Petroleum Engineering Research Articles

2024 SPE Pioneers of Improved Oil Recovery

Reservoirs present plenty of complexity and mystery. Four oil recovery experts have helped remove some of those mysteries, taming the complex to boost production. From developing preformed particle gels that improve conformance when fractures cause severe channeling to simulating enhanced oil recovery (EOR) processes in the reservoir to identifying the aqueous stability concept to demonstrating the distance polymer solutions can travel without degradation, the four 2024 recipients of the 2024 Improved Oil Recovery (IOR) Pioneer Award have made a “sustained and important contribution to increased oil recovery,” Randy Seright, New Mexico Tech, 2024 Pioneer selection committee chairman and 2008 honoree, told JPT. Seright, four other previous recipients of the recognition, and 2024 SPE IOR Conference General Chairman Tom McCoy evaluated a field of 16 nominees for the lifetime achievement honor and selected four who have throughout their careers “made the most lasting and significant contributions to IOR,” Seright said. “It’s why we are where we are today with respect to IOR.” The 2024 IOR Pioneer recipients who were honored during the biannual IOR conference in Tulsa in April are Baojun Bai, professor of petroleum engineering, who sits in the Lester Birbeck Endowed Chair at Missouri University of Science and Technology (Missouri S&T) in Rolla, Missouri; Mojdeh Delshad, research professor in the Hildebrand Department of Petroleum and Geosystems Engineering at The University of Texas at Austin (UT-Austin); Varadarajan Dwarakanath, team lead for chemical EOR at the Chevron Technology Center in Houston; and Stephane Jouenne, who previously led a TotalEnergies team dedicated to surface and subsurface research topics for polymer flooding and is currently CO2 capture project coordinator at TotalEnergies. “It’s the most prestigious award given out in IOR,” Seright said.

Experimental Study of the Rising Behavior of a Single Bubble in Shearshinning Fluids

Background: Non-Newtonian gas-liquid two-phase flows are often seen in industrial processes such as petroleum, chemical, and food engineering. The efficiency of mass and heat transfer between phases is significantly impacted by bubble rise motion in liquids. Therefore, it is crucial to deeply study the hydrodynamic characteristics of a bubble rising in non-Newtonian fluids to improve the transfer efficiency between phases and to enhance the operational efficiency of bubbling equipment. Methods: To understand the rising characteristics of a bubble in non-Newtonian fluids, a single bubble rising in shear-thinning fluids was experimentally studied using a high-speed camera. The effects of xanthan gum (XG) concentration and bubble diameter on bubble shape, trajectory, and terminal velocity were investigated. Results: Bubble terminal velocity increased with an increase in the bubble diameter and a decrease in XG concentrations. The increase rate of bubble terminal velocity varied with an increase in bubble diameter for the bubbles with different diameters and XG concentrations for the solutions with varying XG concentrations. For solutions with the same XG concentration, the Galilei and Eötvös numbers for a small bubble were relatively small but relatively large for a large bubble. Thus, the rise motion of a bubble in XG solutions becomes unsteady with an increase in bubble diameter and a decrease in XG concentrations. The unsteady characteristics of bubble motion decrease with an increase in the XG concentration of solutions. Conclusion: It was found that the influence of XG concentrations on bubble motion depends on bubble diameter since the magnitude of bubble diameter has an essential effect on the shear-thinning effect of solutions. An increase in bubble terminal velocity is mainly caused by an increase in buoyancy (i.e., bubble diameter) rather than a decrease in the apparent viscosity of solutions.

Study Examines Limitations of CCS and Their Effect on Oil and Gas Production

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214950, “Limitations and Fallacies of Carbon Capture and Storage and Impact on Oil and Gas Production,” by S.M. Farouq Ali, SPE, and Mohamed Y. Soliman, SPE, University of Houston. The paper has not been peer reviewed. _ In the complete paper, the authors write that, while carbon capture and storage (CCS) initiatives are affecting oil and gas operations profoundly, such efforts have had little perceptible effect on atmospheric CO2, which continues to increase. The paper aims to show that current CCS regimens have serious technical and fiscal constraints and questionable validity, stating that, globally, CCS has not increased beyond approximately 0.1% of global CO2 emissions in the past 20 years. The paper offers partial solutions and concludes that, while oil and gas will continue to be important energy sources beyond the foreseeable future, oil companies will accomplish the needed CCS. Introduction The authors write that, while CCS efforts have been pursued for 4 decades, little has been achieved. For the past 20 years, the percentage of CO2 captured and stored is less than 0.1% of the CO2 emitted worldwide, if one considers CO2 enhanced oil recovery (EOR) projects to be CSS—which, the authors write, is a fallacy. They emphasize that CCS means injection with no production. The key to CCS success, they write, is major governmental subsidization, by whatever terminology it is known, and that means taxpayer money. Sweeping decisions that have a profound effect on oil and gas production and petroleum engineering education are being made based on predictions of an increase in CO2 concentration in the atmosphere in various time frames. Magnitude of the Problem The problem of world CO2 emissions capture is gigantic. To appreciate the magnitude of the problem, imagine that 1 year’s CO2 emissions (40 billion tonnes) are captured, compressed and liquified, and injected into a reservoir the size of the Ghawar oil field, the largest reservoir in the world, with the entire pore space (approximately 0.5 Tcf) available for storage. In this hypothetical, nine such reservoirs would be required every year. Presumably, such storage space can be found, but collecting the CO2 and bringing it to a storage site is a highly complex task. For example, in a sequestration effort in a building complex in New York, the CO2 is separated, liquified, and trucked to a storage site to be injected underground, which is impractical. Often, the example of the Nordic countries (mainly Denmark, Sweden, and Norway) is cited as evidence of successful emissions reduction. But the total population of these countries is approximately the same as that of metropolitan Mumbai in India. Definitions Carbon capture use and storage (CCUS) implies that the CO2 produced by various processes is captured and used for EOR. This accounts for approximately 30% of the 230 mtpa of CO2 captured globally. CCS means that any CO2 produced by the process is captured and injected into a suitable geological formation for storage for thousands of years. Net-zero emissions (NZE) implies that all the CO2 produced is captured and stored. In Canada, “absolute zero emissions” is discussed, meaning that no CO2 is produced in the first place, pointing to total fossil-fuel phaseout.

Physics-Informed Machine Learning Applied to Complex Compositional Model in a Giant Field

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23730,“Physics-Informed Machine-Learning Application to Complex Compositional Model in a Giant Field,” by Guido Bascialla, SPE, ADNOC, and Coriolan Rat and Soham Sheth, SLB, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. _ Compositional reservoir simulation is a time-intensive activity demanding complex physics. In the complete paper, the authors review the advantages of machine learning (ML) in complex compositional reservoir simulations to determine fluid properties such as critical temperature and saturation pressure. An ML approach to predict critical temperatures during simulation based on the Heidemann-Khalil method is implemented, resulting in more-accurate results with lower computational cost, outperforming the standard method and improving performance on a giant field model with compositional gradient and miscible gas injection. Field Description The case study refers to a giant offshore carbonate field composed of multiple reservoirs. Production is currently in a rampup phase; crestal miscible hydrocarbon gas injection was implemented soon after startup. The availability of high-potential gas producers as a source of makeup gas and the placement of peripheral water injectors maintains the reservoir pressure above minimum miscibility pressure. All reservoirs show complex variable slope compositional gradients along thick oil columns of hundreds of feet (Fig. 1). To match the fluid behavior and the variation of fluid properties with depth, the equation of state needs at least nine components. The rock quality mainly is controlled by diagenesis. Thirteen rock types were modeled. The permeability can change up to four log cycles for the same porosity. Most of the reservoirs are highly heterogeneous, with features such as high-permeability streaks and baffle zones. A wide range of capillary pressure curves is present; these mainly depend on permeability and lithology. Most development wells were completed with inflow control devices (ICDs) to control gas and water breakthroughs and optimize oil production. The combination of numerous ICDs and long slanted production intervals (i.e., thousands of feet) make wellbore-reservoir coupling critical for proper history matching and forecasting. The model grid size in the horizontal direction is 328 ft, which is considered optimal according to simulated sensitivities. The vertical layering is very fine in order to capture the reservoir heterogeneity; the cell thickness ranges from 1 to 1.5 ft. This results in a model with 3.5 million active cells, which makes the simulation performance and run time very challenging when coupled with compositional gradient and ICDs. Phase Labeling In this section of the complete paper, the authors review why accurate phase labeling is important in compositional simulation and how it can lead to convergence problems, particularly for cases with gas injection. A traditional method is compared with an ML method on a simple model using a complex dummy fluid model to highlight issues that may arise in more-complex simulation models.

Partnerships Crucial in Developing Nonmetallic Downhole Tubulars

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23491, “Role of Ecosystem Partners To Make Nonmetallic Downhole Tubulars a Reality,” by Ahmed Aladawy, SPE, and Ameen Malkawi, SPE, Baker Hughes, and Omar El Shamy, SPE, Novel Non-Metallic Solutions. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. _ Nonmetallic (NM) downhole tubulars offer a longer lifetime than their steel counterparts while eliminating corrosion concerns and lowering total cost of ownership. Making them a reality, however, requires a rigorous ecosystem with multidisciplinary skill sets and technology expertise. The complete paper discusses the challenges that face the development of such tubulars starting from academia and research institutes to complement expertise and computer computational power and moving through to material suppliers and manufacturing facilities for pipe prototyping. NM Pipe Construction and Technology Status NM pipes also can include metallic elements, where a hybrid system of NM layers is incorporated into multilayered pipe structures that assume specific roles, similar to a metallic pressure armor layer in subsea flexible risers, jumpers, and flowlines. Another example is polymer-lined steel rigid pipes with glass-fiber reinforced epoxy (GRE), or a dual-layer thermoplastic-lined reinforced pipe (Fig. 1). Composite-based NM pipes can broadly be categorized into reinforced thermoplastic pipe (RTP) and reinforced thermoset pipe (RTR), with glass-fiber reinforced plastic pipe (GRP) and GRE considered a subset of RTR. RTP consists of thermoplastic matrices and layers that can soften after heating and can harden when cooled in a reversible process, thus having the potential to recycle. Because of the flexibility of thermoplastic polymer, RTP pipes up to hundreds of meters long can be spooled on reels and deployed through rigless operation, with reduced system cost and deployment time. This synopsis will concentrate, as does the complete paper, on RTP. RTP pipe design can be classified as unbonded, semibonded, or fully bonded. Essentially, three layers of constituents for RTP exist: the inner layer is a fluid barrier (liner), the second layer is a load-bearing component (reinforcement), and the outer layer is external protection (cover). Unbonded RTP pipe means that the layers are not heat-fused to one another during manufacturing and are free to move between layers. This type of RTP pipe usually is low to medium in pressure rating, especially with regard to collapse rating, but also is lower in manufacturing cost and is suitable in onshore applications for fluid transportation. To increase the pressure rating, semibonded RTP pipes can be considered if pipe thickness is a limitation. For offshore and downhole applications, however, where higher pressure and temperature ratings are required, fully bonded RTP pipes, more commonly known as thermoplastic composite pipes, are preferred to handle high burst and collapse-pressure requirements and more-consistent load transfer across the structure. All RTP types can be manufactured continuously into pipe lengths of hundreds of meters because of their flexibility, but fully bonded RTP may be limited to larger-bend radii than unbonded or semibonded RTP; consequently, a need exists to consider reel-size limitations or even carousels to wind long pipe lengths during manufacturing. Conversely, fully bonded RTP structures may be easier to model and analyze than unbonded pipe.

Adaptive Approach for Reservoir Modeling Reduces Project Time, Improves Collaboration

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23935, “Breaking the Chain: Novel Use of Adaptive Model Approach for Reservoir Modeling Reduces Time Duration of Project and Improves Collaboration,” by Anthony R. Thompson, SPE, and Cesar E. Zerpa Bolivar, SPE, Saudi Aramco. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. _ The complete paper details how the reservoir modeling workflow can be accelerated, and uncertainty reduced, even for challenging greenfield prospects by constructing multiple small fit-for-purpose integrated adaptive models instead of one all-encompassing model. This workflow reduces the number of items on the critical path while simultaneously enabling static and dynamic data to be integrated before the static model is finalized. In addition, this approach enables new ideas to be evaluated more rapidly without affecting the critical path of the project. Adaptive Models Adaptive models are constructed to evaluate a single parameter, although this does not preclude an adaptive model being used to answer more than one question simultaneously. Critical to the successful use of adaptive models is the fact that they can be constructed quickly. This enables the various inputs received to be assessed and quality-controlled within the static and dynamic models the moment the input or interpretation becomes available. The construction of adaptive models normally is best achieved through the construction of a workflow in the static modeling package. Initially, the workflow may only consist of the construction of a grid in which to start to place wells. As data become available and are quality-controlled into the model, in most cases, this can be included into the workflow, enabling more constraints to be applied to the subsequent modeling framework. When the adaptive model is being simulated dynamically, it is critical that the model runs quickly. The use of a sector model can be considered for greenfields because the history-matching parameters before production starts are limited to the vicinity of the well. Full-field models are only required when an event occurs across the whole of the reservoir. Adaptive Modular Modeling Process In contrast to the classical approach to reservoir modeling, which uses a chain-type approach, the use of adaptive models brings components together in the sequence of work completion. This means that the various components of the model can be competed when the resource or team member is available. Thus, until very near the end, the project is unlikely to be waiting on the input of one person.

Study Reviews Reservoir Engineering Aspects of Geologic Hydrogen Storage

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23943, “Reservoir Engineering Aspects of Geologic Hydrogen Storage,” by Johannes F. Bauer, Mohd M. Amro, SPE, and Taofik Nassan, SPE, Technical University Bergakademie Freiberg, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. Reproduced by permission. _ Safe and effective large-scale storage of hydrogen (H2) is one of the greatest challenges of the global energy transition and can be realized only through storage in geological formations. The aim of the study detailed in the complete paper is to address and discuss the reservoir engineering aspects of geological H2 storage (GHS). The study is based on two sources: first, a comprehensive literature review and, second, experimental and numerical work performed by the authors’ institute. H2 Pressure/Volume/Temperature (PVT)/Phase Behavior The definition of the PVT/phase behavior of reservoir fluids is crucial in GHS because thermodynamic properties significantly affect safety and effectiveness. The properties of H2 are widely known and modeled, but its reaction with other gases, such as in-situ gases like natural gas in depleted gas reservoirs (DGR), currently is under investigation. Although the ideal gas law can account for H2 behavior at low pressure, accurate depiction of its thermodynamic properties requires more-sophisticated equations of state (EOS), especially when it is mixed with other gases such as methane. Most commercial reservoir simulators use EOS packages that can model the complex properties of these mixtures, mostly within required reliability. In most instances, calibration is still required if experimental PVT data are available. Reservoir Engineering of GHS. GHS projects must meet three crucial technical benchmarks for underground storage: capacity (storage volume), injectivity/productivity (rate of injection/withdrawal in relation to wellhead pressure), and containment integrity (prevention of leakage). Economic sustainability requires that projects must adhere to these standards, which may vary according to the selected geological formations. Although various subsurface structures can store H2, only specific formations such as salt caverns (SCs), saline aquifers (SAs), and depleted gas/oil reservoirs (DGRs and DORs), fulfill the requirements. While the complete paper discusses all three of these formation types in detail, this synopsis will concentrate on SCs. GHS in SCs. SC storage typically involves up to three wells for one cavern with a volume of up to 500,000 std m3, providing a delivery rate of 8,500–17,000 std m3/day. Working gas accounts for up to 65% of the total gas, while water should be kept to a minimum. SCs usually allow between six and 12 operating cycles per year, each lasting approximately 10 days for withdrawal periods. SCs offer high H2 purity and sealed storage. The storage capacity of caverns in Germany is determined by their volume and pressure limitations while avoiding any negative geomechanical effects. These caverns can range in depth from 500 to 2000 m, with heights of up to 400 m. Approximately 30 to 50% of the total stored volume is used as cushion gas to maintain production pressure. Estimating the capacity of these caverns relies on their geometry and thermodynamics, resulting in relatively lower uncertainties when compared with storages in porous media.

Petroleum engineering innovations: Evaluating the impact of advanced gas injection techniques on reservoir management

Gas injection techniques have emerged as a critical aspect of modern reservoir management in petroleum engineering. This paper explores the impact of advanced gas injection techniques on reservoir management strategies and their implications for oil recovery. By evaluating recent innovations in gas injection technology, including the use of CO₂, nitrogen, and hydrocarbon gases, this study sheds light on their effectiveness in enhancing oil recovery rates and extending the productive lifespan of reservoirs. Through a comprehensive review of literature and case studies, this paper examines the mechanisms and benefits of various gas injection methods. It delves into the technological advancements that have revolutionized gas injection techniques, such as real-time reservoir simulation, 4D seismic monitoring, smart well technologies, and machine learning integration. These advancements have provided reservoir engineers with unprecedented insights into reservoir behavior, enabling more informed decision-making processes and optimization of EOR operations. However, alongside these advancements come significant challenges that must be addressed. Economic feasibility, technical hurdles, and environmental concerns pose persistent challenges to the widespread adoption of advanced gas injection techniques. The paper discusses these challenges in detail and explores potential solutions to overcome them, emphasizing the importance of sustainable practices and cross-industry collaboration. By analyzing real-world case studies and industry trends, this paper provides valuable insights into the current state of gas injection techniques in reservoir management and offers recommendations for future research and development. It highlights the need for continued innovation, collaboration, and sustainability in petroleum engineering to maximize the potential of advanced gas injection techniques and ensure the efficient and responsible recovery of hydrocarbon resources. This review provides a concise overview of the paper's scope, findings, and implications, inviting readers to delve deeper into the topic of advanced gas injection techniques in reservoir management.

Introducing a novel method for determining the effective thermal conductivity at moderate and high Péclet numbers

AbstractFlow and heat transfer in porous materials is a common topic throughout many fields, including environmental and petroleum engineering. Using a coupled approach of experimental and simulation methods, this study presents a novel method for calculating thermal conductivity. Specifically, a new approach for the measurement of thermal dispersivity with both conduction and forced convection drives is proposed. In our experiments, temperature was monitored at different points within the porous medium, providing detailed spatial temperature distributions. These measurements allowed us to calculate and report effective thermal conductivity, enhancing the accuracy of our model. Experiments with various injection rates and temperatures were conducted on a sand pack. There is a relationship between the composition and connectivity of the solid in the geometry and heat transfer. However, in the case of forced convection, the key factor is the Péclet number which is important for optimal extraction of the heat inside the geothermal reservoir according to the cooling rate. When the Péclet number is high, the permeability of the porous medium plays a significant role. The velocity of the fluid can change the effective thermal conductivity up to four orders of magnitude. Due to the thermal resistance of solid and fluid, the temperature gradient between the boundary and the centre of the geometry was seen and temperature peaks were observed in the initial stages of the experiments. The size and number of peaks at the initial stage of the experiments are highly dependent on the matrix properties, such as thermal conductivity and surface area.

Combined effects of nonlinear thermal radiation and suction/injection on bioconvective boundary layer of Maxwell nanofluid over a porous movable surface

The nanofluids exclusively enhance the thermal significance of many engineering and industrial processes including the manufacturing processes, chemical reactions, polymers, thermal devices, heating systems, solar energy etc. The presence of porous medium and suction/injection phenomenon incorporates key importance in the petroleum engineering and plasma physics. The objective of current work is to present a theoretical analysis for investigating the bioconvective flow of Maxwell nanofluid with applications of suction/injection effects. The flow is causing by porous moving surface. The radiative phenomenon with nonlinear expressions is adopted. The chemical reaction features are used for analysis of concentration phenomenon. Modified Cattaneo–Christov approach is followed to model the problem. A set of dimensionless variables are used for simplifying the modeled equations. The solution procedure is subject to implementation of shooting scheme. Graphical explanation of problems is presented in order to evaluates the role of different parameters. Physical behavior of problem is focused and justified in details. It is noted that heat and mass transfer enhances due to suction/injection parameter. The temperature profile reduces due to thermal relaxation parameter. Current results reveal significance in the ehat exchangers, improving the sustainability of thermal systems, controlling the cooling processes, fertilizes, biofuels etc.

Application of Virtual Laboratory Work in the Educational Process of the University

The article is devoted to conducting a laboratory workshop in the study of technical disciplines. The purpose of the article is to substantiate the possibility of using virtual laboratory work in a laboratory workshop at a technical university. Methodology. Based on the widespread development of digital technologies and their introduction into the pedagogical process of a technical university, the possibility of using virtual laboratory work is considered. The method of pedagogical experiment was used to check the effectiveness of virtual laboratory work by students of the oil and gas specialty when studying the discipline “Hydroaeromechanics in Drilling”. General requirements for conducting laboratory work on stationary benches and virtually are considered. Didactic principles of conducting laboratory classes using virtual works are noted. The process of developing and designing virtual labs, consisting of three stages, is presented. An analysis of the positive and negative aspects of the use of virtual works is carried out. The experience of conducting virtual work at the Institute of Oil and Gas of the Ufa State Petroleum Technological University is presented. A detailed description of the work “Sedimentation and removal of sludge particles” is given, during which the process of transporting sludge to the day surface is mathematically modeled. Objective difficulties for carrying out laboratory work on stationary stands to demonstrate the process of drilling wells are presented. The advantages of using virtual works to study the drilling process are noted. The positive results of virtual laboratory work are described.

Investigation of fracture-plugging wellbore strengthening: Large scale true tri-axial experiments and field tests

Lost circulation caused by developed natural fracture occurs frequently in tight sandstone formations located in Sichuan Basin, China. Fracture-plugging wellbore strengthening by lost circulation materials (FPWSLCM) is a widely applied fluid loss control technique globally. The upper limit of the pressure-bearing capacity treated using FPWSLCM and the relevant engineering influencing factors needs to be investigated further. In this paper, a self-designed large-scale true tri-axial cell was developed to simulate the fracturing and sealing processes in a cubic sandstone sample (30 cm × 30 cm×30 cm) under anisotropic stress to investigate the effect of lost circulation materials (LCM) and the experimental processes on the formation pressure-bearing capacity. Three homogeneous cubic tight sandstone samples taken from Xujiahe Formation in Sichuan Basin with a central hole were used for the wellbore strengthening experiments with FPWSLCM, which was used to eliminate the heterogeneity effect of the rock. SRIPE (SINOPEC Research Institute of Petroleum Engineering) bridge plugging materials were used as LCM. The results show that the formation pressure-bearing capacity after treatment by FPWSLCM was affected by the initial injection pressure, the intrusion amount of LCM, the pressure holding time, and the injection rate. The formation pressure-bearing capacity did not decrease consistently with the increase of plugging zone instability times, but showed an obvious characteristic of fluctuations; the formation pressure-bearing capacity exceeded the fracturing pressure in some cases. The experimental results could be explained by the stress cage theory. Finally, the modified FPWSLCM was applied as a lost circulation control approach by drilling into the tight sandstone formation in the Shunbei oil field, which has a history of severe loss of fluid circulations. The result of the field test indicated that the modified approaches were more successful than the previous approaches used in other wells in this block. The research results are of great significance for improving the success rate of lost circulation control and a reduction in drilling costs.

Prediction of the Optimal Post-Fracturing Soaking Time in Multifractured Shale Gas/Oil Formations on the Basis of Modeling of Fluid Imbibition

Summary Post-fracturing fluid soaking is believed to significantly affect productivity of hydraulic-fractured horizontal wells in the oil and gas industry. It is highly desirable to know the optimal soaking time period to maximize well productivity. An analytical model was developed in this research to describe the dynamic spontaneous imbibition process in shale cracks owing to fluid soaking. The model was integrated with pressure falloff data to develop a mathematical approach for forecasting the optimal soaking time, which is defined as the time it takes for the fluid to reach the midpoint between two adjacent hydraulic fractures. The optimal soaking time depends on crack and fluid properties, including crack width, fluid contact angle, and interfacial tension (IFT). A case study from the data of Tuscaloosa Marine Shale (TMS) suggests that the optimal soaking time is 2–4 weeks if the fracturing spacing is 4–6 m. This work provides petroleum engineers with a quick-and-easy method for predicting the optimal soaking time to maximize their well productivity.

CoreViT: A new vision transformer model for lithofacies identification in cores

Lithofacies identification is crucial in fields such as geology, geotechnical engineering, rock mechanics, and petroleum engineering, as it reveals the physical, chemical, and mineralogical characteristics of rocks that aid in identifying oil and gas reservoir types, volumes, and productivity. Traditional methods of identifying rock types, such as manual sample identification, micrograph identification, and experimental identification, are costly and time-consuming. Several studies have endeavored to enhance the degree of lithofacies identification automation using machine learning (ML) and deep learning (DL) techniques. However, their capacity to recognize intricate data remains restricted. To overcome this challenge, we introduce CoreViT, a modified architecture of the advanced vision transformer (ViT) that includes the parallel transformer encoder (PTE) for exchanging information among image patches, and the class encoder (CE) for improved automatic lithofacies identification. Our study, focusing on core images including algal limestone, mudstone, and non-algal limestone from the Fengxi Well 1 in the Qaidam Basin, demonstrates CoreViT's average recognition accuracy at approximately 97.5% with an average loss of 0.071. Compared with other classical convolutional neural network (CNN) models, CoreViT achieves relatively high accuracy and low loss. This study highlights the superiority of the ViT model over traditional deep convolutional neural networks (DCNNs) and suggests the great potentiality of applying the ViT model in lithofacies identification in core samples.

Anisotropic Mechanical Properties and Fracture Mechanism of Transversely Isotropic Rocks under Uniaxial Cyclic Loading

Transversely isotropic rocks, which are special anisotropic materials, are widely encountered in civil, mining, petroleum, geothermal, and radioactive waste-disposal engineering. Rock is frequently subject to cyclic loads resulting from natural and human-caused events. However, to date, the fracture mechanism of transversely isotropic rocks under cyclic loading remains poorly understood. To address this gap, uniaxial monotonic-loading and cyclic-loading tests were performed on slate specimens by the MTS815 system, during which acoustic emission (AE) signals inside the rock were monitored, and finally the fracture surfaces of the tested rock were scanned by scanning electron microscopy (SEM). Through these tests, the anisotropic mechanical properties, damage evolution, AE characteristics and fracture pattern of slate as a transversely isotropic rock were studied. The results show that the peak strength of specimens varies with the loading–foliation angle under monotonic and cyclic loading, following a U-shaped trend. The deformation modulus during unloading is more capable of characterizing the damage inside the specimen than that during loading. By defining the damage degree based on dissipation energy, it is found that the damage variable is influenced by the loading–foliation angle and the cyclic stress step. The AE characteristics of specimens exhibit significant anisotropy, closely correlated to the loading condition and loading–foliation angle. Regardless of cyclic stress step, the AE counts of specimens with a loading–foliation angle of 0° are mainly distributed near the peak region, whereas those of specimens with other loading–foliation angles occur primarily in the early stage of each cyclic loading. Finally, it is revealed that the fracture mechanism of slate specimens is determined by the loading–foliation angle, loading condition, and cyclic stress step.

Volatile light hydrocarbons as thermal and alteration indicators in oil and gas fields

Volatile light hydrocarbons (VLH) are an essential component of reservoir petroleum fluids. Understanding of their origin and fate is crucial not only in exploration but increasingly also in petroleum engineering, as this greatly impacts fluid typing, proper mapping, recoverability and economic value. Due to their sensitivity to subsurface thermal stress and geological alteration processes, their proper characterisation holds promise to understanding the thermal conditions under which petroleum fluids were generated and subsequent fluid modifications during migration and within the reservoir. To study the behaviour of these hydrocarbons under different geological conditions we selected oil and gas fields from two giant conventional petroleum systems in the Arabian Peninsula collectively spanning the entire petroleum spectrum from heavy oil to dry and sour gas. In situ representative bottomhole or recombined pressure–volume–temperature (PVT) fluid composition data were constrained with molecular and stable carbon isotope geochemistry in key wells. Systematic covariance among the slope factor (SF) of propane to pentane and the isomer ratios of butane and pentane with reservoir engineering and geochemical variables in well-constrained black oil to gas condensate petroleum systems allowed the derivation of three formulas to calculate thermal maturity in terms of vitrinite reflectance equivalent from VLH fluid composition: (1) %VRe(SF) = 0.38 SF + 0.41, (2) %VRe(i4) = 1.70 (iC4/nC4) + 0.61, and (3) %VRe(i5) = 0.89 (iC5/nC5) + 0.56. The slope factor, iC4/nC4, and iC5/nC5 ratios all increase monotonically with the thermal evolution of unaltered fluids, allowing for effective application of their derived %VRe formulas across the entire unaltered fluid spectrum, from heavy oil to dry gas. Deviations from indigenous-fluid trends do occur for fluids altered by phase separation, biodegradation, thermal cracking, and thermochemical sulfate reduction (TSR), but corrections can be made to minimize uncertainty in assessing true thermal maturity of altered fluids while respecting other reservoir fluid properties such as gas-to-oil ratio (GOR) and saturation pressure relationships. For instance, although a single charge that has been phase fractionated yields fluids with variable GORs, saturation pressures and slope factors, their butane and pentane isomer ratios remain reflective of the original fluid maturity. In contrast, biodegradation-induced overestimation of maturity based on the isomer ratios of butane and pentane can be corrected by the less affected SF-derived maturity parameter. Reversal to lower apparent SF-derived maturity in thermally and TSR cracked fluids can, on the other hand, be corrected by considering the less affected butane and pentane isomer ratios. Overall, maturities calculated using VLH composition correspond well with fluid type defined based on phase behaviour and source-rock kinetics, thereby putting forward new tools to quantify thermal maturity of reservoir fluids that may be applicable in other petroleum systems.

Liquid–solid two-phase flow and separation behavior in a novel cyclone separator

In response to the prevalent issue of sand presence in liquid, particularly prominent in petroleum engineering, a novel cyclone separator has been meticulously engineered for fine-particle separation. Experiments and numerical simulation methods have provided a profound understanding of the flow-field characteristics and separation efficacy of this device. The internal architecture of the swirling flow inside the separator features a distinctive central vortex core, complemented by a turbulent secondary vortex formation in the lower section of the underflow. As the axial height increases, the secondary vortex gradually dissipates. An analysis of pressure and velocity distribution within the cyclone separator confirms the establishment of a stable cyclone field in the built-in cyclone and a tendency for the flow field within the tank to exhibit uniformity with increasing height. These flow-field characteristics show that the cyclone separator has a good separation effect on fine-rust particle impurities. Furthermore, the separation efficiency of the novel cyclone separator demonstrates a positive correlation with increasing particle size. Of the parameters studied, variation of the inlet velocity is the best method for obtaining optimum separation efficiency for a cyclone desander with a fixed particle size. Specifically, when the inlet velocity reaches 3 m/s, the desander attains an impressive separation efficiency of up to 70%.

State of the Art on Relative Permeability Hysteresis in Porous Media: Petroleum Engineering Application

This paper delivers an examination of relative permeability hysteresis in porous media in the field of petroleum engineering, encompassing mathematical modeling, experimental studies, and their practical implications. It explores two-phase and three-phase models, elucidating the generation of scanning curves and their applications in various porous materials. Building on the research of traditional relative permeability hysteresis models, we have incorporated literature on forward calculations of relative permeability based on digital rock core models. This offers a new perspective for studying the hysteresis effect in relative permeability. Additionally, it compiles insights from direct relative permeability and flow-through experiments, accentuating the methodologies and key findings. With a focus on enhanced oil recovery (EOR), carbon capture, utilization and sequestration (CCUS), and hydrogen storage applications, the paper identifies existing research voids and proposes avenues for future inquiry, laying the groundwork for advancing recovery techniques in oil and gas sectors.

Haar wavelet collocation technique for numerical solution of porous media equations

This paper focuses on using efficient Haar wavelet collocation method to nonlinear parabolic differential equations in order to solve steady state pore-scale creeping fluid flow in porous medium, substituting finite Haar series for space derivatives, incontrast forward difference approach is used to estimate the time derivative for porous media equation. These equations has vast number of application in engineering and various other fields such as, in petroleum engineering, there are often situations where fluids are near critical conditions. As oil pressure reduces below the bubble point when gas forms liquid condensations, or when the surface tension become very low i.e, transition from miscibility to immiscibility. To model gas production by pressure decline requires an accurate description of physical mechanism involved in the appearance of the gas bubbles. The observed stability with theoretical convergence assertion, the conservation law of mass and energy are stated. This supports the convergence of the preferred paradigm. A convergent approximation to the porous media equation is obtained by suggested approach. By calculating the maximum error norm and the experimental rate of convergence for various problems, the method efficiency and dependability are demonstrated. The method is accurate, easily applicable, and efficient.

Visualization and Analysis of Mapping Knowledge Domain of Fluid Flow Related to Microfluidic Chip.

Microfluidic chips are important tools to study the microscopic flow of fluid. To better understand the research clues and development trends related to microfluidic chips, a bibliometric analysis of microfluidic chips was conducted based on 1115 paper records retrieved from the Web of Science Core Collection database. CiteSpace and VOSviewer software were used to analyze the distribution of annual paper quantity, country/region distribution, subject distribution, institution distribution, major source journals distribution, highly cited papers, coauthor cooperation relationship, research knowledge domain, research focuses, and research frontiers, and a knowledge domain map was drawn. The results show that the number of papers published on microfluidic chips increased from 2010 to 2023, among which China, the United States, Iran, Canada, and Japan were the most active countries in this field. The United States was the most influential country. Nanoscience, energy, and chemical industry and multidisciplinary materials science were the main fields of microfluidic chip research. Lab on a Chip, Microfluidics and Nanofluidics, and Journal of Petroleum Science and Engineering were the main sources of papers published. The fabrication of chips, as well as their applications in porous media flow and multiphase flow, is the main knowledge domain of microfluidic chips. Micromodeling, fluid displacement, wettability, and multiphase flow are the research focuses in this field currently. The research frontiers in this field are enhanced oil recovery, interfacial tension, and stability.