Otter Park Research Articles

Seismic Anisotropy Estimation Using a Downhole Microseismic Data Set in a Shale Gas Reservoir

Shale anisotropy has a significant impact on the data processing and interpretation of microseismic monitoring in shale gas reservoirs. A geology- and rock-physics-constrained approach to estimating shale anisotropy using down-hole microseismic data sets is proposed in this study and is applied to the case of Horn River shale. A priori knowledge of shale anisotropy is obtained by integrating geological analyses and rock physics studies. This knowledge serves as an important constraint when building the initial model, minimizing the uncertainties and evaluating the results. The application to Horn River shale shows that the optimized anisotropic velocity model reduces the time misfit by about 65% compared to the originally provided velocity model. As the relocated perforation shot indicates, the event locations are significantly improved. The results also show that a high fraction of clay mineral results in strong fabric anisotropy in the Fort Simpson formation, whereas the quartz-rich shale gas reservoirs (Muskwa and Otter Park formations) show weaker fabric anisotropy. The percentage of velocity anisotropy in Horn River shale can be up to 40%. The fabric anisotropy of shale derived from the downhole microseismic data set is comparable with that of laboratory experiments. This demonstrates that downhole microseismic monitoring, as a quasi in situ experiment, has the potential to contribute to a better understanding of subsurface anisotropy beyond the laboratory. In addition, microseismic measurements of shale anisotropy are conducted in the seismic frequency band and are thus more applicable for further seismic applications.

Integrated Interpretation of Microseismic and Petroleum-Engineering Data for Comparison of Gas Production in Two Interfering Adjacent Wellpads in the Horn River Basin, Canada

SummaryWe 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 (R2) in crossplots of normalized production rate vs. the product of stimulated reservoir volume (SRV) and porosity and total organic carbon (TOC) (SRV×ϕ×TOC) indicate pressure interference between wells or wellpads. Good correlation coefficients in the same crossplots indicate lack of interference.The SRV×ϕ×TOC 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.

Brittleness in the Devonian Horn River shale, British Columbia, Canada

The Middle and Upper Devonian Horn River Group shale in northeast British Columbia is recognized as a major source of natural gas in Canada. This shale unit is approximately 200–500 m thick and consists of three stratigraphic units in ascending order: Evie Member, Otter Park Member and Muskwa Formation.In this study, Uniaxial Compressive Strength (UCS) tests were conducted on core plugs across stratigraphic units of the Horn River Group. Shear and compressional wave velocities are also measured for the core plugs to establish a relationship between static and dynamic elastic parameters. Brittleness is measured using three independent methods: (1) a hand-held hardness tester is used to measure mechanical hardness along a core; (2) the Elemental Capture Spectroscopy (ECS) log is used to calculate a composition-based brittleness in the same well; (3) Density and sonic logs along with laboratory experiments are used to calculate a brittleness coefficient based on elastic (static and dynamic) parameters.In order to compare brittleness and rock composition, a detailed lithofacies analysis was also conducted. Three major lithofacies were observed in the Horn River Group, including massive mudstones, pyritic mudstones and laminated mudstones. The Muskwa Formation and Evie Member are dominantly represented by massive and pyritic mudstones while the vast majority of the Otter Park Member is represented by laminated mudstones.The three independent measurements of brittleness show similar trends of higher brittleness in Muskwa Formation and Evie Member compared to Otter Park. This indicates that all three methods are suitable in identifying brittle zones in shale formations. The results show a clear relationship between lithofacies and brittleness. Massive mudstones and pyritic mudstones lithofacies show relatively higher brittleness compared to laminated mudstones lithofacies. Additionally, brittleness is influenced by the mineralogy of the rock. Clay content is observed to have the most dominant (inverse) relationship with brittleness coefficients, followed by quartz content. The analysis is further confirmed by calculating the fracability index for the Horn River Group.

Evolution and Evaluation of SRV in Shale Gas Reservoirs: An Application in the Horn River Shale of Canada

Summary 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.

Estimation of original kerogen type and hydrogen index using inorganic geochemical proxies: Implications for assessing shale gas potential in the Devonian Horn River Formation of western Canada

Considerable attention has been directed to the Devonian Horn River Formation in western Canada with respect to geochemical evaluation of gas-generation and storage potential. Because organic geochemical analyses are not always useful for characterizing the type and amount of original organic matter, we surmise the original kerogen type and original hydrogen index (HIo) and subsequently estimate a reliable original total organic carbon (TOCo) based on a combination of inorganic and organic geochemical data. Productivity (SiO2 and Ba) and terrestrial input (Al2O3, Hf, Nb, and Zr) proxies are used to estimate original kerogen types, which suggest that the Evie and Muskwa Members formed under conditions of high productivity and minor terrestrial input. These members also formed under reducing conditions, as indicated by the redox proxies (Mo, U, and Th/U). Under such conditions, primarily type II kerogen was preserved. By considering the fraction of biogenic silica, the estimated HIo values (400–500 mg hydrocarbon/g total organic carbon [TOC]) for the middle Otter Park Member are lower than that for Evie and Muskwa Members and higher than the upper and lower Otter Park Member. The stronger correlation between TOCo and trace elements suggests that HIo is useful for reconstructing the coherent variation in TOCo. Based on the original kerogen type and TOCo, the gas-generation and storage potentials of the Evie, middle Otter Park, and Muskwa Members are higher than those of other members. The source-rock potential is excellent for the Evie Member with an approximately 75% difference between TOCo and measured present-day TOC.

Effect of Dilute Acid on Hydraulic Fracturing of Carbonate-Rich Shales: Experimental Study

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 dilute-acid imbibition. Hence, experimental results of this study imply that dilute-acid injection/imbibition/fracturing in carbonate-rich shale reservoirs can lead to hydrocarbon-production improvement caused mainly by the matrix/permeability improvement.

High resolution sequence stratigraphic reconstruction of mud-dominated systems below storm wave base; A case study from the Middle to Upper Devonian Horn River Group, British Columbia, Canada

The application of sequence stratigraphy to deep-water mud-dominated systems is more challenging than in shallow water siliciclastic settings, largely because mudstones display subtle contrasts in grain size and lithology that make identification of facies and recognition of major stratigraphic surfaces difficult. However, the integration of sedimentology, ichnology and geochemistry and an extensive suite of cores from the Middle to Upper Devonian Horn River Group shales allow us to better understand how deep-water mud-dominated systems respond to fluctuations in the relative sea level, manifested in sequence stratigraphic relationships. The Horn River Group consists of, in ascending order, the Evie Member and Otter Park Member of the Horn River Formation and the Muskwa Formation. Four systems tracts, including highstand, transgressive, lowstand and falling stage systems tracts (HST, TST, LST, FSST, respectively) are identified and mapped. Highstand and transgressive systems tracts are both represented by dominantly massive mudstone lithofacies, sparse bioturbation, high Mo/Al ratios and high TOC values (avg. 3.1 and 3.4 wt%, respectively), as well as low Al2O3 concentrations. They can be distinguished by upward increasing gamma ray values for transgressive systems tracts and upward decreasing values for highstand systems tracts. The falling stage and low stand systems tracts display more heterolithic and laminated lithofacies, sparse to intense bioturbation, lower Mo/Al ratio and lower TOC values (avg. 1.2 and 1.7 wt%, respectively) and high Al2O3, concentrations and relatively low gamma ray readings. Sequence boundaries are represented by a transition from unbioturbated units to moderately or intensely bioturbated units, suggesting increased bottom water oxygen levels, which we infer to represent shallower waters. They are gradational and clearly conformable contacts in distal parts of the basin. They are sharp in more proximal settings, but no erosional surfaces were identified that would indicate unconformable contacts. Maximum flooding surfaces are characterized by the highest TOC contents and an increased gamma ray values. Our results suggest that the Otter Park Member belongs to a long-period sea level lowstand (e.g., 2nd order cycle), whereas the Evie Member and Muskwa Formation belong to long-period sea level highstands.

Integrated shale-gas reservoir characterization: A case study incorporating multicomponent seismic data

The objective of this case study is to predict geologic properties of a shale reservoir interval to guide production and completion planning for successful development of the reservoir. The conditioning, analysis, and blending of the converted-wave (PS) seismic data into a quantitative interpretation (QI) workflow are described in detail, illustrating the successful integration of geologic information and multiple seismic attributes. A multicomponent 3D seismic survey, several wells with dipole sonic logs, and a multicomponent (3C) 3D vertical seismic profile are available for the study. For comparisons of the incremental value of PS data, the QI workflow is completed entirely using only PP data and then modified and redone to incorporate information from the PS data. Predictions of the geologic properties for both workflows are assessed for accuracy against the existing well log and core evidence. Determining reservoir properties of the shale units of interest is important to the successful placement of horizontal wells for efficient multistage hydraulic fracturing and maximum gas production. Although conventional interpretation of conventional seismic data can only provide reservoir geometry, the quantitative analysis of prestack multicomponent data in this study reveals detailed distinctions between reservoir units and relative measures of porosity and brittleness bulk properties within each unit. Using all of the elastic properties derived from the seismic data analysis allowed for the classification of lithological units, which were, in turn, subclassified based on unit-specific reservoir properties. The upper reservoir units (Muskwa and Otter Park) were shown to have more variability in brittleness than the lower reservoir unit (Evie). Validation at a reliable well control confirmed these distinctive units and properties to be very high resolution and accurate, particularly when the PS data were incorporated into the workflow. The results of this method of analysis provided significantly more useful information for appraisal and development decisions than conventional seismic data interpretation alone.

Prediction of shale prospectivity from seismically-derived reservoir and completion qualities: Application to a shale-gas field, Horn River Basin, Canada

Prospective shale plays require a combination of good reservoir and completion qualities. Total organic carbon (TOC) is an important reservoir quality and brittleness is the most critical condition for completion quality. We analyzed seismically-derived brittleness and TOC to investigate the prospectivity of the Horn River Group shale (the Muskwa, Otter Park, Evie shales) of a shale-gas field in the western Horn River Basin, British Columbia, Canada. We used the λρ-μρ brittleness template, constructed from the mineralogy-based brittleness index (MBI) and elastic logs from two wells, to convert the λρ and μρ volumes from prestack seismic inversion to the volume for the brittleness petrotypes (most brittle, intermediate, and least brittle). The probability maps of the most brittle petrotype for the three shales were generated from Bayesian classification, based on the λρ-μρ template. The relationship between TOC and P-wave and S-wave velocity ratio (VP/VS) at the wells allowed the conversion of the VP/VS volume from prestack inversion to the TOC volume, which in turn was used to construct the TOC maps for the three shales. Increased TOC is correlated with high brittleness, contrasting with the commonly-held understanding. Therefore, the prospectivity of the shales in the study area can be represented by high brittleness and increased TOC. We propose a shale prospectivity index (SPI), computed by the arithmetic average of the normalized probability of the most brittle petrotype and the normalized TOC. The higher SPI corresponds to higher production rates in the Muskwa and Evie shales. The areas of the highest SPI have not been fully tested. The future drilling should be focused on these areas to increase the economic viability of the field.

The impact of rock composition on geomechanical properties of a shale formation: Middle and Upper Devonian Horn River Group shale, Northeast British Columbia, Canada

The geomechanical properties of a shale reservoir are essential both to the development of natural fractures and to the formation’s response to hydraulic fracture stimulation. We evaluate the rock mechanical properties in the Middle and Upper Devonian Horn River Group shale, including the Evie and Otter Park Members and the Muskwa Formation, applying core hardness measurements and log-derived Young's modulus, Poisson's ratio and brittleness and relate these to shale composition and texture. Clay content is the most significant factor controlling the brittleness of shale rocks. The effect of quartz content on rock mechanical properties depends on the type of quartz present in the rock: authigenic quartz is positively correlated with brittleness, but detrital quartz has little or no effect. Factor analysis indicates that carbonate increases brittleness, while no obvious correlation between TOC content and brittleness was observed. Depositional facies are related to geomechanical properties because each facies has a distinctive composition. Massive mudstone and pyritic mudstone are relatively brittle because of abundant authigenic quartz cement. Laminated mudstone and bioturbated mudstone are relatively ductile because most detrital carbonate and quartz grains are set in a matrix of clay minerals. Brittleness in the Horn River Group shale shows both geographic and stratigraphic variability. Increasing brittleness in the northwest part of the basin largely results from greater distance from the clastic sediment source. The Otter Park Member represents a period of major relative sea level fall and is relatively ductile because of its high clay content, whereas the underlying Evie Member and the overlying Muskwa Formation are relatively brittle because of high carbonate and biogenic silica content, respectively.

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.

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.

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.

Porosity characteristics of the Devonian Horn River shale, Canada: Insights from lithofacies classification and shale composition

This study evaluates pore systems of the Horn River shale in Western Canada Sedimentary Basin from lithofacies classification of core samples to micro-scale pore structure investigation. Samples from the Middle and Upper Devonian Horn River shale sequence were examined by core description, porosity measurement, SEM, and TEM imaging of ion milled samples, and nitrogen adsorption analysis in order to develop a better understanding of the controls of organic and inorganic rock constituents on porosity development and pore microstructure.Five primary shale lithofacies were identified by hand-core and thin section analyses: massive mudstones, massive mudstones with pyrite streaks, laminated mudstones, bioturbated mudstones and carbonates. Porosity ranges from 0.62% to 12.04% and shows wide variation between different lithofacies. Massive mudstones and pyritic mudstones with high total organic carbon (TOC) content have the highest porosity, whereas bioturbated mudstones and carbonates with low TOC content have the lowest porosity. SEM and TEM images suggest that several kinds of sites for porosity development are present, including organic matter, pyrite framboids, clay platelets, quartz rims, carbonate grains and microfractures. A general positive relationship between TOC and porosity indicates that a large proportion of pores are developed in organic matter. Results from the nitrogen adsorption analysis suggest that samples with more organic matter tend to develop smaller pores. Thus while porosity development is a combined function of organic matter, mineral components, fabric and fractures, it is most affected by organic matter concentration.The Muskwa Formation and the Evie Member have more gas storage capacity as they primarily consist of massive mudstones and pyrite-rich mudstones, showing the best porosity. The Otter Park Member has lower porosity, which may relate to the fact that its lithofacies mainly consists of laminated mudstones and bioturbated mudstones.

Liquid uptake of gas shales: A workflow to estimate water loss during shut-in periods after fracturing operations

The imbibition of fracturing fluid into the shale matrix is identified as one of the possible mechanisms leading to high volumes of water loss to the formation in hydraulically fractured shale reservoirs. In an earlier study (Makhanov et al, 2012), several spontaneous imbibition experiments were conducted using actual shale core samples collected from Fort Simpson, Muskwa and Otter Park formations, all belonging to the Horn River shale basin. This study provides additional experimental data on how imbibition rate depends on type and concentration of salt, surfactants, viscosifiers and sample orientation with regard to the bedding plane. The study also proposes and applies a simple methodology to scale up the laboratory data for field-scale predictions.The data show that an anionic surfactant reduces the imbibition rate due to the surface tension reduction. The imbibition rate is even further reduced when KCl salt is added to the surfactant solution. Surprisingly, viscous XG solutions show a considerable spontaneous imbibition rate when exposed to organic shales, although their viscosity is much higher than water viscosity. This observation indicates that water uptake of clay-rich organic shales is mainly controlled through preferential adsorption of water molecules by the clay particles, and high bulk viscosity of the polymer solution can only partly reduce the rate of water uptake.The field scale calculations show that water loss due to the spontaneous imbibition during the shut-in period is a strong function of fluid/shale properties, fracture-matrix interface, and soaking time. The presented data and analyses can be used to explain why some fractured horizontal wells completed in gas shales show poor water recovery and an immediate gas production after extended shut-in periods.

Integrated workflows for shale gas and case study results for the Horn River Basin, British Columbia, Canada

The variation in well performance observed between various shale gas plays, and indeed within individual basins and on individual pads, has gone some way to dispelling myths regarding the perceived homogeneity of “shale gas” targets. With increased quantities of data and more determined analysis, we show that understanding the micro- and mesoscale heterogeneity can be advanced through interdisciplinary studies that incorporate traditional and advanced geophysical data and methods with geological understanding and engineering measurements. This understanding is critical in optimizing well placement, the spacing and length of horizontal wells, and hydraulic fracturing effort to maximize recovery. Specifically, we illustrate that in the Muskwa Formation and the Otter Park, Klua, and Evie members of the Horn River Formation, reservoir quality can be predicted using lambda-rho and mu-rho data extracted from AVO inversion studies. From log data, we show that the most prospective reservoir intervals are characterized by decreasing lambda, increasing mu and/or a lambda:mu ratio less than one.

Very-High-Volume ESP-Lift Systems for Shale-Gas Fracture-Water Supply

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146489, ’Field Application of Very-High-Volume ESP-Lift Systems for Shale-Gas Fracture-Water Supply in Horn River, Canada,’ by Geoffrey C.J. Coppola, SPE, and Ryan C. Chachula, SPE, Encana Corporation, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed. One challenge of the Horn River shale play in British Columbia, Canada, has been the increasing number of fracture stimulations required per horizontal wellbore. Critically important is the massive volume of water required to supply the continuous fracturing operations in the development. To eliminate reliance on surface water, it was decided to produce high volumes of sour water from a relatively unknown underpressurized saline aquifer. The challenge was designing an appropriate lift system capable of producing volumes up to 8500 m3/d per well while addressing unknown fluid inflows, fluid transmissibility and recharge, and reservoir-fluid-chemistry characteristics. Introduction The Horn River basin is in northeastern British Columbia, approximately 1600 km northwest of Calgary, Alberta (Fig. 1). The primary-target horizons are the Muskwa, Otter Park, and Evie formations, which are predominantly organic and silica-rich shale. Since 2005, slickwater fracture treatments have grown from 400 m3 of water with 10 t of proppant in a vertical well to 29 staged fracture treatments per horizontal well, with each treatment consisting of 5000 m3 of water with 200 t of proppant. As the volume and number of treatments have grown, so has the demand for fracture-treatment water. At 5000 m3/stage, approximately 150 000 m3 of water is required for one horizontal-well completion with 30 fractures. The Debolt formation was identified as a potential water source that could supply the required fracture-treatment water. A test well was drilled to determine reservoir properties and the compatibility of the water with the Horn River fracturing program. Subsequent testing of the Debolt water revealed 21 000 mg/L total dissolved solids, 60 ppm H2S concentration in the water phase, and approximately 5000 ppm of H2S in the vapor phase. The Debolt formation was determined to be underpressured, with a pressure gradient of 7.2 kPa/m.

The gas-bearing Devonian Presqu'ile Dolomite of the Cordova embayment region of British Columbia, Canada: Dolomitization and the stratigraphic template

White dolospar of the Presqu'ile Dolomite forms the reservoir for many gas fields of northeastern British Columbia within the Keg River, Sulphur Point, and Slave Point formations along the shelf margin of the Cordova embayment. The embayment fill succession of the organic-rich Klua Shale, the Otter Park shale, and marlstones equivalent to the Sulphur Point and Slave Point formations are aquicludes that blocked the upward and lateral flow of dolomitizing brines. Presqu'ile dolomitization along the Slave Point shelf edge is interrupted in places where the Klua Shale extends shelfward underneath the Slave Point Formation. The Watt Mountain shale was also a regional aquiclude that prevented upward circulation of dolomitizing fluids in areas behind the Slave Point shelf edge. Flow of dolomitizing NaCl-CaCl2-MgCl2-H2O brine solutions began in the shallow subsurface and precipitated dolomite cements (type 1) at temperatures less than 50 degreesC, possibly even during Slave Point deposition, as northwestward-directed shallow subsurface brine reflux from the Elk Point basin began. This was followed by upward-directed subsurface convective flow of NaCl-CaCl2-MgCl2-H2O and NaCl-MgCl2-H2O brines and precipitation of dolomite cements at temperatures of about 130 degreesC during the Late Devonian-Carboniferous. Lower salinity brines that precipitated calcite cements and some dolomite (type 2) may have interacted with connate fluids of marine origin or, less likely, with meteoric fluids. Modeling of organic maturation indicates that the Muskwa shales above the Slave Point Formation passed through the oil generation window in the Permian and the onset of dry gas generation in the middle Mesozoic. Postdolomitization calcite cements precipitated during these times contain abundant liquid hydrocarbon-filled and methane-filled inclusions. High temperatures of close to 200 degreesC experienced by Slave Point strata in the Mesozoic caused stretching, but no leakage or refilling, of fluid inclusions in all dolomite cements.

Geology and Stratigraphy of Clarke Lake Gas Field, British Columbia

The Clarke Lake gas field, near the town of Fort Nelson in northeast British Columbia, contains major reserves of dry gas in the Middle Devonian Slave Point Formation. The field was the first of a series of similar discoveries in northeast British Columbia which indicate the presence of a new major gas area. They are shut in awaiting a pipeline connection. The stratigraphic section in the Clarke Lake field consists of glacial drift and Cretaceous, Mississippian, and Devonian marine rocks overlying a quartzite basement which is probably Cambrian or Precambrian in age. The Middle Devonian consists of four laterally equivalent stratigraphic sequences, each present in a different part of the area. These are: (1) a barrier reef belt, now largely dolomitized within the field itself; (2) a shelf or lagoonal area at the south; (3) a shale basin area north of the field; and (4) the area of the Klua embayment, characterized by a tongue of basinal dark shales which extends into the reef and shelf areas and for which the name Klua Formation is proposed. The Horn River Formation of the basin area is subdivided into three members for which the name Muskwa, Otter Park, and Evie are proposed. Structurally the beds in the Clarke Lake area dip gently south to southwest, but the contact of the Middle Devonian carbonate and shale facies dips steeply north on the north flank of the field. Present porosity and permeability in the field are controlled entirely by the pattern of dolomitization with the barrier reef belt. Pay thicknesses in the field average 200 feet and range up to 360 feet. Absolute open-flow rates range from 50 to 105 million cubic feet per day per well.