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Abstract Characterization of hydraulic fracture system in multi-fractured horizontal wells (MFHW) is one of the key steps in well spacing optimization of tight and shale reservoirs. Different methods have been proposed in the industry including core-through, micro-seismic, off-set pressure data monitoring during hydraulic fracturing, pressure depletion mapping, rate-transient analysis, pressure-transient analysis, and pressure interference test. Pressure interference test for a production and monitoring well pair includes flowing the production well at a stable rate while keeping the monitoring well shut-in and recording its pressure. In this study, the coupled flow of gas in hydraulic fractures and matrix systems during pressure interference test is modeled using an analytical method. The model is based on Laplace transform combined with pseudo-pressure and pseudo-time. The model is validated against numerical simulation to make sure the inter-well communication test is reasonably represented. Two key parameters were introduced and calculated with time using the analytical model including pressure drawdown ratio and pressure decline ratio. The model is applied to two field cases from Montney formation. In this case, two wells in the gas condensate region of Montney were selected for a pressure interference test. The monitoring well was equipped with downhole gauges. As the producing well was opened for production, the bottom-hole pressure of the monitoring well started declining at much lower rate than the production well. The pressure decline rate in the monitoring well eventually approached that of the producing well after days of production. This whole process was modeled using the analytical model of this study by adjusting the conductivity of the communicating fractures between the well pairs. This study provides a practical analytical tool for quantitative analysis of the interference test in MFHWs. This model can be integrated with other tools for improved characterization of hydraulic fracture systems in tight and shale reservoirs.
Abstract Recovery factor for multi-fractured horizontal wells (MFHWs) at development spacing in tight reservoirs is closely related to the effective horizontal and vertical extents of the hydraulic fractures. Direct measurement of pressure depletion away from the existing producers can be used to estimate the extent of the hydraulic fractures. Monitoring wells equipped with downhole gauges, DFITs from multiple new wells close to an existing (parent) well, and calculation of formation pressure from drilling data are among the methods used for pressure depletion mapping. This study focuses on acquisition of pressure depletion data using multi-well diagnostic fracture injection tests (DFITs), analysis of the results using reservoir simulation, and integration of the results with production data analysis of the parent well using rate-transient analysis (RTA) and reservoir simulation. In this method, DFITs are run on all the new wells close to an existing (parent) well and the data is analyzed to estimate reservoir pressure at each DFIT location. A combination of the DFIT results provides a map of pressure depletion around the existing well, while production data analysis of the parent well provides fracture conductivity and surface area and formation permeability. Furthermore, reservoir simulation is tuned such that it can also match the pressure depletion map by adjusting the system permeability and fracture geometry of the parent well. The workflow of this study was applied to two field case from Montney formation in Western Canadian Sedimentary Basin. In Field Case 1, DFIT results from nine new wells were used to map the pressure depletion away from the toe fracture of a parent well (four wells toeing toward the parent well and five wells in the same direction as the parent). RTA and reservoir simulation are used to analyze the production data of the parent well qualitatively and quantitatively. The reservoir model is then used to match the pressure depletion map and the production data of the parent well and the outputs of the model includes hydraulic fracture half-lengths on both sides of the parent well, formation permeability, fracture surface area and fracture conductivity. In Field Case 2, the production data from an existing well and DFIT result from a new well toeing toward the existing wells were incorporated into a reservoir simulation model. The model outputs include system permeability and fracture surface area. It is recommended to try the method for more cases in a specific reservoir area to get a statistical understanding of the system permeability and fracture geometry for different completion designs. This study provides a practical and cost-effective approach for pressure depletion mapping using multi-well DFITs and the analysis of the resulting data using reservoir simulation and RTA. The study also encourages the practitioners to take every opportunity to run DFITs and gather pressure data from as many well as possible with focus on child wells.
Abstract Well spacing and completion optimization in tight and shale reservoirs is a multi-dimensional task which comprise reservoir rock and fluid characterization, well performance study, inter-well communication analysis, and economic evaluation. Two sources of pressure data for characterization of inter-well communication include offset well pressure monitoring during hydraulic fracturing and controlled communication (interference) tests through staggered production. Both types of inter-well communication tests have become common among the operators in tight and shale reservoirs. However, quantitative analysis tools for interpretation of the test results are in their infancy. The focus of this study is quantitative analysis of pressure interference tests. In this study, an analytical model is developed for quantitative analysis of communication between multi-fractured horizontal wells (MFHWs) using pressure data from production and monitoring well pairs. The governing partial differential equation for the more general case of coupled flow in hydraulic fracture and matrix systems is solved using the Laplace transform. In order to validate the analytical model, the results from the analytical solution are compared against numerical simulation models. The analytical model of this study is applied to two field case from Montney formation. In these cases, a well from a multi-well pad is put on production and bottom-hole pressure of a monitoring well from the same pad is recorded using down-hole recorders. Communications between the wells is quantified using the analytical models of this study. The model of this study serves as a novel and practical tool for quantitative analysis and interpretation of inter-well communication in MFHWs. Integration of the model with other direct diagnostic and measurement tools can provide insight into optimized completion intensity for MFHWs.
Abstract A straightforward test with debatable analysis methods, the diagnostic fracture injection test (DFIT) is a pressure-transient test extensively used for reservoir and geomechanical characterization of tight/shale formations. The test provides some key data and information to reservoir and well completion engineers including instantaneous shut-in pressure (ISIP), pore pressure, closure stress, fluid efficiency, reservoir flow capacity, and fracture leak-off regime. A comprehensive regional or field-wide study of the DFITs is deemed very useful for operators at any stage of exploration and development. In this study, DFITs from a group of 174 Montney and Duvernay wells operated by more than 30 producing companies are quality checked and analyzed consistently. The results from DFITs are then compared against the standard poroelasticity equation. The data set of the current study covers a wide range of DFIT conditions and reservoir and geomechanical properties which helps the authors develop reliable correlations for reservoir characterization purposes. True vertical depth (TVD) of the wells ranges from less than 1000m to more than 4000m leading to a wide range of pressure and stress conditions. The study also covers all the geographical areas of Montney and Duvernay. The results ofthe DFITs are used to develop usefulcross-plot betweenpore pressure and closure pressure.A relationship between closure pressure from compliance method and G-function analysis method for Montney and Duvernay is also provided. Results of example DFITs from depleted areas were also provided which gives an idea about the depletion level and the associated well performance degradation. The current study gives field-wide understanding of the variations and distributions of reservoir and geomechanical properties in Montney and Duvernay based on DFIT analysis of a sizable population of wells.
Abstract Gas injection huff and puff (HnP) has been successfully applied in parts of Eagle Ford over the past few years. The success is attributed to gas and oil miscibility achieved by injection of gas at high pressure and rate in a contained hydraulic fracture system with a considerable of stimulated volume. Two key preliminary steps in gas HnP modeling include characterization of reservoir fluid (and its interaction with injected gas) and evaluation of hydraulic fracture system. This study focuses on simplified analytical tools for estimation of stimulated reservoir size from production data. Rate-transient analysis (RTA) is a tool for identification of flow regimes and estimation of key performance metrics for multi-fractured horizontal wells. The flow regimes include enhanced fractured region (EFR), bilinear flow, transient linear flow, transitional flow, and boundary-dominated flow. In this study, the size of stimulated rock and total effective fracture area are estimated using an RTA method. Further, diagnostics fracture injection tests (DFITs) and pressure buildup tests are used to characterize the multi-fractured horizontal wells for the purpose of gas EOR evaluation. Inter-well communication test is used to quantify the conductivity of connecting fractures between communication wells. This study helps the engineers and managers with reservoir and hydraulic fracture characterization and the screening process for gas HnP candidates. The outputs of these methods serve as first pass of SRV size for more detailed numerical modeling studies.
Gas injection huff and puff (HnP) has been successfully applied in parts of Eagle Ford over the past few years. The success is attributed to gas and oil miscibility achieved by injection of gas at high pressure and rate in a contained hydraulic fracture system with a considerable of stimulated volume. Two key preliminary steps in gas HnP modeling include characterization of reservoir fluid (and its interaction with injected gas) and evaluation of hydraulic fracture system. This study focuses on simplified analytical tools for estimation of stimulated reservoir size from production data.
Rate-transient analysis (RTA) is a tool for identification of flow regimes and estimation of key performance metrics for multi-fractured horizontal wells. The flow regimes include enhanced fractured region (EFR), bilinear flow, transient linear flow, transitional flow, and boundary-dominated flow. In this study, the size of stimulated rock and total effective fracture area are estimated using an RTA method. Further, diagnostics fracture injection tests (DFITs) and pressure buildup tests are used to characterize the multi-fractured horizontal wells for the purpose of gas EOR evaluation. Inter-well communication test is used to quantify the conductivity of connecting fractures between communication wells.
This study helps the engineers and managers with reservoir and hydraulic fracture characterization and the screening process for gas HnP candidates. The outputs of these methods serve as first pass of SRV size for more detailed numerical modeling studies.
Thomas, F. Brent (Resopstrategies) | Qanbari, Farhad (Seven Generations Energy) | Piwowar, Michael (Stratum Reservoir) | Noroozi, Mehdi (Stratum Reservoir) | Apil, Ronnel (Stratum Reservoir) | Marin, Juan (Stratum Reservoir) | Gibb, William (Stratum Reservoir) | Clarkson, Carter (Stratum Reservoir) | Zhang, Hongmei (Stratum Reservoir) | Swacha, Stan (Stratum Reservoir)
An experimental apparatus was developed that provides axial fracture flow and radial matrix flow in the context of differential pressure gradients at full reservoir conditions. Flow within the frac(s) and flow between frac(s) and matrix are operative in the system. The influence of cycling pressure, injection gas composition, soak time and level of primary depletion before initiation of GCEOR have been measured previously with volatile oil systems. To date no direct comparison has been made with rich gas condensate GCEOR performance in the same rock with similar GCEOR design parameters. Primary depletion of a volatile oil in a Montney porous media is compared to primary depletion in the same rock with a rich gas condensate. Pursuant to primary depletion, GCEOR was applied for both the oil and the gas condensate fluid.
A novel experimental design for core-flow testing has permitted the quantification of GCEOR using large lab-scale hydro-carbon pore volumes (HCPV). The unique experimental design allows nano-Darcy media to be tested using a time line comparable to conventional millidarcy media. The porous media tested herein exhibited a reservoir oil permeability of 110 nD at full reservoir conditions. Mechanisms for EOR have been described previously on the basis of this experimental protocol. Due to the large hydrocarbon pore volume of this procedure (130 to 480 ml) measurements of produced gas, liquid and recombined fluid compositions are obtained, as a function of Puff cycle number, as well as produced liquid densities and recovery factors cycle to cycle. These procedures were applied to a volatile oil and a retrograde condensate fluid.
A naturally-fractured porous media was saturated with a dew point fluid exhibiting a condensate-gas ratio of 200 BBL/MMscf. Primary depletion was conducted following a linear pressure depletion corresponding to field-real primary production times scaled to the laboratory experiment. Liquid recovery factor, produced fluid compositions and densities along with frac and matrix pressures were recorded. Pursuant to primary depletion GCEOR was conducted in order to quantify the increased liquid recovery after primary production. The system was then extracted to determine Sor. The porous media was then re-saturated and restored with volatile oil and primary depletion followed by GCEOR. It was observed that liquid recovery factor was better for the gas condensate in this low-permeability porous media. Primary depletion produced higher liquid recovery (C6+) with the gas condensate fluid than with the volatile oil. GCEOR after primary depletion performed similarly. Other insights were obtained and are discussed.
Summary Historically, Canadian unconventional gas development has ranged from 4-8 wells per pad site with compression generally located at a centralized site away from the wells. Seven Generations' approach to pad development is to increase the well density up to 36 wells with 50 MMcf/d of compression and processing capability on one central site. Drilling in batches of 4-8 wells at a time, followed by completions and surface facility construction, is quickly followed by the next batch of wells to be drilled. This is done to: 1) reduce the land required to develop the area; 2) increase efficiencies from manufacturing style operations; 3) allow for artificial lift using gas lift; 4) enable the ability for high pressure field gas gathering and transmission; and 5) minimize rig release to initial production time. Operating wells and process equipment during this constant development presents a unique set of challenges. Careful planning is required to design these pad sites for concurrent operations involving several disciplines. This paper will examine the cross discipline approach and organizational effort surrounding the initial development wells on a pad and high pressure infrastructure design, and then moving to increased wells on the pad while maintaining safe & reliable production operations. Multidisciplinary input is needed to ensure 1) sub surface well spacing to maximize reservoir recovery and avoid well bore collision; 2) surface well spacing to allow for multiple drilling rigs operating close to rotating equipment and adequate spacing for completion work overs; and 3) minimal environmental impact. The authors will outline the benefits and challenges from an environmental, drilling, completions, facility construction, and production operations point of view through the life cycle of a typical pad. Proper field planning has allowed Seven Generations to shift from the resource capture and delineation phase to commercial development within a short period of time and allowed for high rates of production growth relative to most of its Canadian peer group. Furthermore, planning for future concurrent operations has helped execute development in a timely, cost-efficient and safe manner.
Kramer, Hermann (Roke Technologies Ltd.) | Yaxley, Tiffiny (Roke Technologies Ltd.) | Williams, Jay (Roke Technologies Ltd.) | Nevokshonoff, Glen (Seven Generations Energy) | Haysom, Steve (Seven Generations Energy)
Abstract Worldwide the oil and gas industry acknowledges that technology is, and will continue to be, the driving force in allowing oil and gas producers and service companies; to continue to deliver results that will improve production performance in a safe, environmentally sound and cost-effective manner. This is especially true for unconventional producers who are also faced with unlocking the technical challenges of unconventional reservoirs. To aid in evaluating the Montney liquids-rich resource play, a new through pipe well logging technology was utilized to provide reservoir formation log data through drill pipe on new horizontal wells and through casing on a vertical well. This technology was run in the 7GEN KAKWA 13-24-65-5W6 cased vertical well, then compared to open hole well logs and to core data, both standard and special core analysis. The same through drill pipe logs were run in 14 horizontal wells in the Kakwa and Karr fields. The data collected in the horizontal wells was compared to the vertical core well and to the strip log data on each well. Calibration of the vertical though casing log data to core analysis provides an accurate determination of the reservoir properties in the lateral section of the horizontal wells. The cost / benefit of utilizing through pipe technology was analyzed. The analysis took into consideration direct and indirect costs associated with data collection and risks associated with horizontal data collection. By evaluating the associated costs and risks it was determined that through pipe data acquisition provides much lower risks and costs less than other data acquisition methods.