Conventional Reservoirs Research Articles

Thickening supercritical CO2 at high temperatures with rod-like reverse micelles

Earlier studies demonstrated the ability of some fluorinated surfactants to form rod-like reverse micelles with the ability to thicken water/supercritical CO2 (scCO2) mixtures at temperatures below 45 ºC [Langmuir 26 (2010) 83–88. Soft Matter 8 (2012) 7044–7055. Colloids and Surfaces B, 168 (2018), 201–210.]. Such viscosity enhancement of scCO2 is known to increase sweep efficiency for oil recovery with CO2 flooding. However, temperatures of up to ∼100 ºC in conventional reservoirs are much higher than those employed in laboratory studies, and tend to weaken inter- and intra-molecular interactions between surfactant molecules, discouraging rod-like reverse micelle formation. With the aim of designing surfactants which form rod-like reverse micelles and thicken CO2 at high temperatures, this study examined phase behavior, nanostructures of reverse micelles and thickening ability of double ω-hydroperfluorocarbon-tail anionic surfactants in W/scCO2 mixtures at temperatures of 35 - 75 ºC and pressure of 80 - 400 bar with different water-to-surfactant molar ratios (W0). The measured CO2 viscosity increased by 1.9–2.2 × for double-chain surfactants M(di-HCF6)x (counterion Mx+ = Ni2+ and Co2+) at 40 mM, over the experimental temperature range. On the other hand, the shorter chain H(CF2)4CH2 twin-tail surfactants M(di-HCF4)x and Na(di-HCF6) gave only 1.1–1.5 × viscosity enhancements. The maximum thickening ability of M(di-HCF6)2 was at W0 = 10 in the W0 range of 5–20 75 ºC and 350 bar. High pressure and high temperature small-angle neutron scattering (SANS) was used determine the micellar structure in these systems, and rod micelles of aspect ratios of 4.5–6.5 were found. The results clearly suggest that ω-hydroperfluorohexyl-tails and divalent counterions induce the formation of rod-like reverse micelles in W/CO2 mixtures, even at high temperatures commensurate with in-reservoir conditions.

Experimental Study of the Fluid Contents and Organic/Inorganic Hydrocarbon Saturations, Porosities, and Permeabilities of Clay-Rich Shale

Unlike conventional reservoirs, shale is particularly complex in its mineral composition. As typical components in shale reservoirs, clay and organic matter have different pore structures and strong interactions with fluids, resulting in complex fluid occurrence-states in shale. For example, there are both free water and adsorbed water in clay, and both free oil and ad/absorbed oil in organic matter. Key properties such as fluid content, organic/inorganic porosity, and permeability in clay-rich shale have been poorly characterized in previous studies. In this paper, we used a vacuum-imbibition experimental method combined with nuclear magnetic resonance technique and mathematical modeling to characterize the fluid content, organic/inorganic porosity, saturation, and permeability of clay-rich shale. We conducted vacuum-imbibition experiments on both shale samples and pure clay samples to distinguish the adsorbed oil and water in clay and organic matter. The effects of clay content and total organic matter content (TOC) on porosity and adsorbed-fluid content are then discussed. Our results show that, for the tested samples, organic porosity accounts for 26–76% of total porosity. The oil content in organic matter ranges from 29% to 69% of the total oil content, and 2% to 58% of the organic oil content is ad/absorbed in kerogen. The inorganic porosity has a weak positive correlation with clay content, and organic porosity increases with rising levels of organic matter content. The organic permeability is 1–3 orders of magnitude lower than the inorganic permeability.

A comparative analysis of gas mixing during the underground hydrogen storage in a conventional and fractured reservoir

Climate change and political tensions are reducing the time for the energy transition. Large-scale underground hydrogen storage (UHS) can be crucial in future energy systems for decarbonizing the world's economy as well as ensuring energy security. There are challenges, however, that prevent it from being used on large scale as an energy carrier. The high cost of hydrogen cushion gas is one of them. It is not economical that a portion of hydrogen remains in a reservoir as a cushion gas during UHS until the end of a storage operation. Consequently, inert gases such as nitrogen can be used as cushion gas. Hydrogen's heating value gets reduced, however, due to gas mixing. Since gas mixing behavior differs in reservoirs with different mechanisms, hydrogen heating value was employed to examine the gas mixing behavior during UHS in conventional and fractured reservoir models (dual-porosity) for the first time in this study. The mixing behavior of hydrogen gas with replaced cushion gas will first be examined in the absence and presence of diffusion using a conventional gas reservoir model. Then some reservoir and operational parameters will be investigated in order to determine how they affect the gas mixing behavior, including reservoir porosity, permeability, rock compressibility, and cushion gas type. Next, a basic UHS scenario with dual-porosity will be examined to determine how hydrogen gas and cushion gas mix in the presence and absence of diffusion and the effects of specific parameters on gas mixing behavior in the fractured reservoir (NFR) model, including matrix-fracture transmissibility and cushion gas type. According to the results, in the conventional reservoir model, considering diffusion during early hydrogen production results in a decrease in hydrogen heating value. While in the second stage of hydrogen production, diffusion increases the hydrogen heating value, resulting from the sweeping effect. Dual-porosity models illustrate the opposite behavior. As well, porosity reduction resulted in higher hydrogen heating values during early production but reversed during late production. Unlike the effect of rock compressibility on heating value of hydrogen, a lower hydrogen heating value was obtained during hydrogen production as the reservoir permeability increased. Also, carbon dioxide cushion gas showed reversed effect on gas mixing during UHS in the conventional compared to the NFR case.

Study on multi-cluster fracturing simulation of deep reservoir based on cohesive element modeling

With the depletion of conventional reservoir development, reservoir fracturing under deep high geo-stress and high geo-stress difference conditions is receiving increasing attention. Deep reservoirs typically require multi-cluster fracturing to achieve efficient reservoir transformation and development. In this paper, considering the relevant geological parameters of a certain reservoir in the southwest, three-dimensional multi-cluster reservoir fracturing models were established based on cohesive element modeling. Then, the propagation law of artificial fractures in reservoirs under the influence of the different number of fracturing clusters, injection displacement, and Young’s modulus in different regions of the 60 m fracturing well section is analyzed, and the quantitative law of parameters such as fracture length, maximum fracture width, injection point fracture width, fracture area, and tensile failure ratio during multi-cluster fracturing construction, as well as the propagation law of fracture morphology are revealed. The simulation results show that using multi-cluster fracturing can significantly improve the effectiveness of reservoir reconstruction, but as the number of fracturing clusters increases, it is also easy to form some small opening artificial fractures. These small opening artificial fractures may not be conducive to the transportation of proppants and fluids. During single cluster fracturing, the interface stiffness and rock Young’s modulus have a significant impact on the propagation of artificial fractures in the reservoir. As the number of fracturing clusters increases, the competition between artificial main fractures expands significantly, which may reduce the impact of interface stiffness and rock Young’s modulus. The fluid injection rate has a significant impact on reservoir fracturing, and in the same area, using high displacement injection can significantly increase the volume of reservoir reconstruction. This study can provide some reference for multi-cluster fracturing construction in deep reservoirs.

EFFECTS OF POROSITY ON THE STRENGTH AND MECHANICAL BEHAVIOUR OF POROUS GEO-MATERIALS UNDER CYCLIC LOADING

Most rocks in nature are porous and usually saturated with different fluids such as water, oil, and gas. The conventional and unconventional hydrocarbon reservoirs are mainly associated with sedimentary formations. The main rocks of these reservoirs are sandstone (porous rock), limestone and oil shale (tight rock), which are associated with varying porosity. Hence, porosity serves as a fundamental parameter for most reservoir rocks. In this research, the effect of porosity on the mechanical behaviour of geo-materials and its fatigue behaviour was investigated. For this purpose, a total of five geo-material sample groups with varying porosities were prepared and designated, i.e. groups A, B, C, D, and E. Group A exhibited the highest porosity 20-21.5%, while group E had the lowest porosity 2-3%, respectively. The conventional quasi-static strength tests and cycle loading tests with constant frequency and amplitude were performed on the samples and different results were obtained. The samples belonging to group E, with the lowest porosity (2-3%), exhibited the highest mechanical strength, elastic modulus and fracture toughness values and the lowest Poisson's ratio compared to those of higher porosity samples. During the cyclic loading period, the fatigue stress-life graph of the E group has the lowest slope compared to the other groups. It means that the slope of the graph increases as the porosity increases in all groups. Therefore, the E group has the lowest porosity and the longest fatigue life time, i.e. porosity and fatigue resistance have an inverse correlation.

Edge of Stability Echo State Network.

Echo state networks (ESNs) are time series processing models working under the echo state property (ESP) principle. The ESP is a notion of stability that imposes an asymptotic fading of the memory of the input. On the other hand, the resulting inherent architectural bias of ESNs may lead to an excessive loss of information, which in turn harms the performance in certain tasks with long short-term memory requirements. To bring together the fading memory property and the ability to retain as much memory as possible, in this article, we introduce a new ESN architecture called the Edge of Stability ESN (). The introduced model is based on defining the reservoir layer as a convex combination of a nonlinear reservoir (as in the standard ESN), and a linear reservoir that implements an orthogonal transformation. In virtue of a thorough mathematical analysis, we prove that the whole eigenspectrum of the Jacobian of the map can be contained in an annular neighborhood of a complex circle of controllable radius. This property is exploited to tune the 's dynamics close to the edge-of-chaos regime by design. Remarkably, our experimental analysis shows that model can reach the theoretical maximum short-term memory capacity (MC). At the same time, in comparison to conventional reservoir approaches, is shown to offer an excellent trade-off between memory and nonlinearity, as well as a significant improvement of performance in autoregressive nonlinear modeling and real-world time series modeling.

Mega-reservoirs of oil and gas: systematization, conditions of formation, influence of natural processes on the scale of accumulations

The ideas about the conditions for the formation of large oil and gas reserves in both traditional reservoirs and unconventional shale, as well as in low-pore reservoirs with hard-to-recover superviscous oils and natural bitumen, have been expanded. The influence of geological and geochemical environments on the scale of hydrocarbon accumulations is analyzed. Keywords: oil; gas; mega-reservoirs; hydrocarbon accumulations; reserves ; area and volume; shale formations; conventional and unconventional reservoirs.

Investigation of the confinement effect on fluid-phase behavior in shale oil reservoirs during CO2 injection process

AbstractDue to the confinement effect of nanopores, the fluid-phase behavior of shale oil reservoirs is much different from that of conventional reservoirs. The accurate description of the phase change characteristics of fluid in nanopores is the basis to design development plan, production system, and EOR methods of shale oil reservoirs. In this study, molecular dynamics simulation was employed to analyze the phase behavior of single-component system and hydrocarbon–CO2 mixture system in organic nanopores. The results show that the confinement effect on the phase change pressure of the single-component system is influenced by the distribution of the electron cloud. The phase change pressure of hydrocarbons with even distribution of the electron cloud would be increased, while that of CO2 would be decreased due to the instantaneous dipole moment. In addition, as the length of carbon chains increases, the confinement effect on hydrocarbons becomes stronger. When the temperature increases, the confinement effect becomes weaker. In the hydrocarbon–CO2 mixture system, when the occurrence condition changes from bulk to the nanopore of 5 nm, the bubble point pressure decreases by 39.21–68.85%, and the critical temperature and pressure decrease by 75.98% and 7.13%, respectively. On the whole, the P–T phase envelope is shrunken under the confinement effect. CO2 is much easier to be miscible with shale oil in nanopores. Moreover, full mixing and keeping in single liquid phase of CO2–hydrocarbons mixture system can reduce the adsorption of hydrocarbons on organic pore walls. Therefore, CO2 injection could be a feasible method to enhance oil recovery in the matrix of shale oil reservoirs.

Injectivity Assessment of Radial-Lateral Wells for CO2 Storage in Marine Gas Hydrate Reservoirs

The carbon dioxide (CO2) leak from conventional underground carbon storage reservoirs is an increasing concern. It is highly desirable to inject CO2 into low-temperature reservoirs so that CO2 can be locked inside the reservoir in a solid state as CO2 hydrates. Marine gas hydrate reservoirs and surrounding water aquifers are attractive candidates for this purpose. However, the nature of the low permeability of these marine sediments hinders the injection of CO2 on a commercial scale due to the low injectivity of wells with conventional completions. This study investigates the injection of CO2 into low-permeability marine reservoirs through a new type of well, namely a radial-lateral well (RLW). A mathematical model was developed in this study to predict the CO2 injectivity of the RLW. The model comparison shows that the use of RLW to replace vertical wells can improve CO2 injectivity by over 30 times, and the use of RLW to replace frac-packed wells can increase CO2 injectivity by over 10 times. A case study and sensitivity analysis were performed with field data from the South China Sea. The result of the analysis reveals that the injectivity of the RLW is nearly proportional to reservoir permeability, lateral wellbore length, and the number of laterals. The CO2 injection rate is predicted to be 19 tons/day to 250 tons/day, which is 3 to 15 times higher than the injectivity of frac-packed wells. It is feasible to inject CO2 into the low-permeability, low-temperature marine reservoirs at commercial flow rates. This work provides an analytical tool to predict the CO2 injectivity of RLW in low-temperature marine reservoirs for leak-free CO2 storage.

Spatiotemporal Data Processing with Memristor Crossbar-Array-Based Graph Reservoir.

Memristor-based physical reservoir computing (RC) is a robust framework for processing complex spatiotemporal data parallelly. However, conventional memristor-based reservoirs cannot capture the spatial relationship between the time-varying inputs due to the specific mapping scheme assigning one input signal to one memristor conductance. Here, a physical "graph reservoir" is introduced using a metal cell at the diagonal-crossbar array (mCBA) with dynamic self-rectifying memristors. Input and inverted input signals are applied to the word and bit lines of the mCBA, respectively, storing the correlation information between input signals in the memristors. In this way, the mCBA graph reservoirs can map the spatiotemporal correlation of the input data in a high-dimensional feature space. The high-dimensional mapping characteristics of the graph reservoir achieve notable results, including a normalized root-mean-square error of 0.09 in Mackey-Glass time series prediction, a 97.21% accuracy in MNIST recognition, and an 80.0% diagnostic accuracy in human connectome classification.

Nonionic Surfactant Blends for Enhanced Oil Recovery in High-Temperature Eagle Ford Reservoir

Summary Nonionic surfactants have proven successful and cost-effective in enhancing production from conventional and unconventional reservoirs. However, studies into the mechanism and performance of nonionic surfactants have been limited to reservoirs with temperatures below 200°F due to the temperature-dependent physiochemical properties, especially cloudpoint (CP). In this study, nonionic-ionic surfactant blends were designed to create nonionic systems with cloudpoint temperatures (CPTs) above 300°F for wettability alteration in high-temperature reservoirs like the Eagle Ford Shale in Texas, USA. Through CP, wettability, interfacial tension (IFT), and spontaneous imbibition experiments, 22 commercial surfactant samples (individual and blends) were investigated. Results showed that the amount of ionic cosurfactant affected thermal stability, with increasing concentration leading to increasing CPT. Wettability alteration was dependent not only on temperature but also on the class of ionic cosurfactant. Cationic cosurfactants were superior at improving nonionic surfactants’ thermal stability. However, they resulted in oil-wet contact angles (CAs) with increasing temperature. On the other hand, anionic cosurfactants displayed better synergy in terms of wettability alteration, creating strongly water-wet and intermediate-wet CAs at high temperatures. Therefore, the focus was placed on nonionic-anionic surfactant blends for the reservoir samples used in this study. Stable surfactant blends with CPTs from 316°F to 348°F were successfully created for enhanced oil recovery (EOR) applications at high-temperature conditions. Spontaneous imbibition studies using these blends indicated improved recovery by up to 173%. This work validates and builds upon previous studies of surfactant performance, wettability alteration, and IFT while providing new insight into nonionic surfactant blends at temperature conditions not currently available in the literature. It also serves as a template for the surfactant screening and selection process when considering nonionic surfactants.

Wide azimuth seismic data processing technology and application: a case study of tight gas reservoirs in western China

As the difficulty of oil and gas field exploration and development increases both domestically and internationally, onshore exploration targets have gradually shifted from the shallow to the deep and from conventional oil and gas reservoirs to unconventional ones. Particularly in the exploration and development of unconventional oil and gas horizontal wells, there is an increasing demand for higher precision and quality of seismic data to better identify formation lithology, rock fractures, and improve the characterization of reservoirs, reservoir positioning, and connectivity. Wide-azimuth seismic exploration possesses significant technical advantages in addressing exploration challenges such as lithologic exploration, small fault imaging, and detailed characterization of oil and gas reservoirs. Wide azimuth seismic data reduces blind spots in seismic acquisition and improves the imaging accuracy of small faults. Notably, there exist distinct anisotropic characteristics in fault areas and fractured reservoirs. Wide azimuth seismic data is particularly advantageous for studying amplitude variation with variations in amplitude with offset (AVO), incident angle (AVA), or azimuth (AVAZ), as well as velocity with azimuth (VVA). These variations aid in identifying faults, fractures, and changes in formation lithology. As the focus of oil and gas exploration gradually shifts to complex lithological reservoirs and unconventional oil and gas reservoirs, narrow azimuth seismic exploration has been gradually replaced by wide azimuth exploration. However, as observation azimuth increases, challenges related to velocity variations with azimuth, azimuth-related traveltime differences, and azimuth-related anisotropy arise. Based on wide-azimuth seismic data from tight gas reservoirs in western China, this study conducted wide-azimuth anisotropic velocity analysis, OVT domain data regularization processing, OVT domain prestack time/depth migration, and horizontally transverse isotropy (HTI) azimuth anisotropy correction techniques. After applying specialized processing to the wide-azimuth seismic data, significant improvements were observed in the S/N and resolution of the target layer. The delineation of fractures related to hydrocarbon sources also became more distinct. These advancements not only provided high-quality results for high-fidelity, high-resolution imaging of tight gas reservoirs but also provided azimuth volume corresponding to fast and slow wave velocities for seismic data interpretation, facilitating velocity variation with azimuth (VVAZ) fracture detection and AVO analysis research.

Long-term operation rules of a hydro–wind–photovoltaic hybrid system considering forecast information

The large-scale integration of wind and solar energy into cascade hydropower stations increases the complexity of hydraulic/electrical relationships and requires a modification of conventional scheduling mode for better energy system performance. This study focuses on the long-term operation rules for hydro–wind–photovoltaics (PV) hybrid energy systems (HESs). Based on the conventional operation chart, a cascade energy operation chart that couples wind, PV output, and runoff forecasts is proposed to obtain the total output of HES, which can promote the utilization of the joint regulation of cascade hydropower stations. A total output allocation method based on the cascade energy operation chart is established to coordinate the operation of each power station. Then an operation chart optimization model with objectives of maximizing power generation and output reliability is proposed to improve HES performance. The case study reveals that compared with the conventional reservoir operation chart, 1) the optimized cascade energy operation chart increased power generation of HES by 9.2 %; 2) the reservoir impounding timing was delayed, the drawdown timing was brought forward, and the drawdown depth was increased; 3) the reliability of HES power output was improved, and the output corresponding to the 95 % guaranteed rate requirement was increased by 18 %.

Numerical Investigation on Mesoscale Evolution of Hydraulic Fractures in Hydrate-Bearing Sediments

Hydraulic fracturing is widely recognized as a potential stimulation technology for the development of challenging natural gas hydrate. However, the fracturing behavior of non-diagenetic hydrate reservoirs has peculiar characteristics that are different from those of conventional oil and gas reservoirs. Herein, a fully coupled fluid-mechanical model for simulating hydraulic fracturing in hydrate-bearing sediments (HBS) was established based on the discrete element method, and the influence of hydrate saturation, in situ stress, and injection rate on the meso-fracture evolution was investigated. The results indicate that with the increase in hydrate saturation, the fracture morphology transitions from bi-wing to multi-branch, thereby enhancing fracture complexity. Both tensile and shear failure modes exist, and the tensile failure between the weakly cemented sediment particles is dominant. The tensile strength of HBS is an exponential function of hydrate saturation, with the breakdown pressure being governed by hydrate saturation and in situ stress, with the form being consistent with the classical Kirsch equation. Additionally, lower in situ stress and higher injection rates are conducive to the generation of microcracks, whereas an excessive injection rate reduces the fracture length. These findings contribute to understanding the meso-evolution mechanism of hydraulic fractures and guide the design of on-site hydraulic fracturing plans of natural gas hydrate reservoirs.

Enhanced system for hydrogen storage and conversion into green methanol in a geothermal environment

Variable Renewable Energy Sources are crucial for decarbonizing industries and efficient energy storage. Hydrogen storage technologies are limited in their large-scale capabilities. PtL technology can synthesize alternative fuels like methanol, which can be used in existing energy infrastructures to produce liquid fuel. The paper presents an innovative approach for utilizing in-situ thermal energy, using a hot reservoir rock (HRR) system for methanol synthesis at high temperature and pressure in an underground large-scale natural reservoir reactor. This approach aims to integrate renewable energy technologies into a single energy generation and fuel production system, including the direct utilization of renewable sources. Solutions from the oil and gas industry can be adapted to this action, such as continuous injection, alternate injection, separate injection, or chemical flooding. Conventional geothermal reservoirs, HDR systems, and depleted hydrocarbon reservoirs can be used as “underground reactors”. However, it was also noted that there are challenges, such as catalyst distribution and the complexity of reservoir pore space.

Evaluation of Viscosity Changes and Rheological Properties of Diutan Gum, Xanthan Gum, and Scleroglucan in Extreme Reservoirs.

The chemically synthesized polymer polyacrylamide (HPAM) has achieved excellent oil displacement in conventional reservoirs, but its oil displacement is poor in extreme reservoir environments. To develop a biopolymer oil flooding agent suitable for extreme reservoir conditions, the viscosity changes and rheological properties of three biopolymers, diutan gum, xanthan gum, and scleroglucan, were studied under extreme reservoir conditions (high salt, high temperature, strong acid, and alkali), and the effects of temperature, mineralization, pH, and other factors on their viscosities and long-term stability were analyzed and compared. The results show that the three biopolymers had the best viscosity-increasing ability at temperatures of 90 °C and below. The viscosity of the three biopolymers was 80.94 mPa·s, 11.57 mPa·s, and 59.83 mPa·s, respectively, when the concentration was 1500 mg/L and the salinity 220 g/L. At the shear rate of 250 s-1, 100 °C~140 °C, scleroglucan had the best viscosification. At 140 °C, the solution viscosity was 19.74 mPa·s, and the retention rate could reach 118.27%. The results of the long-term stability study showed that the solution viscosity of scleroglucan with a mineralization level of 220 mg/L was 89.54% viscosity retention in 40 days, and the diutan gum could be stabilized for 10 days, with the viscosity maintained at 90 mPa·s. All three biopolymers were highly acid- and alkali-resistant, with viscosity variations of less than 15% in the pH3~10 range. Rheological tests showed that the unique double-helix structure of diutan gum and the rigid triple-helix structure of scleroglucan caused them to have better viscoelastic properties than xanthan gum. Therefore, these two biopolymers, diutan gum, and scleroglucan, have the potential for extreme reservoir oil displacement applications. It is recommended to use diutan gum for oil displacement in reservoirs up to 90 °C and scleroglucan for oil displacement in reservoirs between 100 °C and 140 °C.

Advancing "Carbon Peak" and "Carbon Neutrality" in China: A Comprehensive Review of Current Global Research on Carbon Capture, Utilization, and Storage Technology and Its Implications.

Carbon capture, utilization, and storage (CCUS) technology plays a pivotal role in China's "Carbon Peak" and "Carbon Neutrality" goals. This approach offers low-carbon, zero-carbon, and even negative-carbon solutions. This paper employs bibliometric analysis using the Web of Science to comprehensively review global CCUS progress and discuss future development prospects in China. The findings underscore it as a prominent research focus, attracting scholars from both domestic and international arenas. China notably leads the global landscape in terms of research paper output, with the Chinese Academy of Sciences holding a prominent position in total published papers. The research predominantly centers on refining geological storage techniques and optimizing oil and gas recovery rates. Among the CCUS pathways, enhanced oil recovery technology stands out due to its relative maturity and commercial applicability, particularly within the conventional oil and gas reservoirs. The application potential of enhanced gas recovery technology, especially in the Sichuan and Ordos Basins in China, necessitates robust research and demonstration efforts. Within China's current energy landscape, "Blue Hydrogen" emerges as the primary solution for hydrogen production in conjunction with CCUS technology. The underground coal gasification approach holds significant promise as a hydrogen production avenue, albeit with inherent ecological and environmental challenges tied to geological storage that require meticulous consideration. The establishment of effective risk identification and evaluation methodologies for geological storage is imperative. The trajectory ahead involves a strategic convergence of policy, technology, and market dynamics to enhance China's CCUS policy framework, legislative framework, standardization initiatives, and pioneering technological advancements. These collective efforts converge to outline an exclusive development pathway in China. This study assumes a pivotal role in accelerating CCUS technology research and deployment, enhancing oil and gas recovery efficiency, and ultimately realizing the overarching goals of a "Dual Carbon" future.

Technology Focus: Hydraulic Fracturing Modeling (November 2023)

The purpose of hydraulic fracture modeling is to improve engineering decision-making. Success requires practical knowledge, engagement with real data, theoretical understanding, and critical thinking. The payoff is tremendous; design improvements routinely yield major uplifts in well performance and project economics. What types of papers push forward the state of the art for hydraulic fracturing modeling? In the pure development of models, practitioners adopt different philosophies. Some seek faster running models for quicker results. Others focus on integration of physics, trying to capture the essential elements of all key physical processes and how they interact. Still others focus on high-precision answers to narrower aspects of the problem. The appropriate emphasis depends on the context of how and why the model is being used. Many of the most influential papers of the past decade on hydraulic fracture modeling have not been modeling papers at all. Modeling depends on formulating a realistic conceptual model. New types of data collection and new ways of analyzing and interpreting data have given engineers a much clearer picture of what is happening in the subsurface. Extraordinary field-scale data-collection projects have given us calibration data that is not available from any other means. With a firmer foundation of knowledge, engineers can construct models that are not only precise but also, more importantly, accurate, and can apply them to solve practical problems. The work flow—how modeling is integrated with field data, practical knowledge, and engineering decision-making—is just as important as the model itself. Thus, papers that offer practical case studies are valuable because they demonstrate work flows and success stories that others can build upon. Hydraulic fracture modeling continues to be a vital contributor across a range of applications: shale, conventional reservoirs, and developing areas such as enhanced geothermal systems. Recommended additional reading at OnePetro: www.onepetro.org. SPE 212328 Interpretation of Fracture Initiation Points by In-Well Low-Frequency Distributed Acoustic Sensing in Horizontal Wells by Smith Leggett, Texas Tech University, et al. URTeC 3864951 Revealing the Production Drivers for Refracs in the Williston Basin by Alexander Cui, Novi Labs, et al. SPE 214784 Application of Hybrid Physics-Based and Data-Driven Fracture Propagation Modeling for Characterizing Hydraulic Fracture Geometry in Unconventional Reservoirs by K. Aldhayee, Texas A&M University, et al.

Petroleum geology of conventional and unconventional resources: Introduction

Understanding reservoir, source, seal, migration pathways and trap characterization is the first step towards better energy resource exploitation. Several studies have been conducted in recent decades on the reservoir characteristics of conventional resources. Unconventional resources, on the other hand, have received more attention as alternative future energy solutions to depleted conventional resources. Drilling, exploration, development, and production of conventional and unconventional resources pose technical challenges to the energy industry. This special issue attempts to address the most pressing technical challenges in developing conventional reservoirs (such as sandstone and carbonate reservoirs) as well as unconventional energy sources (e.g., shale gas, shale oil, tight gas sand, coal bed methane, geothermal and gas hydrates). The special issue is composed of 21 papers that are classified into six different groups related to the physical and mechanical properties of reservoirs, petroleum geochemistry, petroleum geology, geological modelling, unconventional resource evaluation and conventional reservoir evaluation.

Modeling Usage of Degradable Fluid-Loss Additive Revamps Fracturing Design

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 210633, “Multimaterial Multiphysics Modeling Coupled With Post-Fracturing Production-Flow Simulations: Revamping Hydraulic Fracturing Design Strategy,” by Abdul Muqtadir Khan, SPE, Vadim Isaev, and Ludmila Belyakova, SPE, Schlumberger. The paper has not been peer reviewed. _ With the aid of a multiphysics simulator, the authors recently presented a novel use of a degradable fluid-loss additive (DFLA) as a fracture geometry additive to reduce the pad volume while achieving the same geometry. In this complete paper, the authors extend advanced slurry flow modeling with production simulation to propose the optimal design strategy for fracturing, which may challenge current treatment-design conventions. A novel work flow was developed, with four coupled working blocks of laboratory, slurry flow modeling, production analysis, and machine learning. The new digital framework proposes solutions for the limitations of current methodology. Introduction Across different generations, multiple fluid additives have been introduced to target specific treatment objectives; one of these that has been available for years, but that has been underused, is fluid-loss additive (FLA). Theoretical and field bases have been presented for its use in the following applications: - Conventional prolific reservoirs to mitigate high fluid loss and create sufficient fracture geometry - Tight gas formations with high tectonic influence to mitigate poroelastic effects and fissure-dependent enhanced leakoff - Unconventional reservoirs to avoid repression during production - Openhole wells to control multiple fracture initiation - Multipad wells to avoid interwell communications and fracture hits - Fracturing treatments aimed at optimizing and reducing crosslinked pad volume Despite these benefits, the primary issue of using an FLA is its potential to damage fracture conductivity and the reservoir. Some developments of nondamaging FLA have been presented but are either operationally complex or difficult to use. This subject requires special attention to investigate damage and production loss through laboratory studies, numerical models, and machine-learning models and define a tailored strategy with DFLA. Digital Framework for Treatment Design The authors present an end-to-end work flow from chemistry development to an automated FLA-assisted fracturing design tailored for a specific reservoir and well. The framework is broadly split into three blocks: laboratory testing, fracture modeling, and production modeling. These blocks can be sensitized together with multiple case runs and a large digital database. This data set then can be subjected to regression and classification algorithms. With enough data built in the toolbox, a fully coupled data- and physics-based forward model can be created that can output the fracture design with DFLA type, concentration, and pad volume with inputs of reservoir properties and pore-throat descriptions. The tool infrastructure is built to allow the model to retrain and update with real field data addition. In the first block, multiple laboratory tests evaluate DFLA performance. The laboratory tests include static and dynamic leakoff tests to evaluate reduction in spurt loss and wall-cake building leakoff coefficient with varying concentrations of DFLA in the fracturing fluid. Additionally, core-flow tests are performed to understand the effect of DFLA on regained permeability and validate the postulation of its nondamaging nature.