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Hydraulic Fracture Diagnostics Used To Optimize Development in the Jonah Field
... Visual comparison of first-motion polarities for deep and shallow events confirmed the similarity (Fig. S3). HF-generated fracture orientations are usually different from preexisting fault orientations (44). Moreover, Wolhart et al. (44) illustrates how typical shale fracturing events occur at M < −2 and that larger events represent reactivation of slip on preexisting faults outside the target formation. ...
... HF-generated fracture orientations are usually different from preexisting fault orientations (44). Moreover, Wolhart et al. (44) illustrates how typical shale fracturing events occur at M < −2 and that larger events represent reactivation of slip on preexisting faults outside the target formation. Together, these findings suggest that the shallow seismicity that we observed represents on-fault slip rather than a fracturing process and that both Precambrian and Paleozoic faults experience a common faulting regime. ...
Significance
Recent studies have focused on how wastewater disposal wells have caused dramatic increases in eastern US earthquakes. We focused instead on less common cases where hydraulic fracturing alone has caused earthquakes and found seismicity separated into two depth zones: a shallow zone on younger faults, with more small-magnitude earthquakes than expected, and a deeper zone on older faults, with larger magnitude earthquakes and seismicity continuing after fracturing stops. Hence, inducing deeper seismicity creates more hazard. Our observations are consistent with prior geologic, laboratory, and theoretical work indicating that age and maturity of faults causes the different seismicity patterns. We utilize data from well operators to demonstrate that both fluid pressure changes and rock stress transfer are needed to explain our observations.
... Although the east sequence falls out of the target fracturing region (which is usually within a few hundred meters of the well), it is highly likely that a direct fluid connection exists between the injection well and triggered seismicity through permeable pathways. Such an inference is supported by many other cases documented in the literature (Davies et al., 2013;Galloway et al., 2018;Igonin et al., 2020;Wolhart et al., 2006) where the maximum fluid communication distance can be as far as ∼1 km (Fu & Dehghanpour, 2020;Igonin et al., 2020;Wilson et al., 2018). The uppermost part of the east sequence fault seems to be aseismic, possibly due to the close proximity to the injection area (De Barros et al., 2016;Guglielmi et al., 2015) and/or high clay and organic content in the shale formation that favors stable sliding (Eyre, Eaton, Garagash, et al., 2019;Kohli & Zoback, 2013). ...
Plain Language Summary
Fluid injection‐induced earthquakes (IIE), especially those M ≥ 4 mainshocks, are often observed to occur near or after well completion. Such delayed triggering relative to injection commencement poses serious challenges for both regulators and the energy industry to establish an effective mitigation strategy for the potential seismic risk. In this study, we reveal a high‐resolution, complex three‐dimensional pattern of IIE migration near Fox Creek, Alberta, Canada. The observed first‐outward‐then‐inward IIE sequence highlights the significance of hydrogeological networks in facilitating fluid pressure migration and the associated seismic failure. The detailed spatiotemporal distribution of IIE suggests that the effect of pore‐pressure build‐up from hydraulic fracturing (HF) can be very localized. The delayed triggering is a combined result of the fluid pressure migration and the current stress state of the hosting fault system away from the HF wells. The findings from this study also provide plausible explanations on why only a very limited number of fluid injections are seismogenic.
... The hypocenter distribution also illuminates a previously unrecognized fault system that spans approximately 2 km along strike (Figure 2). We suggest that the occurrences of earthquakes discussed in this study are linked to the reactivation of these preexisting faults by HF since (1) right-lateral strike-slip (wrench) faults in the Western Canada Sedimentary Basin are commonly reported (Davies & Smith, 2006;Wang et al., 2017) and (2) stimulated microseismicity induced by opening new fractures typically occurs at M < −2 (Wolhart et al., 2006). ...
Using data from nodal geophones and broadband seismometers, this study investigates the seismicity near Red Deer, Alberta, a region with increasing cases of hydraulic fracturing (HF) induced earthquakes. A cluster of 417 events was detected, and their spatial distribution and focal mechanisms reveal a NE‐trending rupture area with two strike‐slip fault planes. Reactivation of pre‐existing faults by pore pressure diffusion is likely responsible for the occurrence of the earthquake sequence following the ML 4.18 mainshock. The temporal sequence of reactivated fault orientations suggests apparent changes in the local stress field following the mainshock, which is also responsible for a remotely triggered cluster observed one month after the mainshock. This secondary triggering process highlights the need to consider trailing seismicity during risk assessment.
... While WD is the primary cause of induced earthquakes in the United States within the past decade, other human activities such as carbon sequestration (e.g., Kaven et al., 2015), geothermal energy (e.g., Johnson, 2014), and hydraulic fracturing (HF; e.g., Skoumal et al., 2015c) have also been attributed to seismicity. While microseismicity (M < 1) is an inherent component of the HF process (Warpinski et al., 2012;Wolhart et al., 2006), stimulations that induce larger-magnitude events along preexisting faults (HF-induced seismicity) are less common. HF-induced seismicity can also be differentiated from the inherent microseismicity by the locations of the events; the inherent microseismicity associated with fracture creation/opening are typically isolated near the formation being stimulated, while induced seismicity has been observed in the Precambrian basement or other sedimentary layers (e.g., Kozłowska et al., 2018). ...
Wastewater disposal is generally accepted to be the primary cause of the increased seismicity rate in Oklahoma within the past decade, but no statewide analysis has investigated the contribution of hydraulic fracturing (HF) to the observed seismicity or the seismic hazard. Utilizing an enhanced seismicity catalog generated with multistation template matching from 2010 to 2016 and all available hydraulic fracturing information, we identified 274 HF wells that are spatiotemporally correlated with bursts of seismicity. The majority of HF-induced seismicity cases occurred in the SCOOP/STACK plays, but we also identified prominent cases in the Arkoma Basin and some more complex potential cases along the edge of the Anadarko Platform. For HF treatments where we have access to injection parameters, modeling suggests that poroelastic stresses are likely responsible for seismicity, but we cannot rule out direct pore pressure effects as a contributing factor. In all of the 16 regions we identified, ≥75% of the seismicity correlated with reported HF wells. In some regions, >95% of seismicity correlated with HF wells and >50% of the HF wells correlated with seismicity. Overall, we found ~700 HF-induced earthquakes with M ≥ 2.0, including 12 events with M 3.0–3.5. These findings suggest state regulations implemented in 2018 that require operators in the SCOOP/STACK plays to take action if a M > 2 earthquake could have a significant impact on future operations.
... Both mechanisms commonly generate microseismicity, which constitutes an essential tool for mapping the migration of pressure and flow within the rock mass during reservoir creation (e.g. Niitsuma et al, 1999, Wolhart et al. 2006, Kim 2013, McClure & Horne 2014b. When large fluid volumes are injected, significant earthquakes may be induced, which can lead to the termination of reservoir operations (Kim 2013. ...
... Hydraulic stimulation is inevitably accompanied by induced seismicity (e.g., Zoback and Harjes, 1997;Evans et al., 2005a;Davies et al., 2013;Bao and Eaton, 2016) because the slip triggered by the elevated pore pressure arising from injections may be sufficiently rapid to generate seismic waves. In shale gas-and EGS-related stimulations, clouds of small induced (micro-)seismic events are important monitoring tools for delineating the location, where rock mass volume is undergoing stimulation (e.g., Wolhart et al., 2006). Unfortunately, seismic events induced by the stimulation injections may be large enough to be felt by local populations and even to cause infrastructure damage (e.g., in Basel, 2006;Giardini, 2009). ...
In this contribution, we present a review of scientific research results that address seismo-hydromechanically coupled processes relevant for the development of a sustainable heat exchanger in low-permeability crystalline rock and introduce the design of the In situ Stimulation and Circulation (ISC) experiment at the Grimsel Test Site dedicated to studying such processes under controlled conditions. The review shows that research on reservoir stimulation for deep geothermal energy exploitation has been largely based on laboratory observations, large-scale projects and numerical models. Observations of full-scale reservoir stimulations have yielded important results. However, the limited access to the reservoir and limitations in the control on the experimental conditions during deep reservoir stimulations is insufficient to resolve the details of the hydromechanical processes that would enhance process understanding in a way that aids future stimulation design. Small-scale laboratory experiments provide fundamental insights into various processes relevant for enhanced geothermal energy, but suffer from (1) difficulties and uncertainties in upscaling the results to the field scale and (2) relatively homogeneous material and stress conditions that lead to an oversimplistic fracture flow and/or hydraulic fracture propagation behavior that is not representative of a heterogeneous reservoir. Thus, there is a need for intermediate-scale hydraulic stimulation experiments with high experimental control that bridge the various scales and for which access to the target rock mass with a comprehensive monitoring system is possible. The ISC experiment is designed to address open research questions in a naturally fractured and faulted crystalline rock mass at the Grimsel Test Site (Switzerland). Two hydraulic injection phases were executed to enhance the permeability of the rock mass. During the injection phases the rock mass deformation across fractures and within intact rock, the pore pressure distribution and propagation, and the microseismic response were monitored at a high spatial and temporal resolution.
... on the rock mass such as resulting permeability enhancement and induced micro-seismicity. The abovementioned effects on the rock mass are usually prominent during hydro-shearing in comparison to hydrofracking (Wolhart et al, 2006). ...
... Both mechanisms commonly generate microseismicity, which constitutes an essential tool for mapping the migration of pressure and flow within the rock mass during reservoir creation (e.g. Niitsuma et al, 1999, Wolhart et al. 2006, Kim 2013, McClure & Horne 2014b. When large fluid volumes are injected, significant earthquakes may be induced, which can lead to the termination of reservoir operations (Kim 2013. ...
In-situ hydraulic fracturing has been performed on the decameter scale in the Deep Underground rock Laboratory (DUG Lab) at the Grimsel Test Site (GTS) in Switzerland in order to measure the minimum principal stress magnitude and orientation. Conducted tests were performed in a number of boreholes, with 3–4 packer intervals in each borehole subjected to repeated injection. During each test, fluid injection pressure, injection flow rate and microseismic events were recorded amongst others. Fully coupled 3D simulations have been performed with the LLNL's GEOS simulation framework. The methods applied in the simulation of the experiments address physical processes such as rock deformation/stress, LEFM fracture mechanics, fluid flow in the fracture and matrix, and the generation of micro-seismic events. This allows to estimate the distance of fracture penetration during the injection phase and correlate the simulated injection pressure with experimental data during injection, as well as post shut-in. Additionally, the extent of the fracture resulting from simulations of fracture propagation and microseismic events are compared with the spatial distribution of the microseismic events recorded in the experiment.
... Understanding this fracture network complexity and using it to better design hydraulic fracturing treatments has remained a challenge for the industry. From microseismic and tiltmeter data collected over the last 10 years, a huge diversity in fracture propagation patterns has been observed (Cipolla et al. 2005a;Fisher et al. 2002;Fisher et al. 2004;Griffin et al. 2003;Mayerhofer and Lolon 2006;Warpinski et al. 1996;Weijers et al. 2005;Wolhart et al. 2005;Wolhart et al. 2006). These patterns can guide us in understanding the importance of different variables and hence help us to identify the best stimulation strategy to characterize and induce the appropriate degree of fracture complexity for a given reservoir. ...
The creation of a hydraulic fracture changes the stress distribution in the vicinity of the fracture. This stress shadow can influence the growth of subsequent fractures. Immediately after a hydraulic fracture treatment is pumped, the width of the propped fracture and the associated induced unpropped (IU) fracture network is at its maximum. The hydraulic fracture and the induced unpropped fractures close as a result of fluid leak-off over time. This implies that the stress shadow in their vicinity also decreases over time. Complete closure of induced, unpropped fractures can significantly reduce the stress shadow and make subsequent fracture stages less susceptible to fracture interference and more efficient by avoiding wastage of fluid / proppant into preexisiting fractures. This suggests that increasing the time between successive fractures in a wellbore will lead to improved fracture performance.
Using geomechanical computations we show that waiting for longer times between successive stages of a horizontal well allows for a reduction in the stress shadow and less fracture interference leading to a more efficient fracture network by successive fractures in a horizontal well. We, therefore, propose the idea of establishing a minimum time between successive fracture stages in a well. The time required for the induced un-propped fractures to close can be calculated from our models and varies based on the reservoir and fluid properties but is of the order of hours.
This controlled time-delay in fracturing can be achieved in several ways, without wasting valuable rig time in the field. We suggest several alternate innovative strategies to achieve this on the field. For example, two-well or multi-well zipper fracs can be pumped, hence increasing the time between fractures in a given well substantially (by several hours). Alternatively, in the Texas Two Step method it would be better to pump the fractures in the sequence 1, 3, 5, 2, 4 than the sequence 1, 3, 2, 5, 4 where the numbers represent the sequence of the fractures along a well starting at the toe. We propose several other fracturing sequences for multi-well pad fracturing applications and suggest how the impact of a multi-stage, multi-well pad fracturing treatment can be enhanced while conserving the time and resources used.
Numerous surface-felt earthquakes have been spatiotemporally correlated with hydraulic fracturing operations. Because large deformations occur close to hydraulic fractures (HFs), any associated fault reactivation and resulting seismicity must be evaluated within the length scale of the fracture stages and based on precise fault location relative to the simulated rock volumes. To evaluate changes in Coulomb failure stress (CFS) with injection, we conducted fully coupled poroelastic finite-element simulations using a pore-pressure cohesive zone model for the fracture and fault core in combination with a fault-fracture intersection model. The simulations quantify the dependence of CFS and fault reactivation potential on host-rock and fault properties, spacing between fault and HF, and fracturing sequence. We find that fracturing in an anisotropic in-situ stress state does not lead to fault tensile opening but rather dominant shear reactivation through a poroelastic stress disturbance over the fault core ahead of the compressed central stabilized zone. In our simulations, poroelastic stress changes significantly affect fault reactivation in all simulated scenarios of fracturing 50-200 m away from an optimally oriented normal fault. Asymmetric HF growth due to the stress-shadowing effect of adjacent HFs leads to 1.) a larger reactivated fault zone following simultaneous and sequential fracturing of multiple clusters compared to single-cluster fracturing; and 2.) larger unstable area (CFSgt;0.1) over the fault core or higher potential of fault slip following sequential fracturing compared to simultaneous fracturing. The fault reactivation area is further increased for a fault with lower conductivity and with a higher opening-mode fracture toughness of the overlying layer. To reduce the risk of fault reactivation by hydraulic fracturing under reservoir characteristics of the Barnett Shale, the Fort Worth Basin, it is recommended to 1.) conduct simultaneous fracturing instead of sequential; and 2.) to maintain a minimum distance of ~ 200 m for HF operations from known faults.
The formation of hydraulic fracture-network is an important goal for stable and increased production of unconventional oil and gas resources. However, due to the extremely complex mechanical behavior of hydraulic-fracture propagation, there is still a lack of fine, effective and systematic evaluation methods on 3D fracture-network structure. The quantitative characterization of hydraulic-fractures is of great significance to reveal the law of fracture propagation and to evaluate the reservoir stimulation effectiveness reasonably. Although the micro-cracks evolution process follows a random rather than deterministic pattern, the overall fracture morphology is featuring statistical regularity. In this study, after the indoor hydraulic-fracturing simulation experiments of the tight sandstone specimens, 3D optical scanning was used to visualize the fracture-network. On this basis, two aspects of quantitative statistics of 3D complex fracture-networks were established by plane and sphere cuttings for the first time, including angle distribution statistics and spatial variation statistics. Comparative analyses with reported methods showed that, the overall deflection of the macroscopic fracture-networks varies synchronously with the local roughness of the main hydraulic fractures closest to the wellbore, which satisfied exponential function or power-law function relationship between them. The variation of the area proportion with the propagation radius reflects the specific fracture propagation process such as crack initiation, bifurcation and arrest, and could be used to assess the complexity of the fracture-network. Moreover, a new stimulation evaluation index Es was established by comprehensively considering the stimulated-reservoir-area, the dispersion degree of the angle distribution and the complexity of spatial variation for 3D fracture-network. The insights gained warrant further applicability on hydraulic-fracturing in the actual engineering scale.
A real-time downhole microseismic mapping technique was recently used in the southern Sichuan shale gas development. The case study presented illustrates this technique and analyzes the results, from the geological evaluation through the engineering solution, for a typical H24 pad fracturing.
This paper presents the use of real-time microseismic (MS) monitoring to understand hydraulic fracturing of a horizontal well drilled in the minimum stress direction within a high-temperature high-pressure (HTHP) tight sandstone formation. The well achieved a reservoir contact of more than 3,500 ft. Careful planning of the monitoring well and treatment well setup enabled capture of high quality MS events resulting in useful information on the regional maximum horizontal stress and offers an understanding of the fracture geometry with respect to clusters and stage spacing in relation to fracture propagation and growth. The maximum horizontal stress based on MS events was found to be different from the expected value with fracture azimuth off by more than 25 degree among the stages. Transverse fracture propagation was observed with overlapping MS events across stages. Upward fracture height growth was dominant in tighter stages. MS fracture length and height in excess of 500 ft and 100 ft, respectively, were created for most of the stages resulting in stimulated volumes that are high. Bigger fracture jobs yielded longer fracture length and were more confined in height growth. MS events fracture lengths and heights were found to be on average 1.36 and 1.30 times, respectively, to those of pressure-match.
The highly complex geology of the Sichuan Shale gas play, especially in relation to natural fracture systems at different scales, affects the hydraulic completion efficiency and performance. Ant-tracking-based workflows and borehole image data are regularly used to optimize completion campaigns, but bridge-plug-stuck and screen-out risks are still high. The lack of sufficient understanding and accurate identification of the natural fracture systems are the major challenges to address these engineering risks.
Surface microseismic monitoring campaigns were conducted over several wells of the Changning field, Sichuan Basin, China. The surface receivers were placed in a radial pattern to record microseismicity generated by hydraulic fracturing. The failure mechanism of all mapped microseismic events (i.e., strike, dip, rake, etc.) was extracted using a moment tensor inversion (MTI) method. Improved understanding of the natural fracture systems and their influence during the hydraulic fracturing process has been achieved by integrating the regional geological data, pumping data and MTI results.
Several hydraulic fracturing cases that stimulated near natural fracture systems were investigated. The microseismic monitoring results show that (i) most of the hydraulically induced fractures located in the vicinity of the natural facture or fault did not propagate along the regional maximum stress direction, (ii) the bridge plug got stuck and (iii) screen-out happened frequently in these areas. Moment tensor inversion reveals that (i) the dominant failure mechanism of the natural fractures different from hydraulically induced fractures, (ii) more than one group of natural fractures develop along different directions.
Real-time adjustments of the pumping schedule and bridge-plug settings were conducted to reduce engineering risks based on the improved understanding of natural fractures, which proved effective. The innovation of using surface microseismic monitoring results to improve understanding of natural fractures and reduce the engineering risks in real time represents a key step forward to mitigate natural fracture influence and improve the effectiveness of stimulation.
Microseismic monitoring of hydraulic fracturing in unconventional reservoirs is a valuable tool for delineating the effectiveness of stimulations, completions, and overall field development. Important information, such as fracture azimuth, fracture length, height growth, staging effectiveness, and many other geometric parameters, can typically be determined from good quality data sets. In addition, there are parameters now being extracted from microseismic data sets, or correlated with microseismic data, to infer other properties of the stimulation/completion system, such as stimulated reservoir volume (SRV), discrete fracture networks (DFNs), structural effects, proppant placement, permeability, fracture opening and closure, geohazards, and others. Much of the information obtained in this way is based on solid geomechanical or seismological principles, but some of it is speculative as well.
This paper reviews published data where microseismic results have been validated by experiments using some type of ground-truth or alternative measurement procedure, discusses the geomechanics and seismological mechanisms that can be reasonably considered in evaluating the likelihood of inferring given properties, and appraises the uncertainties associated with monitoring and the effect on any inferences about fracture behavior. Considerable data now exist from tiltmeters, fiber-optic sensing, tracers, pressure sensors, multi-well-pad experiments, and production interference that can be used to aid the validation assessment.
Relatively limited microseismic results have actually been validated in any consistent manner. Fracture azimuth from microseismic has been verified across a wide range of reservoir types using multiple techniques. Good validation of fracture length and height were performed in sandstones for planar fractures; fracture length and height in typical horizontal completions with multiple fractures or complexity have a lesser degree of verification. Other parameters, such as complexity, discrete fracture networks, source parameters, and SRV, have little supporting evidence to provide validation, even though they might have sound physical principles underlying their application. It is clear that microseismic monitoring would benefit from more attention to validation testing. In many cases, the data might be available but have not been used for validation purposes, or such results have not been published.
Fracking of the Preese Hall-1 well in 2011 induced microseismicity that was strong enough to be felt. This occurrence of ‘nuisance’ microearthquakes, unexpected at the time, was a major factor resulting in adverse public opinion against shale gas in the UK and was thus of significant political importance. Despite this, and notwithstanding the technical importance of this instance of induced seismicity for informing future shale gas projects, it has received little integrated study; contradictory results have indeed been reported in analyses that lack integration. This instance therefore provides a case study to illustrate how a small but significant multi-disciplinary geoscience dataset may be put to best use, including how best to quantify uncertainties in key parameters, which may themselves be relatively poorly quantified but whose values may significantly affect the ability to understand the occurrence of induced seismicity. The best-recorded event in this induced microearthquake sequence (at 08:12 on 2 August 2011) is thus assigned an epicentre circa British National Grid reference SD 377358, south of the Preese Hall-1 wellhead, a focal depth of ∼2.5 km, and a focal mechanism with strike 030°, dip 75°, and rake −20°, this NNE-striking nodal plane being the inferred fault plane. Like other parts of Britain, this locality exhibits high differential stress, with maximum and minimum principal stresses roughly north-south and east-west. This instance indeed fits an emerging trend of the occurrence of relatively large induced earthquakes in localities with high differential stress; such an association was predicted many years ago on the basis of experimental rock mechanics data, so observational confirmation might well have been anticipated and should thus not have been unexpected. Many steep faults, striking NNE-SSW or NE-SW, mostly Carboniferous-age normal faults, are present; the stress field is favourably oriented for their left-lateral reactivation, southward leakage of fracking fluid into one such fault having presumably caused the induced seismicity. Given the pervasive presence of similarly oriented faults, future occurrences of similar induced seismicity should be planned for; they pose a significant technical challenge to any future UK shale-gas industry.
Hydraulic stimulation of deep reservoirs is an essential procedure for developing engineered/enhanced geothermal systems (EGS), but also in other Geo-energy contexts. The goal is enhancing permeability to such a degree that fluid flow rates within the reservoir are sufficiently high for an economically productive reservoir. Two fracture stimulation mechanisms are distinguished that may occur concurrently during the hydraulic treatment: 1) During hydro-fracturing (HF) new tensile fractures are propagated from the borehole by means of a fluid pressure overcoming the minimal principle stress σ 3 plus the tensile strength T 0 of intact rock. In case of a pre-existing fracture oriented normal to σ 3 , the fracture can be opened by exceeding σ 3 only. Fluid injection is performed via small packed intervals for creating a stack of hydraulic fractures. 2) During hydro-shearing (HS), over-pressure induces slip along pre-existing fractures that are favourably oriented in the stress field for reactivation in shear. Such stimulation is usually performed in a large packed interval or in an open borehole. Which mechanism occurs predominantly during stimulation depends on the rock mass structure and in-situ stress field, but also on the orientation of discontinuities intersecting the open-hole section and thus being pressurized. Both mechanisms also differ in how they affect fracture permeability. While permeability gained by HS is mostly irreversible due to rearrangement of asperity contacts accompanied with shear dilation, permeability enhanced during HF reduces nearly reversible after pressurization unless proppant is used to ensure permanent apertures. In this contribution, we critically discuss the pros and cons of both mechanisms regarding efficiency of enhancing permeability and the associated hazard of induced earthquakes based on literature review and numerical modelling. We review literature that reports on how much permeability required for productive EGS reservoirs and how much permanent permeability can be gained by stimulation. We also compile information regarding the degree of seismicity induced during HF-or HS-dominated stimulation procedures, together with conceptual studies that reveal characteristics of seismicity associated with the two mechanisms. Many observations and models indicate that HF may have a higher tendency of being aseismic, while felt seismic events are usually associated with HS. Further, we present a hydro-mechanically coupled fracture flow model that investigates, if and to what degree the stimulation strategy can be designed such that one of the two mechanisms is evoked and dominates over the other. It shows that HS may dominate in presence of larger persistent fractures nearly optimally-oriented in the stress field, even if HF is attempted in short packed intervals. The model further demonstrates that stress transfer during HS promotes the development of permeability across an anisotropic layer of the stimulated rock instead of a large volume. Hence, the study sheds light onto the feasibility of creating productive EGS reservoirs in crystalline rock at several kilometres depths.
Much public discourse has taken place regarding hydraulic-fracture growth in unconventional reservoirs and whether fractures could potentially grow up to the surface and create communication pathways for frac fluids or produced hydrocarbons to pollute groundwater supplies. Real fracture-growth data mapped during thousands of fracturing treatments in unconventional reservoirs are presented along with the reported aquifer depths in the vicinity of the fractured wells. These data are supplemented with an in-depth discussion of fracture-growth limiting mechanisms augmented by mineback tests and other studies performed to visually examine hydraulic fractures. These height-growth limiting mechanisms, which are supported by the mapping data, provide insight into why hydraulic fractures are longer laterally and more constrained vertically. This information can be used to improve models, optimize fracturing, and provide definitive data for regulators and interest groups.
The Glauconitic formation is a Cretaceous age sandstone reservoir located across a large area of central Alberta, Canada. Discovered in the late 1970’s, hydraulically fractured vertical wells could produce commercial volumes of natural gas from some of the higher permeability conventional sands. However, wide spread development of the majority of the tight gas sands was not economic with vertical wells.
With the introduction of multiple fractured horizontal well (MFHW) technology in recent years, and much better definition of the geology, a large unconventional resource play has developed in the Glauconitic, which could contain in excess of 5 tcf of gas in place plus associated natural gas liquids (Scotia Capital, 2009).
A pilot project was designed to test the completion effectiveness between a cased and cemented liner and an open hole packer system in this tight gas reservoir. Two vertical microseismic observation wells were located in close proximity to two proposed horizontal wellbores, giving ideal conditions to test how the hydraulic fractures would grow and the ultimate fracture geometry, from two different completion methods.
In this paper we will present the microseismic results of the pilot project, as well as the early production history comparison between the two wells, and the hydraulic fracture effectiveness from a reservoir engineering aspect.
Recent advances in hydraulic fracture mapping technologies have provided a wealth of information on fracture propagation in numerous geologic settings. Prior to such detailed measurements of actual fracture growth, fracture propagation was either assumed to be simple (single planar fracture) or the complexity was inferred based solely on fracturing pressure data. The nature or detail of this inferred fracture complexity and how it related to actual fracture growth (real fracture geometry) could not be determined. This resulted in significant uncertainty in fracture modeling, treatment designs, and many times, sub-optimum field development. This paper illustrates the application of the various methods and techniques available to diagnose fracture complexity, including simple pressure diagnostics such as G-function pressure decline analysis and sophisticated microseismic and tiltmeter fracture mapping technologies. After identifying complexity in hydraulic fracture growth, this information must be integrated with fracture, reservoir, and geologic models to properly evaluate stimulation, completion, and develop options; however, without properly identifying the nature and detail of the fracture complexity, the solution can many times be wrong - resulting in economic loss.
This paper documents field observations of different mechanisms that result in fracture complexity and the corresponding physics that govern fracture growth in these reservoirs. These field observations of fracture complexity are supplemented by and related to results from mine-back and core-through experiments to better understand the relationship between fracture complexity, rock properties, and geology. Distinguishing between the various types of fracture complexity and properly modeling these complexities (in both reservoir and fracture models) can lead to significantly different treatment designs and field development strategies. The paper includes field case histories that document how the remediation of fracture complexity can lead to stimulation success, while in other cases it is the exploitation of fracture complexity that is the key to success.
Introduction
Complex growth of hydraulic fractures has been documented in mine-back experiments, providing direct observations of hydraulic fracture complexity in a variety of environments including tight sandstones and coalbed methane reservoirs. Unfortunately, data from mine-back experiments are very limited, and require other methods to diagnose hydraulic fracture complexity. Until recently, fracture pressure analysis was the only diagnostic available to estimate complexity.1–16 Fracture pressure analysis has been used to estimate both near-wellbore 1,17 and far-field fracture complexity; the focus of this paper is far-field fracture complexity. Hydraulic fracture complexity is usually associated with the interaction of the hydraulic fracture with a pre-existing rock fabric such as natural fractures or fissures, but it can also be linked to laminations and other geologic heterogeneities. In most cases, far-field fracture complexity is deemed detrimental due to excessive fluid leakoff and/or reduced fracture width that can result in early screenouts.18,19 In many cases, fracture complexity is reduced by adding particulates that likely plug secondary fractures and/or fissures 15,20,21; however, sometimes maximizing fracture complexity is the key to stimulation success and treatments are specifically designed to promote complexity.23,25,30 During the past ten years, thousands of hydraulic fracture treatments have been characterized using microseismic and tilt fracture mapping technologies. These measurements have shown a surprising diversity in hydraulic fracture growth, ranging from simple planar fractures to very complex fracture systems to extreme fracture height confinement (that are not explained by variations in rock properties and stress).22–39 The occurrence of complex fracture growth is much more common than initially anticipated and is becoming more prevalent with the increased development of unconventional reservoirs. The nature and degree of the fracture complexity must be clearly understood to select the best stimulation strategy. This paper focuses on techniques to diagnose fracture complexity and the selection of appropriate remediation or exploitation measures.
Tight gas reservoirs are present in every petroleum province, and global tight gas resources in place are large. However, it is uncertain how much of the in-place resource is technically recoverable. Although some publications report the technically recoverable resource of tight gas for small geographical areas, little is known publicly about these resources on a global scale.
The objective of our work was to determine the probabilistic distribution of the technically recoverable resources of tight gas, worldwide. To achieve this goal, we applied the unconventional-gas-resource-assessment system to establish a representative distribution of 25-year technically recovery factors from selected tight gas sandstones of the US. The recovery factors follow the minimum extreme-value distribution, with a P50 of 79%. Then, we extended the distribution of recovery factors to estimate technically recoverable tight gas resources for the seven world regions. Global technically recoverable tight gas is estimated to be 37,000 (P90) to 80,000 (P10) Tcf, with a P50 value of 54,000 Tcf.
Results of this work support the existence of significant global resources of technically recoverable tight gas and may have potential to guide energy strategy, such as to forecast future energy supply worldwide.
Hydraulic fracturing in shale formations induces microseismic events in a region we refer to as the microseismic volume. Many of these microseismic events are signatures of failure in the formation that are believed to be a result of induced unpropped (IU) fractures beyond the primary propped fracture. Areally extensive microseismicity may be evidence that these IU fractures occur and extend spatially beyond the propped fracture during pumping in many unconventional reservoirs. We present evidence that these fractures close over time after pumping is stopped and that this closure of IU fractures can have a significant impact on stress interference between fractures.
To illustrate these effects, microseismic and radioactive-tracer data are presented for four laterals drilled and fractured from a single pad. Two wells on this pad were fractured with the consecutive-fracturing sequence, and the other two wells were fractured with the zipper-fracturing sequence. Geomechanical simulations were performed to model the pad scenario and explain the microseismic and tracer observations, with emphasis on the two different fracturing sequences.
Our simulations show that the opening of the IU fractures results in significant temporary changes to the stress field in the rock. One consequence of this is that later fracture stages tend to propagate into the open-fracture networks of IU fractures created earlier because of stress reorientation. This can lead to inefficient usage of fluid, proppant, and capital because the region that is being stimulated has already been stimulated by the previous stage. By analyzing the net pressure, radioactive-tracer data, and microseismic data from the four-well pad, we show that these IU fractures close over time because the fracture fluid leaks off. This reduces the stress shadow, and subsequent induced fractures are no longer subjected to the significantly altered stresses, allowing for more-efficient fracture-network coverage by subsequent fractures in a horizontal well. On the basis of the data presented and computer simulations, we propose the idea of maximizing the time between fracturing in the microseismic volume of a recently fractured region (within operational constraints). The time required for the IU fractures to close can be estimated from our models and varies on the basis of the reservoir and fluid properties from several hours to days. One example of how this is accomplished in practice is zipper fractures. However, our work suggests that there also may be other fracture-sequencing strategies for accomplishing this.
While microseismic mapping has proven to be a valuable technology for understanding hydraulic-fracture growth and behavior, the seismic waves generated by the microseismic event also contain information that has potential value for understanding the reservoir, natural fractures, stress state, and fracturing mechanisms. Extracting information from the microseismic data requires the use of a source model, which in its most general form is represented by a symmetric moment tensor having six components. Difficulties arise when attempting to invert for the components of the moment tensor if only a single monitor well is available, but in principle the full moment tensor can be extracted for multiple monitor wells. The primary information derived consists of the slippage-plane orientation, the slip direction, and the moment (strength) of the event. Presumably, these slippages occur on existing planes of weakness, such as natural fractures, bedding planes, or potentially even fracture planes induced by the hydraulic fracture, thus providing information about the reservoir and the process. An approach for performing the moment-tensor inversion is discussed for both single and multiple monitor wells, along with methods to estimate various parameters. Both synthetic and field examples are provided to demonstrate what can be extracted from the data set under various conditions.
Microseismic monitoring has proved to be a valuable technology for assessing and optimizing hydraulic fracturing in a host of tight sand and gas shale reservoirs. Parameters such as fracture length, height, azimuth, and asymmetry are readily identified, but this technology can also be useful for understanding staging effectiveness, stimulated volume, complexity and network growth, natural fractures, stress azimuth and changes in that azimuth, fault interactions, and reservoir behavior as a result of the treatment. Various published data sets are examined to show how both quantitative and qualitative information about the fracturing behavior, completion effectiveness, and reservoir behavior can be usefully extracted from the microseismic data. Examples will include both vertical and horizontal wells, relatively planar and network fracture systems, various staging and diversion techniques, and faulted and naturally fractured reservoir response.
Interpretation of fracture geometry is an important aspect of microseismic monitoring, especially for hydraulic fracture stimulations. The fracture geometry is often inferred directly from the microseismic locations, particularly by using the few events comprising the edges of the cloud of microseismic locations. These few events are frequently used to measure the fracture dimensions of height and length, as well as the width to interpret fracture complexity. In this paper, a synthetic dataset assuming different location uncertainties is constructed, to illustrate how location errors relate to uncertainties in the fracture dimensions. If the edges or extremities of the microseismic clouds are used to interpret the fracture extents, the synthetic data demonstrate that these locations are potentially statistical outliers of the microseismic uncertainties. Therefore, the extremities are shown to be biased towards measuring larger fracture dimensions, and potentially misinterpretation of fracture complexity associated with mislocated events. A technique termed compression is introduced which considers the probability density function to interpret the statistical spatial scatter of the microseisms, to enable an interpretation of the fracture dimensions ‘compressed’ away from the extremities of the cloud. The synthetic data is used to validate the technique, demonstrating that the resulting fracture geometries are more accurate and are less biased by the location uncertainty. The compression technique was applied to a hydraulic fracture image, for a dataset which was processed using automatic data processing and then reprocessed with a more accurate algorithm. For both the automatically processed and the refined locations, the compression technique results are similar, confirming the technique is relatively insensitive to the location errors. The refined image was sufficiently accurate to identify two discrete structures in the image.
A hydraulic fracture stimulation was monitored with borehole geophone arrays deployed in two observation wells. The resulting microseismic images showed that the first horizontal well stimulation was characterized by a diffuse cloud of microseismic events, and the production log indicated roughly uniform production along the length of the well. The second horizontal well stimulation was characterized by clustered microseisms, and the production log indicated significant production from the intersection of pre-existing fractures with the well. The resulting case study allowed a comparison of accuracies between a single observation well and two observation wells. A comparison was also made of the microseismic event location accuracy resulting from of the different configurations of observation wells. The dual well observations provide an opportunity for enhanced velocity model validation in addition to enhanced source imaging techniques to provide additional information about the fracture geometry.
One of the most important challenges in the Jonah Field in Sublette County, Wyoming, is to obtain effective fracture-height coverage over the entire 2,800+ ft Lance formation. The Lance formation in Jonah Field is composed of a stacked sequence of 20 to 50 fluvial channel sands interbedded with associated overbank siltstone and floodplain shale deposits. Within this interval, the net-to-gross ratio varies from 25 to 40%. Sandstone bodies occur as individual 10- to 25-ft thick channels and stacked-channel sequences greater than 200 ft in some cases.
Tiltmeter and microseismic fracture mapping was conducted on hundreds of propped-fracture treatments in the Jonah Field. These direct height-growth measurements helped to obtain an understanding about the effectiveness of shale barriers. It was found that a standard triple-combo log suite could be used to identify shale barriers for fracture growth.
A calibrated fracture model was developed for the Jonah Field that ties the log analysis to the fracture-growth behavior that was mapped using direct fracture-mapping technologies and to the net-pressure response measured during propped fracture treatments. These improvements in predictive modeling capabilities have lead to better insight into fracture growth behavior in the Lance formation.
A 3D fracture-growth model was modified to determine perforation strategy and fracture-treatment schedules to obtain effective coverage of the Lance formation in new Jonah wells in a semi-automated process. As a result, the entire process for fracture design can now be performed in an integrated software package.
Microseismic monitoring of hydraulic fractures is an important tool for imaging fracture networks and optimizing the reservoir engineering of the stimulation. The range of magnitudes of the recorded microseisms depends at the lower limit on the array sensitivity; while the upper limit varies significantly from site to site. In this paper the variation in the microseismic magnitude range is examined and compared with the injection and site characteristics. Although there are numerous potential factors effecting the seismic deformation, the energy of the pumping and state of stress appear to be the two dominant factors. However, interaction with pre-existing faults also results in increased deformation. Ultimately, this can potentially be used to design the stimulation to maximize the deformation. Characterization of the seismogenic potential is also important for seismic hazard assessment, as well as the design of passive monitoring.
In many reservoirs fracture growth may be complex due to the interaction of the hydraulic fracture with natural fractures, fissures, and other geologic heterogeneities. The decision whether to control or exploit fracture complexity has significant impact on fracture design and well performance. This paper investigates fracture treatment design issues as they relate to various degrees and types of fracture complexity (i.e., simple planar fractures, complex planar fractures, and network fracture behavior), including the effect of fracture fluid viscosity on fracture complexity, proppant distribution in complex fractures, and fracture conductivity requirements for complex fractures. The impact of reservoir properties (including permeability, stress and modulus) on treatment design is also evaluated. The paper includes general guidelines for treatment design when fracture growth is complex. This includes criteria for the application of water-fracs, hybrid fracs, and crosslinked fluids.
The paper begins with an evaluation of microseismic fracture mapping data that illustrates how fracture complexity can be maximized using low viscosity fluids, which includes an example of how microseismic data can be used to estimate the permeability and spacing of secondary or network fractures. The effect of proppant distribution on gas well performance is also examined for cases when fracture growth is complex, assuming that proppant was either concentrated in a primary planar fracture or evenly distributed in a fracture network. Examples are presented that show when fracture growth is complex the average proppant concentration will likely be too low to materially impact well performance if proppant is evenly distributed in the fracture network and un-propped fracture conductivity will control gas production. This paper also extends published conductivity data for un-propped fractures and embedment predictions for partially propped fractures to lower modulus rock to provide insights into fracture design decisions. Exploiting fracture complexity may not possible when Young's modulus is 2 x 106 psi or lower due to insufficient network conductivity resulting from asperity deformation and proppant embedment.
Fracture conductivity requirements are examined for a wide range of reservoir permeability and fracture complexity. Reservoir simulations illustrate that the network fracture conductivity required to maximize production is proportional to the square-root of fracture spacing, indicating that increasing fracture complexity will reduce conductivity requirements. The reservoir simulations show that fracture conductivity requirements are proportional k1/2 for small networks and k1/4 for large networks, indicating much higher conductivity requirements for low permeability reservoirs than would be predicted using classical dimensionless conductivity calculations (Fcd) where conductivity requirements are proportionate to reservoir permeability (k). The results show that when fracture growth is complex, proppant distribution will have a significant impact on network conductivity requirement and well performance. If an infinite conductivity primary fracture can be created, network fracture conductivity requirements are reduced by a factor of 10 to 100 depending on the size of the network. The decision to exploit or control fracture complexity depends on reservoir permeability, the degree of fracture complexity, and un-propped fracture conductivity.
The paper also examines the effect of fluid leakoff on maximum fracture area, illustrating potential limits for fracture complexity as reservoir permeability increases. Although the expected range of un-propped fracture conductivity is controlled by Young's modulus and closure stress, in many reservoirs it can be beneficial to exploit fracture complexity when the permeability is on order 0.0001 mD by generating large fracture networks using low viscosity fluids (water-fracs). As reservoir permeability approaches 0.01 mD, fluid efficiency decreases and fracture conductivity requirements increase, fracture designs can be tailored to generate small networks with improved conductivity using medium viscosity or multiple fluids (hybrid fracs). Fracture complexity should be controlled using high viscosity fluids and fracture conductivity optimized for moderate permeability reservoirs, on order 1 mD.
Tight gas is becoming an increasingly important asset for petroleum companies. Proper reservoir evaluation and development planning is critical to the success of a tight gas play. To date, the "best practices" for evaluating tight gas performance have not been well defined, and many companies use unreliable or unnecessary methods. As a result, analysts commonly misinterpret (and incorrectly book) tight gas reserves. Furthermore, the development of tight gas reservoirs is often conducted inefficiently, either through over-capitalization (too many wells, too quickly) or ineffective recovery (overly sparse spacing).
This paper presents a straight forward and technically sound approach for evaluating and planning the development of tight gas reservoirs. The critical step in the process is proper identification of the dominant reservoir flow regime. Without this step, we cannot choose the correct analysis plot to use. The techniques detailed in this paper are designed for production data sets ranging from about 3 months and upward. The reservoir and production characteristics (permeability, xf, flow regime) are determined using pressure/rate transient analysis, as are the drainage region and its expansion rate. The resulting model predicts well performance and the rate of increase of accessible recovery over time. Superposition of the appropriate economic model and well constraints allows the analyst to identify a practical range of EUR values that is more reliable than that provided by conventional decline curves. This process can be applied to reserve evaluation as well as optimizing well spacing in the reservoir. The analysis is performed through interpretation of a diagnostic plot paired with an appropriate recovery plot (using well constraints and economics). It is validated using simulated and field examples.
Unconventional gas resource plays continue to have a significant impact on natural gas production in the US due to recent technological advances and higher demand for gas. In the US, 22% of the total energy consumed comes from natural gas. The US domestic production of natural gas is around 85% of the demand; currently about half of that comes from unconventional resources. Primary unconventional sources are tight gas, shale gas, and coalbed methane (CBM). Tight gas, shale gas and CBM production accounts for approximately 28%, 14% and 8%, respectively, of total US gas production. Total US production for 2010 is 21.57 tcf. Achieving sustainable production from unconventional gas resources requires reaching extended areas of the reservoir and performing effective hydraulic fracturing, with its associated technologies, to help reduce risk and increase the success rate.
Compared to production in vertical wells, the production of tight gas and shale gas in horizontal wells has increased significantly due to the ability to reach extended areas as a result of enhanced drilling technologies. Horizontal wells represent a large portion of the well count in US plays, with rigs for horizontal wells increasing from 10% to 58% of the total drilling rigs within the last 6 years (2005–2010). This increase in activity was achieved through careful engineering designs and use of new technologies to address the complexities involved in planning, drilling, completing, and stimulating horizontal wells. In recent years, microseismic hydraulic fracture monitoring (HFM) has become a key technology in understanding the propagation mechanism of the created fractures during stimulation treatments.
The paper discusses horizontal well drilling activity in a south Texas play over a 6-year period beginning in 2005. Drilling activity trends and completion practices in some tight gas and shale gas formations in the south Texas basin are highlighted. Additionally, the paper takes a look at the application of microseismic HFM to increase the success rate of horizontal wells in the south Texas basin by reducing some of the completion risks and challenges. Finally, the paper discusses ways to improve the overall completion and stimulation designs of horizontal wells in unconventional gas formations to ensure efficient recovery.
This paper provides an overview of design and life-cycle considerations for certain unconventional-reservoir wells. An overview of unconventional-reservoir definitions is provided. Well design and life-cycle considerations are addressed from three aspects: upfront reservoir development, initial well completion, and welllife and long-term considerations.
Upfront-reservoir-development issues discussed include well spacing, well orientation, reservoir stress orientations, and tubular metallurgy. Initial-well-completion issues include maximum treatment pressures and rates, treatment diversion, treatment staging, flowback and cleanup, and dewatering needs. Well-life and longterm discussions include liquid loading, corrosion, refracturing and associated fracture reorientation, and the cost of abandonment.
These design considerations are evaluated with case studies for five unconventional-reservoir types: shale gas (Barnett shale), tight gas (Jonah feld), tight oil (Bakken play), coalbed methane (CBM) (San Juan basin), and tight heavy oil (Lost Hills field). In evaluating the life cycle and design of unconventional-reservoir wells, "one size" does not fit all and valuable knowledge and a shortening of the learning curve can be achieved for new developments by studying similar, more-mature fields.
This paper presents a case history of hydraulic fracture stimulation treatments performed on a vertical well completion in the Spraberry-Wolfcamp formations located in Midland County, Texas, in which real-time microseismic Hydraulic Fracture Monitoring (HFM) was utilized to “track” the development of the hydraulic fracture as it propagates through the formation thereby allowing for the implementation of corrective actions to improve the completion efficiency of the well.
The case history is presented in three main themes or sections: background, job execution, and post-job evaluation. The background section will provide an overview of the completion design as well as the HFM setup. The job execution section will then address how the real-time HFM observations and interpretations made during the treatment executions were used to identify undesired height growth, which prompted swift and concise actions to optimize the well completion by modifying the perforation scheme and treatment design. Finally the paper will present the results of the integrated HFM post-treatment evaluation and will discuss the observed differences between the planned and actual fracture geometries as observed from the microseismic monitoring results. Comparison of the microseismic fracture geometry to the anticipated fracture geometry showed that even in areas where we think that there might not be anything new to be learned, opportunities exist to apply new technology that can identify some of the complications and challenges involved, improve the success of stimulation treatments, and identify opportunities to improve operational efficiency.
Overall, this example clearly shows how real-time microseismic monitoring provides the data required to improve fracture modeling, identify fracture behavior that is not predictable by conventional means alone, and reveals several opportunities to improve completion efficiency.
Unconventional reservoirs such as gas shales and tight gas sands require technology-based solutions for optimum development. The successful exploitation of these reservoirs has relied on some combination of horizontal drilling, multi-stage completions, innovative fracturing, and fracture mapping to engineer economic completions. However, the requirements for economic production all hinge on the matrix permeability of these reservoirs, supplemented by the conductivity that can be generated in hydraulic fractures and network fracture systems. Simulations demonstrate that ultra-low shale permeabilities require an interconnected fracture network of moderate conductivity with a relatively small spacing between fractures to obtain reasonable recovery factors. Microseismic mapping demonstrates that such networks are achievable and the subsequent production from these reservoirs support both the modeling and the mapping. Tight gas sands, having orders of magnitude greater permeability than the gas shales, may be successfully depleted without inducing complex fracture networks, but other issues of damage and zonal coverage complicate recovery in these reservoirs. As with the shales, mapping has proved itself to be valuable in assessing the fracturing results.
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