Horn River Basin Research Articles

Chemical Analysis of Flowback Water and Downhole Gas-Shale Samples

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 175925, “Chemical Analysis of Flowback Water and Downhole Gas-Shale Samples,” by Ashkan Zolfaghari, SPE, Yingzhe Tang, Jordan Holyk, Mojtaba Binazadeh, and Hassan Dehghanpour, SPE, University of Alberta, and Doug Bearinger, SPE, Nexen Energy, prepared for the 2015 SPE/CSUR Unconventional Resources Conference, Calgary, 20–22 October. The paper has not been peer reviewed. Recently, flowback chemical analysis has been considered to be a complementary approach for evaluating fracturing operations and characterizing reservoir properties. Understanding the source of flowback salts and the mechanisms controlling the water chemistry is essential but also challenging because of the complexity of water/shale interactions. In this study, samples of flowback water and downhole shales are analyzed to investigate the mechanisms controlling the chemistry of flowback water. Introduction Field data show that chemistry of flowback water is substantially different from that of the injected water. For instance, in the Horn River Basin (HRB), slick water (with salinity levels similar to those of fresh water) is injected into the reservoir to create fractures, while the recovered flowback water is highly saline (40,000–70,000 ppm). Analysis of flowback data from the HRB wells indicates that the shape of the salt-concentration profiles is related to the fracture-network complexity. Knowledge of flowback-water composition is also required for water environmental assessment and selection of appropriate remediation strategies. Although flowback chemical analysis has been used widely to assess fracturing operations, the source of the ions in the flowback water is still a matter of debate. This study analyzes the flowback water and the shale samples to investigate the source of the ions and factors controlling flowback-water chemistry. Intact flowback- water samples are digested in acid to dissolve the precipitated salts and possible colloidal particles. A comparative analysis of the intact and acid- digested flowback-water samples is performed for better understanding of the mechanisms affecting flowback- water chemistry. The intact flowback-water samples are evaporated, and the remaining salts are investigated with X-ray diffraction (XRD) and scanning electron microscopy with energy- dispersive X-ray spectroscopy (SEM-EDXS). Furthermore, a sequential-ion-extraction method is developed to identify the loosely, moderately, and strongly attached ions.

Experimental and Numerical Study on Spontaneous Imbibition of Fracturing Fluids in the Horn River Shale Gas Formation

Summary After hydraulic fracturing, only 10 to 50% of the fracturing fluids is typically recovered. This paper investigates how the remaining fracturing fluids are imbibed by shale as a function of time, and it investigates the influence of various parameters on the imbibition process that include lithology, reservoir characteristics, and fluid properties. In addition, on the basis of experimental results, a numerical model has been developed to estimate the volume and rate of spontaneous imbibition over the entire fracture face. The rock samples are from the Horn River formation onshore Canada. The fracturing fluids used in the experiments included 2% KCl, 0.07% friction reducer, and 2% KCl substitute. In the experimental control group, distilled water was used. Through spontaneous-imbibition experiments, the relationship between imbibed fluid volume and time indicated that clay content was the most important factor that affected the total imbibed amount. Shale matrix with high clay content could imbibe more fracturing fluids than its measured porous space because of the clay's strong ability to expand and hold water. According to contact-angle-test results, the strongly water-wet shale samples had a faster imbibed rate. Total organic carbon (TOC) and porosity had no influence on imbibed volume and rate. These experimental findings can contribute to an improved fracturing-fluid design for different shale-formation conditions to reduce fluid loss. The experiment showed that 2% KCl and 2% KCl substitute fracturing fluids were imbibed from 10 to 40% less than 0.07% friction reducer in the shale formation with high clay content, whereas in the shale formation with low clay content, the opposite occurred. In the low-clay-content shale, 0.07%-friction-reducer test fluid was imbibed from 10 to 30% less than 2% KCl fluid, but had an imbibed amount similar to that of 2% KCl substitute fluid. The numerical-model result was matched with the experimental result to estimate a relative permeability in the model that could represent the rock properties. This model could be used to estimate the total imbibed volume along fracture faces through spontaneous imbibition.

Efficient production estimation for a hydraulic fractured well considering fracture closure and proppant placement effects

It is important to accurately estimate performances of a hydraulic fractured well, because it will be utilized to evaluate various completion parameters and furthermore to establish a future development plan. Shale gas reservoirs with fracture networks have high initial production rates but show drastic production decline as reservoirs are depleted by production. One of the reasons behind this phenomenon is an increased effective stress during production resulting in fracture closures. Gas mainly flows through hydraulic and natural fracture networks, so the fracture closures cause permeability reduction in the flow areas. In typical hydraulic fracturing operations, proppants are injected with fracturing fluid and placed in the fracture networks. Proppants play a crucial role to keep an induced hydraulic fracture open and retain a well productivity. However, only small portion of the fracture networks are filled with proppants (propped fracture) and the rest exist without proppants (unpropped fracture). Therefore, fracture closures of these regions are quite different. In this article, we have investigated to identify the combined effect of fracture closure and proppant placement on production estimation of a shale gas well. A numerical model has been developed to mimic well performances in Horn River Basin, BC, Canada. We have used pressure-dependent correlations based on experiments to consider fracture permeability alteration with changing reservoir pressure. Proppant placements are described using a fracture propagation model and this enables to classify a whole reservoir into sub regions such as propped, unpropped fracture, and matrix. By comparing with different cases, this article shows that reasonable results on gas production estimation are accomplished when considering fracture closure and proppant placement effects together.

Stick/Slip Detection and Friction-Factor Testing With Surface-Based Torque and Tension Measurements

Summary Recently, there has been a strong push toward automation and the use of real-time models in the drilling industry. However, it has been recognized that these new methods require a dramatic improvement in the quality of sensor data gathered at the rig. In this paper, we investigate how accurate measurement of drillpipe torque and tension at the surface can be used to diagnose downhole conditions. A surface-based torque-and-tension sub (TTS) was used to perform measurements while drilling several horizontal wells in the Dilly Creek area of the Horn River Basin, which is onshore in Canada. A filtered version of surface torque was used to calculate a stick/slip metric, which was compared to stick/slip measurements acquired with a downhole tool. The results show that there is reasonable correlation between surface and downhole metrics, but the correlation is highly dependent on torque filter start and stop frequencies. A comparison is also performed between the hookload measured with a deadline sensor and the tension measurement from the surface sub. The results show a systematic discrepancy of approximately 5% that is likely caused by sheave friction. A commercial torque-and-drag (T&D) software package is used to show that values for casing friction factor (FF) may be underestimated if sheave friction is present but ignored in the analysis. The results from this study show that an advanced measurement sub placed below the topdrive can provide valuable information regarding drilling performance. Specifically, the torque signal can be used to estimate the level of downhole stick/slip, which alleviates the need for an expensive downhole-dynamics tool. Also, the tension signal can be used to obtain accurate measurements of wellbore FF, which can be compared with theoretical values obtained with T&D analysis. With an appropriate-software implementation, these measurements can be performed in real time, which would enable rig crews to react quickly whenever excessive stick/slip or wellbore drag is encountered during drilling operations.

Is That Interference? A Work Flow for Identifying and Analyzing Communication Through Hydraulic Fractures in a Multiwell Pad

Summary 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.

Laboratory and field analysis of flowback water from gas shales

Flowback water is usually highly saline and the salt concentration varies by time and well location. Understanding the origin of the flowback salts is essential for evaluating fracturing and flowback processes. In this study, laboratory and field analyses are performed to investigate the origin of the flowback salts. The field data includes the total salt concentration (salinity), individual ion concentration, pH, and dissolved oxygen measured during the flowback process for three wells completed in the Horn River Basin. The rock mineralogy is determined using XRD. The cation exchange capacity (CEC) of shale samples are measured using ammonium acetate method. Water and oil imbibition experiments are conducted for shale samples of different surface-to-volume ratio. The individual ion concentration is measured during the water imbibition experiments using ICP–MS and IC. EDXS analysis is used to investigate the surface of natural fractures.Noticeable amount of barium found on the surface of natural fractures suggests that the barium in the flowback water primarily originates from the natural fractures. Furthermore, the samples with higher clay content have higher CEC. During the water imbibition process, these samples have higher and faster ion transfer from shale-to-water; suggesting the mobilization of the exchangeable ions from the clays. During the water imbibition experiment, the Na/Cl and K/Cl ratios are initially high and decrease at the later times. Leaching of the exchangeable sodium and potassium ions from the clay minerals is a possible reason for the initial high Na/Cl and K/Cl molar ratios. The dissolution of chloride-bearing components increases the chloride concentration, which decreases the Na/Cl and K/Cl molar ratios at later times. The measured pH is slightly above 8 for all of the flowback water samples. The presence of natural buffer systems such as calcite and dolomite may explain the neutral pH range of the flowback water.

Fracture Characterization Using Flowback Salt-Concentration Transient

Summary As observed in many shale-gas operations, salt concentration of flowback water increases with time. Usually, the shape of salt-concentration/load-recovery plots is different from one well to another. We hypothesize that the shape of the salinity profile during the flowback process provides useful information about the complexity of the fracture network. In this study, we propose a model to describe the relationship between salinity and cumulative water production. We also compare the model results and flowback-salinity data to characterize the fracture network. Flowback-salinity data are collected from three multifractured horizontal wells completed in the three shale members [Muskwa (Mu), Otter-Park (OP), and Evie (Ev)] of the Horn River Basin. The salinity profiles for the Mu and OP wells initially increase and finally reach a plateau, whereas the salinity profile for the Ev well shows a continuous increase and does not show a plateau. We hypothesize that the early water with lower salt concentration at the onset of the flowback process is mainly produced from the primary fractures with larger aperture size. Also, we believe that the fractures with smaller aperture size become more important as the flowback process progresses, and therefore, the high-salinity water produced at later times is mainly produced from secondary fractures. We also propose a model to describe the salinity-profile behaviors. The model presents the aperture-size distribution (ASD) of the fracture network. A comparative analysis of the model results and the flowback-salinity data indicates that the Ev well with a steady increase in its salinity profile has a wider ASD compared with the Mu and OP wells with a plateau in their salinity profiles. This suggests that the fracture network is more complex in Ev compared with those in Mu and OP. More-complex fracture network in Ev is also in agreement with its higher gas and lower water recovery during the flowback process as opposed to the lower gas and higher water recovery in Mu and OP. The presented model for describing the behavior of the salinity profile during the flowback process and its meaningful relationship to the fracture-network complexity provide an alternative approach for reservoir characterization. This study encourages the industry to manage the flowback operations carefully and to monitor the water chemistry.

Effect of Electrostatic Interactions on Water Uptake of Gas Shales: The Interplay of Solution Ionic Strength and Electrostatic Double Layer

We conduct spontaneous imbibition experiments using different fluids (deionized, DI, water and brines) and different media (unwashed and washed shale powder) to study the wetting behavior of the shale samples from the Horn River Basin (HRB), a massive unconventional gas play in the Western Canadian Sedimentary Basin. As expected, unwashed shale powder imbibes DI water faster than brine. Surprisingly, washing the powders results in faster imbibition of DI water. The imbibition of DI water into washed shale powders, which have a reduced soluble/leachable ion content, cannot be fully explained by osmotic effects. We explain the observed imbibition profiles using the electrostatic interaction theory. We measure the ion concentration of the brines by ICP-MS analysis and determine the ionic strength, I, of the in situ formed brine. We also calculate the characteristic thickness of electrostatic double layer, κ–1, formed around the surface of charged shale powders. The results indicate that the imbibition rate d...

A shale gas resource potential assessment of Devonian Horn River strata using a well-performance method

Middle to Upper Devonian Horn River strata in British Columbia, western Canada, has become a proven province of commercial shale gas resource in the last few years. The shale gas resource potential in the Horn River Basin has been historically assessed based on reservoir volumetric characteristics. However, as fundamental mechanisms controlling shale gas ultimate recovery remain poorly understood, the classic theories and simulation techniques applied to evaluate recoverable gas for conventional reservoir have proven inadequate for shale gas reservoirs. Determining the ultimate recovery from production data at the well level and projecting these data to the basin level to establish the ultimate recoverable resource may provide a more realistic estimation for long-term sustainable development planning. This paper analyzes well performance of 206 wells using Arps and Valko models in the Horn River Basin with adequately protracted production records and projects these performances to the future to assess the ultimate recovery of shale gas resource. This process yields a mean estimate of recoverable methane gas resource of 114 TCF (1 TCF (trillion cubic feet) = 28.3 × 109 m3), with a large uncertainty range of 38–217 TCF (90%–10% confidence interval). This study also suggests that the drastic variation in estimated ultimate recovery (EUR) from wells across the basin is attributed primarily to the intrinsic geological character of the shale reservoir, though advances in technology and industry practice may also contribute in some degree to this variation.

A flowing material balance equation for two-phase flowback analysis

Abstract Flowback data from wells completed in shale gas reservoirs usually show a surprising behavior of immediate two-phase flow. This is especially the case in wells with an extended shut-in period. This paper seeks to understand the fundamental reasons behind this early-time behavior by identifying trends in water/gas field production data. Diagnostic Gas–Water Ratio plots of 8 multi-fractured horizontal wells from the Muskwa and Otter Park formations show a unique v-shaped trend. Based on this early-time production signature, we hypothesize that the early gas production is linked to the initial free gas in the complex fracture network of the shale reservoir. We test this hypothesis by numerical simulation of the shut-in and flowback processes, and observe a similar v-shaped trend caused by a gradual build-up of free gas saturation in the fracture network during the shut-in period. This conclusion is also backed by extensive imbibition experiments conducted on the corresponding shale samples and by the presence of gas-saturated natural fractures. We also develop a simple mathematical model to describe gas and water production during the early hours of flowback. Based on the observations from field and simulated data, the primary drive mechanism is assumed to be the expansion of free gas built up in the fractures during the shut-in period. Other drive mechanisms considered include fracture closure and water expansion. The driving forces are modeled by an effective compressibility term analogous to the total compressibility in conventional multi-phase flow formulations. This model gives an easy method for the quick interpretation of early-time two-phase flowback data in a manner similar to conventional well testing methods. It can be applied to estimate the effective fracture volume and a dimensionless fracture parameter, which measures the flow capacity of the fracture network. Finally, we demonstrate the application of this model by analyzing flowback data from 2 fractured horizontal wells completed in the Horn River Basin.

Petrophysical approach for estimating porosity, clay volume, and water saturation in gas-bearing shale: A case study from the Horn River Basin, Canada

Petrophysical approach for estimating porosity, clay volume, and water saturation in gas-bearing shale: A case study from the Horn River Basin, Canada

Integrated Characterization of Hydraulically Fractured Shale-Gas Reservoirs—Production History Matching

Summary Advancements in horizontal-well drilling and multistage hydraulic fracturing have enabled economically viable gas production from tight formations. Reservoir-simulation models play an important role in the production forecasting and field-development planning. To enhance their predictive capabilities and to capture the uncertainties in model parameters, one should calibrate stochastic reservoir models to both geologic and flow observations. In this paper, a novel approach to characterization and history matching of hydrocarbon production from a hydraulic-fractured shale is presented. This new methodology includes generating multiple discrete-fracture-network (DFN) models, upscaling the models for numerical multiphase-flow simulation, and updating the DFN-model parameters with dynamic-flow responses. First, measurements from hydraulic-fracture treatment, petrophysical interpretation, and in-situ stress data are used to estimate the initial probability distribution of hydraulic-fracture and induced-microfracture parameters, and multiple initial DFN models are generated. Next, the DFN models are upscaled into an equivalent continuum dual-porosity model with analytical techniques. The upscaled models are subjected to the flow simulation, and their production performances are compared with the actual responses. Finally, an assisted-history-matching algorithm is implemented to assess the uncertainties of the DFN-model parameters. Hydraulic-fracture parameters including half-length and transmissivity are updated, and the length, transmissivity, intensity, and spatial distribution of the induced fractures are also estimated. The proposed methodology is applied to facilitate characterization of fracture parameters of a multifractured shale-gas well in the Horn River basin. Fracture parameters and stimulated reservoir volume (SRV) derived from the updated DFN models are in agreement with estimates from microseismic interpretation and rate-transient analysis. The key advantage of this integrated assisted-history-matching approach is that uncertainties in fracture parameters are represented by the multiple equally probable DFN models and their upscaled flow-simulation models, which honor the hard data and match the dynamic production history. This work highlights the significance of uncertainties in SRV and hydraulic-fracture parameters. It also provides insight into the value of microseismic data when integrated into a rigorous production-history-matching work flow.

Reservoir Characterization and History Matching of the Horn River Shale: An Integrated Geoscience and Reservoir-Simulation Approach

Summary We present a systematic approach to integrate geoscience and dynamic reservoir modeling for two multiwell pads in the Horn River basin, Canada. The Horn River shale-gas play is a world-class unconventional gas resource and is being exploited by use of multistage hydraulic fracturing along horizontal wells. The two well pads, Pad-1 and Pad-2, selected for this study comprise eight and seven horizontal wells, respectively, with 1 to 7 years of production history. Numerical modelling of shale reservoirs has historically been a problematic low-confidence exercise because of the difficulties associated with inadequate characterization of the geologic framework of shale plays; the problems of estimating the properties of induced-fracture networks; and the complexities of capturing multiphase flow in fracture networks and wellbores during production, especially in the face of offset-well activity. This paper provides insights into these issues. The geoscience modelling activity begins with integrating information from cores, well logs, petrophysical analyses, and seismic data into a 3D geocellular model. At first, the model is built upon a simple lithostratigraphic concept, which is the basis of the numerical-flow-modelling exercise of Pad-1. The 3D geocellular model is thereafter thoroughly reworked to incorporate a sequence-stratigraphic perspective to the Horn River shale. This reworked geocellular model has a profound impact on the dynamic modelling of Pad-2. Also, hydraulic conductivity of induced and natural fractures is measured on Horn River core plugs at reservoir conditions to constrain conductivity values assigned to primary, secondary, and tertiary flow paths into dynamic reservoir modelling. As a result of the integrated work flow, we have achieved a history match allowing us to further understand the hydraulic-fracturing behaviour and its impact on producing shale reservoirs of the Horn River formation. On the basis of the findings, we recommend targeting the Evie and Otter Park shale reservoirs for landing horizontal wells and multistage fracturing when the Carbonate Fan is thin; this approach can produce all three compartmentalized shale reservoirs of the Horn River formation. Ultimately, the objective of any reservoir modelling project is to provide a range of reliable forecast of future performance that is grounded in representative geoscience interpretations and that takes operational constraints into account. The technical learnings described in this work will be helpful to further understand hydraulic-fracturing behaviour and its impact on producing shale reservoirs.

The fate of fracturing water: A field and simulation study

Hydraulic fracturing of multi-lateral horizontal wells for shale gas production usually requires a great amount of water. Field data indicate that only a small fraction of the injected water can be recovered during the clean-up phase. Especially, when shale oil and gas wells undergo month-long shut-in periods after multi-stage fracturing processes. Field data also indicate that in some wells, such shut-in episodes surprisingly increase the oil and gas flow rate. However, the fate of non-recovered water in the reservoir and the reasons behind increased early-time oil and gas production after a long shut-in period are poorly understood.In this paper, we first interpret the flowback data of a 18-well pad completed in the Horn River Basin. Then, we use a numerical simulator to investigate the parameters controlling water and gas production during the flowback process. In the simulation model, the shale reservoir is represented by a fracture–matrix model, where the fractures form a continuum of interconnected network. The simulation results show that the counter-current imbibition of fracturing water during the shut-in period can result in a significant gas build-up in the fractures and therefore increases early-time gas production rate. It was also concluded that early-time water and gas production depends on reservoir properties such as capillary pressure and complexity of created fracture network and operational parameters such as shut-in time. The gas production rates from reservoirs with higher capillary pressure is higher at the beginning of flowback process but the production rate falls later. The complexity of fracture network created during hydraulic fracturing process has a great effect on load recovery and gas production. As the complexity increases, the gas production rate increases and load recovery decreases due to higher contact surface created between fractures and shale matrices. Further, field data and simulation results show that extended shut-in period increases early-time gas production but it decreases load recovery and late-time gas production.

Economic appraisal of shale gas resources, an example from the Horn River shale gas play, Canada

Development of unconventional shale gas resources involves intensive capital investment accompanying large commercial production uncertainties. Economic appraisal, bringing together multidisciplinary project data and information and providing likely economic outcomes for various development scenarios, forms the core of business decision-making. This paper uses a discounted cash flow (DCF) model to evaluate the economic outcome of shale gas development in the Horn River Basin, northeastern British Columbia, Canada. Through numerical examples, this study demonstrates that the use of a single average decline curve for the whole shale gas play is the equivalent of the results from a random drilling process. Business decision based on a DCF model using a single decline curve could be vulnerable to drastic changes of shale gas productivity across the play region. A random drilling model takes those drastic changes in well estimated ultimate recovery (EUR) and decline rates into account in the economic appraisal, providing more information useful for business decisions. Assuming a natural gas well-head price of $4/MCF and using a 10 % discount rate, the results from this study suggest that a random drilling strategy (e.g., one that does not regard well EURs), could lead to a negative net present value (NPV); whereas a drilling sequence that gives priority to developing those wells with larger EURs earlier in the drilling history could result in a positive NPV with various payback time and internal rate of return (IRR). Under a random drilling assumption, the breakeven price is $4.2/MCF with more than 10 years of payout time. In contrast, if the drilling order is strictly proportional to well EURs, the result is a much better economic outcome with a breakeven price below the assumed well-head price accompanied by a higher IRR.

How did hydraulic-fracturing operations in the Horn River Basin change seismicity patterns in northeastern British Columbia, Canada?

An increase in regional seismicity has been documented for the Horn River Basin (HRB) since the development of shale gas began in late 2006. Operational parameters of all hydraulic-fracturing (HF) treatments in the HRB between November 2006 and December 2011 were compiled from completion reports collected by the British Columbia Oil and Gas Commission (BCOGC). This database was compared with regional earthquake catalogs to delineate a quantitative relationship between the observed variation of regional seismicity and local HF operations. Taking the HRB as a whole, results suggest that the total injected volume from hydraulic fracturing is a more significant factor in affecting the pattern of local seismicity than injection pressure is. However, no clear change in background seismicity can be observed when the total monthly injected volume is less than ∼ 20,000 m3. The initial effect of increasing injected volume is an increase in earthquake frequency but not magnitude. Relatively large seismic- moment release (> 1014 N m) occurred only when the monthly injected volume exceeded ∼ 150,000 m3. Variable time lags, from days to four months, are observed between intense HF and the occurrence of a significant local earthquake. The hydrologic properties of the source formations and local geologic conditions (such as distribution, geometry, and dimension of preexisting faults) also might play important roles in induced seismogenesis, in addition to the total volume of injection.

Back front of seismicity induced by non-linear pore pressure diffusion

Borehole fluid injections are accompanied by microseismic activity not only during but also after termination of the fluid injection. Previously, this phenomenon has been analysed, assuming that the main triggering mechanism is governed by a linear pressure diffusion in a hydraulically isotropic medium. In this context the so-called back front of seismicity has been introduced, which allows to characterize the hydraulic transport from the spatiotemporal distribution of post-injection induced events. However, rocks are generally anisotropic, and in addition, fluid injections can strongly enhance permeability. In this case, permeability becomes a function of pressure. For such situations, we carry out a comprehensive study about the behaviour and parametrization of the back front. Based on a model of a factorized anisotropic pressure dependence of permeability, we present an approach to reconstruct the principal components of the diffusivity tensor. We apply this approach to real microseismic data and show that the back front characterizes the least hydraulic transport. To investigate the back front of non-linear pore-fluid pressure diffusion, we numerically consider a power-law and an exponential-dependent diffusivity. To account for a post-injection enhanced hydraulic state of the rock, we introduce a model of a frozen (i.e., nearly unchanged after the stimulation) medium diffusivity and generate synthetic seismicity. We find that, for a weak non-linearity and 3D exponential diffusion, the linear diffusion back front is still applicable. This finding is in agreement with microseismic data from Ogachi and Fenton Hill. However, for a strong non-linear fluid–rock interaction such as hydraulic fracturing, the back front can significantly deviate from a time dependence of a linear diffusion back front. This is demonstrated for a data set from the Horn River Basin. Hence, the behaviour of the back front is a strong indicator of a non-linear fluid–rock interaction.

Erratum

The article (March 2015 TLE) by Colin Sayers et al., “Anisotropy estimate for the Horn River Basin from sonic logs in vertical and deviated wells,” did not include footnotes for Table 1 on page 297.

Anisotropy estimate for the Horn River Basin from sonic logs in vertical and deviated wells

Shale anisotropy must be quantified to obtain reliable information about reservoir fluids, lithology, and pore pressure from seismic data. Failure to account for anisotropy in seismic processing can lead to errors in normal moveout (NMO), dip moveout (DMO), migration, time-to-depth conversion, and amplitude variation with offset (AVO) analysis. Kriged estimates of density, vertical compressional-wave, and shear-wave velocities were derived from vertical wells in an area of interest in the Horn River resource play in northeastern British Columbia. The kriged predictions were compared with measured logs along the trajectory of a deviated well. Whereas the density comparison provided a blind test of kriging accuracy because density is scalar and independent of well deviation, the same comparison for sonic velocities revealed that they are systematically higher than the kriged vertical velocities. This difference was used to estimate anisotropy parameters at the location of the deviated well. The fact that the higher velocities observed are caused by anisotropy was confirmed subsequently by using the derived anisotropy parameters to apply a nonhyperbolic moveout correction η to flatten gathers from a seismic survey 10 km north of the area of interest, within which the anisotropy parameters were estimated.

Detection Threshold and Location Resolution of the Alberta Geological Survey Earthquake Catalogue

The Western Canada Sedimentary Basin (WCSB) is a low seismicity area, with fewer than fifteen cataloged M L>3.5 events since 1985 (Earthquakes Canada, 2013b). Since 1918, there have been more than 800 earthquakes reported in this region (Earthquakes Canada, 2013b), mainly clustered near the town of Rocky Mountain House (Rebollar et al. , 1982, 1984; Wetmiller, 1986), the Brazeau River (Schultz et al. , 2014), Fort St. John (Horner et al. , 1994), Turner Valley, Kinbasket Lake (Ellis and Chandra, 1981), and the Horn River Basin (BC Oil and Gas Commission, 2012); a single event larger than M L 4.5 was also reported near Snipe Lake (8 March 1970, 18:52:18 UTC; see Milne, 1970). The most active of these clusters is in the Strachan D‐3A gas field near Rocky Mountain House, where 146 events were recorded over a span of 23 days in 1980 (Wetmiller, 1986). Many of these aforementioned clusters have been conjectured as induced by gas extraction (Baranova et al. , 1999), waste water disposal (Horner et al. , 1994; Schultz et al. , 2014), or hydraulic fracturing operations (BC Oil and Gas Commission, 2012; Farahbod et al. , 2014). Historically, the compilation of the Earthquakes Canada Catalogue (EqCC) has been the responsibility of Natural Resources Canada (NRCan). More recently, a new initiative was taken by the Alberta Geological Survey (AGS) to improve the earthquake catalog in an effort to better understand the tectonics and seismicity of Alberta (AB). Interested readers are referred to Stern et al. (2013) for specific details on the methodology, station parameters, and earthquake locations of the AGS catalog. Overall, the quality and density of documented earthquakes is subject to the performance of the recording array (Fig. 1). Similar to the EqCC, the AGS catalog includes continuous waveform data from the Canadian National Seismic Network (CNSN); …