A Systematic Approach to Fracturing Optimisation of Unconventional Resources

Reliable estimates of hydraulic fracture geometry help reduce the uncertainty associated with estimated ultimate recovery (EUR) forecasts and optimize field developing planning in unconventional reservoirs. For these reasons, operators gather information from different sources with the objective to calibrate their hydraulic fracture models. Microseismic data is commonly acquired by operators to estimate hydraulic fracture geometry and to optimize well completion designs. However, relying solely on estimates derived from microseismic information may lead to inaccurate estimates of hydraulic fracture geometry. The objective of this study is to efficiently calibrate hydraulic fracture geometry by using microseismic data, physics-based fracture propagation models, and the embedded discrete fracture model (EDFM). We first obtain preliminary estimates of fracture geometry based on microseismic events’ spatial location and density with respect to the perforation cluster location. We then tune key completion parameters using an in-house fracture propagation model to provide hydraulic fracture geometries that are constrained by the microseismic cloud. In the history matching process, we included the effect of natural fractures, using the microseismic events location as natural fracture initiation points. Finally, we used cutoff coefficients to further reduce hydraulic fracture geometries to match production data. The results of this work showed a fast and flexible method to estimate fracture half-lengths and fracture heights, resulting in a direct indicator of the completion design. Additionally, hydraulic-natural fracture interactions were assessed. We concluded that the inclusion of cutoff coefficients as history matching parameters allows to derive realistic hydraulic and natural fracture models calibrated with microseismic and production data in unconventional reservoirs.

PreviousNext No AccessUnconventional Resources Technology Conference, Denver, Colorado, 12-14 August 2013Determining the Contributing Reservoir Volume from Hydraulically Fractured Horizontal Wells in the Wolfcamp Formation in the Midland BasinAuthors: Mickey FriedrichMike MillikenMickey FriedrichPioneer Natural ResourcesSearch for more papers by this author and Mike MillikenPioneer Natural ResourcesSearch for more papers by this authorhttps://doi.org/10.1190/urtec2013-149 SectionsAboutPDF/ePub ToolsAdd to favoritesDownload CitationsTrack CitationsPermissions ShareFacebookTwitterLinked InRedditEmail Abstract URTeC 1582170 This paper provides a methodology that is practical and logical in its approach to provide answers involving the evaluation and development of unconventional reservoirs. Multiple sources of data are analyzed to estimate the effectively stimulated volume of reservoir for horizontal wells in the Wolfcamp formation in the Midland Basin of west Texas. Estimating this volume is critical in determining optimum spacing and stacking of horizontal wellbores in unconventional reservoirs. Stimulated Reservoir Volume (SRV), as determined from microseismic, locates seismic events due to rock failure but does not necessarily represent the reservoir volume contributing to production. The reduced volume contributing to production is defined as the Contributing Reservoir Volume (CRV). This paper presents a workflow of using three methods - interpreted microseismic, proppant material balance, and calibrated hydraulic fracture modeling - to collectively estimate the CRV in hydraulically fractured horizontal Wolfcamp wells. Microseismic data is interpreted both by applying a discount factor based on industry studies and by analyzing locations and concentrations of events. Then a method of proppant material balance is used to estimate the maximum propped dimensions based on the mass of sand that is placed in each cluster of perforations. Finally, a calibrated geomechanical hydraulic fracturing model is used to model the CRV of 25 wells drilled in the Wolfcamp throughout the study area. Keywords: horizontal wells, fractures, unconventional, stacking, modelingPermalink: https://doi.org/10.1190/urtec2013-149FiguresReferencesRelatedDetailsCited ByA mathematical model for estimating effective stimulated reservoir volume24 November 2021 | Journal of Petroleum Exploration and Production Technology, Vol. 12, No. 7Analysis of Mancos Shale gas production scenarios under various stress mechanisms24 August 2021 | Arabian Journal of Geosciences, Vol. 14, No. 18A Review of Flow Mechanism and Inversion Methods of Fracture Network in Shale Gas ReservoirsGeofluids, Vol. 2021Production Interference of Hydraulically Fractured Hydrocarbon Wells: New Tools for Optimization of Productivity and Economic Performance of Parent and Child Wells3 June 2019Unconventional Reservoir Geomechanics14 June 2019 | , Vol. 1Surmounting Paucity of Data in Hydraulic Fracture Designs: Case Studies From the Permian Basin23 April 2018Case Study for Effective Stimulated Reservoir Volume Identification in Unconventional ReservoirsJournal of the Korean Society of Mineral and Energy Resources Engineers, Vol. 55, No. 2PKN Solution Revisit: 3-D Hydraulic Fracture Size and Stress Anisotropy Effects24 October 2017 | Rock Mechanics and Rock Engineering, Vol. 51, No. 2Performance-based fractal fracture model for complex fracture network simulation22 December 2017 | Petroleum Science, Vol. 15, No. 1Method of Characterization of Complex Fracture Network with Combination of Microseismic using Fractal theory17 October 2017Case History - Continued Diagnostic Technology Integration with Completions in Horizontal Wolfcamp Shale Wells in the Delaware Basin9 October 2017Midland Basin Wolfcamp Shale: Completions Observations and Lateral Length OptimizationKyle M. Richter12 September 2017Application of the fractal geometry theory on fracture network simulation23 July 2016 | Journal of Petroleum Exploration and Production Technology, Vol. 7, No. 2Deciphering Dynamic Fracture Systems through Multiple Monitoring Wells with Permanent Downhole Gauges in the Midland BasinYula Tang, Baosheng Liang, and Leif Larsen3 August 2016Understanding Wolfcamp Well Performance - A Workflow to Describe the Relationship between Well Spacing and EURJared Pettegrew*, Jiale Qiu, and Lang Zhan3 August 2016Application of Real-Time Bottom-Hole Pressure to Improve Field Development Strategies in the Midland Basin Wolfcamp ShaleKyle D. Scott*, Wei-Chun Chu, and Raymond W. Flumerfelt12 August 2015The role of hydraulic fracture geometry and conductivity profile, unpropped zone conductivity and fracturing fluid flowback on production performance of shale oil wellsJournal of Unconventional Oil and Gas Resources, Vol. 9Application of Real-Time Bottom-Hole Pressure to Improve Field Development Strategies in the Midland Basin Wolfcamp Shale4 August 2015Proper Inclusion of Hydraulic Fracture and Unpropped Zone Conductivity and Fracturing Fluid Flowback in Single Shale Oil Well Simulation17 April 2014Well-Spacing Study to Develop Stacked Tight Oil Pay in Midland Basin1 April 2014Estimation of Stimulated Reservoir Volume Using the Concept of Shale Capacity and its Validation with Microseismic and Well Performance25 February 2014 Unconventional Resources Technology Conference, Denver, Colorado, 12-14 August 2013ISSN (online):2159-6832Copyright: 2013 Pages: 1229 publication data© 2013 Published in electronic format with permission by the Society of Exploration Geophysicists, American Association of Petroleum Geologists, and Society of Petroleum EngineersPublisher:Unconventional Resources Technology ConferenceSociety of Exploration Geophysicists HistoryPublished: 26 Sep 2013 CITATION INFORMATION Mickey Friedrich and Mike Milliken, (2013), "Determining the Contributing Reservoir Volume from Hydraulically Fractured Horizontal Wells in the Wolfcamp Formation in the Midland Basin," SEG Global Meeting Abstracts : 1461-1468. https://doi.org/10.1190/urtec2013-149 Plain-Language Summary Keywordshorizontal wellsfracturesunconventionalstackingmodelingPDF DownloadLoading ...

Accurate modeling of hydrocarbon production is a necessary, yet challenging step for economic exploitation of unconventional resources. One of the main challenges is to model flow to a horizontal well from a complex network of hydraulic and natural fractures. Many unconventional reservoirs comprise well-developed natural fracture networks with multiple orientations and complex hydraulic fracture patterns based on microseismic data. Conventional dual porosity and dual permeability models are not adequate for modeling these complex networks of natural and hydraulic fractures. Also, it is neither practical nor advantageous to model a large number of pre-existing fractures with a discrete fracture model. Therefore, an appropriate approach to model production from low-permeability reservoirs is to perform discrete fracture modeling for hydraulic fractures and employ a dual continuum approach for numerous natural fractures. We have developed a coupled dual continuum and discrete fracture method to simulate production from unconventional oil and gas reservoirs. Large-scale hydraulic fractures (macro-fractures) are modeled explicitly using a discrete fracture model, called EDFM, and numerous small-scale natural fractures (micro-fractures) are modeled using a dual continuum approach. The hybrid model includes three domains: matrix, discrete-fracture, and continuum-fracture domains. A systematic approach is devised to calculate transport parameters between all three domains. Moreover, EDFM allows for not only transverse and longitudinal hydraulic fractures but also macro-fractures of any orientation. Thus, the coupled model provides an effective and reliable environment to improve stimulation designs and completion strategies. We present several examples in this study to show the applicability, robustness, and performance of the hybrid method for the simulation of unconventional oil and gas reservoirs. We examine multi-stage hydraulic fractures with multiple configurations in the presence of numerous pre-existing fractures. Simulations show a noticeable contribution from natural fracture networks on total production. Furthermore, for the tight oil reservoir examined in this study, the stimulation scheme with longer hydraulic fractures improves cumulative oil production compared to the scheme with larger number of shorter hydraulic fractures. We also examine production from a tight gas reservoir wherein hydraulic fractures partially penetrate the formation height. Simulations indicate that inefficient fracture treatment can result in significant loss of production.

Multi-stage hydraulic fracturing has recently gained strong interest in unconventional plays in the Middle East due to high natural gas production potential. However, prevalent characteristics of the area, including high-pressure / high-temperature (HPHT) conditions and presence of complex natural fracture networks, pose significant challenges to reservoir characterization. These challenges have motivated the development of an integrated workflow using microseismic data for the characterization of reservoir properties resulting from the interaction between natural and hydraulic fractures. This study proposes a reliable method for modeling hydraulic fractures from scarce microseismic data. Initially, a microseismic model—based on field records of microseismic data and natural fracture spatial characterization—was developed. Issues related to limited microseismic data availability were tackled through combination of a probabilistic algorithm, Gaussian Mixture Model, and a DFN model. Then, the resulting synthetic microseismic events enabled the generation of a hydraulic fracture model using the embedded discrete fracture model (EDFM) and an in-house microseismic spatial density algorithm that captured major hydraulic fracture growth tendencies. Next, the created hydraulic fracture geometries were validated against a physics-based hydraulic fracture propagation model. Lastly, a single-well sector model—based on a corner point grid that honored the original 3D discrete fracture network (DFN)—was history matched, confirming the successful application of the proposed methodology.

In unconventional shale reservoirs, the presence of natural fractures is common and widespread. Multi-stage hydraulic fracture treatments are used to generate complex fracture geometry and stimulate reservoirs to unlock hydrocarbon in unconventional reservoirs. Natural fractures further complicate the complexity of the fracture geometry. In this paper, the objective is to investigate the impact of natural fractures on multiple hydraulic fracture propagation using an in-house fracture propagation model. We have developed a complex hydraulic fracture model to simulate multiple fracture propagation in naturally fractured reservoirs. The model can calculate partitioning of fluid between multiple fractures, fracture interaction within a stage and between stages, as well as the interaction between hydraulic and natural fractures. For simultaneous multiple fracture propagation, the exterior fractures generally take the majority of fluid and propagate at the expense of the interior fractures. Natural fractures can retard the growth of hydraulic fractures and change the fluid distribution between fractures and propagation trajectories of hydraulic fractures. In a reservoir with a heterogeneous natural fracture distribution, the interruption of natural fractures can complicate fracture geometry. The higher density or smaller spacing of natural fractures can mitigate stress shadow effects and favor more fluid flowing into the inner fractures. Due to the uncertainty of natural fracture distribution, the reliability of the complex fracture geometry provided by numerical models has been challenged. This paper demonstrates the potential of incorporating diagnostic results to constrain numerical results. Through combining diagnostic results with the fracture model, the accuracy of predicted fracture geometry can be improved.

Application of cumulative-in-situ-injection-production technology to supplement hydrocarbon recovery among fractured tight oil reservoirs: A case study in Changqing Oilfield, China

ABSTRACT: The carbonate formations are characterized by developing continuous grid-like fractured structures, which pose a great challenge on effective hydraulic fracturing. In order to investigate the fracture propagation behavior in such grid-like fracture carbonate reservoirs and the interaction between hydraulic fracture and grid-like fracture, we employed a Unconventional Fracture Model (UFM) based on the boundary element approach in this paper to simulate the fracturing process in fractured carbonate reservoirs. The effects of key geological and engineering parameters such as fracture approach angle, pump displacement, and stress difference on stimulated reservoir volume were analyzed, and well trajectories were also optimized. Under the condition of Shunbei carbonate reservoir, when the angle α between the grid-like fracture and the horizontal well is 90°, the hydraulic fracture tends to extend parallel to the direction of the grid-like fracture, when α is 45°, the hydraulic fracture tends to penetrate the grid-like fracture and then propagate along the maximum principal stress, and when α is less than 45°, the hydraulic fracture tends to penetrate the grid-like fracture and then be captured by the natural fracture. In the Shunbei reservoirs, with a local stress difference of 40 MPa, the optimal pump displacement is 4∼6 m3/min. 1. INTRODUCITON Marine carbonate reservoirs are rich for oil and gas resources. In world's proven oil and gas reserves, 60% in the marine carbonate reservoirs, that has become a key area of oil and gas exploitation. Among the marine carbonate reservoirs, grid-like fractured reservoirs is a special structure. Marine carbonate reservoirs are stretched and shear by geological processes, forming deep faults and grid-like fractured zones, that are grid-like fractured reservoirs. Which generally exist in ultra-deep, high-temperature and high-pressure geologic environments, and have received focused attention in recent years (Wang W et al., 2023; LI Y et al., 2022). Currently, hydraulic fracturing is the main means for exploiting grid-like fracture reservoirs. However, hydraulic fracturing communication large grid-like fractures and many natural fractures has limited, and the classical theory of fracture propagation is not applicable (Hui G et al., 2023). Therefore, to study the propagation law of hydraulic fracture in grid-like fracture reservoirs is important. So far, many scholars have conducted a lot of research on the interaction between hydraulic fracture and grid-like fracture (Zhang Q et al., 2021). However, fracture propagation in grid-like fracture Still have not theoretical support, and the mechanism of hydraulic fracture propagation in grid-like fractured reservoirs is not clear. Based on the UFM model and with the help of Kinetix (Kresse O et al., 2013), which is an integrated software platform for geo-engineering. The authors modeled the grid-like fractured reservoirs, and studied the propagation of hydraulic fracture under the condition of grid-like fracture medium (Ma D C et al., 2023).

Microseismicity is a physical phenomenon which allows us to estimate the production capability of the well after hydraulic fracturing (HF) in a naturally fractured (NF) reservoir. Some of the microseismic events are reactivations of NFs induced by a direct hit of HF, while others are induced by the fluid leak-off from the previous stages or by elastic waves emitted into the reservoir with hydraulic fracture plane propagation. The former NFs have a chance to be propped there as the latter will not significantly increase their contribution to the production. Identification of such microseismic events helps to reduce uncertainty in the description of fracture network geometry. Based on inferred data from core analysis NF densities and orientations, we generated multiple realizations of the semi-stochastic Discrete Fracture Network (DFN). In order to constrain them, we used time evolution of microseismic cloud in addition to results of core analysis. Fluid and proppant pumping schedule is used to identify such microseismic events because they should be located close to the pressure diffusion front generated by hydraulic fluid. Events outside of proposed region may be triggered by other factors, such as stress-strain relaxation from other stages and correspondent fractures. In most cases, they are not wide enough to take proppant from the main HF. This approach was used to reduce range of production for DFN realizations. This workflow is implanted to a 15-stage hydraulic fracture treatment on a horizontal well placed in a siltstone reservoir with intrinsic fractures. The spatio-temporal dynamics of microseismic events are classified into two groups by the front of nonlinear pressure diffusion caused by 3-dimensional hydraulic fracturing, considered as effective and ineffective events. DFNs with only effective microseismicity and with all the induced events are generated. Then, two types of DFN related uncertainties on production are performed to evaluate the impact of filtration. Results of aleatory uncertainty quantification caused by the randomness of DFN modeling indicate the filtered events can generate a production DFN with a more consistent connected fracture area. Moreover, sensitivity analysis caused by lack of accuracy in natural fracture characterization shows the production area of DFN with filtration process is more insensitive to the variation of fracture parameters. Finally, a history match with production data and pressure data indicates this DFN model properly represents the reservoir and completion. Our methodology characterizes well the conductive fracture network utilizing core data, microseismic data, and pumping schedule. It could restore the true productivity of each fractured stage from a massive microseismic cloud, which helps understand the contribution of fracturing job right after the treatment.

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 160197, ’Examining the Effect of Cemented Natural Fractures on Hydraulic-Fracture Propagation in Hydrostone-Block Experiments,’ by B. Bahorich, J.E. Olson, SPE, and J. Holder, The University of Texas at Austin, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-10 October. The paper has not been peer reviewed. Microseismic data and coring studies suggest that hydraulic fractures interact heavily with natural fractures, creating complex fracture networks in naturally fractured reservoirs such as the Barnett shale, Eagle Ford shale, and Marcellus shale. Because direct observations of subsurface hydraulic-fracture geometries are incomplete or nonexistent, properly scaled experimental research and computer modeling based on realistic assumptions are used to help understand fracture-intersection geometries. Observations of cores from the Barnett and other shale plays suggest that most natural fractures are cemented. The most significant finding of this research was that fracture-intersection geometries are complex. Results showed that bypass, separation of weakly bonded interfaces, diversion, and mixed-mode propagation are likely in hydraulic-fracture intersections with cemented natural fractures. Introduction The resulting geometry from hydraulic-fracturing treatments in rocks having natural-fracture weaknesses, typically pumped from multiple injection zones spaced along lengthy horizontal wells, is not clear. The best direct evidence of fracture geometry is from mine-back studies in which realistic fracturing fluids were injected into realistic wellbores. But those studies often were at very shallow depths or in igneous or metamorphic rock. These types of studies report hydraulic-fracture diversion along natural planes of weakness, such as natural fractures and bedding planes. Multiple fractures can propagate simultaneously and parallel to one another, but, eventually, under many circumstances, a single fracture plane will dominate. Coring across hydraulic-fracture trends has shown that such multiple parallel fractures exist in tight gas sandstones. Laboratory experiments also investigate the physics of hydraulic-fracture complexity, with the advantage of better boundary-condition control and near-complete observation of fracture geometry. The drawback of laboratory experiments is potential issues with proper scaling to ensure that results are applicable to field operations. The objective of this work was to examine the nature of hydraulic-fracturing interaction with naturally cemented or sealed pre-existing fractures. This investigation was motivated by observations in formations similar to the Barnett shale in the Fort Worth basin in Texas, where most natural fractures are observed to be filled with calcite or quartz. Inclusions (glass slides, Berea sandstone slides, and gypsum-plaster slides) were embedded in gypsum-plaster blocks to represent cemented natural fractures. Linear and crosslinked gel was injected into the blocks under a true triaxial-stress state in which the hydraulic-fracture path was designed to intersect the embedded inclusions (natural fractures). Results showed a variety of interactions between hydraulic and natural fractures that could improve understanding of the subsurface process and provide rea-son to develop more-accurate hydraulic-fracturing models.

It is challenging to simulate unconventional reservoirs efficiently and accurately because of uncertainty in fracture geometry, geomechanics, reservoir parameters, and a lack of holistic physics to integrate data from these three disciplines. We present a holistic approach to accurately predict the pad performance of hydraulically fractured wells. This involves extensive calibration of a frac model to Diagnostic Fracture Injection Test (DFIT) and microseismic data, which is validated by Rate Transient Analysis (RTA) and pressure interference test. A single stage of a multistage fracture horizontal wells was calibrated with DFIT using a hydraulic fracture model. Simultaneously, the hydraulic fracture length (xf) was calibrated to align with microseismic events. This extensively calibrated stage was then replicated across other stages in the pad. Chow Pressure Group Analysis (CPG) was conducted on the four wells on the pad to measure the magnitude of the pressure interference. Results of the fracture model were passed into an in-house reservoir simulator for history matching. This method serves as a way for frac and simulation engineers to create an accurate, calibrated model that can be used for frac, completion and well spacing optimization, technical and business decisions in areas of fields with similar petrophysics and geomechanical properties.

In investigations of tectonic stress fields, natural fractures are often found in low-permeability formations. Fracturing wells in naturally fractured gas fields can differ dramatically from those in conventional isotropic formations. Fluid leak-off is the pri-mary difference. To take account of fracturing fluid leaking into the formation through natural fractures and the matrixes, this paper presents a new model that describes fluid leak-off in naturally fractured gas fields and its exact solution is given by or-thogonal transformation. We studied the effects of some sensitive parameters to fluid leak-off. From the cases studied, fluid leak-off in naturally fractured gas fields should not use the classic leak-off theory which states that leak-off velocity is inversely proportional to the exponent 0.5 of leak-off time. Based on numerous calculations, the equation V = C.t ∧ b (b < 0) is presented to describe fluid leak-off in naturally fractured gas fields, and the constant C is defined as the equivalent leak-off coefficient. If b is equal to -0.5, the new model can be simplified according to the classic model. The model has been applied to investigate fracture propagation in naturally fractured gas fields.Introduction. Fluid loss can be described as leakage of the fracturing fluid leaking out of the main fracture. The rate of fluid leaking into the formation is one of the critical factors involved in the treatment design and in determining the fracture geometry. Moreover, in naturally fractured reservoirs, fluid loss is the key factor affecting the treatment success. Therefore, many investigators have studied the simulation of fluid loss and a number of mathematic models were developed to accurately model fluid loss.Classic theory(1, 2) considers the combined effect of the phenomena as a material property, so that leak-off velocity is given by the Carter equations. To date, it is still extensively used in fracturing simulation and fracturing design. In fact, the net fracturing pressure changes with an increase in pumping time, which has an important effect on fluid loss. Therefore, the pressure-dependent leak-off model was derived(3, 4), which is used for studying hydraulic fracture propagation(5). More recently, van den Hoek(6) developed a nonlinear fluid leak-off model for high-permeability fracturing. But the effects of natural fractures on fluid loss are not considered in the existing models. However, the fluid leak-off rate in naturally fractured reservoirs is typically excessive and completely dominated by the natural fractures(7). Vinod et al.(8) studied dynamic fluid loss in low-permeability formations with natural fractures by room experiments, which has some useful implications for fracturing design in naturally fractured reservoirs. Dietzel and Koehler(9) and Rodgerson(10) offered some key considerations in the hydraulic fracturing of naturally fractured reservoirs. Whereas, the leak-off model with natural fractures has not been reported, the objective of this paper is to set up a new theoretical leak-off model for natural fractures and analyze the effect on fracture propagation.Leak-off Model for Natural Fractures. Basic AssumptionsFigure 1 illustrates the leak-off of fracturing fluid in naturally fractured gas fields. The following are the basic assumptions for deriving the leak-off model:

In this paper, a novel computational framework is introduced for simulation of multiphase flow, geomechanics, and fracture propagation in porous media based on Biot’s model for poroelasticity by focusing on interactions between hydraulic and natural fractures. Since realistic porous media contain many natural fractures, it is important not only to stimulate hydraulic fractures but also to study the interaction between natural and hydraulic fractures. Here, state-of-the-art numerical modeling of natural and hydraulic fractures using a diffusive adaptive finite element phase field approach is employed. The locally mass conservative enriched Galerkin finite element methods (EG) are utilized to model two-phase flow in propagating fractures with relative permeability and capillary pressure. Geomechanics approximated by a continuous Galerkin finite element method is coupled to multiphase flow by applying an iteratively coupled scheme. Numerical examples are presented that demonstrate the effectiveness of this framework for different propagation scenarios by varying the degrees of physics. In addition, the capabilities to perform high-fidelity simulations on complex fracture networks, with randomly joined diffusive natural fractures, are illustrated.

Natural fractures are widely distributed in hydrate reservoirs, resulting in a fracture-filling type of gas hydrate. However, the complexity of fracture networks, including both hydraulic and natural fractures, complicates the evaluations of gas well productivity. This study investigates the heat and mass transfer dynamics in fracture-filling gas hydrate reservoirs developed using a multi-stage fractured horizontal well. A coupled thermal-hydraulic-mechanical model was developed based on the embedded discrete fracture method, and the model was validated against a commercial numerical simulator, demonstrating high accuracy in predicting gas–water production rates and reservoir pressure, temperature, and hydrate saturation field evolution. The simulation results revealed significant insights into gas and water production rates, flux distributions, and field map distributions. Furthermore, we analyzed the impact of various hydraulic fracture parameters, including fracture numbers, angles, lengths, and morphologies. The simulation results show that fractured wells perform better than non-fractured wells, and the initial daily gas production of a multi-stage fractured horizontal well is 4.05 times that of a fractured vertical well. Besides, fracture geometry critically influences the productivity of the multi-stage fractured horizontal well. The greater the number of hydraulic fractures and the longer the fracture length, the higher the daily and cumulative gas production of the gas well due to higher drainage areas. The cumulative gas production is increased by 131.98% as the number of hydraulic fractures is increased from 3 to 9, whereas the increase is 91.66% as the fracture length is increased from 50 to 200 m. A narrower intersection angle between hydraulic fractures and the wellbore corresponds to a diminished drainage area, thereby exacerbating fracture-driven interference effects and accelerating production decline rates. The intersection density between hydraulic fractures and natural fracture systems serves as the primary determinant of drainage efficiency in fracture-filling gas hydrate reservoirs. The findings have important implications for improving gas well productivity and enhancing the efficient exploitation of fracture-filling gas hydrates.

The primary objective of this paper is to introduce fit-for-purpose technologies and best practices aimed at increasing and sustaining the productivity of the Mauddud reservoir in the Greater Burgan Field, Kuwait, to a level of 40,000 bbl/day by 2030. Additional objectives include constructing DFN and 3D geomechanics models, and developing a mechanistic reservoir model to better understand reservoir fluid flow and select sweet spots for new horizontal infill wells. The approach involved a comprehensive analysis of the Mauddud Formation, characterized by thin layers, a tight carbonate matrix, and low productivity. The process included data gap analysis, updating the static model, and constructing 3D and 1D MEM geomechanics models. Natural fracture modeling was employed to understand the distribution of matrix permeability and fracture networks. Machine learning was used to propose development strategies, and cost-effective technology management programs were employed for drilling and workover candidate wells. The study reveals that natural fractures in the Mauddud formation are oriented NE-SW and are fault-related, formed due to multiple tectonic episodes (Fig. 2). The recovery mechanisms are flow from natural fractures and acid frac jobs supported by a larger volume of low-matrix permeability. Single porosity models were found to be inadequate to reproduce production behavior. Wells located within 500 meters of the main faults showed better productivity. Implementing multi-stage acid fracturing in two newly horizontal wells drilled based on study recommendations has increased current oil production by 60%. This paper presents novel insights into the Mauddud Formation's fracture orientation and recovery mechanisms, offering a new understanding of the reservoir's behavior. The use of advanced modeling techniques and machine learning to propose development strategies provides valuable contributions to the existing body of literature, benefiting the petroleum industry by enhancing reservoir management and production optimization.

The KS reservoir is a naturally fractured, deep, tight gas sandstone reservoir under high tectonic stress. Because the reservoir matrix is very tight, the natural fracture system is the main pathway for gas production. Meanwhile, stimulation is still required for most production wells to provide production rates that sufficiently compensate for the high cost of drilling and completing wells to access this deep reservoir. Large depletion (and related stress change) was expected during the course of the production of the field. The dynamic response of the reservoir and related risks, such as reduction of fracture conductivity, fault reactivation, casing failure etc., would compromise the long-term productivity of the reservoir. To quantify the dynamic response of the reservoir and related risks, a 4D reservoir geomechanics simulation was conducted for KS reservoir by following an integrated workflow. The work started from systematical laboratory fracture conductivity tests performed with fractured cores to measure conductivity versus confining stress for both natural fractures and hydraulic fractures (with proppant placed in the fractures of the core samples). Natural fracture modeling was conducted to generate a discrete fracture network to delineate spacious distribution of the natural fracture system. In addition, hydraulic fracture modeling was conducted to delineate the geometry of hydraulic fracture system for the stimulated wells. Then, a 3D geomechanical model was constructed through integrating geological, petrophysical and geomechanical data, and both the discrete fracture network (DFN) and hydraulic fracture system were incorporated into the 3D geomechanical model. A 4D reservoir geomechanics simulation was conducted through coupling with a reservoir simulator to predict variation of stress and strain of rock matrix as well as natural fractures and hydraulic fractures during the field production. At each study well location, a near- wellbore model was extracted from the full-field model and casing and cement were installed to evaluate well integrity during production. The 4D reservoir geomechanics simulation revealed that there would be large reduction of conductivity for both natural fractures and hydraulic fractures, and some fractures with certain dip/dip azimuth will be reactivated during the course of the field production. The induced stress change will also compromise wellintegrity for those poorly cemented wellbores. The field development plan must consider all these risks to ensure sustainable long-term production. The paper presents a 4D coupled geomechanics simulation study applied to an HP/HT naturally fractured reservoir, which has rarely been published previously. The study adapted several new techniques to quantify the mechanical response of both natural fractures and hydraulic fractures, such as to use laboratory tests to measure stress sensitivity of natural fractures, integrating DFN and hydraulic fracture system into 4D geomechanics simulation, and evaluating well integrity on both the reservoir scale and the near-wellbore scale.