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Summary Shear slip of preexisting fractures can play a crucial role in hydraulic stimulation to enable production from unconventional shale reservoirs. Evidence of the phenomenon is found in microseismic/seismic events induced during stimulation by hydraulic fracturing. However, induced seismicity and permeability evolution in response to fracture shear slip by injection have not been extensively studied in laboratory tests under relevant conditions. In this work, a cylindrical Eagle Ford Shale sample having a single fracture (tensile fracture) was used to perform a laboratory injection test with concurrent acoustic emission (AE) monitoring. In the test, shear slip was induced on the fracture at near critical stress state by injecting pressurized brine water [7% potassium chloride (KCl)]. Sample deformation (stress, displacement), fluid flow (injection pressure, flow rate), and AE signals (hits, events) were all recorded. The data were then used to characterize the fully coupled seismo-hydromechanical response of the shale fracture during shearing. Results show that the induced AE/microseismic events correlate well with the fracture slip and the permeability evolution. Most of the recorded AE hits and events were detected during the seismic-slip interval corresponding to a rapid fracture slip and a large stress drop. As a result of dilatant shear slip, a remarkable enhancement of fracture permeability was achieved. Before this seismic interval, an aseismic-slip interval was evident during the tests, where the fracture slip, associated stress relaxation, and permeability increase were limited. The test results and analyses demonstrate the role of shear slip in permeability enhancement and induced seismicity by hydraulic stimulation for unconventional shale reservoirs. Introduction Shear slip of preexisting fractures has long been recognized as a major permeability creation and microseismicity mechanism of reservoir stimulation (e.g., Pine and Batchelor 1984; Mayerhofer et al. 1997; Rutledge et al. 2004; Zoback et al. 2012).
For hydraulic fracturing in unconventional reservoirs, propped volume is the key to predicting total production. Microseismic analysis is frequently performed to detect fracture extension. Recently, microseismic analysis was utilized for various objectives. Though several methods of estimating proppant distribution are currently used, including tracers and core analysis, it is important to investigate whether microseismic analysis can discriminate proppant injection in order to cross-check and decrease the uncertainty of proppant distribution. To estimate the propped fracture distribution, accurate microseismic processing is important. In this study, indications of microseismic events caused by proppant injection were interpreted by accurate microseismic processing and the waveform-similarity clustering of microseismicity in the Horn River shale gas field.
We analyzed a certain hydraulic fracturing stage of zipper fracturing. In this stage, hydraulic fracturing was carried out over 7000 seconds. The first proppant injection started 1000 seconds after starting water injection and continued for 2500 seconds. Next, larger proppant was injected after termination of the first proppant injection and continued for 3500 seconds. Microseismic data was acquired using 36 downhole arrays of 3C geophones in a vertical section of two horizontal wells. Microseismic events were located by focusing P-waves, because, in this field, there is high uncertainty in picking direct S-waves. After that, we classified microseismic events using waveform similarity clustering by cross correlation between each microseismic event in the P-waves and S-waves of the each microseismic data.
Microseismic hypocenters were distributed in a bi-wing pattern from the perforation location. They were concentrated more on the southwest side than the northeast side. Sparse distribution in the northeast side could be caused by existing fractures from the neighboring well treatment. In a time-series histogram of microseismic event frequency, the events are concentrated at the start of water injection and second proppant injection. In a time-distance plot, a linear feature was detected which implies initial fracture opening. Applying the clustering procedure, two clusters were detected which include events that mainly occurred at the start of water injection. These events are located close to each other and have high waveform similarities, which implies that they have the same source mechanism, namely, initial fracture opening. Two other clusters were also detected that include events which only occurred at the start of the second proppant injection. These events were also located close to each other. From net pressure analysis, proppant screenout did not occur. Therefore, the events in the latter clusters are interpreted to have been caused by proppant injection and their hypocentres could represent proppant distribution.
Although further investigation, including fracture propagation simulation, is required and only a few events are interpreted as events caused by proppant injection, this approach should help to estimate the distribution of propped fractures and the total propped volume.
Microseismicity can be triggered by various dynamic processes related to a hydraulic fracturing treatment. These processes alter the
Shear reactivation of pre-existing fractures can play a crucial role in hydraulic stimulation to enable production from unconventional reservoirs. Evidence of the phenomenon is found in microseismic/seismic events induced during stimulation by hydraulic fracturing. However, induced seismicity and permeability evolution in response to fracture shear reactivation by injection has not been extensively studied in laboratory tests under relevant conditions. In this work, a cylindrical Eagle Ford shale sample having a single fracture (tensile fracture) was used to perform laboratory injection test with concurrent acoustic emission (AE) monitoring. In the test, slip was induced on the fracture at near critical stress state by injecting pressurized brine water (7% KCL). Sample deformation (stress, displacement), fluid flow (injection pressure, flow rate) and AE signals (hits, events) were all recorded. The data was then used to characterize the fractures’ fully coupled seismo-hydro-mechanical response during shearing. Results shown that the induced AE/microseismic events correlate well with the fracture slip and the permeability evolution. Most of the recorded AE hits and events were detected during the seismic slip interval corresponding a rapid fracture slip and a quick stress relaxation. As a result of dilatant shear slip, a remarkable enhancement of fracture permeability was achieved. Prior to this seismic interval, an aseismic slip interval was evident during the tests, where the fracture slip, the associated stress relaxation, and the permeability increase were limited. The test results and analyses clearly demonstrate the role of shear slip in permeability enhancement by hydraulic stimulation for unconventional shale reservoirs. Finally, it is further revealed that the transition from aseismic slip to seismic slip is highly dependent on the fracture slip velocity.
Shear slip of pre-existing fractures has been recognized as a major permeability creation and micro-seismicity mechanism of reservoir stimulation for a long time (e.g. Pine and Batchelor 1984, Mayerhofer et al. 1997, Rutledge et al. 2004, Zoback et al. 2012). Most reservoir rocks contain abundant pre-existing fractures, some of which may be sealed with calcite or other infill minerals. Usually, these fractures are inactive and without sufficient permeability before stimulation. A number of modeling and field studies have shown that when the pre-existing natural fractures are favorably oriented with respect to the in-situ stresses, an injection or the leak-off from a hydraulic fracture (even with low fluid pressure) can cause the fractures sliding and propping due to asperities. Also, it is widely observed that the induced microseismic or seismic events during hydraulic injection are mostly related to the shear failure of pre-existing fractures. However, fracture slip-permeability evolution and the associated microseismic signature during injection are still poorly understood. The fundamental investigations through laboratory experiments and field injection tests are insufficient.
Bessa, Fadila (Occidental Petroleum Corporation) | Sahni, Vinay (Occidental Petroleum Corporation) | Liu, Shunhua (Occidental Petroleum Corporation) | Tan, Jiasen (Occidental Petroleum Corporation) | Frass, Manfred (Occidental Petroleum Corporation) | Kessler, James (Occidental Petroleum Corporation)
Understanding and modeling the interaction between hydraulic fractures and natural fractures is important to predict shale production performance. This paper presents a workflow that incorporates natural fractures, rock properties, and stress regimes to understand fracture behavior during stimulation treatment. The methodology also integrates the predefined discrete fracture network (DFN) and 3D reservoir properties to build a comprehensive hydraulic fracturing model. Heat maps are also generated to help evaluate completion design and well spacing strategies.
Applying the integrated fracture characterization workflow to the study area revealed that the vertical and lateral fracture growth is a function of structural context, stress conditions, and rock mechanical properties. Stimulation parameters, including proppant volume and injection pressures, for one horizontal and six vertical wells were utilized to build a comprehensive fracture network for the study area. The resulting model shows: (a) the stimulation of predefined natural fractures, and (b) the generation of induced fractures in the maximum stress direction associated with re-activation of pre-existing faults and fractures. The modeling results were validated by interwell interference data.
Fractures play an important role in hydrocarbon production from organic-rich shale reservoirs (Gale, et al., 2014). This is evident from the higher than expected production rates typically observed from low-porosity and ultra-low permeability shale rocks. Moreover, many shale outcrops, cores, and image logs show an abundance of natural fractures or fracture traces. This study integrates natural fracture characteristics, directional stresses, and hydraulic fractures to characterize and better comprehend Permian Wolfcamp production performance.
Several factors influence the stimulated rock volume (SRV) geometry during a hydraulic fracturing stimulation treatment. These factors include: structural context, natural fracture networks, rock mechanical properties, lithology, and stress changes associated with tectonic events (Gale et al., 2014; Maity, 2018). Furthermore, natural fracture systems in shales are heterogeneous; they can enhance or reduce formation productivity, augment or diminish rock strength, and may have a tendency to influence hydraulic fracture stimulation (Doe et al., 2013). The flow of stimulation fluid through natural fractures and the generation of hydraulic fractures were modeled in this study.
Rathnaweera, Tharaka D. (Monash University /Nanyang Technological University) | Gamage, Ranjith P. (Monash University) | Wei, Wu (Nanyang Technological University) | Perera, Samintha A. (The University of Melbourne) | Haque, Asadul (Monash University) | Wanniarachchi, Ayal M. (Monash University) | Bandara, Adheesha K. (Monash University)
Over the last several decades, many studies have generated a large amount of proppant performance data, but these studies have only focused on proppant conductivity, with no attention to how proppant mechanical properties vary under loading conditions. The impact of mechanical behaviour on proppant performance can only be fully understood by the combined investigation of micro-structural and mechanical changes with increasing loading. Therefore, this study aims to identify such micro-structural behaviour, and in particular the impact on proppant mechanical properties. Proppant samples were tested under one-dimensional compression loading using high-resolution X-ray CT scanning technology. The reconstructed images taken at different load stages were analysed to capture the micro-structural behaviour and finally correlated with the mechanical behaviour of the proppant.
According to the results, there are significant micro-pore voids inside the proppant mass. When the proppant has a higher degree of porosity, there is a considerable reduction of the compressive strength which is not favourable for hydro-fracturing treatment designs. Moreover, it is clear that the brittleness of the proppant decreases with increasing porosity, as its Young’s modulus reduces with increasing pore voids. Therefore, it is important to have high manufacturing standards to achieve effective proppant performance at great depths. The micro-structural behaviour under increasing loading was investigated by performing comprehensive CT image analysis using Drishti software. According to the results, under compressive loading, proppants cleave and generate large fragments like a flower, and this happens suddenly and quite violently through the material. Interestingly, post-failure analysis revealed that the failure mechanism of a single proppant consists of three major stress levels, where initially proppant fails at a high stress level and gains some crushing-associated strength at later stages.
Unconventional oil/gas production has recently attracted the research community due to the uncontrollable increasing demand for primary energy sources (Perera et al., 2016; Wu et al., 2017). Since this method provides a good solution to energy scarcity, over the last several decades, the industry has tried to enhance the production rate, mainly focusing on production enhancement techniques which can be effectively used in the energy extraction from sub-surface geological formations. Of the various options, hydraulic fracturing is one of the best ways to enhance oil/gas extraction, as it increases the formation’s permeability, allowing easy movement of the extracted oil/gas towards the production well (Rutledge and Scott, 2003; Orangi et al., 2011; Vengosh et al., 2014; Wanniarachchi et al., 2015). However, this process may be jeopardised due to the high stress levels acting on the formation at great depths (both vertical overburden and confining pressures). One possible consequence is re-closure of the fracture network under downhole stress conditions, which severely affects the post-fracturing production. Such issues can negate the use of proppant as a hydraulic fracture treatment method where proppants injected with the fracturing fluid prop the fractures, withstanding the fracture-closure stress (Wanniarachchi et al., 2015). Although the proppant gives a reliable solution to overcome this issue (propping the fracture network), sufficient closure stress can cause mechanical failure of the proppant, changing the fracture conductivity, causing re-closure of the fracture network, and altering the bulk properties of the proppant pack, which can negatively influence oil/gas extraction. Therefore, it is important to understand the mechanical behaviour of proppants under downhole stress conditions before injecting proppant with the hydro-fracturing fluid.
Currently, there are several (four main) widely discussed theories used to describe how microseismicity interacts with hydraulic fracturing. Each theory has a different implication for the interpretation of microseismicity used for reservoir modeling. Therefore, better understanding of the relationship between microseismicity and hydraulic fracture stimulation is needed before further reservoir models are developed and applied. This would lead to a more precise estimation of stimulated rock volume, hydrocarbon production and give greater value to microseismic data. We may use either seismic or non-seismic methods. While non-seismic methods provide an independent view of hydraulic fracturing they only provide a limited amount of information on the relationship between hydraulic fracturing and microseismicity. We propose microseismic monitoring of directivity as the most promising way to determine the orientation of fault planes and associated slip vectors. Although this is a suitable method it requires sensors in multiple azimuths that are well coupled to obtain reliable high frequency signals. We suggest using Distributed Acoustic Sensing (DAS) sensors which are capable of sampling at high frequency and may provide continuous data along long offsets at reasonable costs.
Presentation Date: Tuesday, October 16, 2018
Start Time: 1:50:00 PM
Location: 208A (Anaheim Convention Center)
Presentation Type: Oral
A detailed microseismic survey was carried out in the Spraberry Field of Midland County, Texas. A vertical pilot well was completed in eight separate stages and was monitored from four surrounding wells within 300 m of the completion well. Each monitor well was equipped with a 20-level 3C geophone array spanning the completion zones. A velocity model was built from dipole sonic and calibrated for vertical transverse isotropy (VTI) parameters using perforation shots, sonic-derived anisotropy, and crosswell seismic time picks. The microseismic locations reveal simple vertical planar clouds only a few meters wide and oriented along maximum horizontal stress direction. Moment tensor solutions show a mix of strike-slip and dipslip shear mechanisms along failure planes aligned with the hydraulic fracture orientation. Formation microimager data indicate that natural fractures play little or no role in generating the microseismicity or guiding fracture growth. The observations indicate that the microseismic shearing is directly associated with the hydraulic fractures.
Presentation Date: Wednesday, October 17, 2018
Start Time: 1:50:00 PM
Location: 208A (Anaheim Convention Center)
Presentation Type: Oral
Zhang, Ruxin (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, and State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum) | Hou, Bing (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, and State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum) | Zeng, Yijin (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering) | Zhou, Jian (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering) | Li, Qingyang (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University)
Traditional hydraulic fracturing requires lots of water and sand resulting in short fracture length and small SRV with a low production. However, a new waterless fracturing, called Liquefied Petroleum Gas (LPG) fracturing, is applied to stimulate shale formation effectively.
In order to figure out the mechanism of fracture initiation and propagation in LPG fracturing, four large-scale true tri-axial fracturing simulation experiments have been conducted on shale outcrops. Meanwhile, the effects of engineering factors, pump rate and fluid viscosity, on fracture propagation behavior in the shale formation are discussed.
The experimental results indicate that LPG fracturing not only activates discontinuities to form a complex fracture network, but also enhances induced fracture length to form a large SRV. Induced fractures have two initiation points, open-hole section and stress concentration point of wellbore wall, and have three main propagation behaviors, crossing, shear and arrest, dilation and crossing in shale formation. A low viscosity fracturing fluid activates discontinuities resulting in complex fractures, whereas, a high viscosity fluid would like to create some main fractures without opening discontinuities. Moreover, a high pump rate offers more energy for induced fractures to cross the discontinuities resulting in a long fracture length and large SRV. In addition, the anisotropic of shale formation and the existence of discontinuities cause signals attenuation, which increases the arrival time, resulting in location deviation of acoustic emission (AE) events in the AE monitoring. The pressure-time-energy curve, however, shows that the fracture initiation is earlier than the sample ruptured. That is, the initiation pressure is smaller than the ruptured pressure.
The experiments conducted in this paper prove that the LPG fracturing indeed has some advantages than traditional hydraulic fracturing, such as long fracture length and large SRV. And then, the research results provide the theoretical basis for the LPG fracturing operation in shale formation.
Shear stimulation has been recognized as an important factor in enhancing unconventional reservoir permeability during hydraulic fracturing or re-fracturing jobs. The process of shear stimulation is believed to reactivate critical or near critical pre-existing fractures causing them to slip, dilate, and further propagate to generate a fracture network at a treatment pressure below minimum principal stress, resulting in enhanced flow rate. However, the fundamental mechanisms and their contributions to surface area generation and permeability increase are not well understood. In our previous study, we have shown the potential of flow enhancement through dilatant fracture slip on Eagle Ford shales. In this paper, we present the results to another novel experiment on injection-induced fracture propagation and coalescence on pre-flawed shale sample. Cylindrical Eagle Ford shale sample with dimensions of 1.5-inch diameter by 3-inch length, containing two pre-existing flaws, was used to conduct the injection test under triaxial conditions. For a given confining pressure and overburden stress, pure deionized water was injected into the fractures to induce fracture propagation and coalescence to generate a fracture network. Results of the injection test show that flow rate can be significantly enhanced through the propagation and coalescence of pre-existing fractures at a treatment pressure below the minimum principal stress. A pair of tensile cracks emanated from the flaw tips during water injection. These observations show both shear slip and fracture propagation contribute to “hydroshearing” enhancement of unconventional shale reservoir stimulation.
Unconventional shale oil/gas reservoirs require stimulation to achieve economic production rates. Standard hydraulic fracturing jobs in the petroleum industry involve massive injections of water to induce and propagate new tensile fractures at treatment pressures much higher than the minimum principal stress. Proppant is then used to support the induced conductive fractures. However, fracture conductivity and increased reservoir permeability can also result from shear stimulation (Pine and Batchelor 1984, Willis-Richards et al. 1996, Gutierrez et al. 2000, Ghassemi and Zhou 2011, Reece et al. 2014, Weng et al. 2015, Crandall et al. 2017, Fang et al. 2017, Ye et al. 2017, 2018). In contrast to conventional hydraulic fracturing, shear stimulation reactivates pre-existing critically or near critically-stressed fractures causing them to slip and prop open (Pine and Batchelor 1984, Willis-Richards et al. 1996, Baria et al. 1999, Rahman et al. 2002, Nygren and Ghassemi 2005, Cheng and Ghassemi 2016) and possibly propagate new fractures to generate a high conductivity fracture network (Rutledge et al. 2004, Ye and Ghassemi 2018). A relatively small reduction of normal stress by injection can cause reactivation of critically or near-critically-stressed pre-existing fractures at treatment pressure below the minimum principal stress, causing them to dilate. Also, leak-off from a major hydraulic fracture can lead to propagation of natural fractures (Sesetty and Ghassemi 2017, Ye et al. 2018) in the rock resulting in a large stimulated reservoir volume (SRV).