibition is strong, shutting in may be beneficial to enhance oil recovery through counter-current flow. Although many parameters of reservoir properties and operations may affect the shut-in effect, those parameters may be grouped into the pressure drawdown and imbibition strength. The parameters of matrix permeability, wettability, initial water saturation, and formation compressibility are discussed. Analysis and discussion of simulation data also suggest that the oil recovery is a linear function of pressure drawdown, but the relationship between oil recovery and capillary pressure is non-linear and more complex.

The results and discussion from this study suggest that the immediate flow back may outperform the shut-in if a large pressure drawdown is applied. If a reservoir provides a strong imbibition condition, the shut-in may be beneficial. Surfactants may be chosen to enhance imbibition. The surfactants which alter the reservoir from oil-wet to water-wet may be preferred.
Conformance Improvement in Fractured Tight Reservoirs Using a Mechanically Robust and Eco-Friendly Particle Gel PG
Authors: Wei Bing , Mao Runxue , Tian Qingtao , Xu Xingguang , Wang Lele , Tang Jinyu , Lu Jun
Published: April 2022

Conformance control in tight reservoirs remains challenging largely because of the drastic permeability contrast between fracture and matrix. Thus, reliable, durable and effective conformance improvement methods are urgently needed to increase the success of EOR plays in tight reservoirs. In this work, we rationally designed and prepared a mechanically robust and eco-friendly nanocellulose-engineered particle gel (referred to NPG) toward this application due to the superior stability. The impacts of superficial velocity, NPG concentration and particle/fracture ratio on the transport behavior in fracture were thoroughly investigated. We demonstrated that the mechanical properties of NPG such as strength, elasticity, toughness and tensile strain were substantially promoted as a result of the interpenetrated nanocellulose. During NPG passing through fracture model, it produced a noticeably greater flow resistance in comparison with the control sample (nanocellulose-free), suggesting the better capacity in improving the conformance of fractured core. It was found that the generated pressure drop (ΔP) was more dependent on the particle/fracture ratio and NPG concentration.
CCUS in China: Challenges and Opportunities
Authors: Guo Hu , Lyu Xiuqin , Meng En , Xu Yang , Zhang Menghao , Fu Hongtao , Zhang Yuxuan , Song Kaoping
Published: April 2022

CO2 emission was the major cause that accounted for the global warming and climate chance. How to reduce CO2 footprint to stop or slow down the global warming has been hot topic. As a developing country, China has become the largest CO2 emission nation in the world during the industrialization process to develop economy, although the CO2 emission intensity has been reduced significantly compared to previous stage. China has promised and succeeded to keep the promise reduce carbon intensity to meet the requirement of Paris Agreement. To meet the promise to attain carbon peak emission in 2030 and carbon neutrality in 2060 (CPCN), carbon capture, utilization and storage (CCUS) is an important and necessary step. Considering the high cost, high energy intensity and complex technology integrated optimization add uncertainties of CCS, utilization of captured CO2 can be of vital importance. One of the most attractive CCUS in China is CO2 enhanced oil recovery with captured CO2 (CCS EOR). CO2 EOR with captured CO2 may be one the best CCUS ways for China for the following three reasons. First, it can meet the increasing oil demand while reducing the carbon intensive coal. Second, around 66 CO2 EOR field tests have been conducted in China and experiences have ben gained. Finally, CO2 EOR in the USA was a proven technology which can increase oil production significantly and stably. Latest CCUS technology progress in China was reviewed. As of July 2021, 49 projects were carried out or under construction. Net CO2 avoided costs from 39 projects varied from 120 to 730 CNY/ ton CO2 (18.5-112.3 USD/ ton CO2). Although CCUS technology development in China was significant, the gap between global leading levels are obvious. Current challenges of CCS EOR include high CO2 capture cost, small scale, low incremental oil recovery, long-time huge capital input. The costs can be significantly reduced when the scale was enlarged to a commercial scale and transportation costs were further reduced by either pipelines or trains. CO2 transportation with well-distributed high-speed rail in China may be a feasible choice in future. If the CO2 EOR in China develops with the same speed as the USA, CO2 used for EOR in 2050 can be as high as 87.27 million tons. CO2 used for CO2 EOR in 2050 can account for 17% to 44% of the CO2 emission. CCS EOR in China will provid both domestic and international companies with good opportunities.
Full Cycle of Unconventional EOR with Microbial Technology – From Lab to Field
Authors: Lu Bo , Liu Songyuan , Li Yifan , Price Brian
Published: April 2022

Historical production data from unconventional oil wells show rapid decline, that leads to low ultimate recovery. With more and more production wells entering low rate period, it’s critical to conduct well stimulation to recover more from existing wells. Alternate application scenarios for production enhancement is during parent pressure up operations. Operators usually pump large volume water to parent well to prevent frac-hit while performing hydraulic fracturing. EOR application can be easily combined into this process to achieve multiple goal the same time.

Microbial EOR has been developed as an environmentally friendly EOR technology. The objective of this paper is to present the full cycle of a MEOR process, from microbiology theory, to prove concept though lab experiments, then to implementation in field. The lab laboratory experiments are to investigate the mechanism that the microbes can be stimulated and effective to clean up near wellbore fractures. The field trials are to demonstrate the effectiveness of MEOR to shale wells. Field results show that MEOR can be an economical effective approach to add reserves to shale wells at low cost. Additional value of microbial technology is that it doesn’t change oil and water quality in production, then there is no treatment cost as other stimulation methods.
Historical Window-Enhanced Transfer Gaussian Process for Production Optimization
Authors: Zhong Chao , Zhang Kai , Xue Xiaoming , Qi Ji , Zhang Liming , Yan Xia , Zhang Huaqing , Yang Yongfei
Published: April 2022

As a crucial step of reservoir management, production optimization aims to make the optimal scheme for maximal economic benefit measured by net present value (NPV) according to reservoir states. Despite the remarkable success, more advanced methods that can get higher NPV with less time consumed are still in urgent need. One main reason for limiting the optimization performance of existing methods is that historical data cannot be fully used. For a practical reservoir, production optimization is generally implemented in multiple stages, and substantial historical data are accumulated. These hard-won data obtained with lots of time encapsulate beneficial optimization experience and in-depth knowledge of the reservoir. However, when encountered with an unsolved optimization task in new stages, most methods discard these historical data, optimize from scratch, and gradually regain the knowledge of the reservoir with massive time for “trial and error” to find the right optimization direction, which is time-consuming and affects their practical application. Motivated by this, a novel method named historical window-enhanced transfer Gaussian process (HWTGP) for production optimization is proposed in this paper. Each optimization stage is regarded as a time window, and the data in historical windows are adopted as a part of training data to construct the transfer Gaussian process (TGP), which guides the whole optimization process. To solve the high-dimensional feature of practical problems, the prescreening framework based on a dimension-reduction method named Sammon mapping is introduced. The main innovation of HWTGP is that like experienced engineers, it can extract beneficial reservoir knowledge from historical data and transfer it to the target production-optimization problem, avoiding massive time for “trial and error” and getting superior performance. Besides, HWTGP has a self-adaptive mechanism to avoid harmful and ineffective experience transfer when tasks in historical and current windows are unrelated. To verify the effectiveness of HWTGP, two reservoir models are tested 10 times independently and results are compared with those obtained by differential evolution (DE) and a surrogate-based method. Experimental results show that HWTGP can achieve the optimal well controls that can get the highest NPV, and has significantly enhanced convergence speed with excellent stability, proving the effectiveness of transferring historical data.
Visceral Adiposity Index and Sex Differences in Relation to Peripheral artery disease in Normal-Weight Adults with Hypertension
Authors: Shi Yumeng , Yu Chao , Hu Lihua , Li Minghui , Zhou Wei , Wang Tao , Zhu Lingjuan , Bao Huihui , Li Ping , Cheng Xiaoshu
Published: April 2022

Background: Previous studies on the relationship between the visceral adiposity index (VAI) and peripheral arterial disease (PAD) are limited. Therefore, this study explored the relationship between VAI and PAD in normal-weight patients with hypertension.Methods: A total of 6,615 normal-weight patients with hypertension were included in the current study. The VAI, a simple index calculated using blood lipid and waist circumference (WC), can be used as a simple biomarker of body fat distribution. The outcome was PAD, which was defined as present when each side’s ankle-brachial index (ABI) was ≤ 0.90.Results: A significant positive association was observed between VAI and PAD prevalence. For per unit increment in LnVAI, the adjusted odds ratios (ORs) of PAD for the total participants and males were 1.55 (95% CI: 1.15–2.10) and 2.12 (95% CI: 1.46–3.07), respectively. However, the VAI was not associated with PAD in female patients with hypertension (OR, 1.28; 95% confidence interval [CI]: 0.85–1.95). There was no interaction between sex and VAI (P for interaction = 0.128). Accordingly, in total participants, when VAI was assessed in quartiles and compared with quartile 1 (< 0.84), the PAD prevalence was higher than that of quartiles 2 (0.84 to < 1.36: OR, 1.49; 95% CI, 0.92–2.44), 3 (1.36 to < 2.25: OR, 1.95; 95% CI, 1.14–3.32), and 4 (≥ 2.25: OR, 1.93; 95% CI, 1.04–3.57). There were no significant interactions with the other confounders.Conclusion: This study showed a positive association between VAI and PAD in normal-weight adults with hypertension among men but not among women.