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Abstract Although hydraulic fracturing in Liquid-Rich Unconventional Reservoirs (LUR) have become a norm, the recovery factor continues to be low. Use of Enhanced Oil Recovery (EOR) techniques in LUR have recently become more popular to improve the recovery. The objective of this study is to numerically investigate the advantages and disadvantages of the application of CO2 huff-n-puff technique in the LUR formations having complex fracture networks. The study explores the fluid flow mechanisms for oil recovery in the naturally fractured reservoir. A calibrated 3D mechanical earth model with geomechanical and petrophysical property from the Eagle Ford was used for the study. Complex hydraulic fracture model was used to simulate the hydraulic fractures, proppant and fluid distribution around the wellbore. Numerical reservoir simulation on a Perpendicular Bi-section (PEBI) grid was used to capture the permeability, porosity and conductivity distribution due to the proppants in the hydraulic fractures. CO2 huff-n-puff technique using numerical reservoir simulation is used to determine the well performance and recovery factor arising from reservoir fluid viscosity reduction and gas expansion. Effect of fluid thermodynamics to recovery systems in the low permeability reservoir medium is fully captured in approach. Equation of state prepared for simulating the CO2 impact on the oil is prepared with correlating the collected down hole oil sample. Numerical reservoir simulation study coupled with the complex fracture simulation model presents the insights of new means to improve RF in LUR through the injection of CO2. Such EOR method would be critical to increase the long term economic benefits. The study demonstrates that the infill well requirements can be mitigated if the EOR method of Huff-n-puff is utilized in cyclic modes over various time periods of production. Up to 9% extra RF was observed when CO2 Huff-n-puff technique was used as compared to production dependent only on hydraulic fracture stimulation. Parametric sensitivity on job sizes and start timing of EOR in a producing well is used to evaluate the RF. However, the hydraulic fracture geometry and the created footprint along with the time of injection has a larger effect in improving the EOR effectiveness. The methodology provides the demonstration of simulating the EOR methods in unconventional reservoirs for economic assessment. The workflow demonstrates modeling CO2 flooding as an EOR technique on the full wellbore level with complex hydraulic fracture geometry. The approach demonstrated here can be applied to other basins in the unconventional formations to improve the recovery factor.
Abstract A workflow has been developed for a shale play in North America for the strategic deployment of refracturing in an unconventional reservoir. Although it is clearly understood in the industry that refracturing in tight unconventional reservoirs can have a dramatic impact on the productivity and longevity of economic production, until now there has been no workflow that could be counted on to deliver consistent results. The impact of production and stress re-orientation plays a significant role in adding a fourth dimension of time to the existing three-dimensional problem of hydraulic fracture modeling in these reservoirs. We examined the re-orientation of reservoir stress and the change in stress magnitude with production in a case from the Eagle Ford. The stress redistribution occurring due to poroelastic effects was simulated using a finite element geomechanical simulator and then tied back to predict the new hydraulic fracture growth. Fracture geometry as it relates to draining the unstimulated domain was found to play a significant role in fracturing success. The impact of adding new perforations in the wellbore and application of a suitable diversion technique were also considered in the study. Our numerical investigation of the potential increase in productivity with selection of the optimum refracturing treatment timing and technique led to development of a methodology that solves the complex four-dimensional problem. By adopting the guidelines from the case study application of the end-to-end workflow, operators can avoid the futility of too early or too late fracturing and thereby maximize their return on investment.
Abstract Parent-child relationship is becoming a topic of high interest in the Permian Basin as more infill wells are being drilled at various times after the parent well has been produced. This paper uses an advanced modelling workflow to determine the impact of parent depletion on infill well spacing at various periods of the parent well production. As the parent well is being produced, constant well spacing based on virgin condition becomes problematic because pressure depletion around the well leads to change in stress magnitude and orientations. This change in reservoir conditions, is critical for planning infill well. Parent well depletion results in potential negative impact including: –Asymmetric fracture propagation from the child well into the depleted area around the parent well –Potential detrimental fracturing hits to the parent well These effects would potentially impair the production performance of both parent and infill wells, further reducing the overall pad efficiency of the pad completions. Parent well behavior is simulated using an unconventional fracture model (UFM), and the model is calibrated with available treating data. The resulting hydraulic fracture uses an advanced unstructured gridding algorithm that accounts for a fine complex fracture network along the lateral. A high-resolution, numerical reservoir simulator that combines the unstructured grid, rock physics, and reservoir fluid data is then used to match historical production data. The reservoir pressure depletion profile at various timesteps (6, 12, 24, and 36 months) is used as an input to calculate the resulting stress field state via a finite element model. The resulting updated geomechanical properties are used to simulate the infill well hydraulic fracture geometries at various spacing; subsequent unstructured grids are created and used to forecast production. Results are then compared to quantify the impact of depletion. –Initial reservoir pressure and horizontal stress reduce progressively with increasing time of production of the parent well; the average minimum stress change in the stimulated area reaches 18% decrease after 36 months of parent production. –Hydraulic fractures of infill wells grow preferentially towards the adjacent depleted area, reducing fracture extension in virgin rock by more than 60%. –Parent well depletion impacts fracture geometry and production performance of child wells. –Wells closer to the parent are more affected with increasing depletion time; these wells see up to 50% in production reduction as compared to the parent well. –At larger well spacing, little impact is observed due to limited interference between wells. –To help mitigate the impact of parent depletion on infill wells, an innovative spacing scheme that consists of using varying spacing on infill wells closest to the depleted parent well can be used. For this study and with current reservoir properties and completion design, if the parent well has been produced for less than 12 months, infill wells should be placed a least 750 ft away from the parent and at least 900 ft away for parent production beyond 1 year.
Gakhar, Kush (Schlumberger) | Shan, Dan (Schlumberger) | Rodionov, Yuri (Schlumberger) | Malpani, Raj (Schlumberger) | Ejofodomi, E. A. (Schlumberger) | Xu, Jian (Schlumberger) | Fisher, Kevin (Schlumberger) | Fischer, Karsten (Schlumberger) | Morales, Adrian (Schlumberger) | Pope, Timothy L. (Schlumberger)
Abstract As the inventory of single well pads in North American unconventional plays builds up, some critical questions that need to be answered are: What is the optimum spacing for an in-fill well? Where new multiple in-fill wells should be drilled? How should the in-fill wells be fractured? Challenging economics associated with unconventional reservoir development demands for an engineered approach for such multi-well pad development unlike traditional trial and error approach that has been widely adopted by Oil & Gas industry. The engineered approach for evaluating the problem relies on expanded seismic-to-stimulation workflow (Cipolla et al. 2011). The workflow involves complex fracture modeling that honors impact of natural fractures on hydraulic fracture geometry, dynamic reservoir simulation and geomechanical finite element modeling (FEM) to compute spatial and temporal changes in in-situ stresses due to production from parent well, which chronologically is the first well drilled on a pad. The new integrated workflow used in this evaluation involves the following key steps: A 3D structural geologic model based on a vertical openhole pilot well log in Eagle Ford shale reservoir is built. A discrete fracture network (DFN) representative of the area of interest in the reservoir is created from 3D seismic data interpretation. The parent well stimulation treatment is then modeled using ‘Unconventional Fracture Model’, (UFM) (Kresse et al. 2011). An unstructured production grid (Malpani et al. 2015; Ejofodomi et al. 2015) with finer cell size along the complex fractures is then created. Hydrocarbon production from the parent well is modeled using dynamic reservoir simulation, and a geomechanical FEM based simulator is then used to calculate spatial and temporal changes in in-situ stress magnitude and orientation (Morales et al. 2016). The modeling workflow is used to evaluate scenarios for multi-well pad optimization in Eagle Ford shale play. In this paper terms ‘in-fill’ well and ‘child’ well have been used interchangeably. This study evaluates two critical cases. Case 1 focuses on identifying optimum well spacing for an in-fill well that is to be drilled next to the parent well with a production history spanning a little over a year. Child wells drilled 400 ft., 600ft., and 800 ft. away from the parent well are simulated under similar conditions to identify optimum well spacing. Case 2 focuses on four multi-well pad development scenarios in which multiple wells are drilled in configuration A and B at different stages of field development and in areas with minimum and severe impact of kaolinite and smectite rich altered ash beds (Calvin et al. 2015) on vertical conductivity of hydraulic fractures. In multi-well configuration A, two child wells are drilled 600 ft. and 1200 ft. away from the parent well in B1-B2 (Donovan et al. 2010) unit of the lower Eagle Ford. Whereas, in configuration B wells are stacked in different lithostratigraphic sections of Eagle Ford. One of the child wells that is 600 ft. away from the parent well is landed in shallower section, B3-B5 and the second child well is landed 1,200 away in B1-B2, the same section of the Eagle Ford where the parent well is landed. It is important to note that results from this study are applicable to sections of Eagle Ford, where B unit is less than 150 ft. thick. For regions of Eagle Ford shale play, where B Units can be as thick as 300 ft., a similar comprehensive analysis is required to derive an effective multi-well pad development strategy.
Abstract With the advent of high-resolution methods to predict hydraulic fracture geometry and subsequent production forecasting, characterization of productive shale volume and evaluating completion design economics through science-based forward modeling becomes possible. However, operationalizing a simulation-based workflow to optimize design to keep up with the field operation schedule remains the biggest challenge owing to the slow model-to-design turnaround cycle. The objective of this project is to apply the ensemble learning-based model concept to this issue and, for the purpose of completion design, we summarize the numerical-model-centric unconventional workflow as a process that ultimately models production from a well pad (of multiple horizontal laterals) as a function of completion design parameters. After the development and validation and analysis of the surrogate model is completed, the model can be used in the predictive mode to respond to the "what if" questions that are raised by the reservoir/completion management team.