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Collaborating Authors
Locating fractures, recognizing fracture morphology, and identifying fluid-flow properties in the fracture system are important criteria in characterizing reservoirs that produce predominantly from fracture systems.Acoustic techniques can provide insight. Fracture identification and evaluation using conventional resistivity and compressional-wave acoustic logs is difficult, in part because fracture recognition is very dependent on the dip angle of fractures with respect to the borehole. Fractures are physical discontinuities that generate acoustic reflection, refraction, and mode conversion--all of which contribute to a loss of transmitted acoustic energy. In particular, compressional- and shear-wave amplitude and attenuation and Stoneley-wave attenuation are significantly affected by the presence of fractures. Compressional waves are primarily affected by oblique fractures--those with dip angles between 15 and 85 --while shear waves are primarily affected by horizontal or near-horizontal fractures.[1]
- Asia > Middle East (0.17)
- North America > United States > Oklahoma (0.16)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.75)
- Information Technology > Knowledge Management (0.41)
- Information Technology > Communications > Collaboration (0.41)
Natural fractures in the Triassic tight sandstones of the Dongpu Depression, Bohai Bay Basin, eastern China: The key to production
Wang, Zhaosheng (China University of Petroleum, North China University of Science and Technology) | Zeng, Lianbo (China University of Petroleum) | Luo, Zhouliang (Zhongyuan Oilfield Company) | Zu, Kewei (Zhongyuan Oilfield Company) | Lao, Haigang (North China University of Science and Technology) | Meng, Ningning (North China University of Science and Technology)
Abstract Natural fractures are identified as high-quality storage space and seepage channels for the Triassic tight sandstone reservoirs in the Dongpu Depression, playing an important role in tight sandstone oil production. We have evaluated natural fracture growth at different scales using outcrops, cores, thin sections, and imaging logs and analyzed the correlation between fractures and crude oil production capacity with production data. Results show that natural fractures primarily are distributed in fine sandstones and siltstones, which mostly are shear fractures of near eastโwest and northeastโsouthwest strikes. The natural fractures of near eastโwest strikes generally are parallel to the present-day maximum horizontal principal stress with the biggest apertures and the highest permeability, which are the main seepage channels, next being the fractures of northeastโsouthwest strike. The natural fractures of near eastโwest strikes also are the most important contributors to the crude oil production in the Triassic tight sandstones of the Dongpu Depression. The intensity, permeability, and direction of natural fractures govern the crude oil productivity in the per-unit sandstone thickness.
- Asia > China > Henan Province (0.46)
- South America > Venezuela > Zulia (0.28)
- Asia > China > Xinjiang Uyghur Autonomous Region (0.28)
- South America > Venezuela > Zulia > Maracaibo Basin > La Paz Field (0.99)
- Asia > China > Xinjiang Uyghur Autonomous Region > Tarim Basin (0.99)
- Asia > China > Xinjiang Uyghur Autonomous Region > Junggar Basin (0.99)
- (11 more...)
Abstract Natural fractures influence fluid flow into or out of formations. This may take place under in situ conditions but is more likely under stimulated conditions. How fractures behave depends on the natural fracture properties and geomechanical state of the field. If the natural fractures can retain the enhanced permeability due to shear slip brought about by injection, then the pressure-stimulated natural fractures can contribute significantly to production enhancement. To assess the impacts of natural fractures in an intended operation, it is essential to characterise the natural fractures, relate their properties with the geomechanical conditions and model their responses to changing geomechanics during fluid injection (drilling, stimulation) or production. This study aims to characterise natural fracture permeability under in situ stress conditions to determine the best well orientation in order to intersect the greatest number of critically stressed fractures and, ultimately, optimise productivity from future wells. Analytical modelling, considered the in situ conditions, is undertaken to calculate the downhole pressure required to initiate shear slip on well-oriented fractures, make them critically stressed and hence permeable to drilling fluid. Given knowledge of the stress state, the distribution of natural fractures, and the properties of those fractures, it was possible to select the best directions to drill a well to maximise productive contact with the reservoir. Modelling showed that the interpreted fractures would require different pressures (from 10.8 to 16.7 pounds per gallon, ppg) to become critically stressed. Critically stressed fractures strike approximately parallel to the azimuth of the maximum horizontal stress (160ยฐN) and dip ~60ยฐ. The interpreted fractures have a wide range of dips in different wells, ranging from horizontal to vertical whilst most of them are generally steeply-dipping. Fracture trends are predominantly NW-SE except in one well where they trend NE-SW. The best well trajectory to encounter the most permeable fractures is required to be highly deviated, 60ยฐ - 85ยฐ, and parallel to the azimuth of the minimum horizontal stress (070ยฐN). Results showed some variations from well to well, with one well appearing to be an outlier due to the different fracture population interpreted from the image data. Wellbore trajectories were optimized to take advantage of critically stressed fractures for maximum production from the fractured reservoir.
- Asia (0.46)
- North America (0.28)
- Africa > Cameroon > Gulf of Guinea (0.25)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.30)
Summary For enhanced geothermal systems (EGS), multistage hydraulic fracturing along a deviated or horizontal well is a key technology used to create a high-conductivity fracture network between injection and production wells in deep, low-permeability geothermal reservoirs. The purpose of the created fracture network is to allow for the efficient transfer of fluid, heated by the geothermal reservoir, from the injection to the production well; therefore, well spacing (between injection and production wells) and hydraulic fracturing must be designed not only to promote connectivity between well pairs but also to mitigate thermal short-circuiting and thermal breakthrough. Analysis of post-fracture pressure decay (PFPD) data measured after each stage of a hydraulic fracturing treatment can be used to provide critical reservoir and fracture parameters required for well and hydraulic fracturing design optimization; this method provides a low-cost alternative and complementary approach to in-situ observation techniques, such as core-through experiments, fiber optics, or image logs in offset wells. Until now, PFPD has primarily been applied to multifractured horizontal wells (MFHWs) completed in low-permeability hydrocarbon reservoirs. The goal of this study is therefore to develop a methodology to estimate fracture and reservoir parameters using stage-by-stage PFPD data associated with EGS projects. An analytical model is proposed herein to estimate fracturing fluid efficiency, fracture length, average fracture aperture, average fracture conductivity, and reservoir permeability for different possible fracture geometries in EGS reservoirs. PFPD data collected for three hydraulic fracture stages in the injection well at the Utah Frontier Observatory for Research in Geothermal Energy (FORGE) site were analyzed to demonstrate the practical application of the proposed method. The results of this study indicate that, due to the presence of natural fractures in the target (granitic) reservoir, the hydraulic fracturing treatment (using slickwater) in the openhole section resulted in low fracturing fluid efficiency and small hydraulic fractures. In contrast, hydraulic fracturing treatments conducted in the perforated casedhole wellbore resulted in higher fracturing fluid efficiency and created larger hydraulic fractures even with smaller injected volumes. The results of the PFPD analysis were confirmed using a Formation MicroScanner image log and microseismic data collected during each stage of hydraulic fracturing.
- North America > United States > Utah (0.62)
- North America > United States > Texas (0.46)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Energy > Renewable > Geothermal > Geothermal Resource (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Renewable > Geothermal > Geothermal Resource for Power Generation > Enhanced Geothermal System (0.61)
- Oceania > Australia > South Australia > Cooper Basin (0.99)
- Oceania > Australia > Queensland > Cooper Basin (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin (0.99)
Modeling Fractures in a Heterogeneous Carbonate Reservoir Onshore UAE: A Case Study
Lavenu, Arthur P. C. (ADNOC Onshore, PO Box 270, Abu Dhabi, UAE) | Irving, Alan (TotalEnergies, CSTJF, Avenue Larribau, 64018 Pau Cedex, France) | Niculescu, Elena (ADNOC Onshore, PO Box 270, Abu Dhabi, UAE) | Singh, Nepal (ADNOC Onshore, PO Box 270, Abu Dhabi, UAE) | Kusyairi, Amirul (ADNOC Onshore, PO Box 270, Abu Dhabi, UAE) | Douik, Hela (ADNOC Onshore, PO Box 270, Abu Dhabi, UAE)
Abstract A brown field producing from an Upper Cretaceous carbonate reservoir in an elongated anticline is facing water management challenges (increasing water cut, premature water breakthrough), impacting production and recovery. The complexity of heterogeneities encountered in the reservoir (fractures, karst-related features, high permeability dolomitic drains), where depositional settings, diagenesis, and tectonics are intertwined, makes reservoir characterization critical to a successful field development plan. Evidence of dual medium behavior, combined with the presence of fractures from image logs, suggests that fractures may play an important role in reservoir dynamics, and hence need to be modeled appropriately. In this study, the scope of work was threefold: reviewing the conceptual fracture model in considering the latest data, creating updatable workflows to build discrete fracture networks in commercial geomodeling software, and, ultimately, comparing upscaled properties to well test interpretations representing "fracture" and "matrix" responses. Main fracture sets trend NE-SW, parallel to the anticline axis, and E-W. Two fracture scales have been modeled in the present case study: large features that relate to the deterministic component of the dataset (fracture clusters from image log interpretation and seismic lineaments), and small-scale fractures, stochastically distributed, to reflect the permeability contribution of diffuse fractures connecting deterministic objects. Calibration to dynamic data is performed by analytical estimation of fracture aperture per fracture orientation set, upscaling to equivalent grid permeability, and iterating until reaching a satisfactory match with the test-derived permeability. The calibration exercise gives a consistent fracture aperture for the two orientation sets tested (NE-SW and E-W). Fracture modeling was done in parallel to building reservoir matrix properties hence the dynamic calibration considers only fracture permeability. In some cores, measured permeability can reach several Darcies, leading to dual medium behavior without the contribution of fractures. Future work could integrate this analysis with existing sedimentology and reservoir dynamic syntheses to assess the relative impact of high permeability streaks on equivalent permeability and deconvolve it from the role of fractures.
- Geology > Sedimentary Geology (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.69)
- Asia > Middle East > UAE > Thamama Group > Shu'aiba Formation (0.99)
- Africa > Middle East > Libya > Murzuq District > Murzuq Basin > Block NC 115 > Field B Field > Silurian Tanezzuft Formation (0.97)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Abu Dhabi Field (0.94)