This study investigates the effectiveness of applying advanced scaling techniques using a hybrid Deep Belief Net—Random Forest regressor on production data in unconventional reservoirs such as Multi-Fractured Horizontal Wells. The graphical analysis of the log–log (rates vs. material balance time) plots demonstrates improved clarity in classifying four key flow regimes (ramp-up, linear, transition and BDF) and identifying the time of the end of the transient behavior (end of the line of slope 0.5) using a dataset of 50 wells from D–J Basin of the USA. Acknowledging the reservoir heterogeneity, the curated dataset enhances diagnostic quality and allows for more reliable interpretation of reservoir behavior, with high accuracy metrics of the proposed model. The novelty lies in the integration of DBN as a pre-processor to capture nonlinear correlations in reservoir parameters, such as thickness, compressibility, porosity, lateral length and other crucial characteristics, addressing the specific engineering challenge of automating the end of linear flow regime (telf), which is mainly prone to human bias in rate transient analysis. Our DBN-RF model accurately captured fundamental reservoir dynamics with R-square value of 0.76 on the original split, while a cross-validation (with fivefold) reached on average a R2 = 0.71 ± SD = 0.04, demonstrating a physics-validated inverse relationship between reservoir thickness and telf due to hydraulic diffusivity impact and identifying total compressibility as the primary driver for extending transient production life. We also measure the MAE and RMSE with R2 to emphasize robust engineering expectations. Finally, we apply a permutation importance to analyze physical feature drivers of well production. The findings support the development of typical well profiles (TWPs) as predictive tools for future field development, aiming to transition unconventional reservoir management into data-driven and very active strategies.

Depleted shale gas reservoirs offer significant potential for large-scale H2 storage, thanks to their ample pore space, anaerobic environments, effective sealing conditions, and the ability to reuse existing surface and subsurface infrastructure. This study introduces a comprehensive model that incorporates multiple H2 transport mechanisms, intricate fracture networks, and multi-well horizontal pads. The model is solved semi-analytically using Pedrosa's substitution, Laplace transformation, and Stehfest inversion methods. To account for the interference effects from simultaneous H2 injection across multi-well horizontal pads, the superposition principle is employed. Building on this model, we present a workflow designed for the rapid assessment of hydrogen storage capacity (HSC) in depleted shale gas reservoirs. The Fuling shale gas reservoir in China is used as a case study, revealing a maximum HSC of 1.79 x 108 m3 under a constrained pressure of 40 MPa. The energy storage efficiency of UHS is 1.4 to 10.9 times greater than that of coal, light oil, and natural gas. Storing this amount of H2 can save between 1.7 x 106 and 2.14 x 107 USD compared to the aforementioned traditional energy sources. Additionally, H2 combustion can reduce CO2 emissions by 1.04 x 105 to 6.57 x 105 t and SO2 emissions by 7.72 to 1.74 x 104 t. Sensitivity analyses reveal that at low constrained pressure (LCP), the impact of factors such as the effective diffusion coefficient, storage ratio, and well number on HSC is relatively minor, with variations ranging from 1.6 % to 12.0 %. However, under high constrained pressure (HCP), these factors have a much more pronounced effect, leading to variations that range from 58.3 % up to 9.8 times.

The efficiency of CO2 trapping in geological formations is strongly influenced by their mineralogical composition and physical properties. This study investigates the geochemical interactions governing CO2 trapping in three distinct formations: basalt, carbonate, and sandstone. A three-dimensional reactive transport model was developed to simulate the long-term fate of injected CO2, incorporating key trapping mechanisms, including supercritical CO2 retention, dissolution in brine, and mineralization. Additionally, changes in formation porosity and the geomechanical response to injection were evaluated to assess potential reservoir alterations. Simulation results revealed significant variations in CO2 trapping behavior in different types of formations. In sandstone and carbonate formations, CO2 is primarily retained in its supercritical phase through structural and residual trapping, with dissolution contributing to a lesser extent. Mineral trapping is more pronounced in carbonate formations than in sandstone, but basalt exhibits the highest degree of CO2 mineralization, with mineral trapping eventually surpassing dissolution over extended time. This extensive mineralization in basalt leads to a reduction in porosity, with an observed maximum change of −0.001 porosity units, whereas carbonate formations show only minimal porosity alteration. In contrast, sandstone formations retain positive porosity changes, indicating limited mineral precipitation. Additionally, CO2 plume evolution differs among formations, with basalt formations demonstrating the most significant long-term shrinkage due to mineral trapping. A geomechanical analysis further indicated a localized subsidence of approximately 0.3 feet at the injection site, emphasizing the need to monitor formation stability. This study highlights the critical role of geochemical processes in CO2 storage and their implications for long-term containment. The findings provide essential insights into how formation mineralogy influences CO2 storage, aiding in the refinement of Area of Review (AoR) delineation and regulatory frameworks for Class VI permit applications. These results contribute to a more robust understanding of CO2 storage in diverse geological settings and support the advancement of carbon capture and storage (CCS) initiatives.

This study investigated pressure management strategies for Carbon storage project by evaluating brine production in saline aquifers. As carbon capture and storage efforts expand, particularly in the Gulf Coast region, effective pressure mitigation remains a critical challenge for ensuring safe and efficient CO2 injection. We examined the impact of key design parameter, including CO2 injection rates, brine production rates, producer count, and reinjection approaches, on pressure buildup, storage capacity, and geomechanical stability. We conducted a series of reservoir simulations to analyze different configurations of injector and producer wells, varying production rates, and alternative brine handling methods. The results show that increasing brine production rates led to a significant reduction in pressure buildup compared to cases without brine production. Additionally, distributing production across multiple wells further enhanced pressure relief, with three producers achieving the lowest pressure buildup. CO2 injection rates also strongly influenced reservoir behavior, as higher injection rates led to larger plume extents and increased pressure, requiring careful optimization. Beyond pressure mitigation, this study explored the implications of reinjecting produced brine into upper aquifer layers instead of external disposal. While reinjection minimizes water disposal challenges, it reduces available pore space for CO2 storage, leading to pressure behavior similar to that of cases without brine production. Regulatory constraints on brine disposal highlight the need to balance operational feasibility with policy compliance. Additionally, geomechanical analysis showed that subsidence and uplift are minimal under the conditions studied, with minor displacement changes stabilizing post-injection. These findings provide a framework to optimize brine production strategies in CCS projects, and they demonstrate how injection and withdrawal configurations influence both storage efficiency and pressure management. By integrating reservoir simulation with geomechanical evaluation, this study offers valuable insights for designing safe and effective CCS operations, addressing key technical and regulatory challenges in large-scale carbon storage projects.

Shale gas, as a clean, low-carbon, and abundant unconventional natural gas resource, plays a crucial role in achieving clean energy transformation and carbon neutrality. The Fuling shale gas reservoir in Sichuan Basin stands out as China's most promising area for shale gas exploration and recovery. However, the continuous recovery of shale gas in the southern Sichuan Basin has led to well interference events in hundreds of wells, with the furthest well distance reaching over 2000 m. This study introduces a multiscale approach for transient analysis of a multi-well horizontal pad with well interference in shale gas reservoirs. The approach utilizes Laplace transform technology, boundary element theory, and the finite difference method to address the complexities of the system. Well interference is managed using the pressure superposition principle. To validate the proposed multi-scale method, a commercial numerical simulator is employed. The comprehensive pressure behavior of a multi-well horizontal pad in a shale gas reservoir is analyzed, encompassing wellbore storage effect, skin effect, bilinear flow, linear flow,pseudo-radial flow of primary fractures, well interference period, dual-porosity flow, pseudo-radial flow of the total system, and boundary-dominated flow. A case study is conducted on the typical well, the well with the longest production history in the Fuling shale gas reservoir. The rate transient analysis is conducted to integrate up to 229 days of shale gas production daily data and wellhead pressure data,enabling the generation of pressure behavior under unit flow rate. The results indicate that the linear flow, transitional flow, and boundary-dominated flow are more likely to be observed in the actual data.Secondary fractures are considered to be the primary pathways for fluid migration during well interference events. The evaluated formation permeability is 2.58 × 10 -2 m D, the well spacing is 227.8 m, the diffusion coefficient is 1.49 × 10 -4 , and the skin factor is 0.09.

This study investigated the influence of reservoir and geomechanical properties on CO2 storage performance, focusing on trapping mechanisms, pressure evolution, displacement, and plume migration in saline aquifers of the Gulf Coast region. We conducted a numerical simulation and sensitivity analysis to evaluate how key parameters—such as permeability, porosity, Young's Modulus (YM), Poisson's Ratio (PR), and injection rates—affect CO2 containment and long-term storage security. We created a synthetic saline aquifer model simulating multiple cases using a compositional model to assess the impact of reservoir and geomechanical variability. Our sensitivity analysis examined multiple permeabilities, porosities, and different injection rates to evaluate their effects on pressure build-up, CO2 trapping efficiency, and geomechanical deformation. We used tornado charts to rank the relative influence of each parameter on key storage performance indicators. The results showed that permeability and porosity are primary controls on plume extent, pressure distribution, and residual trapping efficiency. Higher permeability cases led to greater CO2 migration and injection capacity, while lower permeability cases resulted in more localized containment and reduced injectivity. Geomechanical properties, particularly YM and PR, played a significant role in subsurface deformation, with softer formations exhibiting greater displacement. Pressure build-up was strongly influenced by porosity and stress anisotropy, though all cases remained within safe operating limits. This study provides a comprehensive framework to characterize reservoir-geomechanical interactions in CCS projects and should help to optimize injection strategies and improve long-term CO2 containment assessment. The findings contribute to enhancing storage security and minimizing leakage risks, offering valuable insights for future site development and monitoring strategies.

Underground gas storage (UGS) plays a critical role in addressing both regional and temporal discrepancies in energy supply and demand, and is a key strategy for optimizing the energy structure and achieving carbon neutrality. The presence of groundwater, coupled with simultaneous high-speed injection-withdrawal from multiple wells, leads to significant relative permeability hysteresis (RPH) and well interference effects. Here, a high-precision numerical model is developed to explore the impact of well interference and gas-water flow on pressure transient behavior (PTB). The model employs unstructured Voronoi grids for accurate mesh discretization and utilizes a discrete fracture network (DFN) model to simulate natural fractures in the formation. The results indicate that the PTB during gas-water injection-withdrawal is positively correlated with the number of cycles, and is reflected in phenomena such as skin effects, radial flow, matrix-fracture flow, well interference flow, and total radial flow. When the gas relative permeability at irreducible water saturation (G-IWS) increases from 0.4 to 0.7, the gas storage capacity (GSC) increases by a factor of 5.9. By contrast, increasing the water relative permeability at residual gas saturation (W-RGS) by 4-fold only results in a 2.05-fold increase in GSC. Moreover, when the residual gas saturation (RGS) increases from 0.10 to 0.30, the GSC decreases by a factor of 1.41. By fitting to field data from China's largest UGS site at Hutubi, the reservoir permeability, initial water saturation, initial pressure, skin factor, and well storage coefficient were estimated to be 8.5 mD, 0.3, 30 MPa, -3, and 0.32 m3/MPa, respectively.

This paper describes a comprehensive subsurface work guide to define the Area of Review (AoR), an important component for Carbon Capture and Storage (CCS) projects to obtain the US Environmental Protection Agency (EPA) Class VI permit. Accurately understanding and assessing the AoR helps to avoid risking the underground sources of drinking water (USDW) from potential contamination with CO2. Delineating the AoR also prevents CO2 lateral leakage outside the allocated land lease, resulting in secure regulatory compliance. In this study, a 3D numerical model that represents saline aquifer in the Texas Gulf Coast area is developed using available geological geophysical and well logs in the area. We examined different development scenarios for sequestrating CO2 for 20 years, including multiple injections and pressure management strategies through aquifer water production, to determine the extent to which the CO2 and pressure plumes circulate over time. We conducted a sensitivity analysis to assess the impact of various subsurface conditions and design parameters on the movement of the plume and, thus, AoR determination. Results showed that although the four scenarios considered could achieve the target of storing up to 33 million metric tonnes (MMT) of CO2, the AoR definition varied depending on the development plan. The work aimed to minimize the AoR as soon as possible, with the completion design used in addition to brine production from the aquifer. To avoid the potential hazard of the AoR extending to the risky legacy well, we proposed several mitigation plans, including dividing injection into two injectors at different locations within the project site and discovering opportunities to produce brine to manage the pressure buildup. The best scenario was selected, and it reflected the advantage of combining various strategies optimized well placement, water production through two producers and injecting using the upper hole recompletion method. Beyond pressure and plume control, the study investigated the impact of the trapping mechanisms on the redefinition of the AoR and thus enhanced long-term containment and security. This presented work, which incorporates analytical and numerical approaches, guides the evaluation of CCS projects established in challenging sites with (1) a high density of existing wellbores, (2) geological uncertainty, and (3) potential environmental risk. To the best of our knowledge, this is the first comprehensive work that targets AoR definition while considering strategies of pressure management and optimized completion design to balance containment and operational feasibility, potentially leading to approved Class VI permits and ultimately successful CCS projects.

This paper introduces a robust framework for applying multi-segment Arps production decline models, specifically for ultra-low-permeability resource development with multi-fractured horizontal wells. In contrast to the industry’s common use of two- or three-segment Arps models for production forecasting, this study outlines four distinct flow regimes: early ramp-up, transient flow with constant b, transition flow over a log cycle with continuously changing b, and boundary-dominated flow with constant b (typically 0.3 < b < 0.5). The methodology estimates the durations of these flow regimes and predicts their start and end times, significantly enhancing individual well forecast accuracy. Additionally, the paper suggests a simple approach to scale production histories from wells to common reference conditions, including average permeability in the stimulated reservoir volume, fracture half-length, stage spacing, and lateral length. It involves identifying transient flow end time, comparing observed and dimensionless rates in Wattenbarger’s solution. This technique adeptly handles variations among wells in a region, crucial for constructing representative type wells and minimizing uncertainty in statistical analyses. This is achieved by expressing transient linear flow variables in dimensionless terms, enabling the normalization of rate-time profiles to selected reference conditions, ultimately proving effective in constructing representative type-well production profiles from groups of analog wells. Determining the end of transient flow presents a challenge, with permeability estimates reflecting an average across fracture stages influenced by treatments introducing microfractures and re-opened natural fractures. We also advise caution in interpreting fracture half-length. Further research is needed to explore the impact of production from outside the stimulated reservoir volume, inter-well interference, and to validate scaling methods in other oil fields.

Complex fracture networks generated by fracturing treatments and the gas-water flow have intensified the well interference in shale gas reservoirs. In this paper, a high-precision numerical model is developed to capture the effects of well interference and gas-water flow on pressure transient behaviors of multi-horizontal-well pads. The unstructured Voronoi grid approach is employed to discretize the physical model. The model's accuracy is verified through published analytical solutions. The findings reveal that a multi-horizontal-well pad in shale gas reservoirs can exhibit up to ten distinct flow regimes. An increase in residual water saturation reduces the water flow ability and leads to an earlier commencement of the gas-water flow regime. Once the formation water becomes flowable, higher water saturation delays the initiation of all flow regimes. The well interference regime exhibits characteristics of the linear flow due to the increased well spacing. As fracture propagation leads to the well communication, the effect of fracture half-length on pressure transient behaviors becomes negligible. The case study from the Fuling shale gas reservoir demonstrates that the proposed model achieves a satisfactory fit to the actual pressure data and the pressure transient behaviors manifest a typical boundary-dominated flow regime.

Due to high energy density, clean combustion products and abundant resources, natural gas hydrates (NGHs) have been regarded as an important clean energy source with the potential for large-scale development and utilization. However, pilot tests in NGHs show that their production rates are far below commercial needs. Multilateral well technology may lead to a solution to this problem because it can dramatically expand the drainage area of production wells. This paper presents the practical rate transient analysis for multilateral horizontal wells in NGHs. In developing solution to the diffusivity equation of multilateral horizontal wells in NGHs, the superposition principle and reciprocity are applied. We wrote the governing equation in cylindrical coordinates to describe the NGH flow process. We used the moving boundaries and dissociation coefficients to model the solid-to-gas transition process in hydrates. To obtain solutions for flow in hydrate reservoirs, we used Laplace transforms and the Stehfest numerical inversion method. Superposition principle and Gaussian elimination are applied to obtain the desired solution for multilateral horizontal wells. We validated our proposed model with a commercial numerical simulator. By performing sensitivity analyses, effects on production behavior of the number of branches, dissociation coefficient, radius of the region with dissociated hydrate, and dispersion ratio are determined. A synthetic case study is conducted to show the typical production behaviors.

Large-scale underground natural gas storage (UNGS) facilities typically allocate only one month annually for well shut-in to facilitate pressure build-up. This limited well shut-in period affects the subsequent pressure measurements and evaluation of gas storage capacity. This study proposes a novel workflow to directly predict the transient pressure behavior of UNGS during pressure build-up without requiring additional well shut-in operations. The proposed workflow uses the gas injection-withdrawal rate as a dynamic input feature for a deep learning model, with reservoir pressure as the output feature. An enhanced WA-BiLSTM model integrates multiple physical mechanisms and advanced optimization algorithms. The model achieves mean squared error (MSE) of 2 x 10-3, which is less than 5 % of traditional model's results. Field data from the largest Hutubi UNGS exhibit a prediction accuracy of 99.0 % during the well shut-in phase. High-precision prediction results with low MSE ensure the reliability of pressure derivative data. By analyzing the predicted pressure data, the actual gas storage volume is 104.75 x 108 m3, accounting for 97.9 % of the facility's designated storage capacity.

Horizontal multi-well pads are frequently used in unconventional reservoirs. Along with infill wells and hydraulic fracturing, interference between multiple multi-fractured horizontal wells (MFHWs) has become a major concern. The current rate transient analysis (RTA) makes the assumption that the unconventional formation contains a single MFHW. This study introduces a novel multi-MFHW solution and associated analysis methodology for analyzing the performance of targeted well rates in a multi-MFHW system. The constant bottom-hole pressure (BHP) condition and the Laplace transform can be used to obtain multi-MFHW solutions for transient flow. We investigated interference between various fractures and MFHWs using the superposition of various constant BHP solutions. The variable BHP of the targeted well is calculated using a variable dimensionless BHP function in the Laplace domain without performing any convolution or deconvolution. The proposed method is rigorously validated using a commercial numerical simulator for cases involving offset MFHWs and multi-MFHW with variable BHP. With this multi-MFHW analysis, we can analyze a target well in the pad using the total material balance of the multi-MFHW system. Offset well interference frequently occurs following the onset of infinite-acting radial flow (IARF) in the target well's hydraulic fracture. It results in an increase in the pressure derivative curves for elliptical flow and IARF, as well as the rate-normalized pressure (RNP) derivative. Inverse semi-log derivatives exhibit the inverse trend. The proposed deviation pressure integral and RNP can be used to diagnose the flow region caused by the offset well's flow rate in a unique manner, displaying the horizontal line, V-shaped dip, and unit slope, respectively, during IARF, cross flow, and boundary-dominated flow (BDF). Sensitivity analysis of well spacing demonstrates that as well spacing increases, the "transition flow" between wells transitions from elliptical to formation linear flow and can exhibit transitional flow characteristics in more common cases.

Summary This paper incorporates the findings of our previous publication (Morales and Lee 2022) and identifies, isolates, and quantifies elements in the annually disclosed proved reserves revisions that should not be considered technical or economic revisions. This has resulted in significantly different technical and economic revisions compared to those simplistically and directly derived using a common interpretation of the Financial Accounting Standards Board (FASB) Topic 932-235-50-5 (a) definition. We have assessed the reliability and comparability of the updated technical revisions when used to judge the reasonable certainty of the underlying proved reserves. We have carried out the analysis separating the proved reserves into developed and undeveloped. To derive a realistic data set to generate the updated technical and economic revisions, we reviewed more than 1,000 annual reports (10K and 20F Forms) and more than 600 comment letters from 141 companies filing annual reports to the Securities and Exchange Commission (SEC) during the period 2010–2020, extracting the information related to annual reserves changes and explicitly focusing on the disclosed revisions of previous estimates (RPE). We present evidence showing that the approach followed is robust and more reliable than the simple approach where technical revisions are estimated by simply subtracting the disclosed revisions due to price effects from the disclosed revisions in annual reports. The root causes for the significant differences between the simplistic approach and the one presented in this paper are mainly due to (1) including annual reserves changes due to nontechnical or economic factors as technical revisions, (2) using different interpretations of SEC and FASB regulations, and (3) not providing critical disaggregation information needed to estimate technical, economic, or other types of revisions correctly. Without proper consideration of these issues, the derived technical and economic revisions from disclosed data can be significantly distorted, affecting any conclusions derived. The annual average changes in technical revisions during a representative period, if correctly estimated, can provide an indication of both overstated and understated certainty of proved reserves estimates, which can impact a company’s relative valuation, asset impairment, internal depreciation, profit/loss, standardized measure, unit development costs, and other indicators based on proved reserves, making the reliability of the technical revisions and their actual upward or downward movements of paramount importance. We also highlight the significant different root causes driving the major differences between developed and undeveloped reserves in their annual technical revisions. The results indicate that for some companies that provide most of the information required for proper analysis, the certainty level of their disclosed developed and undeveloped proved reserves points toward an apparent overestimation of historically disclosed proved reserves. Our analysis shows the dubious quality and lack of reliability and comparability of the disclosed proved reserves revisions and highlights the limited value of existing guidance and current practices. We provide evidence that calls for FASB and SEC to provide complementary guidance in critical areas that currently limit the value, reliability, and comparability of the proved reserves revisions disclosed.

Underground natural gas storage (UGS) serves as an environmentally sustainable remedy for mitigating regional and temporal disparities in energy supply and demand. The phenomenon of substantial well interference and non-uniform pressure distributions in UGS, resulting from high injection and withdrawal rates, requires a comprehensive examination. This study presents an analytical model aimed at investigating the ramifications of well interference on transient pressure dynamics during UGS. Employing the Laplace transform method, an analytical framework for diverse wells within UGS is derived, with well interference effects being effectively incorporated through the application of the superposition principle. To validate the proposed analytical solutions under various scenarios, a commercial numerical simulator is employed. The analysis reveals that when an adjacent well is engaged in gas withdrawal, interference induces an initial rise in pressure derivative followed by a subsequent plateau. Conversely, during gas injection into an adjacent well, the pressure derivative curve exhibits a continuous decline, akin to situations characterized by constant pressure boundaries. Notably, the likelihood of interference with a target well is more pronounced when gas injection or production occurs in a vertical well as opposed to a horizontal one. Preliminary data from the Hutubi UGS in China, one of the largest projects of its kind, indicate cumulative gas injection and withdrawal volumes of 155.43 x 108 m3 and 130.81 x 108 m3, respectively, with a maximum storage capacity of 107 x 108 m3. Ultimately, the gas storage volume reaches 93.50% of the UGS's designated capacity. This substantial quantity of stored natural gas equates to the calorific value of 9.88 x 109 kg of crude oil or 1.29 x 1010 kg of coal. In comparison to conventional fossil fuels such as oil and coal, the utilization of natural gas in the Hutubi UGS results in a significant reduction of carbon dioxide emissions, amounting to 1.04 x 1010 kg and 1.38 x 1010 kg, respectively. This contribution advances the field by proposing an analytical model for the systematic analysis of well interference on pressure dynamics within the Hutubi UGS, thereby facilitating the transition from oil and coal to natural gas, a crucial step in the pursuit of cleaner and more sustainable energy production practises.

This paper presents a new semi-analytical solution and the related methodology to analyze the pressure behavior of multi-branch wells produced from natural gas hydrates. For constant bottom-hole pressure production, the transient flow solution is obtained by Laplace transforms. The interference among various branches is investigated using the superposition principle. A simplified form of the proposed model is validated using published analytical solutions. The complete flow profile can be divided into nine distinct regimes: wellbore storage and skin, vertical radial flow, linear flow, pseudo-radial flow, composite flow, dissociated flow, transitional flow, improvement flow and stress-sensitive flow. A well's multi-branch structure governs the vertical radial and the linear flow regimes. In our model, a dynamic interface divides the natural gas hydrates deposit into dissociated and non-dissociated regions. Natural gas hydrates formation properties govern the composite-effect, dissociated, transitional, and improvement flow regimes. A dissociation coefficient governs the difference in flow resistance between dissociated and non-dissociated natural gas hydrates regions. The dissociated-zone radius affects the timing of these flow regimes. Conversion of natural gas hydrates to natural gas becomes instantaneous as the dissociation coefficient increases. The pressure derivative exhibits the same features as a homogeneous formation. The natural gas hydrates parameter values in the Shenhu area of the South China Sea cause the prominent dissociated flow regime to conceal the later transitional and improvement flow regimes. Due to the maximum practical well-test duration limitation, the first five flow regimes (through composite flow) are more likely to appear in practice than later flow regimes.

Due to high energy density, clean combustion products and abundant resources, natural gas hydrates (NGHs) have been regarded as an important clean energy source with the potential for large-scale development and utilization. However, pilot tests in NGHs show that their production rates are far below commercial needs. Multilateral well technology may lead to a solution to this problem because it can dramatically expand the drainage area of production wells. This paper presents a practical production model for multilateral horizontal wells in NGHs. In developing our solution to the diffusivity equation to model this process, we applied the superposition principle and reciprocity. We wrote the governing equation in cylindrical coordinates to describe the natural gas hydrate flow process. We used moving boundaries and dissociation coefficients to model the solid-to-gas transition process in hydrates. We used Laplace transforms and the Stehfest numerical inversion method to obtain solutions for flow in hydrate reservoirs. We applied the superposition principle and Gaussian elimination to obtain the desired solution for multilateral horizontal wells. We validated our proposed model with a commercial numerical simulator. We also performed sensitivity analyses to determine the effects on production behavior of the number of branches, dissociation coefficient, radius of the region with dissociated hydrate, and dispersion ratio. We used properties from the Nankai Trough as inputs in a case study we conducted.

Multilateral well is a promising solution to increase natural gas hydrate (NGH) production. To simplify the production prediction of multilateral wells in NGH, this paper proposes a meshless method. The moving boundary divides the hydrate reservoir into an expanded dissociated region and an original formation. The Laplace transform and the Stehfest inversion method are used to obtain the solution of dual-porosity media in the dissociated region and the outer original formation with different flow abilities. The superposition principle is chosen to handle the interference effect among various branches. A numerical verification in the commercial simulator is performed. The case study from Shenhu area and the sensitivity analysis show that the production behaviors can be divided into three stages. The first stage of rapid production decline is controlled by the structure of multilateral wells. The second stage reflects the gas flow from matrix to natural fractures in the dissociated region and the dissociation of hydrate to natural gas in the original formation. The third stage is mainly affected by the original reservoir properties and hydrate decomposition. Since the proposed method does not require mesh generation, it has advantages in computational performance and convergence compared with traditional numerical techniques.

Carbon neutrality necessitates cleaner and more efficient use of fossil fuels. The storage of substantial amounts of energy in porous subsurfaces, such as underground natural gas storage (UGS), which is regarded the only longterm energy storage solution, is one of the promising technologies. Appropriate monitoring mechanisms are necessary for the security of UGS with a correctly configured injection-withdrawal capacity. In this research, a semi-analytical model of multi-horizontal well systems is presented and used to large-scale underground natural gas storage. The Laplace transform and Stehfest numerical inversion are used in UGS to solve the radial diffusion equation. We used the line source function and the pressure superposition principle to find a solution for a multihorizontal well system. To illustrate the reliability of the suggested method, a numerical verification was performed. In UGS, pressure behavior at various phases identifies several types of flow regions, including wellbore storage effect stage, skin effect stage, early radial flow stage, linear flow stage, transitional flow stage, and late radial flow stage. Continuous gas injection and withdrawal from offset wells might result in pressure behavior with rising or dropping features when compared to a single well model. The evaluated permeability is 0.68 mD, the well spacing is 502 m, and the initial pressure is 27.28 MPa, according to field data from China's largest Hutubi UGS. The maximum injection and withdrawal capacities for wells with and without interference with wells are 9.46 x 105 and 1.1 x 106 m3/d/MPa, respectively, according to the productivity index. By continually injecting gas from offsetting wells, the target well's potential gas withdrawal capacity is raised by 16.2 %.

The complex fracture networks in shale gas reservoirs bring greater challenges and uncertainties to the modeling in reservoir evaluation. As the emerging potential technology, deep learning can be usefully applied to many aspects of reservoir evaluation. To further conduct the reservoir evaluation in rate transient analysis, this work proposes a data-driven proxy model for accurately evaluating the horizontal wells with complex fracture networks in shales. The production time, variable bottom hole pressure, and the fracture networks properties are used as input variables, while the output variable refers to the production for the forecast time period. The data from boundary element method is used to generate the proxy model for the learning process. The method of shuffled cross-validation is used to increase the model's accuracy and generalizability. The proxy model is coupled with recently developed deep learning methods such as attention mechanism, skip connection, and cross-validation to address the time series analysis problem for multivariate operating and physical parameters. Results demonstrate that the attention mechanism is robust. The operating parameters analysis shows that the attention mechanism has the ability to analyze variable pressure drop/flowrate data. Sensitivity analysis also indicates that the model takes into account the geometric characteristics of fracture network. The model reliability is proved by a case study from Marcellus shale. The computation time of the trained attention mechanism model is approximately 0.3 s, which equates to 3.8% of the physical model's running time.