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Collaborating Authors
Rahman, Khalil
Abstract In many cases, the production prediction at the fracture design stage and later from the post-fracture pressure-matching exercise is never realized. The underperformance of fracture treatments is often attributed either to formation damage, proppant crushing and embedment, or to the poor reservoir quality despite a reasonably good reservoir property indicator from all sources including the pressure decline in a mini-fracture test. Based on several case studies, this paper highlights a number of issues that were found responsible for underperformance of fracture treatments. The understanding and mitigation of these issues require the application of comprehensive geomechanics. For each case, a comprehensive geomechanical model was built for the field, characterizing the depth profiles of all three stresses, rock mechanical properties and the direction of the horizontal stresses by integrating available data from various sources including drilling and logging data, laboratory rock test data and mini-fracture test data. The contrasts in stress and rock mechanical properties among various lithologies along the well path were created based on fundamental geomechanical principles. The hydraulic fracture growth was simulated as per the pressure-matching practice for each treatment carried out. The production condition was applied to the simulated propped fracture to predict the production and compare it with the actual production data where available. Issues that were found responsible for lower-than-expected production include (1) out-of-zone fracture growth that could not be predicted using the oversimplified geomechanics; (2) poor connection between wellbores and fractures for unfavorably oriented wells; (3) non-optimum perforation intervals that caused non-optimum fracture growth and near-perforation low conductivity; (4) malpractices in treatment execution that resulted in disconnected fractures with the perforations; and (5) suboptimal treatments for reservoir conditions. Appropriate mitigation strategies were recommended for wells in production, and increased productions were reported where the recommendations were implemented. One significant observation is that several oversimplified techniques currently used in the industry create significantly different stress contrast profiles than that was found based on fundamental physics of geomechanics, though all these profiles could be calibrated with the same closure pressure from a mini-fracture test. The use of such inaccurate stress contrast profiles is primarily responsible for unrealistic fracture and production predictions.
- North America > United States (0.46)
- Europe (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.72)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.47)
- Geophysics > Borehole Geophysics (0.66)
- Geophysics > Seismic Surveying (0.47)
Abstract Drilling in the Cooper Basin faces challenges from the hostile stress environment, high-pressure and high-temperature conditions, and variations in rock properties with depth. The current understanding is that the Cooper Basin is under a highly deviatoric, strike-slip stress regime with significant stress contrasts between different lithologies. These conditions create challenges for drilling and well stimulation. A series of wells have been reviewed to understand the vertical and lateral stress changes in the Patchawarra Trough in the Northern Cooper Basin. The temperature anomaly at this location appears to be lower than in the Nappamerri Trough in the south. A different level of overpressure is also observed, and the formation pressure appears to vary depending on structural location. Shallow wells on the ridge appear to be near hydrostatic in the Permian sands, but overpressure is as high as 10.5-11 ppg on structures in the deeper part of the Patchawarra Trough. Rocks appear to be generally strong, with siltstones in the Permian section being only slightly weaker than sandstones. The stress anisotropy in the sandstone is large; the SHmax/Shmin ratio is greater than 2. The stress anisotropy is considered to be the reason for preferential wellbore failure in sands instead of shaly siltstones. The stresses in interlayered thick coals tend to be near isotropic. It is also thought that the stress regime is not necessarily uniform with depth; the maximum horizontal stress decreases drastically at shallower depths, and the stress regime becomes normal faulting. The detailed geomechanical analysis shows that the drilling challenges faced in the deeper section are mainly caused by the thick coal sequences. Sandstones and siltstones are relatively strong, should not cause much wellbore instability, and are only expected to develop narrow breakouts. For hydraulic fracturing, the small stress contrast (similar minimum horizontal stress magnitudes) between sandstone and siltstone in the Permian formation would result in difficulty in confining the fracture in zone. Consequently, excessive height growth may cause the fracture to grow into highly fractured coals and may lead to early screen-outs. Detailed geomechanical modeling for a series of wells in the Patchawarra Trough has enabled a thorough understanding of variations in rock properties, pressure and stress in the area. Optimised drilling strategies for mud weight and mud properties were adopted for the drilling of vertical and horizontal wells. Accurate stress modelling also helped the optimisation of hydraulic fracture design to achieve successful fracture treatments for improved production.
- Oceania > Australia > South Australia (1.00)
- Oceania > Australia > Queensland (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- Oceania > Australia > South Australia > Eromanga Basin (0.99)
- Oceania > Australia > South Australia > Cooper Basin > Murta Formation > McKinlay Member (0.99)
- Oceania > Australia > Queensland > Eromanga Basin (0.99)
- (37 more...)
Abstract Drilling and stimulation of exploration and development wells in the Cooper Basin, Central Australia, has been challenging over the decades due to the high-pressure, high-temperature environment, the high stress anisotropy, and the presence of thick coals. Most of the wells drilled to date have been vertical. To improve production, a study was conducted for a low-permeability tight-sand oil field to assess a horizontal well with multi-stage stimulation. The long horizontal well was expected to pass through a region with varying depletions and lithologies, causing lateral variations in stress and rock properties that could only be captured by a 3D geomechanical model. A 3D geomechanical model was constructed to provide an integrated and accurate understanding of the field and to facilitate the planning and design of drilling, completion and stimulation of the horizontal well with reduced cost and risks, and to maximize the productivity. Based on detailed 1D geomechanical modelling, a well-centric understanding of the three principal stresses, fluid pressure and rock mechanical properties of the formations was developed for offset wells in the field. The pore pressure distribution and depletion in 3D space was calibrated using well test and long-term pressure survey data. Rock mechanical properties and stresses were populated in 3D space using seismic interval velocities and relationships developed in the 1D modelling, honouring the 3D static geological and structural models. The model of pressure, stress and rock property variations in 3D space enabled optimization of the casing program and mud weights. Operational best practices to drill the long horizontal well, especially the high-angle build section in overburden coals, were compiled based on a drilling knowledge base developed using data from analogous fields. The use of varying stress and rock mechanical properties along the planned well trajectory in hydraulic fracturing optimization was a differentiating approach to conventional hydraulic fracturing optimization using 1D geomechanics. The treatment was optimized to confine the fracture above the water-bearing formation along the well path. The optimized stimulation design provided the best solution of stages, proppant and fluid selection, and injection schedules to maximize production with minimum cost. Based on the detailed assessment, it was concluded that the horizontal well is drillable with optimized mud properties and good drilling practices to overcome the instability in coals. In addition, the reservoir section can be drilled safely with lower mud weights whilst still maintaining good wellbore shape. A multistage transverse fracturing program was optimized to improve the production, mitigating the challenges from the extremely low stress contrast between reservoir and the underlying water-bearing zone.
- Oceania > Australia > South Australia (1.00)
- Oceania > Australia > Queensland (0.86)
- North America > United States > Wyoming > Campbell County (0.24)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.72)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.67)
- Oceania > Australia > South Australia > Cooper Basin > Patchawarra Formation (0.99)
- Oceania > Australia > Queensland > Cooper Eromanga Basin (0.99)
- Oceania > Australia > Queensland > Cooper Basin (0.99)
- (4 more...)
Abstract Sweet spot identification in unconventional fields generally involves the identification of clusters and intensities of parameters that indicate the resource volume and production-related parameters, i.e., reservoir quality parameters such as total organic content (TOC), porosity, permeability, pay zone thickness, etc. The process usually incorporates interpretation of seismic data, well logs and other data to develop a 3D model that is used to suggest locations for productive wells. While understanding these parameters is essential in unconventional resource development, the potential to achieve productive hydraulic fractures, or the potential to exploit natural fractures, or the potential to achieve both simultaneously determines the feasibility of developing an unconventional resource. There are geomechanical conditions that are favourable to achieve the maximum productivity from stimulation operations. Identifying the geomechanical sweet spots within the field-wide reservoir quality sweet spots is, therefore, essential for optimum placement of wells and hydraulic fractures in unconventional reservoirs. This identification requirement is gaining more and more attention in the industry, which is helping the technique and workflow development. This paper discusses the workflow to identify the existence and properties of geomechanical sweet spots including rock mechanical properties and natural fracture distribution and how they help to decide the vertical location and direction of horizontal wells for optimal reservoir development. The workflow requires a multidisciplinary data set comprising drilling, geology, geophysics, production, geochemistry and geomechanical information. Based on detailed geological understanding, either a 1D or a 3D geomechanical model is built as the foundation for further analysis. Images, seismic data and structural information are the key to develop the understanding of natural fracture distribution. A discrete fracture network (DFN) model, or other definitive models, is required to identify stress-sensitive fracture distributions under different stress conditions. Due to the fact that local in-situ stress and natural fracture properties can be altered by production operations, initial unsweet spots may turn into sweet spots at some stage of production or injection operations. Based on the results of comprehensive geomechanical sweet spot analysis, an optimal development decision can be made based on integrated geomechanics, production and net present value analyses within the identified sweet spots. This paper includes results and illustrations from several case studies completed for a number of fields in the Asia Pacific to demonstrate the concept.
- North America > United States > California (0.46)
- North America > United States > Texas (0.28)
- Asia > Middle East > Saudi Arabia (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)
Abstract Hydraulic fracturing optimization requires addressing numerous challenges for various reservoirs. The proposed paper presents a case study of a thinly-interbedded tight sandstone reservoir with a very low net to gross ratio in a field, onshore Australia. A geomechanical model was developed for hydraulic fracturing optimization. The low contrast in stress and rock mechanical properties between the reservoir and bounding formations posed a challenge to achieve a fracture that was confined to the pay zone, and particularly one that avoided fracturing the underlying water-bearing zone. Optimization modelling showed that the oil flow rate increased proportionately with fracture length and conductivity up to certain threshold values, above which the production benefit diminished. An injection schedule was optimized for production using a proppant and a fracturing fluid both suitable for the reservoir conditions to achieve the optimum or near-optimum fracture length and conductivity, efficient proppant transport, and confinement of the fracture above the water-bearing zone. Production prediction through the optimized fracture design in a vertical well showed a potentially uneconomic recovery. Multi-stage fracturing of a 1,500 m horizontal well was investigated as an alternative completion scenario for which the number of transverse fractures was optimized. The spacing between such horizontal wells was also investigated and optimized based on efficient drainage that could be achieved by the horizontal well with the optimum number of transverse fractures. Optimally spaced horizontal wells with an optimum number of transverse fractures were found as the most recoverable development strategy; use of injection wells for lateral sweeping and pressure maintenance, and artificial lift is likely to increase recovery further whereas infill wells are likely to be necessary for incremental production.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
Geomechanical Assessment Aids Successful Coiled Tubing Drilling (CTD) of Horizontal Wells Through Depleted Reservoirs Interbedded With Weak Formations in the D18 Field
Chatterjee, Avirup (Baker Hughes Inc.) | He, Wei (Baker Hughes Inc.) | Rahman, Khalil (Baker Hughes Inc.) | Pozdnyshev, Maxim (Petronas Carigali Sdn Bhd.) | Wei, Ooi Zhon (Petronas Carigali Sdn Bhd.) | Hamzah, Nurul Ezalina (Petronas Carigali Sdn Bhd.)
Abstract Reservoirs in the D-18 fields, offshore Sarawak, Malaysia, are a combination of structurally and stratigraphically trapped sand bodies. Potential hydrocarbons are accumulated in the stacked sand bodies separated by weaker sealing shale bodies and regional coal seams. The fields have significantly depleted pressure following several years of production from different reservoir levels. Reservoir pressure depletion results in a lower fracture gradient and a narrower drilling mud window. While a lower mud weight is necessary to drill through heavily depleted sands, the lower mud weight may result in excessive wellbore failure in normally pressured, weak formations. A geomechanical assessment is performed to aid coiled tubing horizontal drilling in the depleted reservoirs, which are interbedded with normal-pressure, weak shaly formations. A geomechanical model was developed using available data from offset wells. A stress path factor is estimated to model the fracture gradient decrease from production-induced depletion. A safe mud window is optimized using the reduced fracture gradient in depleted sands and the hole collapse pressure in the normal-pressure weak shales. The operational mud window is optimized for hole size and annulus. The wells were drilled successfully using the recommended mud windows, without losses into the depleted sands or hole collapse in weak, normal-pressure formations. The paper presents the workflow for geomechanical model building incorporating the depletion effect, the safe coiled tubing drilling (CTD) program design assessing various risks and highlights various CTD operational issues and the lessons learned.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.47)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.34)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Pressure Management (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- (6 more...)
Abstract An integrated field development study was performed to develop a shale oil field onshore Australia. Preliminary reservoir characterization indicated that the primary reservoir is very tight with permeability approximately equal to or less than 0.001 mD, containing mainly oil of API gravity close to 41ยฐ. Thus, the reservoir is a good candidate for multistage hydraulic fracturing of a long horizontal well oriented along the minimum horizontal stress to achieve a commercially viable recovery level. A geomechanical model was developed for the field characterizing in-situ stresses, direction of the minimum horizontal stress and rock elastic properties for appropriate well orientation and hydraulic fracture design. The primary challenge in hydraulic fracturing optimization for this reservoir was optimizing the treatment to fracture the entire gross thickness of approximately 600 ft while achieving as long a fracture as possible to maximize the recovery. This objective required optimization of fracturing fluid viscosity, injection rate and perforation interval to overcome the stress barriers within the reservoir. The final stage of optimization involved the number of transverse fractures on the horizontal well (i.e. fracture spacing) incorporating the forecast of post-fracture production and net present value for every alternative scenario. Required fluid volume, proppant mass and pump capacity were useful in estimating the total well drilling and completion cost. When the total well cost was compared against the revenue from the predicted recovery resulting from the optimum fracture treatment, the field was found to be marginal. The overall study enabled decision-making for future drilling, completion and production operations in the field.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.72)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.46)
- Oceania > Australia > South Australia > Cooper Basin (0.99)
- Oceania > Australia > Queensland > Cooper Basin (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- (4 more...)
Abstract Hydraulic fracturing is a key technology to developing unconventional resources. At the planning stage, the prediction of production profiles in the presence of designed hydraulic fractures in the reservoir model is very important. Various analytical methods available are inadequate to produce reliable production profiles by accurately modeling irregular reservoir shape, permeability heterogeneity, multiphase flow and the presence of natural fractures. Any standard reservoir simulator facilitates these modeling features; the key challenge is, however, to model the propped hydraulic fractures accurately in the reservoir. Techniques such as negative skin, equivalent well radius and a uniform conductivity rectangular fracture are common built-in features in almost all available reservoir simulators. The imperative questions are (1) how good are these techniques to reliably model the flow through a non-rectangular fracture having non-uniform conductivity, and (2) how to model the combination of propped hydraulic fractures and stimulated reservoir volume (SRV) in the presence of stimulated natural fractures? This paper presents the results from two case studies that reveal the shortcomings and simulation difficulties with negative skin, equivalent wellbore radius and uniform conductivity rectangular fractures. The paper also presents improved techniques to model propped hydraulic fractures with nonuniform conductivity in nonrectangular geometry (as usually designed) and SRV in the reservoir model for reservoir simulations. The comparison of results and discussion of various techniques are expected to enable engineers to understand why in certain conditions built-in features may not be possible to use because of numerical instabilities during simulation, and the range of variations in prediction from various techniques. The improved technique presented in this paper, which is based on a local grid refinement technique, can provide more reliable production prediction and can overcome numerical instabilities (though it is generally more computation intensive).
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
Abstract Producing tight oil reservoirs by hydraulic fracturing is especially challenging due to relatively low oil mobility. At the planning stage, an integrated approach is essential to optimise fracture parameters using a reliable geomechanical model and reliable reservoir simulations to predict the post-fracture productivity and the net present value (NPV). This paper presents such an integrated case study. The reservoir contained relatively clean sandstones interlaying only a few thin shale layers. A relatively low recovery was expected to yield a good positive NPV because production was planned using a nearby existing production facility. A geomechanical model was built using core, well log and drilling data characterizing the in situ stress, pore pressure and rock mechanical properties in the field. The reservoir properties were characterized from core-log calibration and PVT data from analogue reservoirs. The initial reservoir pressure was very close to the bubble point pressure. Thus, multiphase reservoir simulations were essential to predicting post-fracture production profiles. The study integrated geomechanical modeling, hydraulic fracturing design, reservoir simulations and economic assessments to investigate various well completion scenarios. Various scenarios included a single vertical fracture in a deviated well, an un-fractured 1,000 m horizontal openhole well and a 1,000 m horizontal well with multiple transverse fractures. The un-fractured horizontal openhole scenario required a life cycle wellbore stability assessment. The fractured horizontal well scenario required the optimisation of transverse fractures and their spacing. The production constraints included a 600 psi tubing head pressure, a maximum oil flow rate of 5,000 bbl/d and a maximum 5-year production period with preference for more accelerated recovery. The results from this integrated scheme enabled understanding of the impact of various well completion scenarios on decision-making based on technical and economic issues. The lessons learned in the study can be a guide for optimal development of the target field and other similar fields.
- Asia > Vietnam (0.50)
- North America > United States > Montana > Roosevelt County (0.24)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.72)
- Asia > Vietnam > South China Sea > Nam Con Son Basin (0.99)
- Asia > Vietnam > South China Sea > Cuu Long Basin > Block 9-2 (0.94)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- (3 more...)
Optimizing Hydraulic Fracturing Treatment Integrating Geomechanical Analysis and Reservoir Simulation for a Fractured Tight Gas Reservoir, Tarim Basin, China
Gui, Feng (Baker Hughes) | Rahman, Khalil (Baker Hughes) | Moos, Daniel (Baker Hughes) | Vassilellis, George (Gaffney, Cline & Associates) | Li, Chao (Gaffney, Cline & Associates) | Liu, Qing (Baker Hughes) | Zhang, Fuxiang (PetroChina Tarim Oil Company) | Peng, Jianxin (PetroChina Tarim Oil Company) | Yuan, Xuefang (PetroChina Tarim Oil Company) | Zou, Guoqing (PetroChina Tarim Oil Company)
ABSTRACT A comprehensive geomechanical study was carried out to optimize stimulation for a fractured tight gas reservoir in the northwest Tarim Basin. Conventional gel fracturing and acidizing operations carried out in the field previously failed to yield the expected productivity. The objective of this study was to assess the effectiveness of slickwater or low-viscosity stimulation of natural fractures by shear slippage, creating a conductive, complex fracture net-work. This type of stimulation is proven to successfully exploit shale gas resources in many fields in the United States. A field-scale geomechanical model was built using core, well log, drilling data and experiences characterizing the in-situ stress, pore pressure and rock mechanical properties in both overburden and reservoir sections. Borehole image data collected in three offset wells were used to characterize the in-situ natural fracture system in the reservoir. The pressure required to stimulate the natural fracture systems by shear slippage in the current stress field was predicted. The injection of low-viscosity slickwater was simulated and the resulting shape of the stimulated reservoir volume was predicted using a dual-porosity, dual-permeability finite-difference flow simulator with anisotropic, pressure-sensitive reservoir proper-ties. A hydraulic fracturing design and evaluation simulator was used to model the geometry and conductivity of the principal hydraulic fracture filled with proppant. Fracture growth in the presence of the lithology-based stress contrast and rock properties was computed, taking into account leakage of the injected fluid into the stimulated reservoir volume predicted previously by reservoir simulation. It was found that four-stage fracturing was necessary to cover the entire reservoir thickness. Post-stimulation gas production was then predicted using the geometry and conductivity of the four propped fractures and the enhanced permeability in the simulated volume due to shear slippage of natural fractures, using a dual-porosity, dual-permeability reservoir simulator.
- North America > United States (1.00)
- Asia > China > Xinjiang Uyghur Autonomous Region (0.60)
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.51)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.48)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (0.46)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Louisiana > Haynesville Shale Formation (0.99)
- North America > United States > Arkansas > Haynesville Shale Formation (0.99)
- (3 more...)
- Well Completion > Hydraulic Fracturing (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)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)