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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.
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.
The future of an equitable and sustainable global ocean, or "Blue Economy," depends on more than the resources available for technological advancement and industry expansion. A recent study led by the University of British Columbia (UBC) found that socioeconomic and governance conditions such as national stability, corruption, and human rights greatly affect the ability to achieve a Blue Economy. The study, published in Nature, scored criteria across five global regions--Africa, Americas, Asia, Europe, and Oceania--to identify the areas of investment and research necessary to develop ocean resources in a manner that is consistent with a Blue Economy ethos (socially equitable, environmentally sustainable, and economically viable). These included infrastructure, investment, economic and group equity, gender equality, human rights, biodiversity, habitat, water quality, corruption, and national stability. "We found that there are considerable differences between regions, where some are focused primarily on resources, whereas others are really trying to make sure that development is meeting local social and cultural objectives," said lead author Andrés Cisneros-Montemayor, research associate for the Institute for the Oceans and Fisheries at UBC and deputy director of the Nippon Foundation Ocean Nexus Center.
Abstract Geomechanical rock properties correlations and modeling approach for conventional reservoirs are inappropriate and unsuitable for unconventional shale gas reservoirs where the shale formation is strong and has very low porosity. These correlations are critical in the development of 1D and 3D geomechanical models which are used for various field applications including drilling optimization, hydraulic fracturing design and operation, and field management. The study investigates various geomechanical rock properties and their relationships to one another using data extracted from rock mechanics testing conducted on shale core samples. For rock elastic properties correlations, dynamic elastic properties determined from compressional sonic velocity, shear sonic velocity and density are plotted against laboratory-measured static elastic properties obtained from triaxial tests. Steps were taken to further refine the properties correlations by separating the data from vertical and horizontal core samples, using data from tests conducted at in-situ confining stress condition, and focusing on data only taken from Field A and nearby fields. Similar steps were also taken to develop the correlations for rock strength properties. Correlations for the shale anisotropic elastic properties were also developed based on ratio of horizontal and vertical elastic properties. Blind tests were conducted on three wells in Field A using the new rock properties correlations which showed good matching of the predicted geomechanical properties with the new correlations and core measured test data.
An acquisition this week making ARC Resources the biggest player in the Montney Shale draws attention to a play where profits projections are up along with gas prices, though growth is likely to remain slow and steady. The purchase of Seven Generations Energy for shares worth $2.2 billion combines two companies with combined liquids rich gas production, which will total 340 BOE/D. ARC, which is also in the Pembina Cardium play, will become the large producer of gas liquids in Canada and is third largest natural gas producer. The reasons given for the deal are in lockstep with deals among big shale producers in the US--the efficiencies of running an operation that has more than double its production is expected to save $110 million a year by 2022. That, will increase the free cash flow which will allow it to reduce debt and "deliver incremental returns to shareholders."
The 14 regional Student Paper Contests recognized by SPE are: Africa, Asia Pacific, Canadian, Eastern North America, Europe, Gulf Coast North America, Latin America and Caribbean, Middle East, Mid-Continent North America, Rocky Mountain North America, Russia and Caspian, Western North America, South Asia, and Southwestern North America. Contests held separately from these event regions will not be considered as part of the International Student Paper Contest and may vary in rules and regulations. Students must participate in their own regions as described in the Student Paper Contest Rules and Regulations (pdf) and may only alternate if a contest is not run in their region.
SPE coordinates 14 regional student paper contests at the undergraduate, master's, and PhD levels. Students compete against other students in their region for the opportunity to advance to the International Student Paper Contest held during ATCE. Contestants enter an abstract of their paper and present it on the day of the competition. The papers of the winners who proceed to the International Student Paper Contest at ATCE will be published in the conference proceedings and on OnePetro. Currently, the 14 regional contests recognized by SPE are: Africa, Asia Pacific, Canadian, Eastern North America, Europe, Gulf Coast North America, Latin America and the Caribbean, Middle East, Mid-Continent North America, Rocky Mountain North America, Russia and Caspian, Western North America, South Asia, and Southwestern North America.
Joelle Pineau doesn't want science's reproducibility crisis to come to artificial intelligence (AI). Spurred by her frustration with difficulties recreating results from other research teams, Pineau, a machine-learning scientist at McGill University and Facebook in Montreal, Canada, is now spearheading a movement to get AI researchers to open up their methods and code to scrutiny. Alongside Koustuv Sinha, a PhD student at McGill, Pineau holds one of two new roles dedicated to reproducibility on the organizing committee for the Conference on Neural Information Processing Systems (NeurIPS), a major meeting for AI that this year attracted some 13,000 researchers. Ahead of this year's conference in Vancouver, Canada, from 8 to 14 December, the committee asked scientists to provide their code and fill in a checklist of methodological details for each paper submitted. They also ran a competition that challenged researchers to recreate each other's work.
Yes, you may recognize one of my names (Bob, Robert or Pearson), that old guy who frequently posts an opinion or question on one of the SPE Connect Technical Communities. While in Australia, I had been working on technology transfer from North America that might help inform a deep gas exploration program on several plays that were somewhat analogous to tight gas discoveries in the Piceance Basin, Utah; the Green River Basin, Wyoming; and the Montney play in Western Canada. We had been focussed on demonstrating a business opportunity, based on big picture screening studies and data collection (project management Planning Stage 1). As a result, I only had a passing knowledge of the well and reservoir performance, operational practices, and technical challenges with the appraisal and development of light oil and condensates in the ultra-tight sand, silt, and shale plays in the US and Canada. So, I needed to get back up to speed ASAP.