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Twenty-something Jaime Glas is not your typical young professional. An accomplished petroleum engineer in her own right, she has boldly ventured into the market of women's fire-retardant clothing, launching her first line of coveralls earlier this year. The singular force behind Hot Stuff Safetywear, Glas wears many hats, juggling roles as designer, founder, and primary investor with aplomb. In this interview, entrepreneur Glas shares her thoughts on developing and launching a new product--all while maintaining her full-time job as a reservoir engineer. Jaime Glas graduated from Louisiana State University in 2012 with bachelor's degrees in petroleum engineering and international trade and finance, and a minor in Chinese culture and commerce.
We present a workflow to estimate recovery in unconventional reservoirs that uses flow simulation models constrained by seismic data, geomechanical parameters, and hydraulic stages properties. The goal of the workflow is the rapid testing of different hydraulic stage scenarios in the presence of natural fractures and other hypotheses that can be compared to select the one that yields optimal recovery. All the parameters of interest are generated directly into a flow simulation grid centered on the horizontal well. Thickness of hydraulic stages equals that of one cell of the simulation grid and therefore, details of individual hydraulic fractures are not explicitly considered allowing modeling of larger reservoir scale effects on recovery. The first step is the estimation of natural fracture orientations using seismic data calibrated with independent fracture information. Then, the flow grid is also populated with geomechanical parameters such as stress field and stress orientations, pore pressure, and friction coefficient. After defining locations and geometry of hydraulic stages along the well path and assuming fluid pressure decay functions away from the hydraulic stages, we use Mohr-Coulomb faulting theory to estimate which natural fractures are more prone to reactivation after hydraulic stimulation. This volume of reactivated natural factures is then upscaled to effective fracture permeability that serves as input to an ultra-fast dual-permeability flow simulator. Finally, once the model is in the flow simulator, we use fluid properties and other dynamic parameters for calibrating with production information, changing the simulation model if needed, and performing long term forecast. We illustrate the application of the workflow in the Eagle Ford formation (South Texas) using a data set that consists of 3D seismic, outcrop descriptions, geomechanics measurements, and production information.
Unconventional reservoirs are characterized by extremely low permeabilities that hinder fluid communication between the reservoir and the borehole. These permeabilities are enhanced by the generation of hydraulic fractures after high-pressure fluid is injected into the formations of interest. Even though hydraulic fractures are the main source of permeability enhancement near the wellbore, reactivation of existing natural fractures in the vicinity of the hydraulic fractures is also an important mechanism of self-propped permeability enhancement in the stimulated reservoir volume (SRV) (Gutierrez et al., 2000; Zhang and Li, 2016; Rutledge and Phillips, 2003) and the hydraulic fractures regions (Jeffrey, 2010; Maxwell, 2011).
Reactivation of existing natural fractures depends on the current state of stress, orientation and intensity of existing natural fractures relative to the stress field, injected fluid pressures, rock properties, and geometry of hydraulic stages. In this paper, we consider all these parameters in an integrated fashion that uses Mohr-Coulomb faulting theory to estimate the likelihood of slip of existing natural fractures. Then, we use simple aperture versus fluid pressure assumptions to generate effective permeability volumes of reactivated fractures.
Microseismic data generated during hydraulic fracturing contain a wealth of information, but currently, we are extracting only a small fraction of that information. The primary objectives of this novel microseismic data analysis methodology are three-fold:
1. Accurately image natural and stimulated fractures
2. Image and distinguish stimulated zones from under- and un-stimulated zones
3. Provide accurate flow and fracture parameters to be input into reservoir simulation
Microseismic waves travel through the whole subsurface; therefore, they are sensitive to elevated pore pressures (stimulated and hydraulically-connected zones) and elevated confining stress (un-stimulated and bypassed zones). Here, I present a novel methodology to accurately map the pressure and stress changes in detail within and around the reservoir using inversion of microseismic data. The methodology reduces the volume of microseismic data and then performs an efficient inversion to yield a 3D highresolution image of the effective stress changes in the subsurface. Inversion is performed using an advanced algorithm called waveform-inversion that generates an optimal map of the subsurface moduli that can accurately predict the microseismi waves passing through it. The same inversion procedure is performed for different stages of hydraulic fracturing to yield a time-lapse image of the reservoir that each stage stimulates. This enables more informative decision making in reservoir stimulation even in realtime. In addition, one can analyze the moduli image to determine the fracture opening and tortuosity to be input into the reservoir simulator. Moreover, such an image can provide a more accurate estimate of the stimulated reservoir volume.
The permeability of reservoir rocks can be enhanced through hydraulic fracturing, wherein high-pressure fluids and proppants are pumped into rock formations to create fractures. These fractures create pathways for the oil and gas to flow from the stimulated portions of the rock to the wellbore and then to the surface.
The above process breaks up the rock at many locations in the formation. The disintegration or fracturing of the rocks are associated with a significant drop in the P-wave and S-wave moduli. At other locations, no fractures are created; instead the pore pressure increases because of the fluids pumped at high pressure. These zones will experience a drop in P- and S-wave velocities as can be seen from Figures 1 and 3. Yet at other locations, where the formation has neither been fractured nor has experienced a pore-pressure increase (because of the lack of hydraulic communication with the well bore), the rocks might be subjected to an increase in confining stress. The rock formations above and below the hydraulic fracture zone are a prime candidate for confining stress effects only. The P- and S-wave velocities would increase in these zones (Tosaya, 1982, Figure 1).
Summary Shear slip of pre-existing 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 pre-existing 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).
Abstract Locations and source mechanisms of microseismic events are very crucial for understanding the fracturing behavior and evolution of stress fields within the reservoir and hence facilitates the detection of hydraulic fracture growth and estimation of the stimulated reservoir volume (SRV). In the classic workflow, there are two main methods for locating microseismic events with a calibrated fixed velocity model: grid search and linear inversion. The grid search is very stable; can find a global minimum and does not need initial event locations. However, it is computationally intensive and its resolution depends on the grid size, hence, it is not suitable for real-time monitoring. On the other hand, although the linear inversion method is quite fast, the inversion may be pushed into a local minimum by thin shale layers and large velocity contrasts leading to false locations. The source mechanisms of the located events, which provide information about the magnitudes, modes and orientations of the fractures, are obtained through moment tensor inversion of the recorded waveforms. In this paper, we propose a deep neural network approach to solve the above challenges, in real-time, and increase the efficiency and accuracy of location and moment tensor inversion of microseismic events, induced during hydraulic fracturing. Location of microseismic events was considered as a multi-dimensional and non-linear regression problem and a multi-layer two-dimensional (2D) convolutional neural network (CNN) was designed to perform the inversion. The source mechanisms of the microseismic events were inverted using a multi-head one-dimensional (1D) CNN. The neural networks were trained using synthetic microseismic events with low signal to noise ratio (SNR) to imitate field data. The overall results indicate that both the 2D CNN and 1D CNN models are capable of learning the relationship between the events locations and source mechanisms and the waveform data to a high degree of precision compared to classical methods. Both the event location and source mechanism errors are less than few percent. Deep learning offers a number of benefits for automated and real-time microseismic event location and moment tensor inversion, including least preprocessing, continuous improvement in performance as more training data is obtained, as well as low computational cost.
Li, Qiuguo (Schlumberger) | Michi, Oscar (Schlumberger) | Boskovic, Drazenko (Schlumberger) | Zhmodik, Alexey (Schlumberger) | Faskhoodi, Majid (Schlumberger) | Ferrer, Giselle (Schlumberger) | Ramanathan, Venkateshwaran (Schlumberger) | Ogunyemi, Taofeek (Schlumberger) | Ameuri, Raouf (Schlumberger)
Abstract Geomechanics plays a significant role in hydraulic fracture initiation and propagation and in the interaction between hydraulic fractures and natural fractures, especially in unconventional reservoirs. This paper provides a detailed description of a geomechanical characterization and modeling study for evaluating the impact of geomechanics on completions and hydraulic fracturing stimulations optimization in the Montney resource play, Canada. Following an integrated workflow, 1D mechanical earth models (MEM) for ten wells were constructed in the study area. These 1D MEMs include elastic and strength properties, pore pressure, direction and magnitude of in-situ stresses. Extensive rock mechanics core testing data were used to calibrate the elastic and strength properties. Pore pressure and fracture closure pressure data from diagnostic fracture injection tests were also available to calibrate pore pressure and minimum in-situ stress. Maximum horizontal stress was constrained by modeling wellbore stability and matching it with caliper logs and wellbore stability features on wellbore image. A 3D mechanical earth model was subsequently constructed using a 3D geological model, the 1D MEMs, and seismic inversion data. Elastic properties from seismic inversion were used to populate mechanical properties in the 3D model. In-situ stresses were numerically simulated to account for the impact of faults and structural and mechanical property variation on in-situ stress distribution. The geomechanical analysis shows that there is a decreasing trend in Young’s modulus from upper Montney to lower Montney while Poisson’s ratio is relatively constant in the Montney. The pore pressure in some parts of the field is high and varies across the field. Stress regime is predominantly strike-slip with relatively large stress anisotropy, and this has implications on the hydraulic fracture network that would be simulated, shearing of natural fractures and the stimulated reservoir volume. Rock elastic and strength properties, pore pressure, and in-situ stresses were found to be heterogenous across the whole field. The relatively large variation in pore pressure in the study area and the structural complexities have large impact on the distribution of stresses. Faults alter the stress distribution locally and could affect hydraulic fracture propagation. Hydraulic fracture simulations were subsequently performed, and the geometry of the simulated hydraulic fractures and the stimulated reservoir volume were validated with microseismic events. The effects of geomechanics on fracture geometry and ultimately reservoir production were evaluated. Because of the significant impact of geomechanics on hydraulic fracturing, it is critical to characterize and model geomechanics accurately. This paper provides a comprehensive approach and application to a field in the Montney, showcasing the integrated method of geomechanical characterization and hydraulic fracture simulation and production modeling using various data. The analysis provides an interrelationship among geomechanical parameters, microseismicity and stimulated reservoir volume.
Ye, Zhi (The University of Oklahoma) | Ghassemi, Ahmad (The University of Oklahoma) | Ji, Lujun (Occidental Petroleum Corporation) | Sen, Vikram (Occidental Petroleum Corporation) | Mailloux, Jason (Occidental Petroleum Corporation)
Shear reactivation of pre-existing fractures can play a crucial role in hydraulic stimulation to enable production from unconventional shale reservoirs. However, the mechanisms of permeability enhancement contributed by fracture shear slip are still poorly understood, and the laboratory experiments on shale fractures are insufficient. In this work, injection-induced shear tests were conducted on two reservoir shale samples (from the depth >10,000 ft.) each having a single rough fracture to characterize permeability evolution during fracture shear slip. In the tests, remarkable enhancement of flow rate/permeability have been achieved on both samples through fracture shear slip induced by elevating injection pressure. It is shown that ∼100 times increase in flow rate was induced by a ∼0.1 mm scale of shear slip on the two cylindrical shale samples (with ∼38 mm diameter). The permeability enhancement was retained on the sheared samples even with the decline of fluid pressure. This means that the permeability increase by fracture shear slip may be permanent. In addition, significant stress drops were induced by fracture shear slip in both tests, resulting in further fracture aperture/permeability enhancement. In one sample, a new fracture plane was formed during the shear slip of the original pre-existing fracture, which may help generate an interconnected fracture network. Therefore, dilatant shear slip, stress drop, and the new fractures formation are important and often integral mechanisms of permeability enhancement contributed by pre-existing fractures during shale reservoir stimulation. The results improve the understanding of shear slip in enhancing permeability of shale fractures, and would help engineer solutions for maintaining these fractures open, reducing costs (proppant/water and additive cost savings).
Shear slip of pre-existing fractures has been recognized as a major permeability creation mechanism of reservoir stimulation for a long time (e.g. Mayerhofer et al., 1997; Pine & Batchelor, 1984; 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, the interpretations of induced microseismic events during hydraulic injection have indicated that shear slip of pre-existing fractures around hydraulic fractures can help generate a large stimulated reservoir volume and benefit the production performance (e.g. Fisher et al., 2004; Mayerhofer et al., 2010). However, the fundamental mechanisms of permeability creation by fracture shear slip underlying in shale reservoir stimulation are still poorly understood.
Li, W. F. (Los Alamos National Laboratory) | Frash, L. P. (Los Alamos National Laboratory) | Welch, N. J. (Los Alamos National Laboratory) | Carey, J. M. (Los Alamos National Laboratory) | Meng, M. (Los Alamos National Laboratory)
ABSTRACT In this study, we evaluate the potential significance of wellbore orientation and effective-stress-dependent fracture permeability on shale gas production. To do this, we modeled production from the MSEEL MIP-3H gas well using a simple reducedorder- physics discrete-fracture-network (DFN) reservoir model. Parameters for this model were obtained from site data and laboratory triaxial direct-shear tests. Stress-dependent fracture permeability parameters used a scalable exponential decay function that was fitted to the laboratory measurements. Production was then modeled using a modified transient formation linear gas flow equation. Our results indicate that stress-induced fracture closure can cause significant cumulative production loss in certain scenarios, but not in others. When fracture closure is important, aggressive pressure drawdown can rapidly close the fractures and be detrimental to reservoir performance. Furthermore, the orientation of a horizontal well could be optimized for improved recovery by accounting for both the tectonic stresses and natural fractures. Our results are part of a greater effort to identify production strategies that could help to achieve a higher cumulative shale gas production. 1. INTRODUCTION Fracture networks have long been attributed as a key factor for the economic hydrocarbon production from low-porosity, low-permeability shale formations because they provide primary fluid flow pathways for improved reservoir performance. This network is comprised of artificially induced hydraulic-fractures and natural fractures, given that the fracking treatment activates natural fractures based on microseismic observations (Rutledge and Phillips, 2003). Therefore, studies have been conducted to improve our understanding of the fracture network in the subsurface. These studies include, but are not limited to, natural fracture (NF) characterization (Gale et al., 2003), hydraulic fracturing (HF) optimization (Warpinski et al., 2009), and the HFNF interactions (Blanton, 1986; Wu and Olson, 2016). The deliverability of a naturally fractured shale reservoir strongly depends on the effective stress of the fractures. This is because the fractures function as the primary flow paths and their hydromechanical properties are highly susceptible to stress changes. Experiments have shown that the mechanical aperture of a single fracture in various lithologies can change over an order of magnitude when the effective normal stresses varies from 0 to ∼40 MPa (Bandis et al., 1983). Theoretical linear-elastic calculations also indicate that stress-induced closure is more profound for fractures with small aspect ratios (Jaeger et al., 2007). Furthermore, mathematical models have been developed to link fracture stiffness to the hydraulic properties (Pyrak-Nolte and Nolte, 2016).
Abstract 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.
Abstract Microseismicity can be triggered by various dynamic processes related to a hydraulic fracturing treatment. These processes alter the in-situ stress field inside and around the stimulated reservoir volume, due to both creation of new fractures and fluid leakoff into the surrounding rock matrix. The analysis of spatiotemporal dynamics of fluid-induced seismicity can reveal important characteristics of the hydraulic fracturing process. With the knowledge of treatment data, it can be used in conjunction with the reservoir geomechanical theories in hydraulic fracture growth to investigate the fracture geometry and fluid-rock interactions. By applying these theories to a real microseismic dataset, two types of triggering front expansion patterns are evident. With the presence of a dominant hydraulic fracture, the radius of the triggering front expands linearly with time. Moreover, the microseismic event cloud forms a planar shape with low opening angles (failed by shear), indicating fracture slippages around the major hydraulic fracture. On the other hand, in the case of a complex fracture network with the absence of any major hyfraulic fracture, the triggering front grows non-linearly with time. This scenario can be treated as equivalent to a diffusion model and the microseismic events exhibit a higher fracture of tensile components (either opening or closing) and an equidimensional event cloud. In this study, two stages were analyzed and the derived fracture widths and fluid-loss coeffcients fall into a realistic range of general observations in the context of these two theories.