The options for acquiring microseismic data to evaluate hydraulic fracture treatments have expanded in recent years to include surface and near-surface monitoring. However, there has been an absence of detailed and comprehensive validation and comparison of the various monitoring techniques, leading to misconceptions and uncertainties concerning the different alternatives. Traditional downhole monitoring is constrained by the requirement for adequately located deep monitor wells, which limits application in exploration and appraisal and other areas without suitable monitor wells. Surface monitoring provides a means to gathering important microseismic data without the need for observation wells, although the validity of the results is sometimes questioned.
This paper presents detailed "side-by-side" comparisons of surface and near-surface monitoring techniques and provides guidelines for the application of the various monitoring options. This multi-year journey was undertaken by comparing several surface/near-surface data sets with their downhole counterparts in a series of concurrent surveys in US shale plays. These comparisons answer the following questions concerning sensitivity, attenuation, and location uncertainty of surface monitoring options:
The paper includes a rare dataset from a field laboratory in the Fayetteville shale that was instrumented with a 4000 geophone surface microseismic array, a 5 Shallow Hole Grid, and traditional downhole microseismic arrays located in both vertical and horizontal observation wells. In addition, a 71-level geophone array was deployed from TD to surface in a vertical observation well. This multifaceted monitoring provided an unparalleled dataset to compare the various microseismic monitoring options.
The paper documents how and when the surface or near-surface technique provides a meaningful alternative to downhole monitoring both technically and economically, presents candidate selection criteria and provides a comprehensive comparison of the relative technical and economic merits of each monitoring option.
Microseismic monitoring (MSM) of hydraulic fracture treatments is routine in North America and has added significantly to our understanding of fracture growth. The interpretation of microseismic images is advancing steadily, extracting more information from event patterns, temporal evolution, and acoustic waveforms. The increasing amount of information from MSM provides significant opportunities to improve stimulation designs, completion strategies, and field development. However, the applications of microseismic interpretations are many times ill-defined, overlooked, or not applied properly. Numerous applications of microseismic measurements have been documented in technical publications, typically in the form of case histories focused on specific applications. The industry has lacked a compilation and comprehensive discussion of microseismic applications. This paper presents a practical guide for the engineering application of microseismic interpretations, documenting reliable application workflows while highlighting the consequences of misapplication of microseismic interpretations.
The application of MSM starts with a reliable interpretation of fracture geometry and complexity, but the real value is in the application of the interpretation. This paper divides microseismic applications into three categories, real-time, completion strategies & stimulation design, and field development. The MSM interpretation requirements for each category are documented and a comprehensive guide to properly applying these interpretations is presented. Applications issues such as determining the "effective?? fracture surface area, the relationship between microseismic behavior and well performance, and fracture model calibration are addressed.
There is a growing interest in advanced processing such as moment tensor inversion (MTI) and b-values to determine focal mechanisms, source parameters, and failure mechanisms associated with the microseismic events. However, the engineering application of these interpretations is not well understood. This paper includes a discussion of the applications of advanced processing results, emphasizing how the limitations and uncertainties of the processing affect the subsequent applications.
Economic production from an unconventional gas reservoir is possible only if a complex fracture network can be created that connects a huge reservoir area to the wellbore effectively. This fracture network can be created by hydraulic fracturing. Several techniques can be used to present hydraulic fractures in a simulation model. In a simple model it is assumed that the fractures lie in the single plane of local tartan grid cells that best approximates the true geometric orientation of the fracture.
The local refinement is symmetrically placed within the plane of host cells and has small cells close to the fracture that logarithmically increase in size away from the fracture. Explicitly calculated transmissibility multipliers on the faces of the cells that intersect the fracture are used to model the flow between matrix and the hydraulic fracture. The spacing and conductivity of the hydraulic fractures are critical parameters that control well performance.
A new reservoir modeling and simulation technique has been developed for these complex fracture networks that combines discrete fracture network (DFN) modeling and unstructured fracture (UF) modeling to simulate well performance and improve stimulation design. This is very important for modeling and simulation of a well with hydraulic fractures in a shale gas reservoir with natural fractures.
Results from this new model show a gas shale reservoir can be drained more effectively if a complex fracture network can be created by hydraulic fracture stimulation. In addition to a large increase in the production, the number of fracture treatment stages can be reduced if a high-conductivity fracture can be created, adding to the economic viability of the development of unconventional gas sources. The modeling and simulation technique presented in this paper can help identify stimulation and completion strategies that will significantly improve well performance and ultimate recovery from an unconventional gas reservoir.
In addition to well placement and spacing, completion strategy and hydraulic fracture stimulation optimization are crucial to the economic viability of an unconventional gas reservoir. Contrary to conventional reservoirs, the key to economic success in an unconventional reservoir is to focus on well scale rather than field scale. Successful well design, completion, and stimulation require a very detailed geologic description of the local variation of the structure and rock properties that can significantly affect the stress regime that controls the hydraulic fracture growth, distribution, and orientation.
Evaluating well performance and improving future completions can be difficult without coupling the hydraulic fracture geometry and conductivity with the associated well performance (Mayerhofer et al. 2006; Cipolla 2009). To be able to evaluate the well performance and improve the stimulation technique, it is important to properly model hydraulic fractures and predict flow in the reservoir. However, this modeling remains a challenge in unconventional reservoirs.
Appraisal wells in unconventional, very low permeability, resource plays require large hydraulic fracture treatments to assess economic viability. In many cases, drainage area and hydrocarbon recovery are defined by the areal extent and effectiveness of the hydraulic fracture treatment. To increase the drainage area and recovery per well, multiple hydraulic fracture treatments in horizontal and vertical wells are now common, resulting in more complex and expensive completions. Therefore, appraising the completion and hydraulic fracture treatment are just as important as appraising the reservoir. Unlike conventional reservoirs, the complexity and heterogeneity of unconventional resources can make reliable reservoir characterization difficult, which can result in significant uncertainty when evaluating appraisal well performance. Therefore, applying the appropriate technologies for unconventional reservoirs and a holistic approach are essential to properly separate reservoir quality from completion effectiveness.
This paper details technologies and workflows that are essential to the reliable appraisal of unconventional resources, with an emphasis on appraising resources outside of North America. Due to the high cost of appraisal wells in most environments outside North America, operators must assess the viability of unconventional resources using as few wells as possible. The North American model of assessing unconventional reservoirs by drilling and completing a large number of wells may not be economically feasible in areas with insufficient hydraulic fracturing, drilling, and completion infrastructure.
Due to the variability of both hydraulic fracture growth and reservoir characteristics in unconventional reservoirs, properly assessing new plays and subsequently optimizing fracture treatments and completions has historically been a ?trial and error? process requiring a large number of wells and significant capital risk.
However, efficient evaluation of stimulation treatments and completions is now possible by combining microseismic mapping and other hydraulic fracture diagnostics with advanced logs, specialized core tests, 3D seismic, and newly developed ?unconventional? hydraulic fracture models. This holistic approach reduces the number of wells required to assess the economic viability of unconventional resources and reliably separates reservoir quality from completion effectiveness. The application of these unconventional-reservoir-specific technologies, newly developed hydraulic fracture models, and specialized workflows are illustrated using examples from North America.
Interpreting hydraulic fracture geometry isn't the only proven value application of microseismic imaging. With careful geophysical analysis, the microseismic deformation can also be determined in terms of the fracture strain that results in the source of the observed microseismic signals. The microseismic strain or deformation is potentially of interest, since the deformation associated with the hydraulic fracture controls the fracture dilation and complexity and ultimately the effectiveness of the stimulation. However, evidence is presented here which points to the microseismic being primarily a fast, shearing deformation in contrast to the relatively slow and tensile hydraulic fracture growth. Comparing the deformation energy balance between the recorded microseismic and the hydraulic fracture indicates that the microseismic is a very small component of total deformation. The majority of the fracture deformation is aseismic, beyond what is captured with conventional microseismic monitoring.
The microseismic and hydraulic fracture deformations can be rationalized through a geomechanical model that honors the fracture mechanics and mass balance to simulate fracture growth. A workflow is presented that describes calibrating a geomechanical model using the location, timing and strains of the recorded microseismic to match the modeled interaction between the hydraulic fracture and pre-existing fractures. A rock physics model is also required to define synthetic microseismic data from the geomechanical model, for comparison with the observed microseismic data. The simplest form of calibration is a qualitative match between the relative microseismic density of either number of events or source strength. However, more advanced quantitative matches can also be made between the simulated and monitored microseismicity, by matching the microseismic displacements and mechanisms with the additional constraint of matching the energy balance. Through such a calibrated geomechanical model, the interrelation between stress, fractures, and injected fluid can be examined and used to characterize the hydraulic fracture growth. The validated hydraulic fracture model can then be incorporated into a reservoir simulator to ultimately predict the associated production characteristics. Therefore, beyond hydraulic fracture geometry, microseismic source deformation can be used to constrain a geomechanical model of the hydraulic fracture growth and thereby help describe the overall effectiveness of the stimulation.
Multi-stage stimulation has become the norm for unconventional reservoir development. How many fracture treatment stages and perforation clusters are optimal? What is the ideal spacing between perforation clusters? Where is the best location for each fracture treatment stage? These are critical and difficult questions to answer when designing completions for tight gas and shale reservoirs and the approach to answering these questions can differ considerably for vertical and horizontal wells in different lithologies. In the past, optimizing the number and location of fracture treatment stages has been primarily a manual, time intensive process, resulting in a "cookie cutter?? approach that may not properly account for vertical and lateral heterogeneity. This paper details new algorithms and an integrated workflow that could improve fracture treatment staging in both vertical and horizontal wells.
The primary obstacles to optimizing completions in tight gas and shale reservoirs have been the absence of hydraulic fracture models that properly simulate complex fracture propagation which is common in many reservoirs, efficient methods to create discrete reservoir simulation grids to rigorously model the hydrocarbon production from complex hydraulic fractures, automated fracture treatment staging algorithms, and the ability to efficiently integrate microseismic mapping measurements with geological and geophysical data. One of these obstacles has been overcome with the recent development of complex hydraulic fracture models (Meyer and Bazan, 2011, Weng et al., 2011, Xu et al., 2010). However, the remaining obstacles are just now being addressed.
Algorithms for efficient and rigorous design of multi-stage completions are detailed in the paper. Separate staging algorithms have been developed for vertical and horizontal wells that utilize detailed stress, rock mechanical, and image measurements (i.e. - natural fracture identification) to select stage intervals and perforation locations. The staging algorithms incorporate "fit-for-purpose?? hydraulic fracture models ranging from standard planar pseudo 3D models to newly developed complex fracture models, depending on the environment. The algorithms are seamlessly integrated with microseismic measurements, a common Earth Model, and automated routines to discretely grid the complex fracture geometry for reservoir simulation. A common software platform enables the efficient utilization of multiple data sources from multiple disciplines. The application of the newly developed algorithms and integrated workflow is illustrated using examples from tight gas and shale reservoirs.
The development of unconventional reservoirs (e.g. - tight gas and shale) has evolved significantly in the last 10 years. Multi-stage fracture treatments and commingled completions have been an important catalyst of the continued economic development of most unconventional reservoirs. The development of shale reservoirs is almost exclusively through horizontal wells with 10 to 25 or more hydraulic fracture treatments. Tight gas reservoirs are being developed using mostly vertical wells with multiple hydraulic fracture treatments and comingled completions to access numerous stacked pay zones scattered among thousands of feet of inter-bedded lithologies. Due to the vast divergence of reservoir data, ranging from core samples and petrophysics interpretation based on well logs to 3D seismic data, appropriate reservoir stimulation design depends on the ability of oilfield petro-technical experts to conduct primarily manual processes to collate different pieces of information and design the stimulation and completion. The inefficiency of the subsequent manual integration of disconnected workflows has limited our ability to delineate good reservoir zones from poor zones, identify desired completion zones, optimize the number of stages and perforation clusters, estimate hydraulic fracture growth for a given completion strategy, etc. This has resulted in poor completion efficiency in many wells, especially horizontal wells.
The completion strategy and hydraulic fracture stimulation are the keys to economic success in unconventional reservoirs. Therefore, reservoir engineering workflows in unconventional reservoirs need to focus on completion and stimulation optimization as much as they do well placement and spacing. This well-level focus requires the integration of hydraulic fracture modeling software and the ability to utilize measurements specific to unconventional reservoirs. This paper details a comprehensive integration of software, data, and specialized measurements specific to unconventional reservoirs that allows efficient full-cycle seismic-to-simulation evaluations.
It is very important to properly model hydraulic fracture propagation and hydrocarbon production mechanisms in unconventional reservoirs, a significant departure from conventional reservoir simulation workflows. Seismic-to-simulation workflows in unconventional reservoirs require hydraulic fracture models that properly simulate complex fracture propagation which is common in many unconventional reservoirs, algorithms to automatically develop discrete reservoir simulation grids to rigorously model the hydrocarbon production from complex hydraulic fractures, and the ability to efficiently integrate microseismic measurements with geological and geophysical data. The introduction of complex hydraulic fracture propagation models now allows these work-flows to be implemented.
This paper documents an efficient, yet rigorous, integration of geological and geophysical data with complex fracture models, single-well completion and stimulation focused reservoir simulation, and microseismic measurements. The implementation of a common software platform and the development of specialized gridding algorithms allow complex hydraulic fracture models to be calibrated using microseismic measurements in the context of local geology and structure. The complex hydraulic fracture geometry, including the distribution of proppant, is automatically gridded to a common Earth Model for single-well reservoir simulation.
The software platform, newly developed complex hydraulic fracture models, and automated gridding algorithms are illustrated in a case history from the Barnett Shale unconventional gas play.
Maxwell, Shawn C. (Schlumberger) | Pope, Timothy Lawrence (Schlumberger) | Cipolla, Craig L. (Schlumberger) | Mack, Mark Gavin (Schlumberger) | Trimbitasu, Laura (Schlumberger) | Norton, Mark (Progress Energy) | Leonard, Joseph Albert (Progress Energy Resources Corp)
Microseismic measurements were integrated with seismic reservoir characterization and injection data to investigate variability in the hydraulic fracture response between three horizontal wells in the Montney shale in NE British Columbia, Canada. When wells were close enough, hydraulic fractures were found to interact with pre-existing faults, which acted as a barrier to fracture growth, and resulted in relatively large-magnitude microseismicity. The increased level of microseismic deformation and corresponding fault-related source characteristics correlated with the presence of a pre-existing fault identified by edge detection/ant tracking algorithms applied to seismic reflection data. In cases where the wells were far from pre-existing faults simple, planar hydraulic fractures were observed, although there was a tendency to grow towards regions of low Poisson's ratio based on amplitude versus offset inversion of the seismic reflection data. The tendency for the hydraulic fractures to be asymmetric and grow preferentially towards the low Poisson's ratio region is attributed to material property changes and associated lower stresses in these regions. Integrating microseismic interpretations and fracture treatment data with enhanced reservoir characterization has been used to rethink well placement and completion designs, resulting in improved well performance.
Thousands of hydraulic fracture treatments have been monitored in the past ten years using microseismic mapping, providing a wealth of measurements that show a surprising degree of diversity in event patterns. Interpreting the microseismic data to determine the geometry and complexity of hydraulic fractures continues to be focused on visualization of the event patterns and qualitative estimates of the "stimulated volume??, which has led to wide variations and inconsistencies in interpretations.
Comparing the energy input during a hydraulic fracture treatment and resultant energy released by microseismic events demonstrates that the seismic deformation is a very small portion of the total deformation. The vast majority of the energy is consumed in aseismic deformation (tensile opening) and fluid friction (Maxwell et al. 2008). Proper interpretation of microseismic measurements should account for both seismic and aseismic deformation, coupling the geomechanics of fracture opening and propagation with the shear failures that generate microseisms.
Interpretation of microseismic measurements begins with an evaluation of location uncertainty, using signal-to-noise ratios and error ellipsoids, along with event moment magnitude. In some cases, microseismic event location uncertainty is erroneously interpreted as fracture complexity. The next step is to normalize the data and correct for observation well bias, both distance and azimuth, including use of seismic radiation patterns. Without these corrections fracture behavior from well to well or stage to stage (especially in horizontal wells) can easily be misinterpreted. Advanced geophysical processing that describes the failure mechanisms in more detail may also aid in the interpretation. The final step in the interpretation is to include the geomechanics of the overall process, accounting for the fracture treatment volumes injected, the net pressure in the hydraulic fracture(s) and the shear failures that generated the microseisms. This final, critical step is often overlooked when interpreting microseismic measurements. The paper provides a comprehensive, yet practical guide to the interpretation of microseismic measurements.
Cipolla, Craig L. (Schlumberger) | Weng, Xiaowei (Schlumberger) | Mack, Mark Gavin (Schlumberger) | Ganguly, Utpal (Schlumberger) | Gu, Hongren (Schlumberger) | Kresse, Olga (Schlumberger) | Cohen, Charles Edouard
Microseismic mapping (MSM) has shown that 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 (shale-gas). The nature and degree of fracture complexity must be clearly understood to select the best stimulation design and completion strategy. Although MSM has provided significant insights into hydraulic fracture complexity, in many cases the interpretation of fracture growth has been limited due to the absence of evaluative and predictive hydraulic fracture models.
Recent developments in the area of complex hydraulic fracture propagation models now provide a means to better characterize fracture complexity. This paper illustrates the application of two complex fracture modeling techniques in conjunction with microseismic mapping to characterize fracture complexity and evaluate completion performance. The first complex fracture modeling technique is a simple, yet powerful, semi-analytical model that allows very efficient estimates of fracture complexity and distance between orthogonal fractures. The second technique is a gridded numerical model that allows complex geologic descriptions and more rigorous evaluation of complex fracture propagation.
With recent advances in complex fracture modeling, we can now evaluate how fracture complexity is impacted by changes in fracture treatment design in each geologic environment. However, quantifying the impact of changes in fracture design using complex fracture models alone is difficult due to the inherent uncertainties in both the Earth Model and "real?? fracture growth. The integration of MS mapping and complex fracture modeling enhances the interpretation of the MS measurements, while also calibrating the complex fracture model. Examples are presented that show that the degree of fracture complexity can vary significantly depending on geologic conditions.