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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 Distributed Fiber Optics (DFO) technology has been the new face for unconventional well diagnostics. This technology focuses on measuring Distributed Acoustic Sensing (DAS) and Distrusted Temperature Sensing (DTS) to give an in-depth understanding of well productivity pre and post stimulation. Many different completion design strategies, both on surface and downhole, are used to obtain the best fracture network outcome; however, with complex geological features, different fracture designs, and fracture driven interactions (FDIs) effecting nearby wells, it is difficult to grasp a full understanding on completion design performance for each well. Validating completion designs and improving on the learnings found in each data set should be the foundation in developing each field. Capturing a data set with strong evidence of what works and what doesn't, can help the operator make better engineering decisions to make more efficient wells as well as help gauge the spacing between each well. The focus of this paper will be on a few case studies in the Bakken which vividly show how infill wells greatly interfered with production output. A DFO deployed with a 0.6" OD, 23,000-foot-long carbon fiber rod to acquire DAS and DTS for post frac flow, completion, and interference evaluation. This paper will dive into the DFO measurements taken post frac to further explain what effects are seen on completion designs caused by interferences with infill wells; the learnings taken from the DFO post frac were applied to further escalate the understanding and awareness of how infill wells will preform on future pad sites. A showcase of three separate data sets from the Bakken will identify how effective DFO technology can be in evaluating and making informed decisions on future frac completions. In this paper we will also show and discuss how DFO can measure real time FDI events and what measures can be taken to lessen the impact on negative interference caused by infill wells.
Zeinabady, Danial (University of Calgary) | Zanganeh, Behnam (University of Calgary, Chevron Canada Resources) | Shahamat, Sadeq (Birchcliff Energy Ltd.) | Clarkson, Christopher R. (University of Calgary)
Abstract The DFIT flowback analysis (DFIT-FBA) method, recently developed by the authors, is a new approach for obtaining minimum in-situ stress, reservoir pressure, and well productivity index estimates in a fraction of the time required by conventional DFITs. The goal of this study is to demonstrate the application of DFIT-FBA to hydraulic fracturing design and reservoir characterization by performing tests at multiple points along a horizontal well completed in an unconventional reservoir. Furthermore, new corrections are introduced to the DFIT-FBA method to account for perforation friction, tortuosity, and wellbore unloading during the flowback stage of the test. The time and cost efficiency associated with the DFIT-FBA method provides an opportunity to conduct multiple field tests without delaying the completion program. Several trials of the new method were performed for this study. These trials demonstrate application of the DFIT-FBA for testing multiple points along the lateral of a horizontal well (toe stage and additional clusters). The operational procedure for each DFIT-FBA test consists of two steps: 1) injection to initiate and propagate a mini hydraulic fracture and 2) flowback of the injected fluid on surface using a variable choke setting on the wellhead. Rate transient analysis methods are then applied to the flowback data to identify flow regimes and estimate closure and reservoir pressure. Flowing material balance analysis is used to estimate the well productivity index for studied reservoir intervals. Minimum in-situ stress, pore pressure and well productivity index estimates were successfully obtained for all the field trials and validated by comparison against a conventional DFIT. The new corrections for friction and wellbore unloading improved the accuracy of the closure and reservoir pressures by 4%. Furthermore, the results of flowing material balance analysis show that wellbore unloading might cause significant over-estimation of the well productivity index. Considerable variation in well productivity index was observed from the toe stage to the heel stage (along the lateral) for the studied well. This variation has significant implications for hydraulic fracture design optimization, particularly treatment pressures and volumes.
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.
Hui, Gang (University of Calgary, Alberta, Canada) | Chen, Shengnan (University of Calgary, Alberta, Canada) | Gu, Fei (PetroChina Research Institute of Petroleum Exploration and Development, Beijing, China)
Abstract The recent seismicity rate increase in Fox Creek is believed to be linked to the hydraulic fracturing operations near the region. However, the spatiotemporal evolution of hydraulic fracturing-induced seismicity is not well understood. Here, a coupled approach of geology, geomechanics, and hydrology is proposed to characterize the spatiotemporal evolution of hydraulic fracturing-induced seismicity. The seismogenic faults in the vicinity of stimulated wells are derived from the focal mechanisms of mainshock event and lineament features of induced events. In addition, the propagation of hydraulic fractures is simulated by using the PKN model, in combination with inferred fault, to characterize the possible well-fault hydrological communication. The original stress state of inferred fault is determined based on the geomechanics analysis. Based on the poroelasticity theory, the coupled flow-geomechanics simulation is finally conducted to quantitatively understand the fluid diffusion and poroelastic stress perturbation in response to hydraulic fracturing. A case study of a moment-magnitude-3.4 earthquake near Fox Creek is utilized to demonstrate the applicability of the coupled approach. It is shown that hydraulic fractures propagated along NE45° and connected with one North-south trending fault, causing the activation of fault and triggered the large magnitude event during fracturing operations. The barrier property of inferred fault under the strike-slip faulting regime constrains the nucleation position of induced seismicity within the injection layer. The combined changes of pore pressure and poroelastic stress caused the inferred fault to move towards the failure state and triggered the earthquake swarms. The associated spatiotemporal changes of Coulomb Failure Stress along the fault plane is well in line with the spatiotemporal pattern of induced seismicity in the studied case. Risks of seismic hazards could be reduced by decreasing fracturing job size during fracturing stimulations.
Rodríguez-Pradilla, Germán (School of Earth Sciences, University of Bristol, UK.) | Eaton, David (Department of Geoscience, University of Calgary, Canada.) | Popp, Melanie (geoLOGIC Systems Ltd., Calgary, Canada.)
Abstract The goal of this work is to calibrate a regional predictive model for maximum magnitude of seismic activity associated with hydraulic-fracturing in low-permeability formations in the Western Canada Sedimentary Basin (WCSB). Hydraulic fracturing data (i.e. total injected volume, injection rate, and pressure) were compiled from more than 40,000 hydraulic-fractured wells in the WCSB. These wells were drilled into more than 100 different formations over a 20-year period (January 1st, 2000 and January 1st, 2020). The total injected volume per unit area was calculated utilizing an area of 0.2° in longitude by 0.1° in latitude (or approximately 13x11km, somewhat larger than a standard township of 6x6 miles). This volume was then used to correlate with reported seismicity in the same unit areas. Collectively, within the 143 km area considered in this study, a correlation between the total injected volume and the maximum magnitude of seismic events was observed. Results are similar to the maximum-magnitude forecasting model proposed by A. McGarr (JGR, 2014) for seismic events induced by wastewater injection wells in central US. The McGarr method is also based on the total injected fluid per well (or per multiple nearby wells located in the same unit area). However, in some areas in the WCSB, lower injected fluid volumes than the McGarr model predicts were needed to induce seismic events of magnitude 3.0 or higher, although with a similar linear relation. The result of this work is the calculation of a calibration parameter for the McGarr model to better predict the magnitudes of seismic events associated with the injected volumes of hydraulic fracturing. This model can be used to predict induced seismicity in future unconventional hydraulic fracturing treatments and prevent large-magnitude seismic events from occurring. The rich dataset available from the WCSB allowed us to carry out a robust analysis of the influence of critical parameters (such as the total injected fluid) in the maximum magnitude of seismic events associated with the hydraulic-fracturing stimulation of unconventional wells. This analysis could be replicated for any other sedimentary basin with unconventional wells by compiling similar stimulation and earthquake data as in this study.
Abstract Shale wells are often shut-in after hydraulic fracturing is finished. Shut-in often lasts for an extended period in the perceived hope to improve the ultimate oil recovery. However, current literature does not show a strong consensus on whether shut-in will improve the ultimate oil recovery. Because of the delayed production, evaluating the benefits of shut-in in improving the ultimate oil recovery is crucial. Otherwise, shut-in would merely delay the production and harm the economic performance. This paper uses a numerical flow-geomechanical modeling approach to investigate the effect of imbibition on shut-in potentials to improve the ultimate oil recovery. This paper proposes that imbibition is one of the strongly confounding variables that cause the mixed conclusions in the related literature. The investigation methodology involves probabilistic forecasting of three reservoir realization models validated based on the same field production data. Each of the models represents different primary recovery driving mechanism, such as imbibition-dominant and compaction-dominant recovery. A parametric study is conducted to explore and identify the specific reservoir conditions in which shut-in tends to improve the shale oil recovery. Ten reservoir parameters which affect the imbibition strength are studied under different shut-in durations. Comparison among the three models quantitatively demonstrates that shut-in tends to improve the ultimate oil recovery only if the shale reservoir demonstrates imbibition-dominant recovery. A first-pass economic analysis also suggests that when the shale oil reservoirs demonstrate such an imbibition-dominant recovery, shut-in tends to not only improve the ultimate oil recovery, but also the NPV. A correlation among ultimate oil recovery, flowback efficiency, and NPV also shows that there is no strong relationship between flowback efficiency and ultimate oil recovery. This study is one of the first to emphasize the importance of quantifying the imbibition strength and its contribution in helping recover the shale oil for optimum flowback framework and shale well shut-in design after hydraulic fracturing.
von Gunten, Konstantin (University of Alberta) | Snihur, Katherine N. (University of Alberta) | McKay, Ryan T. (University of Alberta) | Serpe, Michael (University of Alberta) | Kenney, Janice P. L. (MacEwan University) | Alessi, Daniel S. (University of Alberta)
Summary Partially hydrolyzed polyacrylamide (PHPA) friction reducer was investigated in produced water from hydraulically fractured wells in the Duvernay and Montney Formations of western Canada. Produced water from systems that used nonencapsulated breaker had little residual solids (<0.3 g/L) and high degrees of hydrolysis, as shown by Fourier-transform infrared (FTIR) spectroscopy. Where an encapsulated breaker was used, more colloidal solids (1.1–2.2 g/L) were found with lower degrees of hydrolysis. In this system, the molecular weight (MW) of polymers was investigated, which decreased to <2% of the original weight within 1 hour of flowback. This was accompanied by slow hydrolysis and an increase in methine over methylene groups. Increased polymer-fragment concentrations were found to be correlated with a higher abundance of metal-carrying colloidal phases. This can lead to problems such as higher heavy-metal mobility in the case of produced-water spills and can cause membrane fouling during produced-water recycling and reuse.
Wang, Mingyuan (University of Texas at Austin) | Argüelles-Vivas, Francisco J. (University of Texas at Austin) | Abeykoon, Gayan A. (University of Texas at Austin) | Okuno, Ryosuke (University of Texas at Austin)
Summary The main objective of this research was to investigate the effect of initial water saturation on the oil recovery from tight matrices through surfactant-enhanced water imbibition. Two flooding/soaking experiments using fractured tight cores with/without initial water were performed. The experimental results were analyzed by the material balance for the components oil, brine, and surfactant. The analysis resulted in a quantitative evaluation of the imbibed fraction of the injected components (brine and surfactant). Results show that the surfactant enhanced the brine imbibition into the matrix through wettability alteration. The initial efficiency of the surfactant imbibition increased when brine was initially present in the matrix. The imbibition of brine was more efficient with no initial water in the matrix. A possible reason is that the presence of initial water in the matrix was able to increase the initial efficiency of the surfactant imbibition; however, the increased amount of surfactant in the matrix lowered the interfacial tension (IFT) between the aqueous and oleic phases; therefore, the efficiency of brine imbibition was reduced. Another possible reason is that capillary force was lower in the presence of initial water in the matrix, resulting in weaker imbibition of brine. Although the two cases showed different characteristics of the mass transfer through the fracture/matrix interface, they resulted in similar values of final water saturation in the matrix. Hence, the surfactant injection was more efficient for a given amount of oil recovery when there was no initial water in the matrix.
Denver-based Ovintiv announced this week an agreement to sell its Eagle Ford Shale properties to Validus Energy in a deal valued at $880 million. Ovintiv said the proceeds from the south Texas development will help accomplish its goal to divest at least $1 billion in assets, a move designed to bring its total debt below $5 billion by year-end. Combined with a February deal to divest assets in Alberta's Duvernay Shale for $263 million, Ovintiv has raised at least $1.1 billion. Ovintiv said the Eagle Ford asset is on track to reach a 2021 average production rate of 21,000 BOED, including 14,000 B/D of crude and condensates. With the divestures accounted for, Ovintiv estimates its full-year production will be around 190,000 B/D of oil and condensates.