Multi-stage Hydraulic Fracture Stimulation Research Articles

Microseismic examples, Bakken Formation, Williston Basin

The Bakken and Three Forks unconventional reservoirs of the Williston Basin are prolific producers of oil and gas. The reservoir properties for these formations are similar, having low porosity and permeability. The combined technologies of horizontal drilling and multistage hydraulic fracture stimulation are used to obtain economic production from these tight reservoirs. Hydraulic fracture stimulation is used to open existing fractures or create new fractures to help produce tight oil and gas resources. Passive seismic (microseismic) monitoring of fracture stimulations provides information about induced fracture azimuth, width, length, height, and stimulated reservoir volume. This information is critical in determining sizes of drilling units and spacing of wells, what is contributing to production from a wellbore, hydraulic fracture orientation and other properties. Microseismic information is a very important tool for reservoir characterisation and management. In situ horizontal stresses in the Williston Basin are anisotropic with the maximum horizontal stress being in the northeast direction. Microseismic and other data from the Williston basin suggest that the regional maximum horizontal stress direction is NE SW (N55° to N70°E). Regional fractures with a similar orientation result in strong anisotropy of horizontal permeability with the maximum horizontal permeability being in the same direction. This orientation is confirmed by lineament analysis, fractures observed from oriented core data, borehole breakout data, and regional stress field published data. Operators generally orient their horizontal wells in a north-south or northwest-southeast direction to encounter maximum numbers of fractures and to be somewhat perpendicular to the maximum horizontal stress and permeability (kmax) direction.

Downhole Microseismic Monitoring Using FOSS and Its Field Test Comparison With Moving-Coil Geophone

We report downhole microseismic monitoring field test results of a fiber-optic-based seismic sensor (FOSS) array in a multistage hydraulic fracturing stimulation and present, for the first time, its systematic comparison with the conventional moving-coil geophone array deployed on-site. Perforation shots' analysis demonstrates that the FOSS has ~7.5 dB higher narrowband signal-to-noise ratio and, thus, 2.3 times smaller azimuth calibration error than the commercial moving-coil geophone. These benefits are mainly attributed to the intrinsic immunity to electromagnetic interference and a higher frequency resonance of FOSS. Field test results show that the FOSS can identify P- and S-waves of microseismic events, the temporal and spatial distributions of which are consistent with the geophone. In addition, the FOSS is found preferable to detect microseismic events with higher frequencies from some hundreds of Hz-to-kHz range. This superior ability contributes to distinct signatures in the identified P- and S-waves, including a shorter event duration and more concentrated frequency band, comparing to those collected by the geophone. The fracture interpretation results validate the application of fiber-optic seismic sensors on downhole microseismic monitoring.

Advancing Production Flow Profiling With Subatomic Fingerprints and Big Data Analytics

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 196172, “Unleashing the Power of Smart Particles for Completion Diagnostics: Advancing the Production-Flow-Profiling Technology With Subatomic Fingerprints and Big-Data Analytics,” by Talgat Shokanov, SPE, and Pavel Khudorozhkov, QuantumPro, and Adilkhan K. Shokanov, Abai University, prepared for the 2019 SPE Annual Technical Conference and Exhibition, Calgary, 30 September-2 October. The paper has not been peer reviewed. This paper describes a smart-tracer-portfolio testing and design solution for multistage hydraulic fracturing which will, write the authors, enable operators to reduce operating cost significantly and optimize production in shale wells. The technology combines recently developed smart tracers with advanced subatomic measurements in an automated process with stringent quality control that assures precise tracer addition onsite and provides accurate and actionable completion diagnostics results at a fraction of the cost of production-logging testing, distributed temperature testing, or distributed acoustic sensing. Introduction Multistage hydraulic fracturing operations costs - including high-pressure pumping, proppant, and fluid - ranged from $2.9 million to $5.6 million per well in a typical US shale well in 2018, representing close to 60% of the total drilling and completion cost for each well. Yet industry studies reported that up to 50% of the clusters and stages and up to 40% of the fracture net-works do not produce in the current geometric factory-mode-completion approach, leading to estimates that up to 40% of the drilled and completed shale wells in North America alone could be uneconomical. Additionally, interactions between fractures in adjacent horizontal wells, and the costly negative effects of these interactions, have become the focus of much discussion and debate within the technical community. The impetus for this attention has been the effect of these interactions on productivity and the mechanical integrity of the parent wells. These issues drive the need for oil and gas operators to have more-accurate, affordable, and timely data on the performance of individual fracturing stages, measured intrawell communication, and temporary and long-term frac/frac connections to enable improved decision-making and optimization of multistage hydraulic fracturing operations as well as overall field development. The complete paper describes smart tracer technology, including a patented portfolio and fracturing-/completion-optimization work flow; laboratory testing and performance analysis; and integration with completion diagnostics. Smart Tracer Technology To control the effectiveness of multistage hydraulic fracturing stimulation treatments, it is essential to use special tracing methods based on the addition of the labeled substance to the proppant, water, or gas, and monitor the release of tracers with flowback water and produced oil and gas from the current well or nearby observation wells. Currently, conventional water- and oil-soluble chemical substances with fluorescent properties and ionic, organic materials, or radioactive isotopes, are used as the tracers. Tracers with fluorescent properties and ionic and organic materials are high-cost, limited to chemical-measurement techniques at a molecular level, and often have reported false-positive results for long-term communication. Environmental regulations in many countries prohibit the use of radioactive tracers (i.e., radioactive isotopes) because they pollute the environment and could contaminate subsurface layers.

Downhole Microseismic Monitoring Using Time-Division Multiplexed Fiber-Optic Accelerometer Array

Microseismic monitoring is of importance for several geoscience research aspects and for applications in oil and gas industry. For signals generated by the ultra-weak microseismic events, conventional moving-coil geophone systems have reached their limit in detection sensitivity especially at high frequency range. Here we for the first time present a specially tailored fiber-optic sensing system targeting at downhole microseismic monitoring. The system contains 30 individual interferometric accelerometers and 2 reference sensors, which are time-division multiplexed into a 12-level vector seismic sensor array. The multiplexed accelerometers can achieve ~50 ng/ $\sqrt {\mathrm{Hz}} $ noise equivalent acceleration, which is superior to the commercial available moving-coil geophone systems at frequencies above 200 Hz. The measured sensitivity of the accelerometers can reach ~200 rad/g from 10 Hz to 1 kHz. The dynamic range is above 134 dB over the same frequency range and is higher than its electronic counterpart in the low frequency band. Moreover, the sensors can function properly under the harsh condition of 120 °C temperature and 40 MPa pressure over the 4-hour test duration. The sensor array along with the interrogator has been running uninterruptedly over 3 weeks in a multi-stage hydraulic fracturing stimulation field test. On-site results show that our system can clearly resolve the vector nature of both compressional and shear waves generated by the microseismic events.

Unconventional petroleum potential in the Mowry Shale, Southern Powder River Basin, Wyoming

The Lower Cretaceous Mowry Shale is a major source rock in the northern Rocky Mountain region (Schrayer and Zarrella, 1968; Nixon, 1973; Byers and Larson, 1979; Burtner and Warner, 1984; Momper and Williams, 1984; Davis et al., 1989; Modica and Lapierre, 2012). The source rock contains primarily Type II organic matter with an admixture of Type III kerogen towards the west. Thermally mature Mowry Shales are closely associated with petroleum accumulations in both Lower and Upper Cretaceous reservoirs. The Mowry Shale has produced modest amounts of oil from older vertical wells in the Powder River basin (Figure 1). With technology improvements (horizontal drilling and multistage hydraulic fracture stimulation) over the past decade, the Mowry is now a prospective target for hydrocarbon production (Finley, 2017). Horizontal drilling is currently targeting the Mowry in the deeper parts of the Powder River Basin. The Mowry Shale overlies the Shell Creek Shale or Muddy/Newcastle sandstones and is overlain by the Frontier Formation or Belle Fourche Shale (Figure 2). The Mowry petroleum system consists of the Mowry source rock and the following Cretaceous reservoirs: Lakota, Fall River, Muddy, Newcastle, Mowry, Frontier, and Turner.

Exploration of an unconventional petroleum resource through extensive core analysis and basin geology interpretation utilising play element methodology: the Lower Goldwyer Formation, onshore Canning Basin, Western Australia

Theia Energy Pty Ltd1 (Theia Energy) discovered a potential unconventional hydrocarbon resource in the Ordovician Lower Goldwyer (GIII) Formation shale located on the Broome Platform of the onshore Canning Basin. The collation, processing, analysis and interpretation of all available regional data culminated in a successful exploration well, Theia-1 (drilled in 2015), which, based upon petrophysical and core analyses, intersected a 70 m gross oil column at 1500–1570 m depth. Theia-1 recovered essential core and wireline log data required to analyse and assess the play elements and reservoir properties necessary for a viable shale oil and gas development. Utilisation of an ‘Unconventional Play Element’ methodology has proven the unconventional hydrocarbon potential of the GIII Formation, and preliminary modelling indicates that economic stimulated flow rates may be achieved. Further operations (a test well with multi-stage hydraulic fracture stimulation) are scheduled in the coming permit year to further quantify the presence of extractable organic matter in the GIII Formation, assess hydrocarbon flow rates, determine fluid composition and appraise commercial viability. This paper will discuss Theia Energy’s exploration campaign in the onshore Canning Basin starting with the regional evaluation, which encompassed all available geoscience data (offset wells, pre-existing seismic and potential analogue fields) and modern specialised shale analysis (sequence stratigraphy, paleogeography, geochemistry, unconventional petrophysics and petroleum systems modelling), to develop a robust regional geological model for the GIII Formation. Pre-drill analysis reduced exploration risk and successfully identified the key geological play elements essential for the successful Theia-1 exploration evaluation program.

Unlocking Egypt’s Unconventional-Resource Potential

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 188587, “Unlocking Egypt’s Unconventional Potential,” by Amr Zaher, Etienne Loubens, Mohamed Zayed, SPE, Nicholas Gill, SPE, Oneil Sadhu, SPE, and Layla El Hares, SPE, Shell, prepared for the 2017 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 13–16 November. The paper has not been peer reviewed. The Apollonia tight-gas chalk play is located in the Abu Gharadig Basin in the Western Desert of Egypt. This has long been ignored as a gas play in the overburden, while the Jurassic and Cretaceous oil fields deeper in the basin have been explored and developed. However, several structures in the Apollonia are known to contain potentially significant hydrocarbon volumes, although a potential Apollonia full-field development is challenging because of regulated gas prices in the Western Desert and low-productivity formations. This paper discusses the process of developing the first unconventional-gas opportunity in Egypt. Introduction Vertical appraisal wells show that low production rates and low estimated ultimate recoveries (EURs) present a challenge for cost-effective development of tight gas in Apollonia. With the play’s decreasing levels of permeability, long-reach horizontal wells are needed with induced stimulation. The optimized technique of deploying multistage hydraulic-fracture stimulation efficiently has been documented and applied successfully in North America and has potential for success in Apollonia. Shell and Apache created a joint-development proposal to unlock the significant stranded gas in Apollonia. The proposal consisted of a staged development, starting with a three-horizontal-well pilot followed by an optional full-field development. Geology Apollonia is a homogeneous reservoir; however, it is very tight, and induced stimulation by hydraulic fracturing is required to produce a commercial and sustainable production rate. Smectite and illite contribute to reservoir quality and can be predicated by conventional logs. Fracture densities in Apollonia are low. The fractures are either closed or only partially open, and their contribution to production is perceived to be low. In addition to these factors, development may require drilling many wells (low spacing) with induced stimulation in order to deliver cost-effective production rates. This requires lower well costs than currently exist. While production from the three existing vertical wells continues, EURs from these wells are suboptimal. Apollonia comprises tight, microporous chalky carbonates that are proved to contain movable hydrocarbons. The formation is subdivided into four members, Apollonia A (top layer) through D (bottom layer). Apollonia A and C are composed of thick massive limestones (chalk) with minor marly and shaley intervals, while Apollonia B and D are dominated by shale. Most of the porous intervals occur within Apollonia A and C. Regional correlations have shown that most of the thickness variations are confined to Apollonia C and, to a lesser extent, D. However, recent seismic interpretation has shown that there are also thickness variations in Apollonia A and B associated with Eocene inversion. The individual porous zones within Apollonia A and, to a lesser extent, C are laterally correlatable over large distances.

Microseismic evidence for horizontal hydraulic fractures in the Marcellus Shale, southeastern West Virginia

An integrated analysis of multistage hydraulic fracture stimulation done in three horizontal wells in the Marcellus Shale in southeastern West Virginia revealed that nearly half (14 out of 31) of the examined stages initiated horizontal hydraulic fractures. The study was performed in an area characterized by a transitional strike-slip/reverse faulting stress state where the maximum horizontal principal stress (SHmax) is oriented N55°E. The stages that produced horizontal hydraulic fractures were all within the organic-rich Lower Marcellus Shale. Two lines of evidence indicate horizontal hydraulic fracture propagation. The measured least principal stress of those stages was of similar magnitude to the vertical stress (SV), indicating that the vertical stress and microseismic events are limited to a narrow horizontal layer and do not propagate vertically out of the Lower Marcellus Shale. Both lines of argument indicate that the vertical stress is the least principal stress, perhaps due to viscoplastic stress relaxation in the clay- and kerogen-rich Lower Marcellus Shale. In the 17 stages where perforations were placed in the stiffer Onondaga and Cherry Valley formations, the measured least principal stresses were less than the magnitude of SV, indicating that Shmin was the least principal stress. The microseismic data indicate vertical hydraulic fracture propagation, principally upward outside the Marcellus Shale. Significant gas was produced from the two wells with horizontal fractures in the organic-rich Lower Marcellus Shale, perhaps because twice as much proppant was used as in stages characterized by vertical fracture propagation.

Enhancing recovery and sensitivity studies in an unconventional tight gas condensate reservoir

The recovery factor from tight gas reservoirs is typically less than 15%, even with multistage hydraulic fracturing stimulation. Such low recovery is exacerbated in tight gas condensate reservoirs, where the depletion of gas leaves the valuable condensate behind. In this paper, three enhanced gas recovery (EGR) methods including produced gas injection, CO2 injection and water injection are investigated to increase the well productivity for a tight gas condensate reservoir in the Montney Formation, Canada. The production performance of the three EGR methods is compared and their economic feasibility is evaluated. Sensitivity analysis of the key factors such as primary production duration, bottom-hole pressures, and fracture conductivity is conducted and their effects on the well production performance are analyzed. Results show that, compared with the simple depletion method, both the cumulative gas and condensate production increase with fluids injected. Produced gas injection leads to both a higher gas and condensate production compared with those of the CO2 injection, while waterflooding suffers from injection difficulty and the corresponding low sweep efficiency. Meanwhile, the injection cost is lower for the produced gas injection due to the on-site available gas source and minimal transport costs, gaining more economic benefits than the other EGR methods.

Effects of nano-pore wall confinements on rarefied gas dynamics in organic rich shale reservoirs

The advancements in horizontal well drilling and multistage hydraulic fracturing technology enabled us to unfold major sources of hydrocarbon trapped in ultra-tight formations such as organic rich shales. Tremendous gas production from these reservoirs has transformed today’s energy landscape [1]. Even though multi-stage hydraulic fracturing stimulation provides high permeability paths to transfer gas to the wellbore, however, most of the gas is stored in nano-organic pores of the ultra-low permeability shale matrix that needs to be transferred to the hydraulic fractures to be able to be produced. Studies using advanced imaging technologies such as FIB/SEM and low temperature adsorption measurements show that in the organic rich shale gas reservoirs, Kerogen, the finely dispersed organic nano-porous material with an average pore size of less than 10 nm holds bulk of the total gas in place (GIP). The molecular level interactions between fluid–fluid and fluid–solid organic pore walls govern the transport and storage in these organic nano-pores.To understand the high gas production rates from these ultra-tight formations, the objective of this study is to advance our understanding of non-ideal gas dynamics in multiscale pore structure of organic rich shale matrix (i.e., gas storage and transport influenced by adsorption and adsorbed gas transport) and develop a model to quantify these effects under wide range of reservoir conditions. Among different methods used to model gas dynamics in organic nano-pores such as the multi-continuum, molecular dynamics and Monte Carlo, the lattice Boltzmann method (LBM) is more effective method with much less computational cost relative to other techniques. In this study we focus on rarefied gas dynamics in Kerogen organic nano-tubes under wide range of reservoir pressure and temperature conditions using a two dimensional LBM model.In this model the Langmuir-slip boundary condition at capillary walls, convection or darcy flow and diffusive transport (slippage of free gas molecules and surface transport of adsorbed molecules combined) are considered to model gas transport. Different transport mechanisms and their contribution in gas transport is investigated in a large range of Knudsen numbers from continuum flow to transition flow regime under different reservoir conditions. The deviation from classical theory of fluid flow in micro channels such as Knudsen’s minimum in the mass flow rate is investigated and the effect of gas slippage and double slippage on Knudsen minimum is discussed in details. Finally the results are compared with analytical, and semi analytical solutions available in the literature.The LBM model results displays a clear indication that the gas transport in the capillary tube is highly depends on the pore width size, pressure and temperature. The relative impact of pore size, pressure and temperature on maximum gas velocity and gas wall velocity differs at different flow regime conditions. A critical Knudsen number exists at different reservoir conditions, where the anticipated parabolic fluid velocity profile in organic nano-pores alters and shows higher flow rate as capillary widths reduces due to the underlying effect of molecular phenomena of double slippage and the wall confinement. The comparison with traditional continuum Hagen-Poiseuille law, Klinkenberg slip theory, and recent modified versions of Klinkenberg slip flow equations show that the previous models are valid only in the continuum flow regime, however, they fail to capture high gas flow rates at high Knudsen number and transition flow regimes which is the case in most of the shale organic nano-pore conditions [2].This work is not only important for the advancement of shale gas flow simulators, but also for organic rich shale characterization.

The Graneros-Greenhorn petroleum system, a possible new resource play, Rocky Mountain region, USA

The Graneros-Greenhorn Petroleum System is a widespread unit in the Denver Basin. Organic-rich source rocks are found in both the Graneros and Greenhorn formations (Kaiser, 2012; Durkee, 2016). Reservoir rocks are found in the Greenhorn Limestone. This petroleum system is age equivalent to the Eagle Ford Formation of the Gulf Coast region. Numerous hydrocarbon shows and some vertical well production suggest the high potential for this petroleum system in the Denver Basin (Kaiser, 2013; Durkee, 2016). Horizontal drilling and multi-stage hydraulic fracture stimulation may be keys to future production from this interval. The Graneros and Greenhorn were deposited during the Cenomanian and lower Turonian stages of the Cretaceous (~ 92.1 to 97.2 Ma, Kauffman et al., 1993) (Figures 1, 2). Paleoenvironmental reconstruction for Greenhorn time is shown by Figure 2. This paper illustrates the potential of the Greenhorn to become a resource play and some of the similarities between the Greenhorn and the existing resource play of the Niobrara Formation. The term resource play implies widespread production (continuous accumulation) with somewhat predictable, repeatable results.

Exploring the Beetaloo: will Australia's first viable shale play be sourced by billion year old gas?

Origin Energy completed exploration campaigns in 2015 and 2016 in the Beetaloo Sub-basin of the Greater McArthur Basin in the Northern Territory, drilling three vertical wells and one horizontal well. These wells have provided a wealth of technical data to assist in the characterisation of the primary source rock reservoirs or ‘shale gas’ plays in the Basin – the Velkerri Formation Play and the Kyalla Formation Play. In this paper we demonstrate the presence of thick, gas saturated and over-pressured source rocks across the sub-basin. In addition to the drilling campaign, the multi-stage hydraulic fracture stimulation of the Amungee NW-1H horizontal well was completed in 2016 – this operation was unique as it represents the first horizontal stimulation operation in the Beetaloo Sub-basin and the longest ‘plug and perf’ type horizontal completion in Australia. Data from the extended production test of the Amungee NW-1H are critical from a technical and, potentially, economic and political perspective. In addition to the technical work program, Origin has undertaken preliminary environmental baseline studies and substantial stakeholder engagement. Ensuring environmental baseline data are available is key to demonstrating that onshore gas developments can be undertaken without adverse environmental outcomes, and also for gaining social acceptance. However, data and facts alone are not sufficient to build community confidence. Origin has engaged extensively with pastoralists, local communities and Traditional Owners to build direct relationships and partnerships that encourage acceptance of the gas industry’s ability to coexist and deliver mutual benefits to the businesses and communities of the Barkly region and the Northern Territory more broadly.

Measurement of realistic fracture conductivity in the Barnett shale

The Mississippian Barnett shale of the Fort Worth Basin is one of the most successfully developed shale gas plays in North America by applying multistage hydraulic fracturing stimulation techniques. The fracturing design involves pumping low viscosity fluid with low proppant concentrations at high pump rate, commonly known as “slick water fracturing”. Direct laboratory measurement of natural and induced fracture conductivity under realistic conditions is needed for reliable well performance analysis and fracturing design optimization.During the course of this study a series of conductivity experiments was completed. The cementing material present on the surface of natural fractures was preserved during the initial unpropped conductivity tests. The induced fractures were artificially created by breaking the shale rock along the bedding plane to account for the effect of irregular fracture surfaces on conductivity. Proppants of various sizes were manually placed between rough fracture surfaces at realistic concentrations. The two sides of the induced fractures were cut in a way to represent either an aligned or a displaced fracture face with a 0.1inch offset. The effect of proppant partial monolayer was also studied by placing proppants at ultra-low concentrations.Results from the experiments show that unpropped induced fractures can provide a conductive path after removal of free particles and debris generated when cracking the rock. Poorly cemented natural fractures are effective flow paths. Unpropped fracture conductivity depends strongly on the degree of shear displacement, the presence of shale flakes and particles, and the amount of cementing material removed. The propped fracture conductivity is weakly dependent on fracture surface roughness at higher proppant concentrations. Moreover, propped fracture conductivity increases with larger proppant size and higher concentration in the testing range of this study. Results also show that proppant partial monolayers cannot survive higher closure stresses.

Production Analysis of Multi-Stage Hydraulically Fractured Horizontal Wells in Tight Gas Reservoirs

Activities in exploitation and developing tight gas reservoirs grown tremendously in recent years. The horizontal well with multi-stage hydraulic fracture stimulation has proven to be an effective strategy of developing these unconventional resources. However, to evaluate the fracturing treatment and predict the long-term production behavior of wells in gas recovery it is important to estimate the effective half-length and spacing of created hydraulic fractures and the extent of the stimulated reservoir volume (SRV). In this paper, a simplified linear model is presented to represent the relationship between fractures and matrix rock. Four flow regimes are identified with this model which exhibits the production dynamics of multi-stage fractured horizontal wells (MFHW). Rate-normalized gas pseudopressure is derived from production data and used to interpret flow regimes with corresponding calculation equations. We illustrate the analysis procedure with two field cases from a tight gas reservoir in Northeast China. The results prove that the proposed method works well in analyzing production data from tight gas wells in their early life. The potential in further developing this technique for practical application is obvious and looks very promising.

The role of preexisting fractures and faults during multistage hydraulic fracturing in the Bakken Formation

We performed an integrated study of multistage hydraulic fracture stimulation of two parallel horizontal wells in the Bakken Formation in the Williston Basin, North Dakota. There are three distinct parts of this study: development of a geomechanical model for the study area, interpretation of multiarray downhole recordings of microseismic events, and interpretation of hydraulic fracturing data in a geomechanical context. We estimated the current stress state to be characterized by an NF/SS regime, with [Formula: see text] oriented approximately [Formula: see text]. The microseismic events were recorded in six vertical observation wells during hydraulic fracturing of parallel wells X and Z with three unusual aspects. First, rather than occurring in proximity to the stages being pressurized, many of the events occurred along the length of well Y, a parallel well located between wells X and Z that had been in production for approximately [Formula: see text] years at the time X and Z were stimulated. Second, relatively few fracturing stages were associated with an elongated cloud of events trending in the direction of [Formula: see text] as was commonly observed during hydraulic fracturing. Instead, the microseismic events in a few stages appeared to trend approximately [Formula: see text], approximately 30° from the direction of [Formula: see text]. Earthquake focal plane mechanisms confirmed slip on faults with this orientation. Finally, the microseismic events were clustered at two distinct depths: one near the depth of the well being pressurized in the Middle Bakken Formation and the other approximately [Formula: see text] above in the Mission Canyon Formation. We proposed that steeply dipping N75°E striking faults with a combination of normal and strike-slip movement were being stimulated during hydraulic fracturing and provided conduits for pore pressure to be transmitted to the overlaying formations. We tested a simple geomechanical analysis to illustrate how this occurred in the context of the stress field, pore pressure, and depletion in the vicinity of well Y.

Monitoring increases in fracture connectivity during hydraulic stimulations from temporal variations in shear wave splitting polarization

SUMMARY Hydraulic overpressure can induce fractures and increase permeability in a range of geological settings, including volcanological, glacial and petroleum reservoirs. Here we consider an example of induced hydraulic fracture stimulation in a tight-gas sandstone. Successful exploitation of tight-gas reservoirs requires fracture networks, either naturally occurring, or generated through hydraulic stimulation. The study of seismic anisotropy provides a means to infer properties of fracture networks, such as the dominant orientation of fracture sets and fracture compliances. Shear wave splitting from microseismic data acquired during hydraulic fracture stimulation allows us to not only estimate anisotropy and fracture properties, but also to monitor their evolution through time. Here, we analyse shear wave splitting using microseismic events recorded during a multistage hydraulic fracture stimulation in a tight-gas sandstone reservoir. A substantial rotation in the dominant fast polarization direction (ψ )i s observed between the events of stage 1 and those from later stages. Although large changes in ψ have often been linked to stress-induced changes in crack orientation, here we argue that it can better be explained by a smaller fracture rotation coupled with an increase in the ratio of normal to tangential compliance (ZN/ZT) from 0.3 to 0.6. ZN/ZT is sensitive to elements of the internal architecture of the fracture, as well as fracture connectivity and permeability. Thus, monitoring ZN/ZT with shear wave splitting can potentially allow us to remotely detect changes in permeability caused by hydraulic stimulation in a range of geological settings.