Teklu, Tadesse Weldu (Colorado School of Mines) | Park, Daejin (Korea Gas Corporation and Colorado School of Mines) | Jung, Hoiseok (Korea Gas Corporation and Colorado School of Mines) | Amini, Kaveh (Colorado School of Mines) | Abass, Hazim (Halliburton and Colorado School of Mines)
Tadesse Weldu Teklu, Colorado School of Mines; Daejin Park and Hoiseok Jung, Korea Gas Corporation, and Colorado School of Mines; Kaveh Amini, Colorado School of Mines; and Hazim Abass, Halliburton and Colorado School of Mines Summary Matrix and fracture permeability of carbonate-rich tight cores from Horn River Basin, Muskwa, Otter Park, and Evie Shale formations, were measured before and after exposing the core samples to spontaneous imbibition using dilute acid [1-or 3-wt% hydrochloric acid (HCl) diluted in 10-wt% potassium chloride (KCl) brine]. Permeability and porosity were measured at net stress between 1,000 and 5,000 psia. Brine and dilute-acid imbibition effect on proppant embedment, rock softening/weakening, and fracture roughness were assessed. The following are some of the experiment observations: (a) Formation damage caused by water blockage of water-wet shales can be improved by adding dilute HCl or by using hydrocarbon-based fracturing fluids; (b) matrix permeability of clay-rich or calcite-poor shale samples is usually impaired/damaged by dilute-acid imbibition; (c) matrix permeability and porosity of calcite-rich shales usually improved with dilute-acid imbibition; (d) effective fracture permeability of unpropped calcite-rich shales is reduced by dilute-acid imbibition; the latter is because of "rock softening" and "etching/smoothing" of fracture roughness on the "fracture faces." Nevertheless, dilute-acid imbibition is less damaging than brine (slickwater) imbibition; and (e) proppant embedment was observed during both brine (slickwater) and diluteacid imbibition. Introduction A statistical report in EIA (2016) shows that, in the United States, oil and gas production from tight formations have become increasingly significant since 2007. This is mainly because of the advancement of multistage hydraulic-fracture stimulation in horizontal wells. Even with multistage hydraulic-fracture stimulation horizontal-well technology, oil recovery from tight formations such as the Bakken is usually less than 10% (Alharthy et al. 2015; Sheng 2015; Teklu et al. 2017a). Hence, many researchers are devoted to improving this low oil recovery.
Next to the Alaska Highway 97 north of Fort St. John in the thick forests of northern British Columbia natural gas is trucked out from the Highway Natural Gas Liquids Plant in the North Montney shale formation. Unconventional oil and gas have come to dominate the exploration and development scene in Western Canada since 2005, much as they have in the US. Both countries share essential elements needed to launch and sustain unconventionals: A long history of drilling, publicly available data, well-understood sedimentary basins, extensive infrastructure, a diverse corporate sector, and regulatory regimes supportive of innovative resource development. Following closely on developments in the US, the “tight gas” concept was a key component of the Canadian oil patch in the 1980s and 1990s. Horizontal drilling and hydraulic fracturing were employed in ever-tighter reservoirs, and in the early 2000s, Canadian operators began to appreciate the true potential of oil and gas from shales, tight reservoirs, and coal seams.
Berner, U. and E. Faber, 1988, Maturity related mixing model for methane, ethane and propane, based on carbon isotopes, Organic Geochemistry, vol.
Teklu, Tadesse Weldu (Colorado School of Mines) | Park, Daejin (KOGAS, Daegu and Colorado School of Mines) | Jung, Hoiseok (KOGAS, Daegu and Colorado School of Mines) | Miskimins, Jennifer L. (Colorado School of Mines)
The geomechanics of a shale play: what makes a shale prospective.
Sheng Yang, University of Calgary; Nicholas B. Harris and Tian Dong, University of Alberta; and Wei Wu and Zhangxin Chen, University of Calgary Summary This paper documents the formation of natural fractures in the Horn River Group, a major Canadian shale gas play, and addresses relationships between natural-fracture development and rock-mechanical properties derived from cores and well logs. Most natural fractures in the Horn River Shale are narrow vertical fractures, sealed with carbonate minerals. In this study, the formation of observed fractures is primarily determined by a lithology type, mineral composition, and rock-mechanical properties at the timing of fracturing. Brittleness is an important geomechanical property controlling the formation of fractures, because brittle shale is more easily fractured than ductile shale, and fractures in brittle shale tend to persist when the fracturing pressure is released. In this study, a hardness value measured by a commercial hardness tester is found to be a good proxy for the brittleness of shale layers. On the basis of a statistical analysis, the threshold values of both hardness and brittleness are estimated to predict the distribution of natural fractures, assuming that the mechanical properties of the host rock were relatively stable from at least the time at which fractures formed. Hardness values are shown to be more reliable than brittleness. Introduction Researchers have conducted many studies on different aspects of natural fractures and fractured reservoirs (Lorenz et al. 1991; Laubach et al. 2004) [e.g., the characterization and effects of fractures in the carbonate and siliciclastic reservoirs of the Middle East (Ameen et al. 2009, 2010, 2014)]. In recent years, natural fractures in shale reservoirs have become a key focus of research (Curtis 2002; Kresse et al. 2011; Gale et al. 2014) [e.g., the comprehensive study of natural fractures in the Qusaiba shale conducted to evaluate shale reservoir proceptivity by Ameen (2016)].
We analyzed microseismic spatial and temporal distribution, magnitudes, b-values, and treatment data to interpret and explain the observed anomalies in microseismic events recorded during exploitation of shale gas reservoirs in the Horn River Basin of Canada. The b-value shows the relationship between the number of seismic events in a certain area and their magnitudes in a semilogarithmic scale. The b-value is important because small changes in b-value represent large changes in the predicted number of seismic events. In this study, b-value is considered as an indicator of the mechanism of observed microseismicity during hydraulic-fracturing treatments.
We estimated the directional diffusivity to define the microseismicity front curve for each stage of hydraulic fracturing. On the basis of our definition of an average front curve, we managed to separate most of the microseismic events that are related to natural-fracture activation from hydraulic-fracturing microseismic events. We analyzed b-values for microseismic events of each stage before and after separating fracture-activation microseismic events from original data, and created a map of b-values in the study area. This allowed us to approximately locate activated fractures mostly in the northeastern part of the study wellpad. The b-value map agrees with our assumption of activated-fracture locations and high ratio of seismic activities. The dominant direction of the suggested activated natural fractures agrees with the general trend of the Trout Lake fault zone located approximately 20 km west of the study area.
Suggested fracture direction also agrees with anomalous-events density, energy distribution, and treatment data. We are proposing intermediate b-values for calculation of the stimulated reservoir volume (SRV) in areas with both hydraulically fractured events and events related to natural-fracture-network activation in those instances in which it is not viable to separate events based on their origin.
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
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.
Teklu, Tadesse Weldu (Colorado School of Mines) | Park, Daejin (KOGAS, Korea Gas Corporation, Colorado School of Mines) | Jung, Hoiseok (KOGAS, Korea Gas Corporation, Colorado School of Mines) | Amini, Kaveh (Colorado School of Mines) | Abass, Hazim (Colorado School of Mines)
Matrix and fracture permeability of carbonate rich tight cores from Horn River basin Muskwa, Otter Park, and Evie shale formations were measured before and after exposing the core samples to spontaneous imbibition using dilute acid (1 or 3 wt. % HCl acid diluted in 10 wt. % KCl brine). Permeability and porosity were measured at varying net stress of 1,000 psia up to 5,000 psia. Brine and dilute acid imbibition effect on proppant embedment, rock softening/weakening, and fracture roughness were assessed. The following are some of the experiments observations: (a) formation damage due to water blockage of water-wet shales can be improved by adding dilute HCl acid or using hydrocarbon based fracturing fluids; (b) matrix permeability of clay rich or calcite poor shale samples are usually impaired / damaged by dilute acid imbibition; (c) matrix permeability and porosity of calcite rich of shales usually improved with dilute acid imbibition; (d) effective fracture permeability of unpropped calcite rich shales are reduced by dilute acid imbibition; this is because of "rock softening" and "etching/smoothing" of fracture roughness on the "fracture faces". Nevertheless, dilute acid imbibition is less damaging than brine (slick water) imbibition; (e) acid injection instead of acid soaking/imbibition with proppant can optimize matrix permeability or Stimulated Reservoir Volume (SRV) of carbonate rich shales; (f) proppant embedment is caused by both brine (slick water) and dilute acid imbibition and can be minimized by resorting to low-concentration acid in such reservoirs; and (g) significant permeability and porosity hysteresis were observed due to proppant embedment during brine and dilute acid imbibition.
We present a case study of hydraulic fracturing treatments for two horizontal wells located in the Horn River Basin, B.C. The wells were completed using a technique that we refer to as Short Interval Re-injection (SIR). For each individual treatment stage, this technique makes use of an initial injection interval using conventional hydraulic fracturing pumping procedures, followed by a “soaking" period that may last from a few hours to about one day in duration, during which the well is temporary shut in. This is followed by a subsequent re-injection interval with a pumping schedule similar to the first interval. Several commercial names are in use to describe this type of approach, which has a desired goal of enhancing the overall effectiveness of the treatment. In this study, we observe a significant increase in the rate of microseismic activity that occurs after the initial soaking period. This type of response has been documented previously and, in some cases, has been empirically related to increased production for wells. We postulate that cohesion of pre-existing fractures is reduced by the initial injection and soaking period, facilitating reactivation of fractures during the second injection. A numerical model has been developed using the software 3DEC in which the cohesion parameter for a discrete fracture network (DFN) is set to zero after the first injection stage. Preliminary results produce a satisfactory match with respect to increased events. Future work will include adjustments to the DFN in order to increase the match with the spatial locations.
The Horn River Basin (HRB) is an important resource play in northeastern British Columbia, Canada. While conventional oil and gas developments have been underway in the HRB for several decades, since 2005 operators have targeted the large shale resources that are in place.
A hybrid hydraulic fracture (HHF) model composed of (1) complex discrete fracture networks (DFN) and (2) planar fractures is proposed for modeling the stimulated reservoir volume (SRV). Modeling the SRV is complex and requires a synergetic approach between geophysics, petrophysics, and reservoir engineering. The objective of this paper is to characterize and evaluate the SRV considering the initial hydraulic fracturing efficiency, fracture network complexity, mechanics, and microseismicity distribution along 145 stimulated stages in a multilateral horizontal well on the Muskwa, Otter Park and Evie Formations in the Horn River Shale in Canada.
Hydraulic fracturing jobs in shale reservoirs are designed with a view to achieve economic production by exploiting fracture network complexity. The task involves significant challenges in modeling and forecasting, which complicates the examination of operations to enhance their performance, including refracturing or infill drilling.
In this study, an HHF is run in a numerical simulation model to evaluate the SRV performance in planar and complex fracture networks using microseismicity data collected during 75 stages of hydraulic fracturing in the Horn River shale. Post-fracturing production is appraised with Rate Transient Analysis (RTA) for determining effective permeability under flowing conditions, compare to the numerical simulation and the hydraulic fracturing design.
Fracturing stages with larger fracture patch sizes, associated with the microseismic events in a fixed stress drop, correspond to higher stimulated areas, fracture conductivity, and gas production. Several microseismic events are observed in the heel of the laterals that are aligned to the far field NE stresses, indicated a loss of efficiency along the wellbore lateral during hydraulic fracturing. The hydraulic propagation modeling revealed increment of the leak-off coefficient, related to the natural fractures and communication with other stages. The production performance is evaluated in the numerical model, to measure interference between stages.
The SRV, modeled with HHF networks, is able to match the post-fracturing production history. Fracture mechanics is important in order to understand the flowing performance of the reservoir.
The inclusion of propagating models and RTA allowed to characterize possible fracture geometries in the reservoir and to observe limitations inherent to large dispersion and uncertainty of the microseismicity cloud. Also, to observe areas where the stimulation may have propped natural fractures totally or partially, which will benefit the production of gas.
This study presents a better understanding and characterization of the SRV in shale gas reservoirs, especially in those cases where microseismicity dispersion is problematic and where the SRV is not easily delimited.