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A new approach is proposed to quantify the communication between wells in a tight multi-layered shale gas reservoir. In this approach, a wide range of data sets, from microseismic monitoring to the production data are analyzed to evaluate the communication between wells in every stage of well development. The results provide new insight into how the initial well communication during stimulation impacts the well interference during production.Microseismic data collected during hydraulic fracturing are analyzed for a three-well pad drilled in the Appalachian basin. The microseismic event locations, magnitudes, and fracture plane characteristics are used to construct a discrete fracture network (DFN). The permeability of a numerical reservoir model is calculated from the generated DFN, and the model is further integrated with available reservoir data. History matching is carried out using three years of production data to calibrate the reservoir model, which was also used to predict water and gas production for thirty years. Finally, decline curve analysis (DCA) is used to examine the production behavior of the reservoir.The microseismic data monitored during hydraulic fracturing show the presence of communication between wells in the pad. This communication, also known as frac hits, is established as more events are recorded in the offset wells, indicating the extent of hydraulic fractures. In addition, the pressure perturbation in the offset wells confirms the presence of a pathway connecting the wells during stimulation. Furthermore, the reservoir model built in the numerical reservoir simulator shows overlap of drainage volumes. In the reservoir model, the depleted region expands across multilayer formations in both lateral and vertical directions. An analysis of the production behavior of the wells using DCA suggests an almost logarithmic trend which is expected for these types of reservoirs. Surprisingly, detailed analysis of the results reveals there is no significant deviation in the overall performance of wells associated with well interference, especially in the early years of production. However, at greater than 10 years of production, the expansion of the depleted zone accelerates the well interference which leads to lower performance of the pad in the long term. The results demonstrate that the enhanced permeability zones created due to frac hits may not have an immediate impact on production performance.Traditionally, frac hits and well communication were considered damaging to the reservoir production. However, this new result shows that the well communication during fracturing may not impact short-term production. Additionally, it highlights the importance of a thorough examination of the fracture network along with the reservoir properties to evaluate the potential impact of frac hits on reservoir production.

Optimizing a well's hydraulic fracture design within a pad development environment is a multi-disciplinary effort and requires a 4-dimensional understanding of the reservoir. This paper presents a workflow that uses an integrated workflow that combines geology, and geomechanics to build a reservoir model which can be interrogated and updated with a geologically and geomechanically constrained grid-based 3D planar frac model and production simulation using a fast marching method. In this case, as applied to an Eagle Ford well to address concerns of completion optimization, production and depletion forecasting, well spacing and well interference. The workflow captures the variability of stresses and rock properties along the wellbore and around it by using multiple geologic and geomechanical approaches. The estimated variability of rock mechanical properties is used as input in a 3D planar frac simulator. An alternative approach to geoengineering a completion, using the differential stress derived from geomechanical simulation that overcomes the limitations of well centric methods, is also illustrated. The frac design results are used as inputs/constraints in a new reservoir simulator that was developed using the Fast Marching Method to estimate drainage area. This allows for a constrained, yet extremely fast estimate of the EUR and resulting pressure depletion, addressing the important concerns of well spacing optimization and prevention of frac hits and well interferences, all in a timely manner. The integrated approach facilitates adaptive frac design which honors in-situ conditions including stress field heterogeneity, stress shadow effects and the pressure depletion from nearby producing wells. The proposed workflow enables greater investment efficiency and promotes field development optimization.

Research on stress shadows between stages and wells has provided new elements for understanding how the initial stress state in the subsurface is altered by the creation of hydraulic fractures. Furthermore, variations in pore pressure and the presence of faults and natural fractures are key factors contributing to heterogeneous initial stress conditions that ultimately influence fracture propagation patterns. In this case study, time-based poroelastic and viscoelastic approaches are used to quantify lateral stress gradients between wells and analyze stress shadow interactions at the stage-to-stage scale observed during completion of two Upper Montney siltstone wells. Utilizing interpreted microseismic data and offset well pressure monitoring data recorded during continuous-pumping completions of the two wells, a fault and pore pressure constrained poroelastic stress and relaxation model is derived. This model is used to map local modification of the initial stress state along parallel Upper Montney laterals. Initial stress conditions and stress shadow influences on observed fracture propagation patterns in the second well at multiple points during the completion is then used to determine dynamic, reservoir specific stress state modification characteristics as a function of time. Microseismic data from the two wells showed preferential fracture growth toward a fault identified in the seismic volume and an existing production Well 1. Well 2 situated closest to the fault and the existing producer Well 1, showed a modal fracture growth bias to the southwest, towards Well 1. Well 3, situated furthest from the fault and existing producer exhibited a bimodal fracture propagation direction. The initial southwesterly propagation bias repeatedly alternated to the northeast, away from the low stress envelope caused by the fault and existing producer. Based on the initial conditions and the unique fracture propagation patterns in the two wells, lateral stress variation is mapped and modeled using poroelasticity. To better understand the short-term stress relaxation effects on fracture propagation and the phenomenon of repeated asymmetric growth on either side of Well 3 (NE-SW-NE-SW…), a viscoelastic model is used to quantify the impact of stress shadowing and various relaxation times on fracture propagation. These observations led to the conclusions that the initial stress state is locally modified during hydraulic fracturing operations and that the stress disturbance caused by the depletion in one compartment around the existing production well continues to affect the stress conditions over significant distances, even in hydraulically disconnected reservoir compartments. This in turn affects the stimulation patterns of recently completed wells.

Productivity of hydraulically stimulated unconventional wells depends greatly on the successful interconnection of the enhanced permeability and the natural fracture system. Such success is achived by proper understanding of the distribution of mechanical properties of the rock, presence of natural fractures, and regional stresses characterisitcs. With this understanding of the reservoirthe response of the rock to the stimulation can be quantified. Currrently, there are multiples approaches adopted by the industry to support such a process, making fracture designs more robust and reliable. However, theseworkflows often neglect the underlying physics of pressure wave propagation throughout the reservoir, crossing geological features such as faults, natural fractures, ash and karst layers among others. Pressure depletion caused by production of the first well in a section (parent well) generates continuous changes in stress magnitude and orientation. Simplistic geomechanical models ignore such effects and usually are built based on original conditions, resulting in overestimation of induced strain which will be reflected in oversized hydraulic fracture jobs that negatively affect not only the subsequent wells (child wells) but also the first well in section itself. Negative effects such as frac hits are usually irreversible, and proper estimation of the potential damage needs to be quantified and understood in order to put in place a mitigation plan. This work presents a workflow where changes in the pressure field are incorporated and taken into consideration during geomechanical modeling of induced strain using full continuum mechanics. As a result, hydraulic fracture designs are adjusted to the reservoir conditions at the time a new child well will be drilled and completed, thus reducing thepotential for negative effects such as frac hits. A fracture design for a planned child well to be drilled after two years of production of its parentis presented under two scenarios: first, ascenario ignoring the effect of pressure depletion, second, a scenario using the full continuum geomechanical solution to account for the effects of parent depletion. Results of the fracture design are migrated to dynamic simulation to estimate the effect on the resulting EUR.

The production from a hydraulically fractured unconventional well depends on the stimulated permeability and its interaction with the naturally fractured background permeability. Since the propagation of a hydraulic fracture is often asymmetric and depends on geomechanical factors, the ensuing pressure depletion and the EUR depends on this asymmetric behavior. An analytical asymmetric tri-linear model to approximate pressure depletion is presented. The model uses asymmetric frac design results as input and estimates the pressure depletion around a parent well. This new approach represents an acceptable alternative to full reservoir simulation when investigating frac hits problems. This asymmetric tri-linear model was combined with our poro-elastic geomechanical modeling simulator in order to capture the physics created by the depleted pressure sink zone. This physics combines the stimulation operations in the neighboring infill well and their interactions with the complex local and far scale geologic features such as natural fractures and faults. The pressure depletion determined at an Eagle Ford well using the asymmetric tri-linear model was similar to those found with a full reservoir simulator. Hydraulic fracture modeling of a child well located in the vicinity of a parent well with a pressure depleted zone highlighted the potential of developing a frac hit if geological features in the area were creating fluid and pressure conduits. A similar observation is made for a Wolfcamp well where a fault affected the nearby stage causing interference between potential stacked wells. The integration of the asymmetric tri-linear model and our geomechanical simulator presents the necessary completion modeling tool to quickly, yet accurately design hydraulic fracturing while preventing frac hits, especially now with the increasing of number of infill unconventional wells.

Modelling unconventional reservoirs requires a continuum multi-scale approach to represent the dominant physics occurring at each scale (Figure 1). In the most common far field studies (thousands of feet around the wellbore), geophysics used in conjunction with processes such as facies constrained extended seismic elastic inversion (Kiche et al., 2016) provide dynamic geomechanical properties throughout the entire reservoir volume – properties, which are critical to the optimal selection of landing zones and completions of unconventional wells. It is also in the far field that the combination of geomechanical properties with continuous natural fracture models (Jenkins et al., 2009) are used as input in a robust reservoir geomechanics workflow (Aimene and Ouenes, 2015) that is able to simulate the interaction between the regional stresses and the three major sources of stress gradients affecting hydraulic fracturing: variable geomechanical properties, geologic discontinuities, and pore pressure variability. The resultant locally varying differential stress distribution provides the initial reservoir stress conditions before fracking and the correct input for the estimation of strain during and after hydraulic fracturing, which should be validated with a predicted microseismicity (Aimene and Ouenes, 2015). This strain provides coupling between the far and mid-field studies and creates the unique opportunity to constrain the mid-field frac design (Paryani et al., 2016) and reduce the uncertainties of multiple frack design parameters by constraining lateral stress gradients and imposing the symmetric frac lengths that the earth will allow. The behaviour of the mid-field hydraulic fracturing is also affected by multiple near field effects such as type of completion (Peterson et al., 2017) and its effects on the near wellbore geomechanics. The near field effects could be estimated at any well using surface drilling data (Jacques et al., 2017) which could provide the necessary information required in the mid and far fields in the inverse design and validation process in situations where there is lack of data.

Abstract Recent natural and anthropogenic events, such as Hurricanes Katrina and Rita and the Deepwater Horizon oil spill, have identified significant gaps in our ability to predict risks associated with offshore hydrocarbon production as well as our capabilities to respond to deleterious events of varying scope, magnitude, and duration. As offshore hydrocarbon development in the Gulf of Mexico continues to push into new territory, there is a need to develop computational tools that enable the rapid prediction of outcomes associated with unexpected hydrocarbon release events from deepwater and ultra-deepwater systems in the Gulf of Mexico. To date, no comprehensive system-wide tool exists that can simulate the complexities of engineered-natural systems and provide the baseline data that is required to drive the simulations. To address this gap, we are developing the Gulf of Mexico Integrated Assessment Model (GOM IAM), the first coordinated platform that will allow for independent, rapid-response, and science based predictions providing the capabilities to assess risks and potential impacts associated with deep and ultra-deep water drilling in the Gulf of Mexico. This predictive model and its analyses allow for the assessment and quantification of risks and environmental impacts from deepwater and ultra-deepwater oil and gas drilling and production, as well as provide a robust tool and database that can provide crucial information necessary for the response and recovery following future loss of control events. Once the GOM IAM is developed, it can be utilize to:identify potential risks;identify technology gaps,improve our understanding of the degree of uncertainty relative to key systems and interactions associated with deep and ultra-deep water offshore hydrocarbon development to promote safer development and operations, and iv) run scenarios to serve as a baseline rapid response tool for any future oil spill events.