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. Enhanced-oil-recovery studies in tight formations through surfactant and gas injection and acid treatment are among the recent research directions toward improving the ultimate recovery of tight formations or shales (Teklu et al. 2017a, 2018).
A hybrid-hydraulic-fracture (HHF) model composed of (1) complex discrete fracture networks (DFNs) 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 in nine horizontal multilaterals covering the Muskwa, Otter Park, and Evie Formations in the Horn River Shale in Canada, with a view to match their production histories and to evaluate the effectiveness and potential problems of the multistage hydraulic-fracturing jobs performed in the nine laterals.
To accomplish this goal, the HHF model is run in a numerical-simulation model to evaluate the SRV performance in planar and complex fracture networks using good-quality microseismicity data collected during 75 stages of hydraulic fracturing (out of 145 stages performed in nine laterals). The fracture-network geometry for each hydraulic-fracture (HF) stage is developed on the basis of microseismicity observations and the limits obtained in the fracture-propagation modeling. Post-fracturing production is appraised with rate-transient analysis (RTA) for determining effective permeability under flowing conditions. Results are compared with the HHF simulation and the hydraulic-fracturing design.
The HHF modeling of the SRV leads to a good match of the post-fracturing production history. The HHF simulation indicates interference between stages. The vertical connectivity in the reservoir is larger than the horizontal connectivity. This is interpreted to be the result of the large height achieved by HFs, and the absence of barriers between the formations.
It is concluded that the HHF model is a valuable tool for evaluating hydraulic-fracturing jobs and the SRV in shales of the Horn River Basin in Canada. Because of the generality of the Horn River application, the same approach might have application in other shale gas reservoirs around the world.
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)
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.
Sayers, Colin (Schlumberger) | Lascano, Maria (Schlumberger) | Gofer, Edan (Schlumberger) | Boer, Lennert Den (Schlumberger) | Walz, Milton (Schlumberger) | Hannan, Andrew (Schlumberger) | Dasgupta, Sagnik (Schlumberger) | Goodway, William (Apache Corporation) | Perez, Marco (Apache Corporation) | Purdue, Gregory (Apache Corporation)
Summary Economic production from tight shale formations entails increasing the surface area in contact with the reservoir via hydraulic fracturing. Important to the design of efficient hydraulic fractures is knowledge of the orientation and magnitude of principal stresses and geomechanical rock properties. Using the results of seismic AVA (Amplitude Variation with Angle) inversion calibrated to geomechanical measurements on cores, a 3D MEM (Mechanical Earth Model) is built for an area in the Horn River Basin. The variation in principal stresses over the area is evaluated using the Finite Element Method. Computed stresses are seen to be consistent with variability in production over the area and show stress rotations near faults in agreement with microseismic data.
The topic of interwell communication in unconventional reservoirs has received significant attention because it has direct implications for well-spacing considerations. However, it has been the observation of the authors that interference is often inferred without direct evidence of its occurrence, or without an understanding of the various mechanisms of interference. Some common discussions on interference among engineers refer to fracture “hits” and fracture-fluid production that suddenly appears at offset producing wells. These are indications of communication, but do not necessarily imply that a strong connection will be maintained throughout the life of the wells.
This paper presents a rigorous procedure for correctly identifying interference by use of data acquired during a typical multiwell-pad-production scheme. First, the various mechanisms of interference are defined. Next, analytical simulations are run to reveal the expected behavior for interference through fractures and reservoir matrix. Data provided from an eight-well pad in the Horn River basin are then scoured, revealing evidence of interference between at least two wells. Through this exercise, a procedure is developed for identifying interference by searching for changes in buildup trends while wells are staggered on/off production. Finally, the data are history matched with numerical models to confirm the interference mechanism.
The procedure in this paper is designed to help production analysts diagnose interference and avoid common pitfalls. The work flow is generalized and can be applied to other multiwell-pad completions.
The importance of evaluating well productivity after hydraulic fracturing cannot be overemphasized. This has necessitated the improvement in the quality of rate and pressure measurements during flowback of multistage-fractured wells. Similarly, there have been corresponding improvements in the ability of existing transient models to interpret multiphase flowback data. However, the complexity of these models introduces high uncertainty in the estimates of resulting parameters, such as fracture pore volume (PV), half-length, and permeability. This paper proposes a two-phase tank model for reducing parameter uncertainty and estimating fracture PV independent of fracture geometry. This study starts by use of rate-normalized-pressure (RNP) plots to observe changes in fluid-flow mechanisms from multistage- fractured wells. The fracture “pressure-supercharge” observations form the basis for developing the proposed two-phase tank model. This model is a linear relationship between RNP and time, useful for interpreting flowback data in wells that show pseudosteady-state behavior (unit slope on log-log RNP plots). The linear relationship is implemented on a simple Monte Carlo spreadsheet. This is then used to estimate and conduct uncertainty analysis on effective fracture PV by use of probabilistic distributions of average fracture compressibility and gas/water saturations. Also, the proposed model investigates the contributions of various drive mechanisms during flowback (fracture closure, gas expansion, and water depletion) by use of quantitative drive indices similar to those used in conventional reservoir engineering. Application of the proposed tank model to flowback data from 15 shale-gas and tight-oil wells estimates the effective fracture PV and initial average gas saturation in the active fracture network. The results show that fracture-PV estimation is most sensitive to fracture closure compared with gas expansion and water depletion, making fracture closure the primary drive mechanism during early-flowback periods. Also, the initial average gas saturation for all wells is less than 20%. The parameters estimated from the proposed model could be used as input guides for more-complex studies (such as discrete-fracture-network modeling and transient-flowback simulation). This reduces the number of unknown parameters and uncertainty in output results from complex models.
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.
In 2010 a noise test and microseismic emission detection test was performed in the Horn River Basin in northeastern British Columbia, Canada, to determine a) the suitability for surface microseismic monitoring and b) the character of the near-surface noise in an effort to determine the optimal depth to bury geophones.
The test consisted of a low density, low aperture array of 14 stations that covered the heels of eight wells. Initially the array was used to capture six treatments located outside of the array footprint. Two additional stages, located under the array footprint, were recorded and processed at a later date.
This coarse array allowed for the detection of several hundred events and a single moment tensor solution was determined. A dip-slip focal mechanism with a failure plane oriented NE-SW. This information, however not ideal, was adequate to create a limited amplitude based discrete fracture network (DFN) to be developed for the test results as well as a preliminary estimate of stimulated reservoir volume (SRV) for the test stages. Microseismic events that were imaged that were located outside of the array had larger positional uncertainty and reduced amplitudes compared to events recorded from stages within the array. This was a limitation imposed by the aperture of the array used in the test, as well as the low number of stations.
Test results indicate that the Horn River Basin is an adequate environment for surface microseismic monitoring, with good signal-to-noise characteristics. The test results suggest that adequate surface noise suppression is achieved by placing the sensors at or below 30m depth. The test also demonstrates that there is a need for appropriate array fold and wider aperture in order to fully describe the fracture network and obtain the most reliable estimates of SRV.
In 2010, a permanent shallow buried array consisting of 14 stations was deployed over an area of 2.5km x 2.3km on the Dilly Creek property in the Horn River Basin in northeast British Columbia, Canada (Figure 1). A buried array design was chosen based on a number of factors including; the long well lengths, which reached 2500m of lateral length, changing completions schedules and timing, and difficulties with event multipathing which can complicate downhole processing (Eisner, 2009). The array was designed to monitor 32 hours of completions activities on an 8 well pad. The limited monitoring time was due to the high monitoring and processing costs, and the noise test objective was met with 32 hours of recording.
The geometry of hydraulic fracture networks in a naturally-fractured reservoir is controlled by geomechanical factors, in particular the stress state and interactions between the induced hydraulic fractures and pre-existing natural fractures (Discrete Fracture Network or DFN). A calibrated model of hydraulic fracture growth in the Muskwa Formation of the Horn River Basin in British Columbia was developed using a coupled hydraulic-geomechanical simulator. The reservoir geomechanical model was represented by log-derived stresses and elastic properties, and the DFN geometry was refined using the attributes of the microseismic events, with strength properties derived from correlations.
Fracturing fluid injection into the geomechanical model is simulated using the field pump schedule and fluid characteristics, including proppant transport (with settling, bridging and the potential for screenouts). Fluid injection results in mechanical deformation, and the associated stress changes may cause slip and microseismic events. As the simulation progresses, the model computes the deformation and consequent stress changes, predicts where failure could occur, and whether microseismic events would be associated with those failures. The accuracy of the model is determined by quantitatively comparing the synthetic microseismic events with those observed in the field.
In this case study, the model was initially calibrated by determining the input parameters which both honored the known data such as logs, and best matched the field microseismic data. These initial simulations were used to gain an understanding of the key variables governing the model response and assess the sensitivity to uncertainty in the available geomechanical data or changes in reservoir geomechanical properties.
The calibrated model was then used to determine how changes in completion parameters (such as fracturing fluid type, injection rate and volume, and stage and cluster spacing) would affect fracture geometry and proppant placement. The results of this modeling can be used both to explain the production response to various completion scenarios and also to guide future field testing of alternative completions.
Understanding the coupled geomechanical and hydaulic processes is key to understanding the fracture geoemetry and contact with the reservoir and more crucially the proppant placement and associated enhanced permeability. Ultimately, a customized hydraulic fracture design can be defined for specific reservoir conditions to both enhance production and optimize operational costs.
A 3D geomechanical model of a hydraulic fracture treatment in the Horn River Basin was calibrated by comparing synthetic microseismic events to field data. Using this calibrated model, sensitivity studies were performed to determine the effect of geological parameters and operational variables on the resulting fracture geometry and microseismic response. Microseismic geomechanics was shown to be a reliable calibration methodology for this model because changes in hydraulic fracture geometry were reflected by changes in the microseismic calibration. The results show that the orientation of the DFN is a key parameter driving the microseismic response. When hydraulic fractures intersect natural fractures at high angles, the pre-existing fractures are stimulated more and exhibit a greater microseismic response. Application of the calibrated model to optimize completion changes is demonstrated by investigating the effect of several potential changes on fracture geometry.
Hydraulic fracturing of horizontal wells has been an important factor in the development of low permeability formations such as shales (Gale et al., 2007). The high-pressure injection of hydraulic fracturing fluid creates tensile fractures which may connect with and activate natural fractures. Hydraulic fracture modeling requires close coupling between the hydraulic (fluid flow) and mechanical models. For tight formations, the geomechanical aspect of the model is even more important than in conventional reservoirs, because natural fractures can play an important role in production.
Hydraulic fracturing typically causes microseismicity, usually through shear deformation (slip) on natural fractures and bedding planes. This microseismicity is the only far-field measurement of fracture geometry, and can be used to calibrate geomechanical models of fracture geometry and proppant distribution.
This paper presents a case study in which a coupled hydraulic-geomechanical simulator (3DEC, Damjanac and Cundall, 2016) is used to simulate hydraulic fracture growth in a naturally fractured formation and predict the corresponding microseismicity. The mechanical model is constructed with principal stresses, pore pressure and mechanical properties obtained from well logs, and a Discrete Fracture Network (DFN) is embedded in the stimulated area. The evolution of the mechanical deformation during the hydraulic fracturing process is simulated, including both the creation of new (hydraulic) fractures and the activation of pre-existing natural fractures. The model is calibrated by comparing the synthetic microseismic (MS) events with the field data.