Not enough data to create a plot.
Try a different view from the menu above.
Results
Numerous surface-felt earthquakes have been spatiotemporally correlated with hydraulic fracturing operations. Because large deformations occur close to hydraulic fractures (HFs), any associated fault reactivation and resulting seismicity must be evaluated within the length scale of the fracture stages and based on precise fault location relative to the simulated rock volumes. To evaluate changes in Coulomb failure stress (CFS) with injection, we conducted fully coupled poroelastic finite-element simulations using a pore-pressure cohesive zone model for the fracture and fault core in combination with a fault-fracture intersection model. The simulations quantify the dependence of CFS and fault reactivation potential on host-rock and fault properties, spacing between fault and HF, and fracturing sequence. We find that fracturing in an anisotropic in-situ stress state does not lead to fault tensile opening but rather dominant shear reactivation through a poroelastic stress disturbance over the fault core ahead of the compressed central stabilized zone. In our simulations, poroelastic stress changes significantly affect fault reactivation in all simulated scenarios of fracturing 50-200 m away from an optimally oriented normal fault. Asymmetric HF growth due to the stress-shadowing effect of adjacent HFs leads to 1.) a larger reactivated fault zone following simultaneous and sequential fracturing of multiple clusters compared to single-cluster fracturing; and 2.) larger unstable area (CFSgt;0.1) over the fault core or higher potential of fault slip following sequential fracturing compared to simultaneous fracturing. The fault reactivation area is further increased for a fault with lower conductivity and with a higher opening-mode fracture toughness of the overlying layer. To reduce the risk of fault reactivation by hydraulic fracturing under reservoir characteristics of the Barnett Shale, the Fort Worth Basin, it is recommended to 1.) conduct simultaneous fracturing instead of sequential; and 2.) to maintain a minimum distance of ~ 200 m for HF operations from known faults.
- North America > Canada (1.00)
- North America > United States > Texas > Travis County > Austin (0.28)
- North America > United States > Texas > Tarrant County > Fort Worth (0.24)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (1.00)
- Geology > Structural Geology > Fault (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- (2 more...)
- South America > Argentina > Patagonia > Neuquรฉn > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Wyoming > Green River Basin > Jonah Field (0.99)
- North America > United States > West Virginia > Appalachian Basin (0.99)
- (51 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 3864861, โGeomechanics Modeling of Strain-Based Pressure Estimates: Insights From Distributed Fiber-Optic Strain Measurements,โ by Wei Ma and Kan Wu, Texas A&M University, and Ge Jin, Colorado School of Mines. The paper has not been peer reviewed. _ The combination of Rayleigh frequency shift distributed strain sensing (RFS-DSS) and pressure-gauge measurements has been reported recently in field applications. The main objective of the study detailed in the complete paper is to investigate the relationship between strain change and pressure change under various fractured reservoir conditions and provide guidelines for better using this novel strain/pressure relationship to estimate conductive fractures and pressure profiles. Introduction With a spatial resolution of 20 cm and a sensitivity of less than 1 ฮผฮต, RFS-DSS can measure mechanical strain changes along the fiber with higher accuracy and sensitivity than low-frequency distributed acoustic sensing measurements. The field applications of RFS-DSS have improved the understanding of near-well and far-field fracture characteristics and the relationship between stimulation and production in unconventional reservoirs. Although some numerical modeling works have been conducted to study the mechanisms of RFS-DSS data sets, the sensitivity, or influencing factors, of the relationship between strain change and pressure change along the fiber are still unclear. In this work, the authors use a coupled geomechanics and fluid-flow simulator to simulate the strain change and pressure change measured along the producing and monitoring wells during both stable production and shut-in periods. Methodology A 3D multilayer reservoir model with dimensions of 300ร400ร55.82 m was created using Permian Basin data sets. The reservoir was discretized into 553ร129ร5 gridblocks. To ensure accurate simulation of field RFS-DSS measurements, the mesh was refined around the fracture and wellbore. The fracture width was set to be the same as the RFS-DSS spatial resolution (0.2 m), and the grid size was set to 5 m except for the refined region. As shown in Fig. 1, the reservoir had 11 perforation clusters along the producing well and the monitoring well was 65 m away from the producing well. A fiber cable was installed on both wells to measure the RFS-DSS data set. The producing well was operated for 240 days before being shut in for 4 days, followed by a 1-day reopening and then continued production for 1 year. The pressure decline was 30โ40 psi during the 1-day stable production period. Note that the moment after producing 239 days was taken as the reference time to calculate the strain change during the 1-day production (239โ240 days) and the moment after 240 days as the reference time to calculate the strain change during the shut-in period (240โ244 days).
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.89)
Enhancing Fracture Conductivity in Soft Chalk Formations With Diammonium Phosphate Treatment: A Study at High Temperature, Pressure, and Stresses
Desouky, Mahmoud (Department of Petroleum Engineering, King Fahd University of Petroleum & Minerals) | Aljawad, Murtada Saleh (Department of Petroleum Engineering, King Fahd University of Petroleum & Minerals) | Abduljamiu, Amao (Center for Integrative Petroleum Research, King Fahd University of Petroleum & Minerals (Corresponding author)) | Solling, Theis (Center for Integrative Petroleum Research, King Fahd University of Petroleum & Minerals) | Abdulraheem, Abdulazeez (Center for Integrative Petroleum Research, King Fahd University of Petroleum & Minerals) | AlTammar, Murtadha J. (Department of Petroleum Engineering, King Fahd University of Petroleum & Minerals) | Alruwaili, Khalid M. (Center for Integrative Petroleum Research, King Fahd University of Petroleum & Minerals)
Summary This study aims to address the problem of fracture hydraulic conductivity decline in soft formations using a diammonium hydrogen phosphate (DAP) solution. A naturally weak carbonate, Austin chalk was chosen as an ideal specimen. Flat chalk samples with reduced elastic modulus and roughness were evaluated before and after aging with 1 M DAP for 72 hours at 75ยฐC and 1,000 psi. The fracture gas conductivity of DAP-aged and untreated samples was measured at various flow rates and stresses while recording sample compaction using linear variable differential transformers (LVDTs). The study found that DAP aging increased the reduced elastic modulus of chalk specimens up to 330% of the original value, improving their resistance to deformation and failure under stress by 200 psi. The hydraulic conductivity of DAP-aged samples was at least twice that of untreated samples, with an extended hydraulic fracture conductivity seven times higher than that of the untreated ones. Scanning electron microscopy (SEM) and energy-dispersive X-ray spectroscopy (EDS) analysis revealed that DAP reacted with the chalk to form hydroxyapatite (HAP), which binds the calcite grains, yielding a stiffer, more deformation-resisting rock surface. Overall, the study demonstrates the potential of chemically enhancing and extending the fracture hydraulic conductivity of weak carbonates using DAP.
- North America > United States > Texas (1.00)
- Asia (1.00)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (0.88)
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 2023-3864710, โA Comprehensive Simulation Study of Hydraulic Fracturing Test Site 2 (HFTS-2): Part IโModeling Pressure-Dependent and Time-Dependent Fracture Conductivity in Fully Calibrated Fracture and Reservoir Models,โ by Han Li, Jichao Han, SPE, and Jiasen Tan, SPE, Occidental Petroleum, et al. The paper has not been peer reviewed. _ Combining fracture and reservoir diagnostic analysis with integrated geomechanics and reservoir simulation is an efficient and cost-effective approach to generate realistic fracture geometry, understand fluid flow behavior, and define fracture-conductivity distribution in unconventional reservoirs. The complete paper presents a case study of integrated geomechanical and reservoir simulation with a developed fracture-conductivity-calculation work flow that was validated with diagnostic results to evaluate well spacing and completions design. Introduction This study extends that of previous authors by matching field fracture diagnostics and reservoir simulation using variable fracture conductivity. In the example used by the authors from the Hydraulic Fracturing Test Site 2 (HFTS-2) development, multiple fracture diagnostic methods were used to calibrate hydraulic fracture models. Once the model was calibrated, a new proppant-conductivity algorithm assigned conductivity values along the hydraulic fractures based on a physics-based model calculation of proppant concentration. Multiple mechanisms, such as stress- and pressure-dependent effects, time-dependent conductivity degradation, unpropped fractures, and proppant embedment, can all be considered in the novel fracture-conductivity-calculation methodology. Fracture-Conductivity-Calculation Work Flow The conductivity work flow developed by the authors uses simulated proppant concentration from a fracture model and experimental conductivity measurements of propped and unpropped fractures to define variable conductivity along hydraulic fractures. Conductivity measurements included sets of long-term (50-hour) experimental fracture-conductivity tests with various mesh sizes, proppant types, and closure stresses. The conductivity-calculation work flow developed by the authors was applied to the integrated simulation project of multifractured horizontal wells in the HFTS-2 project. Fig. 1 shows a flow chart of the work flow from fracture propagation modeling through integrated reservoir simulations. In general, the work flow consists of developing a 3D geological model, creating and calibrating parent wellsโ hydraulic fracture models, calculating the fracture conductivity based on proppant concentration, history-matching the parent wellsโ production and constraints with reservoir simulation, performing fracture-propagation modeling for child wells, and history matching and predicting the estimated ultimate recovery (EUR) for the entire pad. HFTS-2 Project Overview The HFTS-2 is in the Delaware Basin and is a cost-shared, field-based project designed to study hydraulic fracturing processes and production using state-of-the-art diagnostics, including fiber optic (FO) distributed temperature sensing and distributed acoustic sensing (DAS) pressure monitoring, image logs, cores through the fractures, and microseismic monitoring. Many studies have detailed the project overview of the HFTS-2, and this paperโs authors only include the overview of completions in the HFTS-2 project.
- North America > United States > Texas (0.25)
- North America > United States > New Mexico (0.25)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin (0.99)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
- Information Technology > Modeling & Simulation (1.00)
- Information Technology > Communications > Networks > Sensor Networks (0.55)
A Two-Phase Type-Curve Method with Fracture Damage Effects for Hydraulically Fractured Reservoirs
Zhang, Fengyuan (National Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum-Beijing, Beijing, China) | Pan, Yang (National Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum-Beijing, Beijing, China) | Rui, Zhenhua (National Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum-Beijing, Beijing, China) | Emami-Meybodi, Hamid (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University, State College, Pennsylvania, USA) | Yang, Chia-Hsin (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University, State College, Pennsylvania, USA) | Wang, Ruiqi (Department of Oil Field Development, Research Institute of Petroleum Exploration & Development, Beijing, China) | Zhang, Wei (Department of Geoscience, University of Calgary, Calgary, Alberta, Canada)
Abstract Type-curve analysis on flowback and production data is a powerful tool in characterizing hydraulic fractures (HF) and reservoir properties. In order to evaluate HF characteristics and their dynamics for multi-fractured horizontal wells (MFHWs) in hydrocarbon reservoirs, we provide a novel type-curve method and an iterative workflow. The type curve incorporates the fracture damage effect, which is characterized by choked-fracture skin factor, into the two-phase flow in HF and matrix domains. The type-curve method can be applied to inversely estimate choked-fracture skin factor, fracture pore-volume, fracture premeability, and fracture permeability modulus through the analysis of two-phase production data. By introducing the new dimensionless parameters, the non-uniqueness problem of the proposed semianalytical method is significantly reduced by incorporating the complexity of fracture dynamics into one set of curves. The proposed type curve's accuracy is examined by numerical simulations of a shale gas and shale oil reservoir. The validation results demonstrate the good match of analytical type curves and numerical data plots and confirms the accuracy of the proposed approach in estimating the static and dynamic fracture properties. The flexibility and robustness of the proposed method are illustrated using the field example from a shale oil MFHW. The interpreted results from the flowback analysis of the field example offers a quantitative insight of fracture properties and dynamics.
- North America > United States (1.00)
- North America > Canada > Alberta (0.28)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.90)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Walker Ridge > Block 628 > Julia Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Walker Ridge > Block 627 > Julia Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Walker Ridge > Block 584 > Julia Field (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (8 more...)
Dynamic Fracture Characterization Using Multiphase Rate Transient Analysis of Flowback and Production Data
Zhang, Zhengxin (China University of Petroleum Beijing) | Sun, Guoqing (Northeast Petroleum University) | Zhou, Xingze (PetroChina Changqing Oilfield Company) | Dang, Kaiyan (Shaanxi YanChang Petroleum Group Co., Ltd.) | Su, Xing (Pennsylvania State University)
Abstract This study presented a comprehensive method for characterizing reservoir properties and hydraulic fracture (HF) closure dynamics using the Rate Transient Analysis (RTA) of flowback and production data. The proposed method includes straight-line analysis (SLA), type-curve analysis (TCA), and model history matching (MHM), which are developed for scenarios of two-phase flow in fracture, stimulated reservoir volume (SRV), and NSRV domains. HF closure dynamics are characterized by two key parameters: pressure-dependent permeability and porosity controlled by fracture permeability-modulus and compressibility. The above techniques are combined into a generalized workflow to iteratively estimate the five parameters (four optional parameters and one fixed parameter) by reconciling data in different domains of time (single-phase water flow, two-phase flow, and hydrocarbon-dominated flow), analysis methods (SLA, TCA, MHM), and phases (water and hydrocarbon phase). We used flowback and production data from a shale gas well in the US to verify the practicability of the method. The analysis results of the field cases confirm the good performance of the newly developed comprehensive method and verify the accuracy in estimating the static fracture properties (initial fracture pore volume and permeability) and the HF dynamic parameters using the proposed generalized workflow. The accurate prediction of the decreasing fracture permeability and porosity, fracture permeability-modulus, and compressibility demonstrates the applicability of the workflow in quantifying HF dynamics. The field application results suggest a reduction of the fracture pore volume by 30%, and a reduction of the fracture permeability by 98% for shale gas well. Instead of a single analysis method for RTA, this paper proposed a comprehensive analysis method that includes SLA, TCA, and MHM. The interpretation results of the three analysis methods are mutually constrained, which can reduce the non-uniqueness problem of inversion. Compared with the others fracture characterization workflow that need fixed input and output parameters. This proposes general workflow not only completely characterizes the fracture closure dynamics but also can select the unknown parameters (to be determined) according to the actual scenarios of a well and the demands of reservoir engineers.
- Asia (1.00)
- North America > United States (0.89)
- North America > Canada > Alberta (0.28)
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- Geology > Geological Subdiscipline > Geomechanics (0.70)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.56)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (8 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (3 more...)
Abstract The understanding of fracture distributions plays a critical role in managing fractured reservoirs as they govern early water/CO2 breakthrough, impact sweep efficiency, and determine production behaviors. However, traditional simulation-based approaches, such as history matching, encounter significant difficulties in accurately predicting fracture distributions, and high-fidelity simulations can be computationally prohibitive. This paper proposes a comprehensive machine learning-based workflow to effectively characterize and describe fracture distributions for unconventional reservoir models. The proposed workflow has four components. Firstly, a single fracture parameterization is implemented, utilizing four fracture parameters: fracture initiation point, length, angle, and azimuth. Secondly, a Variational Autoencoder (VAE) is employed for fracture map parameterization. The encoder maps a high-dimensional fracture distribution map to a low-dimensional latent space, and the decoder reconstructs the fracture distribution map from the reduced latent dimension to the full reservoir dimension. Thirdly, a neural network is utilized for fracture distribution prediction, establishing a regression relationship between latent variables and production data. Finally, a nearest-neighbors selection is achieved by applying principal component analysis (PCA) in 2D principal coordinates for quantifying uncertainty. The efficacy of the proposed workflow is demonstrated in a 2D synthetic case and subsequently applied to the 3D benchmark case. A total of 5,000 fractured permeability realizations are generated by randomly selecting the four fracture parameters. The values for these parameters are generated based on a normal distribution. Each realization has a unique fracture distribution. These realizations are split into training (4,500), validation (250) and testing (250) sets. The VAE model is trained on the training set first. Then the best model was selected using the validation set, and finally tested on the testing set. The trained VAE decoder serves as a fracture generator. A total of 200 latent variables are selected to represent the latent fracture distribution and fed to the decoder to reconstruct the fracture maps. To predict an unknown fracture distribution given only observed production data, we establish regression models between the production data and latent variables. The regression models are neural network models trained on the production data and the latent vectors of the training set. In the prediction stage, the observed production data was fed to the regression models to predict the latent vectors. Then the latent vectors were passed to the trained VAE decoder to predict the latent fracture maps. Finally, to account for the geological uncertainty, we applied the nearest neighbor selection to select multiple realizations from the training and validation set as the results. The comprehensive data-driven workflow presented in this paper not only offers an efficient and effective way for fracture parameterization and prediction, but also demonstrates the practical feasibility in field case study.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
Abstract Economic optimal recovery of hydrocarbons from unconventional reservoirs requires consistent and sufficient stimulation energy across an entire drill spacing unit (DSU), both along laterals and between them. This necessitates an understanding of how and why fractures propagate away from the treatment well. While legacy methods such as Distributed Acoustic and Temperature Surveys (DAS/DTS), pressure responses, logging/imaging has allowed us to investigate the point of stimulation origination, analyzing Low Frequency Distributed Acoustic Sensing (LF-DAS) gives us unique insights into far field fracture behavior. This paper aggregates several existing LF-DAS datasets in the Marcellus as well as the most representative log data available to draw conclusions on the impacts of geology, completion test parameters, stage and well frac order, frac design and materials, lateral placement, and many other influence factors on far field fracture behavior. Both statistical analysis and data visualization of these datasets independently and in aggregate was used to identify numeric as well as engineer-based observations and conclusions. By using these two methods, correlations between influence factors and far field fracture behavior are identified and quantified, and a level of variability is demonstrated for the Marcellus as well as some specific sub-plays. The analysis presented identifies controllable parameters to adjust as well as uncontrollable parameters that must be designed around to achieve stimulation goals. Also included is a description of where additional data collection is required to improve certainty and robustness of the analysis. Aggregated analysis on cross well far field fracture behavior has not previously been performed for Marcellus. This paper displays multi-project trends that were previously unidentified allowing the opportunity to design future tests around and confirm or challenge existing theories and conclusions. Previously non discussed fracture behaviors in the dataset are also described and addressed.
- North America > United States > West Virginia (1.00)
- North America > United States > Pennsylvania (0.84)
- North America > United States > New York (0.84)
- (2 more...)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.66)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.41)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
i-Geo Sensing: An End-to-End Fracture Direct Diagnostic Platform
Van Pham, Vuong (Chemical and Petroleum Engineering, University of Kansas, KS, USA) | Dahaghi, Amirmasoud Kalantari (Chemical and Petroleum Engineering, University of Kansas, KS, USA) | Babakhani, Aydin (Samueli Computer and Electrical Engineering, University of California, Los Angeles, California, USA)
Abstract Within the development of unconventional resources, especially in the United States, multi-stage hydraulic fracturing across multiple fields is adapted to become the best practice in the industry. In hydraulic fracturing, a complex fracture network is always initiated before the slurry fluid is pumped into the reservoir. Consequently, understanding this fracture network's geometry and its degree of complexity has been one of the forefronts of unconventional development. The industry has been conducting various methods to achieve this forefront, divided into three categories: direct near-wellbore (e.g., production/temperature logs, tracers, borehole imaging), direct far-field (e.g., micro-seismic fracture mapping), and indirect modeling (net pressure method). Unfortunately, none of these methods provide direct and dynamic information about the hydraulic fracture network. In this study, a novel integration of both hardware (namely, the Smart Microchip Proppants, abbreviated as SMPs) and software (namely, the i-Geo Sensing) is conducted to address the "indirect" drawback of current fracture diagnostic techniques and practicalize the power of modern Deep Learning in semi real-time fracture mapping. The SMPs are explicitly designed to be injected directly into the reservoir along with the conventional proppants. This paper focuses on the transmitted smart microchip proppants data in semi-real time. The i-Geo Sensing is integrated between three core modules: the unsupervised, the supervised, and the connector. The unsupervised module digests the transmissible signal from the SMPs, performs necessary pre-processing, and recognizes prospective fractures. The supervised module receives the result from the unsupervised module, combines with the support from the data generator module, flow-back/production data, and eventually predicts the most reasonable realizations of the hydraulic fracture network. The i-Geo Sensing's capability is tested using a case study with the pre-defined hydraulic fracture geometry. Results from the case study indicate the robustness of the supervised module under unknown loss of data transmission from the SMPs (2-5% decrease in accuracy) and consistent improvements of accuracy between 9-25% in fracture diagnostic from the unsupervised module to the supervised module.
- North America > United States > Texas (0.46)
- North America > United States > California (0.28)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
- (2 more...)
- Information Technology > Data Science > Data Mining (1.00)
- Information Technology > Communications (0.89)
- Information Technology > Artificial Intelligence > Machine Learning > Neural Networks > Deep Learning (0.89)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning > Clustering (0.69)
Abstract This study presents the integration of sedimentology and well completion to explain variable production performances in wells from an unconventional siliciclastic reservoir. The significance of our study is that multidisciplinary approaches are among the most comprehensive solutions that can forecast areas with different performance and, thus, make consistent completion strategies before drilling and optimize the development of unconventional reservoir acreages. The main producing interval within the area of interest includes cm-thick, carbonate-rich layers that based on a total of 20 vertical wells are inferred to extend several km. The cumulative thickness of these layers and their frequency (number of layers/thickness of producing interval) vary across the area. This variation is compared to hydraulic fracturing and completion data that include breakdown pressure, pressure decline, hammer effect, ISIP gradient, fracture driven interactions, and completion strategies (i.e., proppant intensity, volume of fluids, cluster, stages, well spacing). All these data are then compared to the reported production from horizontal wells (> 150). Both the correlation of vertical wells and the distribution maps predict the existence of higher cumulative thickness and frequency of carbonate-rich layers towards the center of the study area. Also, the frequency of carbonate-rich layers reveals a positive relationship with the normalized production of nearby horizontal wells, which points to increased production as brittleness of the system increases. However, a variable degree of data dispersion is seen in this positive relationship, and it is attributed to different completion strategies over the years. One way, though, to explore the relationship between completion parameters, sedimentology, and well production is to use a correlation matrix that allows to differentiate the relative importance of each factor. For instance, we observe a strong and negative correlation between the frequency of carbonate-rich layers and the ISIP gradients, whereas the ISIP gradients and the well production exhibit a small, albeit positive, correlation. Completion and hydraulic fracture designs undoubtedly influence well production but there exists an inherent anisotropy, related to the presence of cm-thick, fragile, carbonate-rich layers between m-thick, plastic, clay-rich intervals, that affects the toughness of the system and, ultimately, impacts well production. This work presents solution seeking through integration of multidisciplinary approaches with application of data analytics to create predictive methodologies. The use of two different disciplines such as sedimentology and completion design, rarely integrated together for an unconventional play, is novelty by itself. Correlation matrices could play a fundamental role in the optimization of field development plans in general and bespoke hydraulic fracture design.
- North America > United States > Texas (0.46)
- North America > United States > Pennsylvania (0.29)
- Geology > Sedimentary Geology (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Mineral (0.90)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.33)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (4 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Sedimentology (1.00)
- (4 more...)