SPE 164018 Integration of Fracture, Reservoir, and Geomechanics Modeling for Shale Gas Reservoir Development Jugal K Gupta, Richard A Albert, Matias G Zielonka, Yao Yao, Elizabeth Templeton-Barrett, Shalawn K Jackson, Wadood El-Rabaa, ExxonMobil Upstream Research Company, Heather A Burnham, Nancy H Choi, XTO Energy Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Middle East Unconventional Gas Conference and Exhibition held in Muscat, Oman, 28–30 January 2013 This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s) Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s) The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied The abstract must contain conspicuous acknowledgment of SPE copyright Abstract Fracture nucleation and propagation are controlled by in-situ stresses, fracture treatment design, presence of existing fractures (natural or induced), and geological history In addition, production-driven depletion and offset completions may alter stresses and hence the nature of fracture growth For unconventional oil and gas assets the complexity resulting from the interplay of fracture characteristics, pressure depletion, and stress distribution on well performance remains one of the foremost hurdles in their optimal development, impacting infill well and refracturing programs ExxonMobil has undertaken a multi-disciplinary approach that integrates fracture characteristics, reservoir production, and stress field evolution to design and optimize the development of unconventional assets In this approach, fracture modeling and advanced rate transient techniques are employed to constrain fracture geometry and depletion characteristics of existing wells This knowledge is used in finite element geomechanical modeling (coupling stresses and fluid flow) to predict fracture orientation in nearby wells In this paper, an integrated methodology is described and applied to a shale gas pad as a case study The work reveals a strong connection between reservoir depletion and the spatial and temporal distribution of stresses These models predict that principal stresses are influenced far beyond the drainage area of a horizontal well and hence can play a critical role in fracture orientation and performance of neighboring wells Strategies for manipulating stresses were evaluated to control fracture propagation by injecting, shutting-in, and producing offset wells In addition, we present diagnostic data obtained from the pad that demonstrates inter-well connectivity and hydraulic communication within the pad The workflow presented herein can be used to develop strategies for (1) optimal infill design, (2) controlling propagation of fractures in new neighboring wells, and (3) refracturing of existing wells Introduction The spatial and temporal evolution of stresses due to reservoir depletion and mechanical opening of fractures has received widespread attention over the past two decades due to the richness of the associated physical phenomena as well as its technological importance in governing fracture propagation and geometry (Detournay and Cheng, 1988; Bruno and Nakagawa, 1991; Elbel and Mack, 1993; Berchenko and Detournay, 1997) Recently, the concepts have been extended to ultra low permeability unconventional reservoirs such as tight gas and shale gas reservoirs, where the phenomenon of stress reorientation has shed light on refracturing of wells (Zhai and Sharm., 2007) and led to the development of new completion strategies for improving well productivity (Soliman et al., 2010) Stress reorientation around vertical wells and fractured vertical wells has been studied extensively in the past (Siebrits et al., 1998) Experimental (Bruno and Nakagawa, 1991; ElRabaa, 1987) and field observations (Dozier et al., 2003; Wright et al., 1995) have been pivotal in providing fundamental insights into the mechanisms by which stresses reorient 2 SPE 164018 Although it is generally accepted that geomechanical stresses are important for understanding fracture propagation in shales with low contrast in principal compressive stresses, the absence of precise knowledge of input parameters needed for reliable predictions has limited the broad use and applicability of geomechanical models (Dozier et al., 2003) Parameters such as permeability, fracture half length, number of propagated fractures and geological heterogeneity still carry much uncertainty for shales and can have a significant impact on model predictions In this paper, ExxonMobil presents a methodology (Figure 1) to address some of these limitations by integrating knowledge derived from production and fracturing data to reduce the uncertainty in key parameters and enable realistic predictions We have employed advanced rate transient techniques in conjunction with numerical history matching of production data and fracture modeling to deconvolve the complex interplay of parameters impacting well productivity Recent geomechanical studies of multistage horizontal shale gas wells (Roussel and Sharma, 2010) have quantified the impact of key reservoir and mechanical parameters on the extent and degree of stress reorientation However, most of these studies have been limited to investigation of stresses near a single fracture and have used periodic boundary conditions to extend predictions to a multi-fractured horizontal well This paper moves beyond past studies (Mahrer et al., 1999) of near fracture stress reorientation effects by describing a set of 2D and 3D simulations that take into account far field, i.e, thousands of feet away from the drainage area, deformation-driven stress reorientation Figure 1: Multidisciplinary approach that integrates fracture, reservoir and geomechanical analyses to achieve an integrated solution for optimizing the development of unconventional oil and gas resources We have investigated the spatial and temporal evolution of stresses for multiple horizontal fractured shale gas wells on a pad by explicitly modeling each of the hydraulic fracture extending from the wellbore The models are contructed using simplifying assumptions of planar bi-wing fractures Both 2D plane strain and full 3D formulations are used Our results reveal significant reorientation of principal stresses thousands of feet away from a producing well in addition to the anticipated near fracture stress changes The reorientation of stresses far from a producing well can have a significant impact on hydraulic fracture propagation during stimulation of new infill or neighboring wells This is especially relevant for maturing shale gas plays where operators are actively engaged in refracturing and infill drilling In this paper, we present a case study of a shale gas pad to illustrate: (1) evolution of stresses far beyond the drainage area of a hydraulically fractured shale gas well, (2) the potential for propagating tilted or longitudinal fractures instead of the expected transverse fractures, and (3) communication between infill wells during fracturing operations The workflow that we have developed has been employed in a number of published (Gupta et al 2012) and unpublished scenarios such as refracturing of declining wells, infill drilling in maturing regions and steering of fractures away from water producers SPE 164018 Methodology A multidisciplinary approach integrating aspects related to completion, reservoir production, and geomechanics was utilized to optimize development of unconventional gas assets The available well, reservoir, production, and geologic data were incorporated to better constrain the problem and to enable prediction of fracture characteristics, drainage areas, and spatial and temporal changes in stress with reasonable accuracy A high level overview of the integration of the different aspects is shown in Figure It illustrates the three main components of this approach: fracture, reservoir, and geomechanics analysis and modeling Fracture pressure analysis and fracture modeling were conducted to estimate the number of propagating fractures in a stage and to predict fracture length and height Reservoir modeling and production data analysis were employed to use available production data and obtain estimates for drainage area, gas-in-place, permeability, and estimated ultimate recovery (EUR) Geomechanical modeling was utilized to determine the evolution of stress state for existing and infill wells and to predict new fracture orientation Input: Reservoir, Geological, and Mechanical Properties Input Reservoi Completio Hydraulic Fracture Modeling and Analysis Production Data Analysis & Flowing Material Balance Geomechanic Output Obtain initial estimates of permeability, drainage area, fracture height and length to reasonably constrain geomechanics models Output: Improved performance prediction based on new fracture geometries Finite Element Geomechanics Analysis (FEA) Spatial and Temporal Evolution of Stresses Numerical History Matching of Production Data Predict Hydraulic Fracture Orientation Collect Field Data for Model Validation Output: Strategies for infill, refracturing, new field development Figure 2: Flow chart illustrating an integrated methodology that employs fracture modeling, production data analysis, numerical history matching and finite element geomechanics analysis to predict spatial and temporal evolution of stresses and strategies to manipulate them for potential application in refracturing, steering of fractures and optimizing infills A detailed workflow showing the interaction among all three disciplines is highlighted in Figure The main inputs for this process are reservoir, geological, and mechanical properties of the formation, which are used in hydraulic fracture modeling and analysis, production data analysis (diagnostic plots), flowing material balance, numerical history matching and finite element geomechanics analysis The production analysis determines the dominant flow regimes in the well to infer fracture-tofracture and well-to-well interference Using information from production data analysis and fracture height, EUR, and drainage area are calculated from type curves and numerical simulations Finite element analysis (FEA) is conducted to determine evolution of stresses due to production, shut-in, injection, and offset well completion These geomechanical models utilize reservoir properties, number of fractures per stage, drainage widths and reservoir pressures to predict the stresses SPE 164018 surrounding single or multiple wells If an offset well comes on line, then fractures are explicitly added to the wellbore along the maximum horizontal compressive stress direction as predicted by FEA Numerical history matching, incorporating new predicted fracture geometries and any additional field data, can be performed to better constrain permeability and fracture halflengths This process is repeated for each well on the pad Additional details of the workflow, including the modeling assumptions and limitations that define the framework for this paper, will be discussed in the case study that follows This workflow is ultimately used to develop strategies that optimize: (1) the timing, well placement and fracture strategy of infill wells, (2) the timing and fracture strategy for refracture candidates, or (3) the timing, well placement, and fracture strategy for new field developments In the following sections, we will discuss the application of this methodology to an infill well scenario in a shale gas reservoir Case Study The shale gas pad shown in Figure 3A consists of two primary wells (drilled and fractured at different times) and four infill wells that had been drilled but not fractured This type of development strategy, which has been employed by several operators in the US, involves initially drilling wells at a sparse spacing to hold acreage followed later by infill drilling to optimize resource development Such a strategy allows the lease retention constraints to be honored and assists with identifying production performance "sweet spots" for further drilling The objectives of this case study were twofold: (1) to assess the potential for interference between the primary (Well and 2) and infill wells due to fracturing of infill wells (Wells 3-6) and (2) to identify a completion strategy to minimize interference By utilizing the available data, our integrated methodology employing reservoir, fracture, and geomechanics modeling was used to make reasonable predictions and develop practical operational recommendations Below we describe each component of the workflow in detail and summarize the lessons learned Figure 3: (A) Layout of primary and infill wells for the pad and (B) production data for Well Figure 3B shows the production data from Well 1, a top performer in the region Two key observations were made by closely inspecting the production data from Wells and First, we observed significantly different productivity between Wells and 2, despite the two wells being in close proximity to each other Normalizing the initial production by lateral length (IP/lateral length) showed that Well had twice the productivity of Well 2, despite more sand being pumped into the latter Similar observations have also been made in the past for shale gas wells where it has been difficult to discern the role of geology and completion practices to substantiate the performances of the wells Second, we observed well-to-well connectivity induced by nearby fracturing operations In Figure 3B, several spikes in the production rates of Well were observed (some indicated by arrows) We were able to associate most of these spikes in gas rate with a fracturing event taking place in the close vicinity of the pad These observations suggest well-to-well connectivity during a fracturing operation when the reservoir is dilated with millions of gallons of fracturing fluid However, whether these reservoir connections persist long after the flowback of fluids is still unknown We will revisit some of these observations in light of results obtained from modeling and analysis of the pad Fracture Modeling We first sought to take advantage of the available fracture treatment and pumping pressure data to constrain fracture length, height, and the number of fractures per stage With regards to completion and fracture design in a horizontal well, several perforation clusters (~3-8) are typically placed along one fracture stage to generate multiple fractures It is unlikely that fractures propagate from every perforation cluster in the plug-and-perf approach for fracturing shales A recent study by SPE 164018 Schlumberger on more than 100 horizontal shale gas wells concluded that 30-40% of perforations not contribute to the flow (Miller et al., 2011) However, an estimate of the number of fractures propagating per stage is important to reduce uncertainty in fracture character and to make reasonable predictions This is accomplished by calculating perforation friction from fracturing treatment pressures and determining the number of perforation clusters taking fluid The perforation friction as a function of number of open perforations (McClain, 1963) can be calculated by: p perf C 0.2369 q2 n DpC (1) 0.459 exp(1.5187 D p ) where pperf (psi) is the total perforation friction, q (bpm) is the total flow rate, (ppg) is the fluid density, n is the number of open perforations, Dp (in.) is the perforation diameter, and C is the discharge coefficient For wells that were investigated, perforation friction was estimated to be 400-700 psi Based on the Equation (1), two to three propagating fractures were assumed for each stage Figure 4: (A) Wattenbarger diagnostic plot to identify dominant flow regimes in Well (B) Flowing material balance to calculate volume of the depleted reservoir and (C) fracture models to calculate height of propped fractures When combined, these analyses provide an estimate of the drainage area of Well (D) The red and green dotted boxes correspond to the best and the conservative estimate of the drainage area, respectively Fracture modeling was also conducted to estimate fracture height (Figure 4C) Mechanical properties (Young’s Modulus, Poisson’s ratio, fracture toughness, and critical stress) of shales were derived from sonic logs and correlations using conventional analysis Mechanical properties along with wellbore and treatment designs were added to a fracture simulator to estimate fracture heights and lengths Note that these simulations are based on a pseudo-3D model with inherent assumptions of elasticity, symmetry, no natural fractures, bi-wing fractures, and layer homogeneity in lateral directions For the given mechanical properties and treatment size we calculated a fracture height of ~150 ft and a length of ~400 ft as a reasonable estimate of fracture dimensions 6 SPE 164018 Reservoir Modeling To further constrain the reservoir and fracture characteristics, we employed advanced rate transient analysis developed recently for unconventional gas resources, e.g Wattenbarger diagnostic plot (Wattenbarger et al., 1998) Figure shows the step-by-step methodology to estimate the drainage area of Well First, a diagnostic Wattenbarger plot was made to identify the dominant flow regimes experienced by Well As shown in Figure 4A, a half slope signature was observed for an initial linear or transient flow (also confirmed by a square root time plot) followed by a slope of unity, indicating possible boundary effects As suggested by others (Anderson et al., 2010; Song et al., 2011; Houze et al., 2011) and in the absence of nearby wells and known geological features, we interpreted the observation of boundary effects as interference between fractures on the same horizontal lateral This evidence for fracture-to-fracture interference is independent of the fracture character – biwing or complex fracture network Similar observations of fracture-to-fracture interference have also been reported for other shale gas wells (Warpinski et al., 2008) Collectively these observations suggested that although we would anticipate the transient linear flow to last for a dominat part of a well’s life due to ultra low permeabilities, production data suggested an early transition to a boundary dominated flow depending on fracture character Next, we performed a flowing material balance to estimate the stimulated rock volume (SRV) assuming minimum contribution of gas from the unstimulated rock (Anderson et al., 2010) This stimulated rock volume along with the estimate of fracture height from fracture model provided an estimate for the drainage area of Well of 130 acres It is important to note that the methodology to calculate this drainage area did not involve making any assumptions about the permeability, a parameter that has a high degree of uncertainty The estimated drainage area of 130 acres for Well based on production, reservoir properties, and fracture height is shown in Figure 4D by the red dotted box The green dotted box shows a conservative estimate of the drainage area (65 acres) based on a fracture height extending through the entire pay zone With these calculations and including uncertainties, we estimated the drainage area of Well to be between 65-130 acres We associated this unusually high number for drainage area (as compared to drainage areas typically used for shale gas wells) for Well due to its extraordinary production performance Based on this result, the already-drilled infill wells, Wells and 4, have a very high likelihood of laying within the drainage area of Well 1, making it very likely that these wells would communicate during fracturing operations (Figure 4D) Figure 5: History matching of the Well production data (A) and normalized pressure derivative (B) to estimate permeability and number of propagated fractures To obtain an estimate for permeability, history matching of the production data was performed using a numerical model with fine gridding to capture sharp pressure gradients near the fractures The history matching assumed bi-wing fractures uniformly spaced over the lateral length The extent of the fractures or the fracture half length was already estimated from the drainage area calculations discussed above The history matching variables were the permeability and the number of fractures The history match of the production data of Well is shown in Figure 5A Due to occasional spikes in the gas rate (resulting from fracturing in neighboring wells) a perfect history match could not be obtained at those times For the same reason, many history matches could be obtained that appeared very similar to the one shown in Figure 5A To reduce this non-uniqueness, we plotted the derivative of the integral of normalized pressure (Figure 5B) of the history-matched data to uniquely identify the flow regimes noted in Figure 4A This additional constraint significantly reduced the non-uniqueness, and the best history match yielded a permeability of 400 nD and an average of 2.4 fractures per stage totaling to 12 fractures for stages The estimated number of fractures from the production data was consistent with 2-3 open perforations per stage as estimated from pumping pressures For Well 2, diagnostic plots similar to Well indicated the presence of linear flow Due to the short SPE 164018 production history of Well relative to Well 1, diagnostic signatures for boundary effects were not observed In the presence of linear or transient flow any history match of the production data yields non-unique results, i.e., several combinations of permeability and fracture half length will be obtained that match the production data However, the uncertainty is reduced from the square root time plot, which demonstrates that, nf xf Km 120 ft (mD)1 / where, nf is the number of fractures, xf is the fracture half length and Km is the matrix permeability Since it is impossible to determine nf and Km uniquely, we obtain one of the realizations by assuming permeability for Well to be similar to that obtained for Well based on proximity, and had estimated xf to be ~400 ft from fracture modeling These assumptions render nf to be 15 As we will see, Well predominantly dictated the evolution of stresses due to its better performance and longer time of production as compared to Well 2, hence discounting for the higher degree of uncertainty around the parameters estimated for Well Geomechanical Modeling Based on the fracture and reservoir analyses, we anticipated interference between primary and infill wells during fracturing of the infill wells Such interference can potentially lead to proppant or fracturing fluid production in primary wells which could severely impact their performance In order to gauge the magnitude of this interference and to develop effective strategies to minimize well interference we ran geomechanical models using a commercial finite element code to (1) predict the propagation of fractures in the infill wells and (2) evaluate strategies based on injection, shut-in and production in primary or infill wells to steer the propagation of fractures in the infill wells (Wells and 6) away from the highly productive primary wells It is important to note that we not model the creation and propagation of hydraulic fractures Instead, all fractures are predefined in the mesh prior to their activation according to the production schedule from the wells The fractures are linear features that are loci of production or injection of pore fluid, but not explicitly open Our finite element analyses for this case study were conducted in 2D plane strain, but we did run models to address the importance of 3D effects The fracture geometry was assumed to be planar bi-wing The stresses portrayed in the following figures are effective stresses with a Biot coefficient close to unity Figure 6: Plan view layout for Well with pore pressures (A, C, E) as a function of time and trajectories of maximum horizontal compressive stress (B, D, F), with arrows added to emphasize reorientation of stresses versus time Note that the paths of infill Wells and are not shown in this figure PR and PW on the scale refer to reservoir and well bottom-hole pressures respectively As shown in Figure 2, our finite element analyses followed an iterative process in which we simulated the completion and production schedule for an initial well in a pad (Well in this case) and noted the orientations of the most compressive horizontal principal stresses ( max) in the vicinity of the next well at the time it was to be fractured (Well 2) The fractures SPE 164018 originating from the newly activated Well were oriented parallel to the most compressive stress field at this well assuming that the fracture propagation direction in this 2D analysis is predominantly governed by maximum horizontal compressive stresses It has been noted that the propagation of fractures is also controlled by pre-existing discontinuities or planes of weaknesses (Olson et al., 2009), the net pressure used for fracturing and configuration and alignment of perforations (Olson et al., 1995); however, we have ignored the impact of these parameters in this study The spacing between fractures on the lateral as estimated from the fracture and reservoir models is large enough to ignore stress shadow effects (Bai and Pollard, 2000) In the manner described above, the fracture orientations for each well were determined by the evolution of the stress field based on production from all nearby wells that were active prior to the addition of the following well Fracture lengths, permeability and the number of fractures used to construct geomechanical models were reasonably constrained by the fracture and reservoir models described earlier We created a geomechanical finite element model for the pad with the considerations described above The direction of in situ principal maximum horizontal compressive stress is shown in Figure 6A In the model, we first simulated the evolution of stresses due to production in Well until Well was fractured To set up the model, a permeability of 400 nD and 12 fractures of 400 ft half length each aligned with the direction of maximum principal stress (almost transverse) were used for Well Figure shows the spatial and temporal evolution of stresses on Pad A Figure 6A and B shows the pore pressure distribution and stress configuration, respectively, soon after Well started producing We note that soon after production initiation in Well the high pore pressure gradients are confined near the fractures (consistent with the early timed linear flow exhibited by Well as seen in Figure 4A), and the stress orientation had not shifted appreciably from the initial state Figures 6C and D shows the distribution of pore pressure and stresses right before Well was fractured We observed that with production in Well 1, the drainage area confining the pore pressure gradients had expanded but was still in the vicinity of the fractured rock The maximum compressive stress orientation at this time had altered over an area that extended beyond Well and the magnitude (as noted by the red arrows) of this change in stress direction was also significant It is interesting to note that the predicted fracture geometry for Well was tilted fractures with the tilt varying along the wellbore as illustrated in Figure 6D To predict the evolution of stresses after Well was fractured, a new mesh was generated to include Well in the model A permeability of 400 nD and 15 fractures with 400 ft half length aligned according to the stress configuration illustrated in Figure 6D were used to simulate the effect of production of both Wells and Figure 6E and F shows the impact of production from both wells on pore pressure and stress distribution immediately prior to fracturing the infill wells Figure 7: Predicted hydraulic fracture geometry based on the assumption of simple bi-wing planar fractures (A) Plan view layout (as per Figure 6F) showing overall maximum compressive stress orientation Stress orientation (thin lines defining the vector field) near the top of Well (B) and Well (C) showing the tendency for producers to protect fractures (Zhai and Sharma, 2007, Singh et al., 2008) by orienting the stress parallel to the pre-existing fractures (D) The compressive stress in the vicinity of infill Wells and runs parallel to their borehole paths, suggesting longitudinal fractures (E) Simple schematic of the fracture orientation for assuming bi-wing planar fractures with the cracks from Well intersecting infill and the fractures at Well in close proximity to infill PR and PW on the scale refer to reservoir and well bottom-hole pressures respectively Figure shows the overlay of Figure 6E and F and zooms of regions to illustrate the orientation of maximum stresses Close inspection of Figure 7D suggested that the orientation of maximum stress in a region between Well and had almost reversed with respect to its original direction and was now almost longitudinal to the infill drilled wells Assuming that the SPE 164018 propagation of fractures was predominantly governed by existing stresses as mentioned earlier, we anticipated propagating longitudinal fractures in the infill wells (Well and 5) A schematic of the expected fracture pattern, based on the previously discussed assumptions, is shown in Figure 7E In summary, geomechanical simulations predict stresses which suggest propagation of tilted fractures in Well and longitudinal fractures for Wells and 5, fracture geometries that are otherwise not obvious In light of this predicted fracture pattern we revisit the question regarding the differences in the performance of wells closely spaced as noted earlier Potential reasons for the lower performance of Well as compared to Well despite their close proximity could be (1) the difference in the fracture character (transverse vs tilted fractures) as predicted by our models and (2) the large skin damage observed for Well as compared to Well as noted in the y-intercept of the square-root time plot (Anderson et al., 2010) Other potential reasons include geological complexity and completion differences which are not discussed in this paper Prior studies that have reported stress reorientation in fractured horizontal wells either in the context of refracturing (Roussel et al., 2009) or stress shadow effects (Soliman et al., 2010) have primarily focused on stress effects very near to the fractures The case study presented in this paper aimed at investigating far field impact of depletion-driven stress reorientation and its implication in understanding well interference and optimizing resource developments Figure illustrates the impact of depletion-driven stress reorientation at two different length scales for Well 1: effects near the fractures as vastly studied and reported in the past and far field effects at distances of the order of infill well spacings After one year of production in Well 1, the stress field between the individual fractures had remained parallel to the initial most compressive horizontal stress component, essentially transverse to the path of Well However, very near to the fractures themselves the stress was reoriented and almost orthogonal to the fracture orientation (Figure 8A and B) Previous work (El-Rabaa, 1989; Elbel and Mack, 1993; Berchenko and Detournay, 1997; Seibrits et al., 1998; Roussel and Sharma, 2009) has shown that this orientation is to be expected, and that the extent of the re-orientation zone around the individual fractures is a function of time This timedependent stress re-orientation is essentially a poroelastic phenomenon, but that inclusion of the mechanical effects of fracture opening adds to the maximum spatial extent of stress re-orientation (Roussel and Sharma, 2010) They show that this expansion and contraction of the reorientation zone creates the prospect of an optimum time for refracturing Within this study, we also note that after a year of production in Well the stresses far from it (at Well in Figures 8A and C) have also dramatically changed relative to the initial stress orientation At Well stresses are both parallel to the borehole path (lower half of the well in Figure 6C) as well as transverse to the path (upper section of the well in Figure 6C) Figure 8: (A) Plan view showing stress orientations [running left to right: Well (with transverse fractures), infills and 5, and Well 2] (B) Detail of the maximum compressive stress field near the transverse fractures of Well showing reorientation of stresses very near to the fractures (C) Far-field stress field shows the reorientation of stress along the borehole path of Well PR and PW on the scale refer to reservoir and well bottom-hole pressures respectively A 3D finite element model of a single well was developed to verify the assumption of 2D plane strain in the FEA models used in the integrated modeling approach Figure shows the 3D finite element model for Well Pore pressures were prescribed as a function of time and the reservoir depletion history, perforation spacing and fracture length are the same as that used in the 2D modeling Figure 10 shows a comparison between the stress orientations predicted using the 2D finite element and 3D finite element model with a fracture height of 200 ft at three different times The stress field and orientation predictions of 2D and 3D models are comparable at late times Although the drainage area is similar to the fractured area, both the 2D and 3D models show that the stress field is altered well beyond the fractured region Compared with the 3D model, 2D plain strain model shows a more severe stress reorientation and predicts that a larger zone is affected by depletion A parametric study was performed for perforation spacing, magnitude of stress contrast and fracture height using the 3D model The parametric study showed that higher stress contrast constrains the fracture reorientation Both the stress reorientation and stress shadowing 10 SPE 164018 effects are highly dependent upon the perforation spacing with tighter perforation spacing leading to stronger stress shadowing effect and stress reorientation The 3D analysis also shows that for the same fracture length, the size of the zone in which stress reorientation occurs increases with increasing fracture height Generally, 3D modeling provides a more accurate prediction for the stress field and stress orientation surrounding a hydraulically fractured well, particularly for fractures with confined height However, in this case a 2D model can be used to produce comparable results to the 3D at production times of interest and can provide a good estimate to stress reorientation with reasonable accuracy with minimal computational expense Figure 3D finite element model for of Well Figure 10 Comparison between stress orientations predicted using 2D plain strain finite element model and a 3D finite element models with fracture height of 30 m at three different times Next, we sought to extend our observation of depletion-driven far field stress reorientation for a range of permeability and stress anisotropy relevant to shale resources and develop quantitative trends as shown in Figure 11A and B We selected the distance to the far field isotropic point from the well midpoint, L, as a measure of the extent of stress changes due to reservoir depletion and explored the relationship between L and the reservoir permeability (Figure 11A) The normalized distance (L/xf) increases as the permeability increases when comparing results at identical times Essentially this occurred because the effects of pore pressure reduction in the field from production at the well are experienced over a greater distance when the permeability is higher This is a poroelastic effect, with the stress change due to porous flow being proportional to the pressure gradient in the reservoir That is, with a very low permeability, the significant pressure gradients are very close to the fractures and the mechanical ‘pulling’ of material toward the sink is concentrated near the fractures For a higher permeability, the pore pressure gradients are more distributed and the ‘pulling’ of the rock toward the sink occurs over a larger spatial extent The isotropic point is at least twice the fracture half-length for the most unfavorable stress ratio and 400 nD permeability SPE 164018 11 10 10 A Perm=100 nD Shmax/Shmin=1.05 Perm=600 nD L/Xf L/Xf Shmax/Shmin=1.03 Perm=400 nD B Shmax/Shmin=1.01 Perm=200 nD 5 4 3 2 1 1.01 1.02 1.03 1.04 Stress Contrast Shmax/Shmin 1.05 200 400 600 Permeability [nD] Figure 11: (A) Graphical definition of the distance from the well ‘center’ to the isotropic point of the ambient stress field (B) Variation of the normalized distance versus reservoir permeability for three values of horizontal principal stress ratio (C) Variation of the normalized distance versus horizontal principal stress ratio for three values of reservoir permeability shows the sensitivity of the field to nearly isotropic stress fields In addition, we examined how L/xf changes with the initial in-situ stress ratio (Figure 11B) Initial stress ratios in the reservoir that are close to unity disrupt the stress orientations at a greater distance from the well when compared to initial stress ratios that display more significant stress heterogeneity In other words, the more significant the difference in reservoir initial stress magnitudes (i.e., when comparing the horizontal maximum and minimum principal stresses) the greater the resistance to stress reorientation from poroelastic effects from nearby production As L/xf represents the spatial measure of stress reorientation we see that highly anisotropic stress states retard the extent of production-induced reorientation at a given time What is striking in this figure is how significantly the stress reorientation zone is reduced for relatively small degrees of anisotropy in the in-situ stress state For example, a stress anisotropy of ~3% reduces the stress reorientation zone approximately 50% for reasonable shale permeability With the predicted fracture geometries for the wells on the pad, we next sought to test strategies to manipulate stresses to steer the fracture propagation from infill wells (Well and 6) away from the nearby primary wells with superior production The strategies we planned to test were based on the tendency for injectors to act as fracture attractors and for producers to act as fracture deflectors (Zhai and Sharma, 2007; Singh et al., 2008; Bruno and Nakagawa, 1991) To develop operational recommendations, we explored three scenarios with a combination of injection, shut-in and production (as shown in Table 1) Scenario Well Well Well Well Production Injection Injection Production Shut-in Injection Injection Shut-in Shut-in No activitiy No activity Shut-in Table 1: Options explored for steering fractures in Wells and The wells in the table are in order of spatial arrangement in the pad Figure 12 shows the results of the geomechanical simulations for the first scenario In all the scenarios tested, we were not able to identify a favorable stress state that would direct fracture growth away from the producers within a pratical time frame of the order of weeks Although we noted that if we waited for a long time (Figure 12C) the maximum horizontal compressive stresses were directed towards injectors and suggesting that propagated fractures in Wells and might be drawn away from Wells and We concluded that the close proximity of Well to Well 1, and Well to Well creates the prospect of strong interference from frac jobs on each of the infill Wells and from its nearby producer However, to minimize this interference, we developed following recommendations, (1) fracture inner wells (4 and 5) first by utilizing relatively large treatment sizes to create a high pressure zone, (2) fracture outer wells (3 and 6) right afterwards with smaller treatment sizes, (3) injection in inner wells (4 and 5) will not be effective as higher rates and longer duration will be required and (4) utilize chemical tracers to monitor well interference We review the results of these recommendations later in this paper Infill Well Fracturing Program and Diagnostics The primary wells (Wells and 2) demonstrated good production prior to the infill wells being fractured One of the objectives of the study was to identify means of treating the infill wells without adversely affecting the productivity of the primary wells We investigated several operational procedures for minimizing this impact based on the analyses from our integrated 12 SPE 164018 workflow To this end, the inner infill wells (Wells and 5) were fractured before the outer infill wells (Wells and 6) Treatment of infill Wells and first was based on the expectation that fractures in the next set of infill wells (Wells and 6) might be better steered away from the primary wells (Wells and 2) and hence minimize production interruptions at those wells Additionally, the prospect of steering fractures in Wells and away from the primary wells by injecting into Wells and was studied via geomechanical modeling Attraction of fractures toward injectors has been shown in previous experimental and numerical studies (Zhai and Sharma, 2007; Bruno and Nakagawa, 1991) Hence, the goal of minimizing production impacts in Wells and by attracting fractures from Wells and towards the center of the pad by injecting into Wells and seemed promising However, the finite element analysis revealed that a substantial injection time period would be required result in any effective fracture steering Moreover, the amount of stress reorientation would be minimal due in part to the effect of large-scale deformation induced in the reservoir (Gupta, et al., 2012) that resulted from production in Wells and over time Figure 12: (A) Pore pressure field resulting from several years of production at Wells and with subsequent injection at Wells and for about six years while production at and continued (scenarios 1) Inset (B) and (C) show maximum horizontal stress orientations with stress fields being drawn toward the injectors (blue arrows) The plot corresponods to a time of ten years after the start of production at Well PI, PR and PW on the scale refer to injection, reservoir and well bottom-hole pressures respectively The operational procedure that seemed most promising for minimizing production impacts on the primary wells (Wells and 2) was to shut-in Wells and while fracturing all of the infill wells Wells and were shut-in while Wells and were fractured For the fracturing of Wells and 6, all of the previously fractured wells were shut-in (primary Wells and 2; newly fractured Wells and 5) After all of the infill wells were fractured, the Wells and were put back on production first, followed by the infill wells As expected, an improvement in the initial production for Wells and was observed relative to the production just before their shut-in, consistent with prior observations (Figure 3B) To track the potential interaction of fractures (either hydraulic or natural) between the wells in this pad, tracer tests were conducted Wells and were treated with four and three chemical tracers, repectively during their fracturing Figure 13 highlights one of the chemical tracers injected into Wells and While not shown, similar plots were obtained for the other chemical tracers used in these wells The distribution of the tracers showed that there was inter-well communication across the pad For example, the chemical tracers from Well were present in Wells 1, 2, 4, and 5, with a higher tracer concentration observed in primary Well compared to its most proximal infill neighbor, Well Tracers from the fracturing of Well were found in Wells 2, 3, and 5, with a higher tracer concentration observed in Well than its closest infill neighbor, Well Tracers from Well were also found in another well (not shown in Figure 3A but to the right of Well 2), which was more than 1000 feet away from Well The dispersal of different tracers along the various stages of the wells assists in the identification of major fracture networks in the pad As an example, the highest tracer content detected in Well was concluded to arise from the heel of Well The tracer tests showed that there is very likely an extensive fracture system in this pad and inspection of core indicated sufficient natural fracture presence to permit tracer transport as detected by these tests Additional evidence for a pervasive fracture system follows from spikes in the production history of Well (Figures and 5) and Well which are thought to arise SPE 164018 13 from production operations elsewhere in the field With the presence of a broadly distributed fracture system within the pad, shielding Wells and from production upsets due to fracturing operations on the infill wells would be difficult to achieve Tracer Concentration [ppb] Tracer Concentration [ppb] Present day Present day Day wells 3,4,5,6 start production 1 3 (A) Day wells 3,4,5,6 start production Well Day wells 1,2 resume production Tracer Injection Day Time [days] (B) Well Day wells 1,2 resume production Time [days] Tracer Injection Day Figure 13: (A) Schematic of one of the chemical tracers injected into Well showing in which wells the tracer was located and the relative concentration to the source B) Schematic of one of the chemical tracers injected into Well The tracer injected into Well was not sought in Well For both plots, the abrupt onset of tracer concentration at a given time arises from the start of measurement of that particular tracer concentration on that day Conclusions Overall, this case study demonstrated that our integrated workflow which incorporates fracture, reservoir, and geomechanical models can be used to develop customized plans for drilling and completion of infill wells for a given pad The strength of the integrated methodology used above to derive these results lies in the utilization of all of the available data and reasonably constraining the models parameters The product of this approach is obtaining more reliable and customized predictions for every well or pad rather than using generalized numbers for parameters such as well spacing By understanding the effect of stress field alterations on fracture propagation patterns, early decisions on infill well placement, orientation, and timing can be made to minimize early well-to-well interference and damage caused due to fracturing of neighboring wells The broad lesson from the case study presented is that an understanding of the near- and far-field impact of subsurface stress reorientations presents an excellent opportunity for optimizing resource development through customizing the number of wells that need to be drilled in a region and thereby improving the marginal economics associated with shale resource development In addition, the presented workflow provides a framework for formulating strategies for timing the developments of pads Some of the key technical findings from the case study are highlighted below: A number of wells exhibited linear flow followed by pseudo boundary effects originating from fracture-to-fracture interference Identification of these effects, for example in Well 1, enabled us to reasonably constrain the reservoir and fracture properties critical to making reliable predictions Such diagnostics (e.g., early fracture-fracture interference) obtained from production data analysis also provides important feedback on completion effectiveness and on long term well productivity Calculations based on flowing material balance and fracture height estimates can provide reliable approximations of drainage area and assist with customizing well spacing (e.g., drainage area calculations for Well suggested that the infill well closest to Well will most likely interfere with Well 1) The strength of the flowing material balance calculations to estimate drainage volumes lies in making no assumptions about fracture character and permeability (two parameters with high degree of uncertainty) Stresses are an important consideration for shales with small contrasts in stress anisotropy Geomechanical modeling predicts stress reorientation at two different length scales: (1) reorientation of stresses in the close vicinity of the individual fractures arising from poroelastic effects and (2) reservoir depletion-driven far field stress reorientation occurring at length scales of the order of thousands of feet, far beyond the extent of the drainage area of the well Whereas the stress reorientation near fractures has an important implication on refracturing and optimizing fracturing operations, we report that the large scale effects have an implication on optimizing well spacing and the number of infills and hence optimizing the resource development 14 SPE 164018 Finite element geomechanical simulations predict the possibility of propagating tilted or longitudinal fractures (based on stress configuration) in contrast to generally assumed transverse fractures For example, the geomechanical simulations predict stresses which would dictate propagation of tilted fractures in Well and longitudinal fractures for Wells and The fracture geometry – transverse, tilted, or longitudinal – severely impacts well productivity and resource development Effectiveness of injection, shut-in, or production strategies to steer fracture propagation to avoid well interference during fracturing should be evaluated on an individual pad basis and should not be generalized Nomenclature PI PR PW max Pperf q Dp Km xf C Injection pressure, psi Reservoir pressure, psi Bottom hole pressure, psi Maximum principal compressive stress, psi Minimum principal compressive stress, psi Perforation friction, psi Total flow rate, bpm Fluid density, ppg Perforation diameter, ft Permeability, nD Fracture half length, ft Discharge coefficient Acknowledgements We thank many individuals for discussions regarding the topics and results in this paper including Ovunc Mutlu, Jason Hilliard, Kyle Morgan, Gerard Pechal, Kevin Searles and Bhargaw Adhibhatla We thank Shalawn Jackson and David Khemakhem for management support for this research and this paper Finally, we thank 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