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Results
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 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...)
Abstract The increasing demand for hydraulic fracturing to stimulate low-permeable reservoirs has lead to the use of various fracture optimization techniques to find optimum values of controllable design parameters. In case of inappropriate values of these parameters, many unexpected complexities may arise during treatments that lead to high treatment cost and low productivity. While recognizing the role of incompatible fracturing fluids and inappropriate execution of treatments, the role of inappropriate treatment optimization is not well investigated. To avoid complexities, one needs to solve a constrained model to screen out potentially problematic designs with the aid of an intelligent optimization algorithm, in contrast to the widely-followed conventional approach of unconstrained parametric optimization. This paper presents an integrated constrained model for treatment optimization to maximize production. The Model has incorporated many design constraints based on hydraulic fracture mechanics and industry experience, and the global optimization scheme is driven by an intelligent moving object algorithm. The design constraints relate fracture geometry and its growth, surface operational parameters, non-dimensional fracture conductivity, proppant number and proppant fall rate in the fracture. Successful viscosity scheduling of the fracturing fluid is particularly influenced by power-law parameters and shear rate in the fracture, which can be controlled by fluid preparation and controlled injection. These parameters are included in the free design variables in optimization work for the first time. A combined objective function is formulated to maximize production while simultaneously minimizing the treatment cost, and trade-offs between these two conflicting design objectives have been investigated. While applied this model to a low permeable oil reservoir to demonstrate its merits, an optimum treatment designed by this model has offered an incremental production by 100% and a treatment cost saving by 20% of their initial cost. Sensitivity results of various parameters also indicate the implication of design other than optimum. Introduction The petroleum industry is still in the practice of mainly nonprocedural optimization techniques to decide the injection parameters for hydraulic fracturing jobs, though during the last few decades, hydraulic fracture treatments are being carried out widely to enhance oil and gas production. Based on experiences, the authors believe that the post-frac poor productivity is attributed to inappropriate design of treatment parameters in many instances resulting from the nonprocedural techniques. Also these authors believe that a design treatment to be safely executable and non-damaging to the reservoir formation quality should satisfy certain conditions (we call them design constraints from here on) that are derived based on engineering principles. Thus, the design engineer must decide the optimum values of treatment parameters, such as injection rate and time, proppant type and concentration, proppant loading schedule, and fracturing fluid viscosity with a realistic fluid behaviour model to improve a specific design objective, or objectives, while all the design constraints are satisfied. A systematic and integrated procedure can aid the designer to perform this design task efficiently and enforce a favourable hydraulic fracture geometry that meets the above requirements. In most hydraulic fracturing design works, maximization of net present value (NPV) is used as the design objective. The improvement in NPV is attempted by parametric sensitivity analysis systematically varying a number of treatment parameters and fracture length. Such a procedure is tedious and does not guarantee to achieve the ‘best possible’ design because it often fails to explore all the potential design scenarios and to address various operational factors and fracture growth control requirements. Furthermore, there may be benefits in considering other design objectives, such as maximizing production/NPV with minimum treatment cost, etc.
- Oceania > Australia (0.28)
- North America > United States (0.28)
- North America > Mexico (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.61)