Fractured Reservoir Research Articles

Integrated modelling of CO2 plume geothermal energy systems in carbonate reservoirs: Technology, operations, economics and sustainability

The rising CO2 content in the atmosphere calls for urgent decarbonization efforts. Carbon capture and storage (CCS) have proven effective in storing large volumes of CO2 in geological reservoirs. Nevertheless, challenges persist in identifying sustainable energy sources and efficient storage sites, especially in carbonate reservoirs. This study aims to characterize the Miocene carbonate reservoir in the Jintan Megaplatform, for CO2 storage and geothermal energy utilization. By integrating advanced technologies such as CO2 Plume Geothermal (CPG) with 3D seismic techniques, borehole analysis and numerical modelling, the study reveals the distribution of critical reservoir characteristics, including architecture, heterogeneity, karstification, fractures, porosity, permeability, temperature and pressure that are paramount for CO2 plume and energy production. The reservoir is estimated to store over 31 Gt of CO2, produce 3.824 × 1018 J of geothermal energy and ⁓44.3 GW of power. This power output can be utilized for electrification of the CCS operations, industrial and municipals, potentially generating over $1.4 billion in revenue. A flow-through model has been proposed to improve energy efficiency, reservoir management, and risk mitigation. This study advances to achieving net-zero targets and the United Nations Sustainable Development Goals on clean energy, climate action and sustainable communities.

Diagenesis including cataclastic band development in the Permian Penrith Sandstone, Vale of Eden Basin, England

Diagenesis in the Penrith Sandstone is characterized by early hematite and mixed illite/smectite cementation, followed by burial compaction, feldspar and two episodes of quartz cementation. The primary quartz overgrowths are characterized by heterogenous luminescence; however, the secondary quartz overgrowths are characterized by thinner and darker luminescence. Cataclasis post-dates primary quartz cementation, and significantly reduces grain and pore aperture size. The apex of mercury volume for a deformed sample was reduced up to three times in comparison with the undeformed rock. Dissolution occurred during cataclasis as authigenic hematite was removed in deformation zones, improving pore aperture size and consequently enhancing sandstone porosity and permeability. Recent fracturing created fractured-pores and improved porosity and permeability in tight cataclastic samples. Evidence for syn-cataclastic dissolution is observed in the samples studied. This is indicated by the dissolution of authigenic feldspars and the enhancement of poroperm parameters adjacent to cataclastic zones and the absence of hematite cement within them. Based on those the sequence of diagenetic evolution in the Penrith Sandstone can be reconstructed. Host samples were characterized by good to very good poroperm values, varying between 20 and 24% porosity and from 809÷1445 mD permeability. Cataclastic core plugs have 13÷21% porosity and 0.12÷39 mD permeability. The porosity reduction by cataclasis was estimated to be as much as 4.5% on average. Fracturing and dissolution improved poroperm parameters in studied samples. Recently fractured core plugs have about 292 mD permeability on average. Dissolution-cataclastic samples have 32% porosity and 18 mD permeability, whereas dissolution-host samples have 31% porosity and maximum permeability as much as 2469 mD on average. Cataclasis occurred in combination with in situ significant reservoir dissolution and fracturing may improve a sandstone reservoir in excellent quality.

An improved mathematical model of gas–water two-phase flows in fractured horizontal wells accounting for physical contact behaviors of fractures with total factor characteristics

In water-bearing gas reservoirs, water existence affects gas production performances due to two-phase flows occurring in matrix and fracture systems. Under the background of staged multi-cluster fractured horizontal wells, this work focuses on an improved gas–water two-phase flow model accounting for physical contact behaviors of fractures with total factor characteristics. Combining a point-convergence method with fractal theory and applying Laplace transform and Stehfest numerical inversion, analytical solutions of this proposed model are solved to validate against the field production data and numerical simulation results. Subsequently, the analytical nephograms of formation pressure and water saturation at different stages are given for the first time, throughout which formation pressure and water saturation distributions at different locations of the fractured reservoir embedded with segmented multi-cluster tree-shaped fracture networks are visually exhibited. The results demonstrate that draining area evolution is limited to each segment at early stage and mid-stage, whereas these multi-cluster segments are really integrated into the whole draining area at late stage. Thus, the moving boundary of fracture-controlled unit is also delineated based on water saturation nephograms and expands with continuous production from 65 to 180 m in the y axis direction, contributing to the effective fracturing area for a high productivity. Furthermore, the share of free gas and adsorbed gas are 83% and 17% at early stage, while free gas and adsorbed gas account for 57% and 43% of total gas at the late stage. Those findings contribute to high-efficient and sustainable development of unconventional gas resources.

Application of CO2-Soluble Polymer-Based Blowing Agent to Improve Supercritical CO2 Replacement in Low-Permeability Fractured Reservoirs.

Since reservoirs with permeability less than 10 mD are characterized by high injection difficulty, high-pressure drop loss, and low pore throat mobilization during the water drive process, CO2 is often used for development in actual production to reduce the injection difficulty and carbon emission simultaneously. However, microfractures are usually developed in low-permeability reservoirs, which further reduces the injection difficulty of the driving medium. At the same time, this makes the injected gas flow very fast, while the gas utilization rate is low, resulting in a low degree of recovery. This paper conducted a series of studies on the displacement effect of CO2-soluble foaming systems in low-permeability fractured reservoirs (the permeability of the core matrix is about 0.25 mD). For the two CO2-soluble blowing agents CG-1 and CG-2, the effects of the CO2 phase state, water content, and oil content on static foaming performance were first investigated; then, a more effective blowing agent was preferred for the replacement experiments according to the foaming results; and finally, the effects of the blowing agents on sealing and improving the recovery degree of a fully open fractured core were investigated at different injection rates and concentrations, and the injection parameters were optimized. The results show that CG-1 still has good foaming performance under low water volume and various oil contents and can be used in subsequent fractured core replacement experiments. After selecting the injection rate and concentration, the blowing agent can be used in subsequent fractured cores under injection conditions of 0.6 mL/min and 2.80%. In injection conditions, the foaming agent can achieve an 83.7% blocking rate and improve the extraction degree by 12.02%. The research content of this paper can provide data support for the application effect of a CO2-soluble blowing agent in a fractured core.

Geomechanics Modeling of Strain-Based Pressure Estimates: Insights from Distributed Fiber Optic Strain Measurements

Summary Rayleigh frequency shift distributed strain sensing (RFS-DSS) has been demonstrated as a potential technology for characterizing fracture geometries and optimizing the completion design in unconventional reservoirs. The combination of RFS-DSS strain and pressure gauge measurements has been reported recently in field applications (Dhuldhoya and Friehauf 2022; Haustveit and Haffener 2023) to characterize conductive fracture dimensions and production profiles. Haustveit and Haffener (2023) demonstrated a novel technique that uses RFS-DSS strain change during production, measured from a far-field observation well, to monitor the drain profile of a horizontal multistage well. The strain change and pressure change were strongly related during production, and this relationship was applied to continuously estimate pressure drawdown along the full length of the well. However, the sensitivity or influencing factors of the relationship between strain change and pressure change along the fiber are not yet fully understood. Therefore, the main objective of this study is to investigate the relationship between strain change and pressure change under various fractured reservoir conditions and provide guidelines for better utilizing this novel strain-pressure relationship to estimate conductive fractures and pressure profiles. We use a coupled geomechanics and fluid flow model to simulate the strain and pressure changes in the near-well and far-field regions during stable production and shut-in periods. A linear relationship is used to fit the strain change and pressure change data obtained from both producing and monitoring wells. We analyze the impact of various fracture properties [size and permeability of the stimulated reservoir volume (SRV) around fractures, fracture conductivity, fracture area, and skin factor] on the linear relationship based on the R2 value and fitting error. The relationship between the strain change and pressure change during the stable production obtained by our numerical study is consistent with the field measurements. The slope of strain change vs. pressure change during one day of production is significantly influenced by fracture properties. Overall, the monitoring well shows a stronger linear relationship than the producing well during both stable production and shut-in periods. A better linear relationship between the strain change and pressure change is associated with a larger fracture conductivity or larger fracture spacing scenario on both producing and monitoring wells during the stable production period. The cluster spacing affects the linear relationship between strain and pressure change during rock deformation. When cluster spacing is reduced, the nonlocal effect of deformation becomes more pronounced, resulting in a weaker linear relationship. During the shut-in period, the monitoring well exhibits a stronger linear relationship with a high R2 value and small fitting error compared to the producing well. The linear relationship obtained during the shut-in period is less reliable for the producing well. In cases of homogeneous fractures, where the fracture properties are uniform, the strain change and pressure change are similar, except for two outer fractures. This study provides a better understanding of the relationship between strain change and pressure change measured in the near-well and far-field regions during stable production and shut-in periods. The results of our study also demonstrate the potential for utilizing the RFS-DSS strain measurement to characterize the effective fracture and drainage dimensions.

Superposition Rate: A Developed Approach for Analyzing Production Data in Tight Gas Reservoirs

The paper examines the application of various methods to analyze production data in which the superposition principle being one of them. This principle is divided into two main methods: Superposition rate and Superposition time. Both are designed to deal with multiple flow rates within production data. The Superposition time converts the production time into constant values and uses the final flow rate value. On the other hand Superposition rate consolidates multiple rates into a single flow rate during production time. This study focuses on analysis of production data using a developed method based on superposition-rate approach. This method converts variables such as flow rate and pressure into constant values, where each flow regime has its own technique by which superposition-rate is utilized. In addition, comparison between conventional and unconventional reservoirs is involved, particularly emphasizing the benefits and drawbacks of tight gas reservoirs.Various types of superposition methods with their functions were discussed. Among them, a workflow part includes a case study of a dominated flow regime used for a hydraulic fractured single well. The workflow part of this study includes a case study of hydraulically fractured well under a dominant flow regime. Results comparing multiple rates method with super position-rate method indicate that the latter has better accuracy with (R) coefficient of (0.96). Case study on fracture reservoir also shows further validated of superposition-rate by accurately estimating drainage volume.

Propagation of interfered hydraulic fractures by alternated radial-circumferential extensions and its impact on proppant distribution

The fracture extension mechanisms and proppant transport characteristics play key roles for optimizing hydraulic fracturing in unconventional reservoirs. In this work, the visual physical simulation method was used to analyze the 3D dynamic extension processes of multi-stage hydraulic fractures and the subsequent impact on proppant distribution. The interfered fracture in multi-stage hydraulic fracturing exhibit alternated radial-circumferential extension behavior. More specifically, these behavior changes from unilaterally radial initiation, circumferential extension to radial extension. Unilaterally radial initiation results in the formation of both mirror and conchoidal features, while circumferential extension leads to stepped feature, and radial extension gives rise to feather feature. The four features of hydraulic fractures result in four types of non-uniform proppant distribution: uniform, scattered, cluster, and regional distribution. The proppant transport shifted from linear to radial mode, promoting further fracture extension. The effects of segment spacing and proppant injection sequence were studied. The results showed that the influence on the interfered fracture decreases as the segment spacing increases. In addition, the propped fracture area is larger when the small-size proppant is injected first, followed by large-size one. The research can improve understanding and optimization of multi-stage hydraulic fracturing in unconventional oil and gas reservoirs.

A Morphological Method for Predicting Permeability in Fractured Tight Sandstone Reservoirs Based on Electrical Imaging Logging Porosity Spectrum

Summary Permeability is a crucial parameter in formation evaluation, which reflects reservoir fluid mobility and directly influences subsequent development and production. In conventional to tight sandstone formations without fractures, numerous methods have been developed to predict permeability. However, permeability prediction accuracy based on the current method is low in fractured tight sandstone reservoirs due to the influence of heterogeneity, and little research is focused on permeability evaluation in such reservoirs. Conventional wireline and nuclear magnetic resonance (NMR) logging lose their role in fracture parameter evaluation, whereas electrical imaging logging is available for reflecting fracture information. Hence, we adopt electrical imaging logging, instead of conventional wireline and NMR logging, to predict permeability in fractured tight sandstone reservoirs. In this study, we propose a morphological method for permeability prediction using electrical imaging logging. Initially, we process the electrical imaging logging data to obtain the porosity spectra and determine the peak of the primary porosity spectrum. We then extract the mean and standard deviation of the primary porosity spectrum based on its distribution morphology. Meanwhile, we also use the normal distribution function to fit the primary porosity spectrum and accumulate the amplitudes of the original and fitted porosity spectra, respectively. When the cumulative amplitude of the fitted spectra stabilizes, the corresponding porosity indicates the boundary between primary and secondary pores. This boundary allows us to calculate the proportion of primary pores to total pores. Permeability in fractured tight sandstone formations is influenced by both primary and secondary pores, showing a strong correlation with the proportion of primary porosity. Finally, we establish a permeability prediction model based on total porosity and the proportion of matrix pores. The reliability of our established permeability evaluation model is confirmed by comparing the predicted permeabilities with core-derived results in the Triassic Chang 63 Member of the Jiyuan area in the Ordos Basin. In unfractured formations, the predicted permeability based on our raised model closely matches the results derived solely from total porosity. In fractured formations, however, the calculated permeability using our proposed model aligns more closely with the core-derived result, while predictions based on current and NMR models tend to underestimate permeability.

Dynamic prediction of fracture propagation in horizontal well hydraulic fracturing: A data-driven approach for geo-energy exploitation

Accurate and efficient prediction of hydraulic fracturing fracture propagation is of utmost importance for unconventional reservoir development. Traditional numerical simulation methods require specialized domain knowledge and technical expertise, and machine learning approach can be an alternative predictive tool for fracture propagation. Additionally, existing neural networks cannot be directly applied to hydraulic fracturing scenarios influenced by multiple coupled factors. Thus, this study presents an innovative approach, “AE-ATT-ConvLSTM”, that integrates an additional Convolutional Layer, Autoencoder, and an Attention Mechanism Feature Fusion Layer into the architecture of a Convolutional Long Short-Term Memory (ConvLSTM) sequential image prediction network. This approach aims to predict fracture propagations in different fracturing stages of horizontal wells. The proposed model is trained on a sample dataset consisting of 5000 instances of hydraulic fracturing in horizontal wells. The dataset includes crucial data such as fracture propagation images, wellbore perforation images, natural fracture images, pumping schedules, and reservoir properties. The model achieves remarkable results, with an MSE less than 15 × 10−5, a maximum SSIM of 0.93, and an average FMAE less than 48. The research findings demonstrate that this method significantly enhances prediction efficiency and provides new insights for predicting fracture morphology and optimizing fracturing design.

Life Cycle Optimization of CO2 Huff ’n’ Puff in Shale Oil Reservoir Coupling Carbon Tax and Embedded Discrete Fracture Model

Summary Amidst escalating environmental pressures, energy-intensive industries, particularly the oil and gas sector, are compelled to transition toward sustainable and low-carbon operations, adhering to the constraints of the environmental economy. While conventional reservoirs have been extensively developed, unconventional reservoirs, such as shale reservoirs, are poised to be the focal point in the future. Carbon dioxide enhanced oil recovery (CO2-EOR), a potent development tool proven effective in shale reservoirs, offers substantial carbon storage potential while significantly augmenting production. However, prior studies have solely optimized shale oil CO2-EOR production based on a singular optimization algorithm with net present value (NPV) as the objective function. In this study, we propose a novel NPV concept incorporating a carbon tax, which incorporates carbon taxes regulated by governments or organizations, thereby guiding carbon offsetting in oil reservoirs. We employ the embedded discrete fracture model (EDFM) approach to strike a balance between the accuracy of shale reservoir fracture simulation and computational efficiency, thereby enhancing timely technical guidance in the field. Subsequently, we compare the existing mainstream reservoir optimization algorithms and introduce a novel life cycle CO2 huff ’n’ puff (HnP) optimization workflow based on low-carbon NPV. The optimized NPV of the target reservoir witnessed an increase of 116.30%, while the optimization time was reduced by 89.47%, and the CO2 storage capacity was augmented by 12.58%. The workflow accelerates the simulation of the CO2 HnP in shale reservoirs, optimizing the production efficiency and CO2 storage capacity of shale reservoirs, and facilitating comprehensive and efficient production guidance for the production site.

Numerical simulation of CO2-ECBM for deep coal reservoir with strong stress sensitivity

CH4 production rate of coalbed methane (CBM) well decreases rapidly during primary recovery in the deeply buried coal seam, resulting in a lot of CH4 residues. CO2 pour into deep coal seam with high stress sensitivity is available for enhancing CH4 recovery by improving permeability for reservoir fracture and displacing CH4 adsorbed in matrix. A coupled adsorp-hydro-thermo-mechanical (AHTM) model for deep methane development is established by considering the coupling relationships of non-isothermal and non-constant pressure competitive adsorption between CO2 and CH4, multi-phase flow, unsteady diffusion, heat transmission and in-situ stress variety. The model is verified by historical production and then used for CO2 enhanced CBM (CO2-ECBM) of deep coal reservoir in a sedimentary basin in Northwest China. The simulation results show that: (1) For primary recovery, permeability in coal reservoir drops rapidly with the development of CBM, which seriously restricts the production of CH4. The permeability of the reservoir decreases from 7.89 × 10−16 m2 to less than 1.50 × 10−16 m2, CH4 production rate in CBM well reduces to below 2000 m3/d, and the average total CH4 content of coal reservoir is reduced by 5.49 m3/t with the decrease of only 1.12 m3/t of average adsorbed CH4 in a production duration of 2000 d (2) With 10 MPa CO2 continuous injection into coal seam after 700d of primary, the permeability for reservoir and CH4 production rate increase while the total CH4 content and adsorption CH4 content in reservoir decrease compared with the primary recovery. (3) CO2 pouring into coal reservoir increases the CH4 production time and rate, which improves CH4 recovery of coal reservoir. And it increases by 23.36 %, 23.07 % and 22.46 % with shut-in thresholds of CH4 production rate of 1000 m3/d, 800 m3/d and 600 m3/d, respectively. The investigation is of great significance for the development of deep coalbed methane.

Study on enhanced oil recovery improvement of fractured tight reservoir at extra high water cut stage

Study on enhanced oil recovery improvement of fractured tight reservoir at extra high water cut stage

Study on the Fracture Extension Pattern of Shale Reservoir Fracturing under the Influence of Mineral Content.

This study aimed to investigate the effect of the microstructure of shale on fracture initiation and extension during hydraulic fracturing. The Longmaxi Formation shale reservoir in the Sichuan Basin was considered as the research object; its structure was modeled from a microscopic perspective, and a zero-thickness cohesive unit was embedded within the solid unit. Numerical simulations were performed to study the effect of mineral content on the microextension of the hydraulic fracture, extension behavior, and evolution law of shale. The results showed that changes in the mineral content resulted in changes in the forces between molecules within the minerals, which, in turn, affected the shale's brittleness. The percentages of brittle mineral content in the Long I, II, and III reservoir sections are 60.37, 47.60, and 53.56%, respectively. The fracture initiation pressures of the three reservoirs were 29.22, 31.42, and 30.22 MPa, respectively, and a linear correlation was found between the fracture initiation pressures and the brittle mineral contents of the reservoir sections. An increase in the reservoirs' percentage of brittle mineral content facilitated the fracture initiation, with a corresponding gradual decrease in the resistance to fracture initiation. The pore pressures of the fractures in the three reservoirs after fracture initiation were 0.90, 1.18, and 1.00 MPa, respectively. The larger the percentage of brittle minerals was, the lower was the fracture pore pressure. The greater the length, number, area, and width of the cracks were, the more likely they were to form longer and wider cracks. Hence, reservoirs with a high percentage of brittle minerals should be prioritized as the target formations for hydraulic fracturing operations. The results of this study reveal how the mineral content affects the extension of microscopic hydraulic fractures in shale reservoirs. As such, this work can provide a theoretical basis for rationally selecting a hydraulic fracturing operation layer in shale gas reservoirs.

A Study on Three-Dimensional Multi-Cluster Fracturing Simulation under the Influence of Natural Fractures

Multi-cluster fracturing has emerged as an effective technique for enhancing the productivity of deep shale reservoirs. The presence of natural bedding planes in these reservoirs plays a significant role in shaping the evolution and development of multi-cluster hydraulic fractures. Therefore, conducting detailed research on the propagation mechanisms of multi-cluster hydraulic fractures in deep shale formations is crucial for optimizing reservoir transformation efficiency and achieving effective development outcomes. This study employs the finite discrete element method (FDEM) to construct a comprehensive three-dimensional simulation model of multi-cluster fracturing, considering the number of natural fractures present and the geo-mechanical characteristics of a target block. The propagation of hydraulic fractures is investigated in response to the number of natural fractures and the design of the multi-cluster fracturing operations. The simulation results show that, consistent with previous research on fracturing in shale oil and gas reservoirs, an increase in the number of fracturing clusters and natural fractures leads to a larger total area covered by artificial fractures and the development of more intricate fracture patterns. Furthermore, the present study highlights that an escalation in the number of fracturing clusters results in a notable reduction in the balanced expansion of the double wings of the main fracture within the reservoir. Instead, the effects of natural fractures, geo-stress, and other factors contribute to enhanced phenomena such as single-wing expansion, bifurcation, and the bending of different main fractures, facilitating the creation of complex artificial fracture networks. It is important to note that the presence of natural fractures can also significantly alter the failure mode of artificial fractures, potentially resulting in the formation of small opening shear fractures that necessitate careful evaluation of the overall renovation impact. Moreover, this study demonstrates that even in comparison to single-cluster fracturing, the presence of 40 natural main fractures in the region can lead to the development of multiple branching main fractures. This finding underscores the importance of considering natural fractures in deep reservoir fracturing operations. In conclusion, the findings of this study offer valuable insights for optimizing deep reservoir fracturing processes in scenarios where natural fractures play a vital role in shaping fracture development.

A fully coupled thermo-poroelastic model for energy extraction in naturally fractured geothermal reservoirs: sensitivity analysis and flow simulation

The development of a novel method for modelling fluid flow and heat transfer in naturally fractured geothermal reservoirs represents a significant advancement in geothermal energy research. This Study presents a hybrid approach, which combines discrete fracture and single continuum techniques, to effectively capture the complex interactions between fluid flow and heat transfer in geothermal fractured reservoirs. In addition, the incorporation of the local thermal nonequilibrium method for simulating heat transmission accounts for the disparities in temperature between the rock matrix and the fluid, providing a more realistic representation of heat transfer processes. The study also presents a fully coupled thermo-poro-elastic framework that integrates fluid flow and heat transfer to comprehensively evaluate reservoir responses to injection/production scenarios. This coupled approach allows for the prediction of changes in reservoir properties, such as permeability and porosity, under varying fluid pressure and temperature conditions. The application of the proposed model to evaluate a geothermal reservoir’s long-term response to injection/production scenarios provides valuable insights into the reservoir’s behaviour and potential energy production capacity. The sensitivity analysis further enhances the model’s utility by identifying the key reservoir parameters that significantly influence the thermal depletion of the reservoir. Overall, this novel modelling approach holds promise for improving the understanding and management of naturally fractured geothermal reservoirs, contributing to the optimization of geothermal energy extraction strategies.

An Accurate Calculation Method on Blasingame Production Decline Model of Horizontal Well with Dumbbell-like Hydraulic Fracture in Tight Gas Reservoirs

Blasingame production decline is an effective method to obtain permeability and single-well controlled reserves. The accurate Blasingame production decline curve needs an accurate wellbore pressure approximate solution of the real-time domain. Therefore, the aim of this study is to present a simple and accurate wellbore pressure approximate solution and Blasingame production decline curves calculation method of a multi-stage fractured horizontal well (MFHW) with complex fractures. A semi-analytical model of MFHWs in circle-closed reservoirs is presented. The wellbore pressure and dimensionless pseudo-steady productivity index JDpss (1/bDpss) are verified with a numerical solution. The comparison result reaches a good match. Wellbore pressure and Blasingame production decline curves are used to analyze parameter sensitivity. Results show that when the crossflow from matrix to natural fracture appears after the pseudo-state flow regime, the value of the inter-porosity coefficient has an obvious influence on the pressure approximate solution of the pseudo-steady flow regime in naturally fractured gas reservoirs. The effects of relevant parameters on wellbore pressure and the Blasingame decline curve are also analyzed. The method of pseudo-steady productivity index JDpss can applied to all well and reservoir models.

Evaluation of the Hydraulic Fracturing Tendencies of Consolidated Sandstone Reservoirs Based on the Catastrophe Theory

The evaluation of rock hydraulic fracturing tendency plays a crucial role in the selection of fracturing layers within reservoirs and the evaluation of post-compression capacity. The sandstone reservoirs in the Yihuang New Area have poor physical properties and are deeply buried. It is necessary to increase the production of oil and gas by hydraulic fracturing. Regarding the sandstones in the region, the following parameters were considered: combined compressive strength, bulk modulus, shear modulus, fracture index, horizontal-stress difference coefficient, and fracture toughness. In accordance with the catastrophe theory, a multi-level structure was established for the hydraulic fracturing-tendency evaluation of sandstone reservoirs, consisting of a target layer, a guide layer, and an indicator layer. A catastrophic model for evaluating the hydraulic fracturing tendency of sandstone reservoirs was established. The results are consistent with those obtained from the Analytic Hierarchy Process. However, the catastrophe theory significantly reduces subjective interference. The results indicate that when the hydraulic fracturing-tendency evaluation value is greater than 0.8, the reservoir can be fractured well; when the hydraulic fracturing-tendency evaluation value is between 0.7 and 0.8, the fracture reservoir is moderate; and when the hydraulic fracturing-tendency evaluation value is less than 0.7, the fractured reservoir is poor. The optimal fracture intervals for the Yi 70 well are 1320–1323 m, 1350–1355 m, and 1355–1360 m. The optimal fracture planes for the Yi 76 well are 1921–1925 m and 1925–1930 m. The optimal fracture planes for the Yi 10-1-26 well are 2487–2495 m, 2585–2587 m, and 2589–2591 m. The hydraulic fracturing-tendency model developed in this study has been applied to several well sections of sandstone reservoirs in the Yihuang New Area. Additionally, the model was compared with existing hydraulic fracturing-tendency evaluation models. The evaluation results are in agreement with the post-pressure capacity-monitoring data. The accuracy of the model presented in this study has been verified, as has its applicability to other sandstone reservoirs.

Production optimization in a fractured carbonate reservoir with high producing GOR

The Gas-Oil Ratio (GOR) is a crucial production parameter in oil reservoirs. An increase in GOR results in higher gas production and lower oil production, potentially leading to well shut-ins due to economic infeasibility. This study focuses on a real fractured oil field that requires urgent production operations to reduce the producing GOR. In this study, the static model for the field was developed using commercial software, involving steps such as data collection, fault modeling, meshing, and statistical analysis to prepare for dynamic simulation. The dynamic model incorporates geometry, gridding, and rock properties from the static model, utilizing a dual-porosity approach for the naturally fractured reservoir and the Peng-Robinson equation for fluid phase behavior. Initial reservoir conditions, production history, and rock-fluid interactions were defined, with relative permeability curves indicating a water-wet reservoir and low critical gas saturation affecting the GOR. To better understand the relationship between reservoir and production parameters, a detailed sensitivity analysis was performed using the Response Surface Methodology (RSM). Following the sensitivity analysis, a history matching process was conducted using the Designed Exploration and Controlled Evolution (DECE) optimizer to validate the model for future forecasts. Six operational scenarios were defined to decrease the production GOR and enhance final recovery from the field. The results indicate that the water injection scenario is effective in preventing the GOR increase by maintaining reservoir pressure, thereby sustaining production over a longer period. This scenario also improves oil recovery by approximately 6% compared to the base case. Finally, optimization was carried out using the DECE optimizer for each scenario to fine-tune the operational parameters. The goal was to maximize oil revenue for each scenario during the optimization process. This study stands out as one of the few that provides a comprehensive analysis of production behavior and development planning for a real fractured reservoir with high producing GOR.

High-resolution analysis of 3D fracture networks from Digital Outcrop Models, correlation to plate-tectonic events and calibration of subsurface models (Jurassic, Arabian Plate)

The performance of different reservoirs, both hydrocarbon and gas storage, is significantly influenced by the presence of natural fracture networks mainly originated in response to tectonic deformation. However, adequate characterization of fracture networks in the subsurface is often difficult since most of the used techniques are either spatially sparse (well and log data) or have limited resolution (seismic and well tests). In this study, we use UAV-based digital photogrammetry to reconstruct a 3D Digital Outcrop Model and characterize natural fracture sets of the late Jurassic Hanifa Formation (Tuwaiq Escarpment, Saudi Arabia). We analyzed the exposed fracture patterns in terms of fracture distribution, intensity, and lateral variability. The fracture dataset was collected using manual sampling approaches since the automatic sampling techniques are highly influenced by outcrop morphology thus not yet reliable to quantify and interpret fracture networks along reservoir outcrop analogues. The well-exposed late Jurassic outcrops in Wadi Birk, southern central Saudi Arabia, are considered analogous in depositional facies to subsurface reservoirs in the region. The observed fracture patterns are congruent with patterns reported from same-age formations in other parts of the Arabian Plate and hence can be related to plate-wide tectonic events that impacted Arabia during the Late Cretaceous (Alpine I) and the late Tertiary Period (Alpine II). This association provides support for using outcrop-based fracture studies as analogue scenarios for the orientation, distribution and intensity of fractures in subsurface reservoirs. The applied methodology for fracture network characterization have potential implications for hydrocarbon development, gas storage (H2) and Carbon Capture Utilization and Storage (CCUS).

Temperature Variations in Deep Thermal Well LZT-1 in Lądek-Zdrój (Bohemian Massif; SW Poland)—Evidence of Geothermal Anomaly and Paleoclimatic Changes

The thermal water deposit in Lądek-Zdrój (SW Poland) occurs in fractured reservoir rocks, and its hydrogeological regime is controlled by the features of the local geology and lithology of the hosting crystalline complexes, mainly impermeable high-grade metamorphosed mica schists and gneisses. The fractured thermal water aquifer is confined by a thrust fault-type aquitard that creates artesian pressure and, therefore, the water intakes and natural springs in Lądek Zdrój provide spontaneous outflow. Classical geothermometers yield an estimation of reservoir temperatures that ranges from 50 to 70 °C, with a maximum of 88 °C. The heat flux (HF) value of the Lądek-Zdrój region is 64 mW/m2. The new borehole, LZT-1, is in the border zone of a local thermal anomaly with a geothermal degree of 25–27 m/°C. The estimated temperature at the bottom of the LZT-1 borehole, under thermal equilibrium conditions, ranges between 70 °C and 80 °C. A stream of heated waters from the deep system flows from the recharge areas, shaping the local geothermal anomaly and thus influencing the thermal conditions in the Lądek-Zdrój area. The activation of this water circulation system occurred in the Pleistocene.