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Results
Integrated Interpretation of Microseismic and Petroleum-Engineering Data for Comparison of Gas Production in Two Interfering Adjacent Wellpads in the Horn River Basin, Canada
Yousefzadeh, Abdolnaser (University of Calgary) | Li, Qi (University of Calgary) | Aguilera, Roberto (University of Calgary) | Virués, Claudio (Nexen Energy ULC)
Summary We present an integrated interpretation of microseismic, treatment, and production data from hydraulic‐fracturing jobs carried out in two adjacent wellpads in the Horn River Basin, northeast British Columbia, Canada. We conclude that poor correlation coefficients (R) in crossplots of normalized production rate vs. the product of stimulated reservoir volume (SRV) and porosity and total organic carbon (TOC) () indicate pressure interference between wells or wellpads. Good correlation coefficients in the same crossplots indicate lack of interference. The product reflects the hydrocarbon pore SRV because there is a relationship between TOC and hydrocarbon saturation in shales (Lopez and Aguilera 2018). Our results suggest that natural‐fracture networks have an important effect on well connectivity and on the spatial distribution of microseismic data. Connectivity between wellpads occurs through a network of pre‐existing natural fractures, which are approximately perpendicular to the least principal compressive stress in the area. This conclusion is supported by data analysis from Wellpads I and II in the Horn River Basin. Wellpad I includes eight wells that were drilled and fractured in the Muskwa and Otter Park formations (four wells in each formation) in 2010. Wellpad II includes three wells drilled and fractured in 2011 in each of the three shale formations, Muskwa, Otter Park, and Evie. There is a 1‐year interval between fracturing on the first and second wellpads. The data analysis includes evaluation of magnitudes, b‐values, moment‐tensor inversion (MTI), and the spatial and temporal distributions of three‐component microseismic events recorded during more than 200 stages of fracturing by multiwell downhole arrays. We analyzed Gutenberg‐Richter frequency/magnitude graphs for each fracturing stage, and with proper integration of b‐values, fracture‐complexity index (FCI), MTI information, and treatment data, we distinguished hydraulic‐fracturing‐related events and events associated with slip along the surface of natural fractures. The results are compared with 5‐ and 4‐year gas‐production data in Wellpads I and II, respectively. Identification of natural fractures and information about interactions between hydraulically fractured wells are both essential for optimal well placement and completion, reservoir characterization, SRV calculation, and reservoir simulation. This study presents a distinctive insight into the integrated interpretation of microseismic events and production data to identify the activation of natural fractures and interference between the hydraulically fractured wells. The methodology developed in this study is thus related to production engineering, but examines it from the point of view of microseismic data.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Mineral (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.76)
- (2 more...)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Kansas > Thomas Lease > Simpson Formation (0.99)
- North America > Canada > Yukon > Western Canada Sedimentary Basin > Liard Basin (0.99)
- (10 more...)
Eagle Ford Huff-and-Puff Gas Injection Pilot: Comparison of Reservoir Simulation, Material Balance and Real Performance of the Pilot Well
Orozco, Daniel (Schulich School of Engineering, University of Calgary) | Fragoso, Alfonso (Schulich School of Engineering, University of Calgary) | Selvan, Karthik (Nexen Energy ULC) | Aguilera, Roberto (Schulich School of Engineering, University of Calgary)
Abstract A comparison is made of real data from an Eagle Ford huff-and-puff (H&P) gas injection pilot with reservoir simulation and tank material balance calculations. The comparison is good and supports the conclusion that oil recovery from the Eagle Ford (and likely other shales) can be increased significantly with the use of H&P. The study is based on the container methodology: for H&P to work, the injected gas and the insitu oil in the shale must be contained vertically and laterally following hydraulic fracturing. Containment is critical for the success of H&P. Vertical and lateral containment exist in the Eagle Ford as demonstrated previously (Fragoso et al., 2015) with the upside-down distribution of fluids: natural gas is at the bottom of the structure, condensate in the middle and oil at the top. Two different matching and forecasting approaches are used in this study: reservoir simulation and tank material balance calculations. Results show a good history match of primary recovery and secondary recovery by H&P in the pilot well. The history match is good in the case of both reservoir simulation and tank material balance calculations. Once a match is obtained, the simulation and material balance are used to forecast secondary recovery over a period of 10 years with sustained H&P injection of dry gas. Results indicate that dry gas H&P can increase oil recovery from the Eagle Ford shale significantly. Under favorable conditions, oil recovery can be doubled and even tripled over time compared with the primary recovery. The addition of heavier ends to the H&P gas injection can increase even more oil recoveries, putting them on par with conventional reservoirs. The benefit of H&P occurs both in the case of immiscible and miscible gas injection. The H&P benefits can likely be also obtained in other shale reservoirs with upside-down containers for dry gas, condensate and oil. The novelty of the work is the combined use of reservoir simulation and tank material balance calculations to match performance of an H&P gas injection pilot in the Eagle Ford shale of Texas. The conclusion is reached that oil recoveries can be increased significantly by H&P.
- North America > United States > Texas (1.00)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.15)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.88)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (9 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
An Investigation on the Feasibility of Combined Refracturing of Horizontal Wells and Huff and Puff Gas Injection for Improving Oil Recovery from Shale Petroleum Reservoirs
Fragoso, Alfonso (Schulich School of Engineering, University of Calgary) | Selvan, Karthik (Nexen Energy ULC) | Aguilera, Roberto (Schulich School of Engineering, University of Calgary)
Abstract Huff and Puff gas injection through horizontal wells in shale petroleum reservoirs is moving cautiously from being a promising theoretical possibility, to becoming a reality for increasing oil recovery. This study investigates how oil recoveries from shales can be increased by (1) a combination of refracturing and huff and puff gas injection, and (2) huff and puff gas injection when the length of the gas injection and production cycles are increased over time. The possibility of improving oil recoveries from shales by a combination of refracturing and huff and puff gas injection is investigated using a compositional simulation approach. Previous studies published in the literature, have considered the implementation of regular constant-time cycles throughout the huff and puff process. This may not be the optimum strategy. In this work, the use of cycles with increasing time-lengths is investigated with a view to maximize the oil recovery by huff and puff gas injection. The combination of (1) huff and puff gas injection followed by (2) refracturing and (3) stopping gas injection is found to be a good option to increase oil recovery from shale petroleum reservoirs when the initial hydraulic fracturing (IHF) has been successful. The benefits of this approach are demonstrated through a comparison made when refracturing is carried out without previous huff and puff injection. If the IHF has not been implemented properly, the huff and puff gas injection does not provide attractive recoveries. In this case, a refracturing job followed by huff and puff gas injection is shown to improve recoveries significantly. A comparison of the different scenarios considered in this paper shows that proper design of the injection and production schedule is very important in the development of a huff and puff gas injection. Optimizing the schedule by using the appropriate cycles with variable increasing-time spans can lead to improving the huff and puff performance. This study investigates how to increase oil recovery from shale petroleum reservoirs by (1) the combined use of refracturing and huff and puff gas injection, and (2) the use of cycles of variable length as opposed to the regular-length constant-time cycles considered in previous publications. To the best of our knowledge, the two cases considered in this paper are novel and have not been published previously in the literature.
- Europe (0.94)
- North America > United States > Texas (0.46)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.16)
- Research Report > New Finding (0.88)
- Overview (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (5 more...)
- Well Completion > Hydraulic Fracturing > Re-fracturing (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Production and Well Operations > Artificial Lift Systems > Gas lift (1.00)
Breaking a Paradigm: Can Oil Recovery from Shales be Larger than Oil Recovery from Conventional Reservoirs? The Answer is Yes!
Fragoso, Alfonso (Schulich School of Engineering, University of Calgary) | Selvan, Karthik (Nexen Energy ULC) | Aguilera, Roberto (Schulich School of Engineering, University of Calgary)
Abstract Oil recovery worldwide from conventional reservoirs vary significantly from case to case, but it is sometimes presented at an approximate average of 30-35 % of the original oil in place (OOIP), including primary and secondary recovery. This study shows that proper implementation of huff and puff gas injection in shales can lead to larger percent oil recoveries. Explaining the reasons for this controversial and out of the box conclusion is the key objective of this paper. This research starts by investigating flow units and pore throat sizes of shales, and by demonstrating the separate ‘upside-down’ or inverted vertical containment of natural gas, condensate and oil in shale reservoirs. Once vertical containment is demonstrated with data from the Eagle Ford shale in Texas, the research moves to investigating huff and puff gas injection in hydraulic fractured horizontal wells. The investigation is carried out by considering theoretical, core, laboratory, and petrographic data; and a simulation match and economics of an Eagle Ford huff and puff gas injection pilot. Results, dramatic and that no doubt will become highly controversial, lead to the out of the box conclusion that oil recovery with correctly-performed huff and puff gas injection can lead to oil recoveries even larger than oil recoveries from conventional reservoirs, reaching levels of up to 40%+ of the OOIP in the oil container. The finding is important as oil recoveries from shales have been reported up to this point in the literature to be very low ranging between approximately 5 and 10 %. The term "container" is not used generally in petroleum engineering, but proved of significant value in our research. A container is "a reservoir system subdivision, consisting of a pore system, made up of one or more flow units, which respond as a unit when fluid is withdrawn" (Hartmann and Beaumont, 1999). Although this investigation is carried out only for the Eagle Ford shale of Texas, preliminary scoping studies indicate that a similar potential might exist in other tight and shale reservoirs such as the Duvernay, Montney and Doig reservoirs in Canada, and Vaca Muerta in Argentina. The key contribution of this paper is highlighting the extraordinary potential of huff and puff gas injection in shale petroleum reservoirs, which can increase oil recoveries to even higher levels than the recoveries commonly achieved in conventional oil reservoirs. Economic benefits as a result of huff and puff gas injection in shales are included in the paper.
- North America > United States > Texas (1.00)
- North America > Canada (1.00)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Geological Subdiscipline (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (15 more...)
Abstract Primary oil recovery from shales is very low, rarely exceeding 10% of original oil in place (OOIP). The low recovery has aroused a recent and growing interest in the petroleum industry for using Improved Oil Recovery (IOR) methods in shales. This paper presents a new semi-analytical material balance equation (MBE) to forecast the performance of shale oil reservoirs under natural depletion and huff-and-puff gas injection scenarios. For undersaturated reservoirs, recovery is calculated from the proposed MBE explicitly using a multiporosity effective oil compressibility. For saturated reservoirs, the MBE is solved at each pressure step using a finite differences scheme. For huff-and-puff gas injection, the average reservoir pressure p is calculated after injecting a certain gas volume during the huff period. At each huff-and-puff cycle, the remaining OOIP is considered, and the injected gas volume (which is known) is written in terms of the p following injection (which is unknown). Adding the gas injection term to the MBE generates a nonlinear equation for p, which is solved using a numerical method. Results indicate that oil recovery from shales can be increased significantly by huff-and-puff gas injection. A case study from the Eagle Ford shale in the United States is used to demonstrate these results, which are presented in tabular form as well as crossplots of oil rates, cumulative oil production, gas-oil ratio and average reservoir pressure vs. time. An important feature of the proposed MBE is the inclusion of hydraulic fractures, as well as inorganic, organic and natural fracture porosities. These porosities are included in a history-matching presented in detail for a well undergoing huff-and-puff gas injection. The novelty of this work resides on the introduction of a new MBE that considers multiple porosities and enables quick evaluations of primary recovery and huff-and-puff gas injection scenarios in shale oil reservoirs. The new MBE results compare favorably against real data of the Eagle Ford shale. The good comparison allows making reasonable projections of future oil rates and cumulative oil recoveries by huff-and-puff gas injection.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play (1.00)
- Geology > Geological Subdiscipline (1.00)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- (8 more...)
3D Geomechanical Modeling in the Complex Fracture Network of the Horn River Shale Using a Fully-Coupled Hybrid Hydraulic Fracture HHF Model: Permeability Evolution and Depletion
Urban-Rascon, Edgar (Schulich School of Engineering, University of Calgary) | Virues, Claudio (Nexen Energy ULC) | Aguilera, Roberto (Schulich School of Engineering, University of Calgary)
Abstract The objective of this paper is to improve the evaluation and characterization of the fracture network as well as the production matching in the Horn River Shale of Canada. The task is carried out by extending the hybrid hydraulic fracture (HHF) model introduced by Urban et al. (2017) to a fully coupled fluid flow-geomechanical model that considers the far field stress stemming from the overburden, sideburden and underburden of the shale reservoir in an optimized simulation grid. The model evaluates the effects of depletion, of fracture closure and of permeability change using a discretized complex fracture network. In this paper, the fracture network is discretized using microseismic observations, when available. However, microseismic data may be limited in some of the fractured stages, or like in the case of most hydraulically fractured wells it might be non-existent. The fully coupled HHF model is developed to (1) improve the shale characterization and the simulation history matching, (2) study the fracture closure and permeability change in the fracture network due to gas production, and (3) alleviate microseismic data scarcity by generating a representative fracture network of those stages where microseismic data are unavailable. The stress change from the initial hydraulic fracturing is evaluated in nine paths multi-level horizontal wells that penetrated the Horn River Shale. The stress shadow is corroborated with microseismic observations and exhibited areas with high fracture density and productivity. The HHF model further evaluates the reservoir response to pore pressure depletion stemming from production, which leads to stress and permeability changes, fracture closure, and fracture reorientation. The procedure improves the simulation history matching by improving reservoir characterization, especially in stages closer to the toe where an understanding of fracture network geometry is problematic due to the cloud dispersion and scarcity of the microseismicity. The model also evaluates interference between well-paths and helps to determinate the optimum well, fracture and stage spacing. The HHF model was used to observe changes in volume, permeability and fracture connectivity in undepleted areas close to the fracture network. These areas reveal possible candidates for refracturing. A refracturing scenario that restores fracture conductivity and increases the drainage area of the fracture network is analyzed economically for evaluating the viability of that type of operation in the Horn River Shale. The HHF simulation model improves the shale reservoir understanding and simplifies the use of a highly complex fracture network for evaluating history matching, fracture closure and permeability changes during gas production. Furthermore, it provides a viable methodology to optimize well and stage spacing, and to evaluate potential refracturing candidates, where microseismic data is unavailable and a fracture network needs to be developed.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (5 more...)
Coupling of Wellbore and Surface Facilities Models with Reservoir Simulation to Optimize Recovery of Liquids from Shale Reservoirs
Fragoso, Alfonso (Schulich School of Engineering, University of Calgary) | Trick, Mona (Schlumberger Canada Limited) | Harding, Thomas (Nexen Energy ULC) | Selvan, Karthik (Nexen Energy ULC) | Aguilera, Roberto (Schulich School of Engineering, University of Calgary)
Abstract The objective of this paper is to couple wellbore and surface production facilities models with reservoir simulation for a shale reservoir that contains dry gas, condensate and oil in separate containers. The goal of this integration is to improve liquid recoveries by dry gas injection and gas recycling. Methods published up to now to investigate possible means of improving recovery from shales have concentrated on laboratory work and the reservoir itself, but have ignored the surface and wellbore production facilities. The coupling of these facilities in the simulation work is critical, particularly in cases involving condensate and oil reservoirs, gas injection and recycling operations. This is so because a change in pressure in the reservoir is reflected almost immediately in a change in pressure in the wellbore and in the surface installations. The development presented in this paper considers multi-stage hydraulically fractured horizontal wells. Dry gas is injected into zones that contain condensate and oil. Gas stripped from the condensate production is re-injected in the condensate zone in a recycling operation. The study leads to the conclusion that liquid recoveries can be maximized by utilizing continuous and huff and puff gas injection schemes. In general, huff and puff injection provides better results in terms of production and economics. Molecular diffusion is found to play a crucial role in continuous gas injection operations. Conversely, the effect of this phenomenon is negligible in huff and puff gas injection. This research demonstrates that proper design of wellbore and surface installations, including for example downhole pumps and compressors, is important as they play a critical role in the performance of production and injection operations, and in maximizing recovery of liquids from shale reservoirs. The novelty of the methodology developed in this paper is the coupling of models that handle surface facilities, wellbores, numerical simulation including oil, condensate and dry gas reservoirs, gas injection and gas-condensate recycling operations. Essentially the shale containers, wellbore and surface facilities are ‘talking’ to each other continuously. To the best of our knowledge this integration for shales has not been published previously in the literature.
- North America > United States > Texas (1.00)
- North America > Canada (1.00)
- North America > United States > North Dakota (0.68)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (14 more...)
Comparison of PKN, KGD, Pseudo3D, and Diffusivity Models for Hydraulic Fracturing of the Horn River Basin Shale Gas Formations Using Microseismic Data
Yousefzadeh, Abdolnaser (Schulich School of Engineering, University of Calgary) | Li, Qi (Schulich School of Engineering, University of Calgary) | Virues, Claudio (Nexen Energy ULC) | Aguilera, Roberto (Schulich School of Engineering, University of Calgary)
Abstract We present a comparison of three different hydraulic fracture models as well as an anisotropic diffusivity model with the observed microseismic data from shale gas reservoirs in the Horn River Basin of Canada. We investigated the validity of these models in the prediction of hydraulic fracture geometries using tempo-spatial extension of microseismic data. In the study area, ten horizontal wells were drilled and hydraulically fractured in multiple stages in the Muskwa, Otter Park, and Evie shale gas formations in 2013. The treatments were monitored by downhole microseismic measurements. We integrated microseismic analyses, geomechanical information extracted from well logs, and fracturing treatment parameters performed in the area. We compared fracture geometry predicted by Perkins-Kern-Nordgren (PKN), Khristianovic-Geertsma-de Klerk (KGD), and a Pseudo-3D (P3D) fracturing models as well as an anisotropic diffusivity model with actual fracture geometries derived from microseismic records in more than one hundred fracturing stages. For the study area, we find that there are no barriers to hydraulic fracture vertical growth between the Muskwa, Otter Park and Evie shales. Therefore, the fracture height to length ratio is higher than unity in many stages. Large fracturing heights suggest that the PKN model might be more suitable for fracture modeling than the KGD model. However, our analyses show that the fracture length predicted by the KGD model is closer to, but still far less than the fracture length illustrated by microseismic events. Pseudo 3D model also predicts fracture lengths which are slightly larger than the modeled fracture lengths by the KGD and PKN equations and still significantly smaller than the microseismic fracture lengths. These differences are observed throughout all stages suggesting that these methods are not able to perfectly predict the hydraulic fracturing behavior in the study wellpad. Vertical extension of microseismic data with linear patterns into the Keg River formation below the shale formations suggests the presence of natural fractures in the study area. This study presents a distinctive insight into the complex hydraulic fracture modeling of shales in the Horn River basin and suggests that diffusivity mapping is a simple, but powerful tool for hydraulic fracture modeling in these formations. Observed microseismic fracture lengths are significantly higher than lengths predicted by the geomechanical models and closer to diffusivity models, which suggests the possibility of increasing well-spacing in future development using diffusivity equation for improving treatment design.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (12 more...)
Refracturing Vs. Infill Drilling - A Cost Effective Approach to Enhancing Recovery in Shale Reservoirs
Urban, Edgar (University of Calgary) | Orozco, Daniel (University of Calgary) | Fragoso, Alfonso (University of Calgary) | Selvan, Karthik (Nexen Energy ULC) | Aguilera, Roberto (University of Calgary)
Abstract Multi-stage hydraulic fracturing (HF) of horizontal wells is at the heart of successful oil and gas production performance from tight and shale reservoirs. Fractures generated during the initial HF completion and natural fractures, tend to close as a well goes on production due to the increase of net stress on the fractures. The fractures closure reduces permeability and consequently productivity of the stimulated well. This study shows that under favorable conditions the production performance of the well can be revitalized with the use of a refracturing job. But there are key questions that need to be addressed: When is the optimum time for refracturing? What is the increase in permeability, production rate and cumulative production performance that can be expected from the refracturing job? Is it better to refracture the well or to drill an infill well? This paper addresses those three questions by considering multi-porosities known to exist in shale reservoirs. This includes inorganic matrix porosity (ϕm), natural fractures (microfractures and slot porosity, ϕ2), organic porosity (ϕorg) and adsorbed porosity (ϕads_c). In addition, hydraulic fracturing generates porosity around the wellbore (ϕhf). These porosities form a quintuple porosity system that is further fed by gas dissolved in solid kerogen. The porosities mentioned above are included in a material balance that is combined with fracture closure for generating a model that calculates the optimum time for refracturing. Production rates and ultimate recoveries from this model and observations of actual refracturing jobs are compared with results from infill drilling. By considering the same reservoir properties and exactly the same hydrocarbons in place the conclusion is reached that refracturing has the potential to be more cost effective as compared with infill drilling. The novelty of the approach is the development of an easy to use production performance method that can be reproduced readily in a spread sheet for calculating optimum re-fracturing time, production rates, and cumulative recovery; and for making quick comparisons of the benefits of refracturing vs. infill drilling in shale reservoirs. Results of the easy to use material balance are corroborated with a state of the art commercial reservoir simulator.
- North America > United States > Texas (0.94)
- Europe (0.93)
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.54)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
Integrated Interpretation of Microseismic and Petroleum Engineering Data for Comparison of Gas Production in Two Interfering Adjacent Wellpads in the Horn River Basin, Canada
Yousefzadeh, Abdolnaser (University of Calgary) | Li, Qi (University of Calgary) | Virues, Claudio (Nexen Energy ULC) | Aguilera, Roberto (University of Calgary)
Abstract We present an integrated interpretation of microseismic, treatment, and production data from hydraulic fracturing jobs carried out in two adjacent wellpads in the Horn River Basin, Northeast British Columbia, Canada. Wellpad I includes 8 wells which were drilled and fractured in the Muskwa and Otter Park formations (4 wells in each formation) in 2010. Wellpad II includes 3 wells drilled and fractured in each of the three shale formations, Muskwa, Otter Park, and Evie, in 2011. There is one-year interval between fracturing of the first and second wellpads. We studied magnitudes, b-values, moment tensor inversion, and the spatial and temporal distribution of three-component microseismic events recorded during more than 200 stages of fracturing by multi-well downhole-arrays. We analyzed Gutenberg-Richter frequency-magnitude graphs for each fracturing stage, and with proper integration of b-values, fracture complexity index (FCI), moment tensor inversion information, and treatment data, we distinguished hydraulic fracturing-related events and events associated with slip along the surface of natural fractures. The results are compared with five-year gas production data in each well. Our results show the effects of natural fracture network on well-connectivity as well as spatial distribution of microseismic data. We show that hydraulic fracturing and production from wellpad II lead to interference with wells already producing from wellpad I. The integrated study indicates that hydraulic fracturing and production from wellpad II is the main source of four months of anomalous production decline in wellpad I. This anomalous production decline started about two months after hydraulic fracturing in wellpad II. We also show that the tendency of microseismic distribution in wellpad II toward wellpad I is due to the connection of the two wellpads through a network of pre-existing natural fractures, which are approximately parallel to the largest principal compressive stress in the area. Both identification of natural fractures and information about interactions between hydraulically fractured wells are essential for optimum well placement and completion, reservoir characterization, stimulated reservoir volume calculation, and reservoir simulation. This study presents a distinctive insight into integrated interpretation of microseismic events and production data to identify the activation of natural fractures and interference between the hydraulically fractured wells.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Mineral (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.56)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.50)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Kansas > Thomas Lease > Simpson Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Horn River Basin > Otter Park Formation (0.95)
- (3 more...)