Morales, Adrian (Chesapeake Energy Corp.) | Holman, Robert (Chesapeake Energy Corp.) | Nugent, Drew (Chesapeake Energy Corp.) | Wang, Jingjing (Chesapeake Energy Corp.) | Reece, Zach (Chesapeake Energy Corp.) | Madubuike, Chinomso (Chesapeake Energy Corp.) | Flores, Santiago (Chesapeake Energy Corp.) | Berndt, Tyson (Chesapeake Energy Corp.) | Nowaczewski, Vincent (Chesapeake Energy Corp.) | Cook, Stephanie (Chesapeake Energy Corp.) | Trumbo, Amanda (Chesapeake Energy Corp.) | Keng, Rachel (Chesapeake Energy Corp.) | Vallejo, Julieta (Chesapeake Energy Corp.) | Richard, Rex (Chesapeake Energy Corp.)
An integrated project can take many forms depending on available data. As simple as a horizontally isotropic model with estimated hydraulic fracture geometries used for simple approximations, to a large scale seismic to simulation workflow. Presented is a large-scale workflow designed to take into consideration a vast source of data.
In this study, the team investigates a development area in the Eagle Ford rich in data acquisition. We develop a robust workflow, taking into account field data acquisition (seismic, 4D seismic and chemical tracers), laboratory (geomechanical, geochemistry and PVT) measurements and correlations, petrophysical measurements (characterization, facies, electrical borehole image), real time field surveillance (microseismic, MTI, fracture hit prevention and mitigation program through pressure monitoring) and finally integrating all the components of a complex large scale project into a common simulation platform (seismic, geomodelling, hydraulic fracturing and reservoir simulation) which is used to run sensitivities.
The workflow developed and applied for this project can be scaled for projects of any size depending on the data available. After integrating data from various disciplines, the following primary drivers and reservoir understanding can be concluded. At a given oil price, optimum well spacing for a given completion strategy can be developed to maximize rate of return of the project. Many operators function in isolated teams with a genuine effort for collaboration, however genuine effort is not enough for a successful integrated modelling project, a dedicated multidisciplinary team is required.
We present what is to our knowledge, one of the most complete data sets used for an integrated modelling project to be presented to the public. The specific lessons from the project are applied to future Eagle Ford projects, while the overall workflow developed can be tailored and applied to any future field developments.
Gonzalez, Daniel (Chesapeake Energy) | Holman, Robert (Chesapeake Energy) | Richard, Rex (Chesapeake Energy) | Xue, Han (Schlumberger) | Morales, Adrian (Schlumberger) | Kwok, Chun Ka (Schlumberger) | Judd, Tobias (Schlumberger)
The stress state at infill wells changes as a function of production from the existing producer. Understanding spatial and temporal in situ stress changes surrounding drilled uncompleted (DUC) wells or infill wells has become increasingly important as the industry works through its inventory of DUC wells and redesigns infill wells with an engineering approach.
Optimizing infill/DUC well completion designs requires an estimation of the altered in situ stress state. This study presents the concept of a "production shadow" as the stress change in four-dimensional space, affecting well performance and optimal well configurations for pad development. The production shadow accounts for the compound effects from both hydraulic fracture mechanical opening and stress-state alteration from depletion.
This paper details an Eagle Ford case study integrating production shadow effects into the parent and infill well hydraulic fracture modeling as well as "frac hit" analysis. The production shadow influences the degree of fracture complexity developed by the infill/DUC well stimulation. Understanding and accounting for the production shadow are critical in engineering to establish and preserve an optimal connection of the induced stimulated fracture network to the wellbore.
Carr, Timothy R. (West Virginia University) | Wilson, Thomas (West Virginia University) | Kavousi, Payam (West Virginia University) | Amini, Shohreh (West Virginia University) | Sharma, Shikha (West Virginia University) | Hewitt, Jay (Northeast Natural Energy LLC) | Costello, Ian (Northeast Natural Energy LLC) | Carney, BJ (Northeast Natural Energy LLC) | Jordon, Emily (Northeast Natural Energy LLC) | Yates, Malcolm (Schlumberger) | MacPhail, Keith (Schlumberger) | Uschner, Natalie (Schlumberger) | Thomas, Mandy (Schlumberger) | Akin, Josiah (Schlumberger) | Magbagbeola, Oluwaseun (Schlumberger) | Morales, Adrian (Schlumberger) | Johansen, Asbjoern (Schlumberger) | Hogarth, Leah (Schlumberger) | Anifowoshe, Olatunbosun (Schlumberger) | Naseem, Kashif (Schlumberger) | Hammack, Richard (National Energy Technology Laboratory) | Kumar, Abhash (National Energy Technology Laboratory) | Zorn, Erich V. (National Energy Technology Laboratory) | Vagnetti, Robert (National Energy Technology Laboratory) | Crandall, Dustin (National Energy Technology Laboratory)
The Marcellus Shale Energy and Environment Laboratory (MSEEL) involves a multidisciplinary and multi-institutional team undertaking integrated geoscience, engineering and environmental research in cooperation with the operator, Northeast Natural Energy LLC., numerous industrial partners and the National Energy Technology Laboratory of the US Department of Energy. The objective of MSEEL is to provide a long-term collaborative field site to develop and validate new knowledge and technology that can improve recovery efficiency while minimizing environmental implications of unconventional resource development
MSEEL consists of two legacy horizontal production wells completed in 2011, two new logged and instrumented horizontal production wells completed in 2015, a cored vertical pilot bore-hole, a microseismic observation well, and surface geophysical and environmental monitoring stations (Figure 1). Production from the new horizontal wells began in December 2015 and monitoring continues. Production logging to determine production efficiency was undertaken in early 2017 and is under evaluation. MSEEL has generated a large and diverse (multiple terabyte) dataset that provides significant insight into drilling operations, Marcellus Shale geology and fracture stimulation operations.
During drilling detailed geomechanical and image logs of the lateral and geochemical analysis of the whole core and sidewall cores were obtained. As part of the core analysis, kerogen was extracted from the different zones and analyzed to understand hydrocarbon generative potential, and interaction of the organic and inorganic matrix components with the fracture stimulation fluids (Agrawal et al., 2016; Agrawal et al., 2017; Agrawal and Sharma, 2017; Sharma et al., in press). Core and log data were coupled with microseismic and slow-slip seismic monitoring, and distributed temperature sensing (DTS) and distributed acoustic sensing (DAS) fiber-optic monitoring during completion. Subsequent production logging and continued DTS monitoring show the influence and interaction in the Marcellus Shale of both the present stress regime oriented northeast-southwest and the numerous preexisting healed and calcite cemented fractures oriented approximately east-west. The analysis of the comprehensive cluster-by-cluster completion data derived from surface and subsurface from the MSEEL project has contributed to an improved understanding of the effect of stage spacing and cluster density practices that could be used to significantly improve stimulation effectiveness and optimize recovery efficiency in the Marcellus and other unconventional reservoirs.
In the Permian basin, unconventional reservoirs have been the main target of horizontal well drilling since the early 2000s. Over the years, completion and stimulation design in horizontal wells has evolved from conservative to radical designs. It has also progressed from exploration mode to full development, and from single-well pads to multi-well pads and stacked laterals. In field development mode, infill drilling between pre-existing wells that have been on production for some time is typically done. Production interference has been observed to occur and known to have negative impact on pre-existing (parent) wells. The parent well would cause reservoir depletion resulting in localized “pressure sinks” that can cause the infill (child) well’s hydraulic fractures to grow towards the pressure sink and damage the parent well. In addition, the production potential of the child well is likely to decrease because of the pressure sinks (depleted area). The main purpose of this paper is to understand the impact of different well spacing configurations on well interference and production performance in unconventional reservoirs. This paper is an extension of a previous work presented by Ajisafe et al. (2016) on the use of discrete fracture network (DFN) from seismic data for complex fracturing modeling.
A multi-disciplinary integrated workflow was applied in a multi-well pad, with an extensive dataset consisting of seismic, high-tier vertical and horizontal logs and microseismic data. The multi-well pad consists of two wells, a parent well that has been completed and put on production for a year, and a new (child) well to be completed on the same pad. Two different well spacings were investigated, at 660 feet and 1,320 feet to understand the negative impact of interference on the parent well production, as well as the performance of the child well due to reservoir pressure depletion of the parent well. To mitigate/avoid the negative impact of production interference on the parent well and to improve performance of the child well, the child well was landed deeper in the Avalon shale.
The DFN model and geomechanical properties were key inputs into understanding the complex fracture geometry constrained with microseismic data for the parent well. Seismic data provided an improved DFN model along and particularly away from the wellbore. The different models are discussed in detail in Ajisafe et al. (2016). The reservoir pressure depletion pattern and complex fracture geometry were then used as key input into a geomechanics simulator for an updated in-situ stress state at 1 year, which was then used for complex fracture modeling of the child well. The effect of a year of production-induced depletion on the parent well shows a change in the reservoir pressure, horizontal stress magnitude and maximum horizontal stress azimuth. Reservoir simulation was done to quantify production performance of both the parent and child wells at the different spacing configuration.
Wilson, Thomas (West Virginia University) | Carr, Timothy (West Virginia University) | Carney, B. J. (Northeast Natural Energy, LLC) | Hewitt, Jay (Northeast Natural Energy, LLC) | Costello, Ian (Northeast Natural Energy, LLC) | Jordon, Emily (Northeast Natural Energy, LLC) | MacPhail, Keith (Schlumberger) | Uschner, Natalie (Schlumberger) | Thomas, Miranda (Schlumberger) | Akin, Si (Schlumberger) | Magbagbeola, Oluwaseun (Schlumberger) | Morales, Adrian (Schlumberger) | Johansen, Asbjoern (Schlumberger) | Hogarth, Leah (Schlumberger) | Naseem, Kashif (Schlumberger)
In this study, we take a preliminary look at microseismic data collected along the length of two Marcellus shale horizontal wells (the 3H and 5H) drilled by Northeast Natural Energy LLC (NNE) in Morgantown, West Virginia. Detailed log data are also available along the length of one of the laterals (the 3H) that provide a wealth of information concerning geomechanical properties, fracture trend and intensity. Logging, processing and interpretation of image logs were provided by Schlumberger. Preliminary interpretation of the microseismic cluster trends reveals orientations on average of about N59°E. Image logs in the vertical pilot well reveal similar average open fracture trend of ~N58°E. The orientation of SHmax estimated from induced fractures observed in the vertical pilot well is ~N57°E, while that from breakouts is about N64°E. The majority of the induced fractures are observed in the Marcellus, while the breakouts are largely observed about 2000 feet above the Marcellus. Image logs collected along approximately 7400’ of lateral provide additional insights into the fracture network within the Marcellus target zone. Over 1600 fractures were interpreted by the Schlumberger analyst. The distribution was unimodal with average fracture trend of N78°E. Along the length of the lateral, average trends of fracture clusters varied from about N64°E to N110°E.
Shmin in the area is approximately 6500 psi with horizontal stress anisotropy varied between 100 to 400psi in agreement with the acoustic scanning platform data. The vertical stress (Sv) is approximately 8800psi. Asymmetry in the microseismicity associated with the well is interpreted to be associated with a drop in Shmin toward parallel well (the 5H well) located northeast. Hydraulic fracture stimulation of the local fracture network along the 3H well required introduction of a negative horizontal stress gradient in Shmin northeast towards the 5H well that was treated a few days earlier to produce observed asymmetry in the microseismic distribution. Variation in stage-to-stage shut-in pressures did not suggest significant stress shadowing or increase in Shmin stage-to-stage toward the heel (see Nagel et al., 2013a and b) or between wells.
In this initial look at the microseismic data, model fracture stimulation patterns are compared to microseismicity from a single stage along the 3H lateral. Initial uncalibrated MEM and stochastic based DFN models suggest that the observed microseismic event trends require interaction of the local N83°E fracture set observed in the image log along the wellbore in this area with a more regional ~N59°E fracture set. Although the inferred N59°E set is not prominent in the image log interpretations in the target landing zone, it is a prominent open fracture set in the vertical pilot well and its presence appears to control microseismic event trends and natural fracture stimulation at the site. This set appears to provide tensile conduits that channel fluids into and facilitate microseismically audible rupture of east-northeast fractures that are observed in the vicinity of the stage and that fail through shear.
Presentation Date: Tuesday, October 18, 2016
Start Time: 1:00:00 PM
Location: Lobby D/C
Presentation Type: POSTER
To investigate interwell interference in shale plays, a state-of-the-art modeling workflow was applied to a synthetic case on the basis of known Eagle Ford shale geophysics and completion/development practices. A multidisciplinary approach was successfully rationalized and implemented to capture 3D formation properties, hydraulic-fracture propagation and interaction with a discrete-fracture network (DFN), reservoir production/depletion, and evolution of magnitude and azimuth of in-situ stresses by use of a 3D finite-element model (FEM).
The integrated workflow begins with a geocellular model constructed by use of 3D seismic data, publicly available stratigraphic correlations from offset-vertical-pilot wells, and openhole-well-log data. The 3D seismic data were also used to characterize the spatial variability of natural-fracture intensity and orientation to build the DFN model. A recently developed complex fracture model was used to simulate the hydraulic-fracture network created with typical Eagle Ford pumping schedules. The initial production/depletion of the primary well was simulated by use of a state-of-the-art unstructured grid reservoir simulator and known Eagle Ford shale pressure/volume/temperature (PVT) data, relative permeability curves, and pressure-dependent fracture conductivity. The simulated 3D reservoir pressure field was then imported into a geomechanical FEM to determine the spatial/temporal evolution of magnitude and azimuth of the in-situ stresses.
Importing the simulated pressure field into the geomechanical model proved to be a critical step that revealed a significant coupling between the simulated depletion caused by the primary well and the morphology of the simulated fractures within the adjacent infill well. The modeling workflow can be used to assess the effect of interwell interferences that may occur in a shale field development, such as fracture hits on adjacent wells, sudden productivity losses, and dramatic pressure/rate declines. The workflow addresses the complex challenges in field-scale development of shale prospects, including infilling and refracturing programs.
The fundamental importance of this work is the ability to model pressure depletion and associated stress properties with respect to time (time between production of the primary well and fracturing of the infill well). The complex interaction between stress reduction, stress anisotropy, and stress reorientation with the DFN will determine whether newly created fractures propagate toward the parent well or deflect away. The technique should be implemented in general development strategies, including the optimization of infilling and refracturing programs, child well lateral spacing, and control of fracture propagation to minimize undesired fracture hits or other interferences.
Gakhar, Kush (Schlumberger) | Shan, Dan (Schlumberger) | Rodionov, Yuri (Schlumberger) | Malpani, Raj (Schlumberger) | Ejofodomi, E. A. (Schlumberger) | Xu, Jian (Schlumberger) | Fisher, Kevin (Schlumberger) | Fischer, Karsten (Schlumberger) | Morales, Adrian (Schlumberger) | Pope, Timothy L. (Schlumberger)
As the inventory of single well pads in North American unconventional plays builds up, some critical questions that need to be answered are: What is the optimum spacing for an in-fill well? Where new multiple in-fill wells should be drilled? How should the in-fill wells be fractured? Challenging economics associated with unconventional reservoir development demands for an engineered approach for such multi-well pad development unlike traditional trial and error approach that has been widely adopted by Oil & Gas industry. The engineered approach for evaluating the problem relies on expanded seismic-to-stimulation workflow (Cipolla et al. 2011). The workflow involves complex fracture modeling that honors impact of natural fractures on hydraulic fracture geometry, dynamic reservoir simulation and geomechanical finite element modeling (FEM) to compute spatial and temporal changes in in-situ stresses due to production from parent well, which chronologically is the first well drilled on a pad.
The new integrated workflow used in this evaluation involves the following key steps: A 3D structural geologic model based on a vertical openhole pilot well log in Eagle Ford shale reservoir is built. A discrete fracture network (DFN) representative of the area of interest in the reservoir is created from 3D seismic data interpretation. The parent well stimulation treatment is then modeled using ‘Unconventional Fracture Model', (UFM) (Kresse et al. 2011). An unstructured production grid (Malpani et al. 2015; Ejofodomi et al. 2015) with finer cell size along the complex fractures is then created. Hydrocarbon production from the parent well is modeled using dynamic reservoir simulation, and a geomechanical FEM based simulator is then used to calculate spatial and temporal changes in in-situ stress magnitude and orientation (Morales et al. 2016). The modeling workflow is used to evaluate scenarios for multi-well pad optimization in Eagle Ford shale play. In this paper terms “in-fill” well and “child” well have been used interchangeably.
This study evaluates two critical cases. Case 1 focuses on identifying optimum well spacing for an in-fill well that is to be drilled next to the parent well with a production history spanning a little over a year. Child wells drilled 400 ft., 600ft., and 800 ft. away from the parent well are simulated under similar conditions to identify optimum well spacing. Case 2 focuses on four multi-well pad development scenarios in which multiple wells are drilled in configuration A and B at different stages of field development and in areas with minimum and severe impact of kaolinite and smectite rich altered ash beds (Calvin et al. 2015) on vertical conductivity of hydraulic fractures. In multi-well configuration A, two child wells are drilled 600 ft. and 1200 ft. away from the parent well in B1-B2 (Donovan et al. 2010) unit of the lower Eagle Ford. Whereas, in configuration B wells are stacked in different lithostratigraphic sections of Eagle Ford. One of the child wells that is 600 ft. away from the parent well is landed in shallower section, B3-B5 and the second child well is landed 1,200 away in B1-B2, the same section of the Eagle Ford where the parent well is landed. It is important to note that results from this study are applicable to sections of Eagle Ford, where B unit is less than 150 ft. thick. For regions of Eagle Ford shale play, where B Units can be as thick as 300 ft., a similar comprehensive analysis is required to derive an effective multi-well pad development strategy.
Morales, Adrian (Schlumberger) | Zhang, Ke (Stanford University) | Gakhar, Kush (Schlumberger) | Marongiu Porcu, Matteo (Schlumberger) | Lee, Don (Schlumberger) | Shan, Dan (Schlumberger) | Malpani, Raj (Schlumberger) | Pope, Tim (Schlumberger) | Sobernheim, David (Schlumberger) | Acock, Andrew (Schlumberger)
This paper continues the investigation of interwell fracturing interference for an infill drilling scenario synthetic case based on Eagle Ford available public data and explores pressure and stress-sink mitigation strategies applied to the simulation cases developed in the previous publication (SPE 174902). Emphasis is given to refracturing scenarios, given the intrinsic restimulation value for depleted parent wells and the strategic importance due to the current low oil prices.
The stress and pressure depletion methodology is expanded in this paper, adding a refracturing scenario before the infill child well is stimulated. Changes in stress magnitudes and azimuths caused by new and reactivated fractures are calculated using a finite element model (FEM). After refracturing the parent well, modeling shows that stress deflection and repressurization of the originally depleted production zone will reduce subsequent fracture hits from infill wells.
The first mechanism to reduce fracture hits is the stress realignment, which promotes transverse fracture propagation from the infill well away from the parent well. The second fracture-hit-reduction mechanism is repressurization of depleted zones to hinder fracture propagation in lower-pressure zones. Prevention of fracture hits by active deflection results in an increased stimulated reservoir volume (SRV) for both the parent and child wells. Overall pad level and individual wellbore cumulative production experience a significant increase due to increased SRV. With proper reservoir and geomechanical data, this approach can be applied in a predictive manner to decrease fracture-hit risk and improve overall recovery.
This workflow represents the first comprehensive multidisciplinary approach to coupling geomechanical, complex hydraulic fracture models, and multiwell production simulation models aimed towards understanding fracture-hit reduction using refracturing. The workflow presented can be applied to study and design an optimum refracturing job to prevent potentially catastrophic fracture hits during refracturing operations.
Acid fracturing is the most recognized and successful reservoir stimulation technique for conventional carbonate formations. Resulting fracture conductivity is the key parameter that controls final well productivity, while the competing diffusion and reaction phenomena control the vital acid coverage along the full areal extension of the fracture. However, not all reservoirs lend themselves to the same fracture geometry and conductivity, and this is where the Unified Fracture Design (UFD) approach is irreplaceable. Classic fracture design optimization with the UFD approach involves the maximization of well productivity. For any mass of proppant to be injected as part of the treatment, the algorithm determines the unique fracture length and width (with height as a parasitic variable) that will provide the maximum productivity index. In this paper we recast the UFD approach for specific acid fracturing applications, where the maximum productivity index is now determined as a function of the optimum fracture geometry determined for any volume of injected acid. The optimum fracture width profile is then obtained by solving the convectiondiffusion equation for acid propagation, and subsequently used to study the required acid coverage through the fracture as a function of such optimum fracture width profile. Acid reaction retardation plays a crucial role in ensuring proper acid coverage throughout the optimum fracture length, and this paper focuses on the two major reaction retardation fluid systems: Acid-Internal Emulsions (AIE) and gelled acids. The workflow presented in this paper provides the basis for designing optimum acid fracturing treatments as a function of the volume of acid injected, the acid injection rate and the selected acid retardation method.
To investigate interwell interference in shale plays, a state-of-the-art modeling workflow was applied to a synthetic case based on known Eagle Ford shale geophysics and completion/development practices. A multidisciplinary approach was successfully rationalized and implemented to capture 3D formation properties, hydraulic fracture propagation and interaction with a discrete fracture network (DFN), reservoir production/depletion, and evolution of magnitude and azimuth of in-situ stresses using a 3D finite-element model.
The integrated workflow begins with a geocellular model constructed using 3D seismic data, publicly available stratigraphic correlations from offset vertical pilot wells, and openhole well log data. The 3D seismic data were also used to characterize the spatial variability of natural fracture intensity and orientation to build the DFN model. A recently developed complex fracture model was used to simulate the hydraulic fracture network created with typical Eagle Ford pumping schedules. The initial production/depletion of the primary well was simulated using a state-of-the-art unstructured-grid reservoir simulator and known Eagle Ford shale pressure/volume/temperature (PVT) data, relative permeability curves, and pressure-dependent fracture conductivity. The simulated 3D reservoir pressure field was then imported into a geomechanical finite-element model to determine the spatial/temporal evolution of magnitude and azimuth of the in-situ stresses.
Importing the simulated pressure field into the geomechanical model proved to be a critical step that revealed a significant coupling between the simulated depletion caused by the primary well and the morphology of the simulated fractures within the adjacent infill well. The modeling workflow can be used to assess the effect of interwell interferences that may occur in a shale field development, such as fracture hits on adjacent wells, sudden productivity losses, and drastic pressure/rate declines. The workflow addresses the complex challenges in field-scale development of shale prospects, including infilling and refracturing programs.
The fundamental importance of this work is the ability to model pressure depletion and associated stress properties with respect to time (time between production of the primary well and fracturing of the infill well). The complex interaction between stress reduction, stress anisotropy, and stress reorientation with the DFN will determine if newly created fractures propagate toward the parent well or deflect away. The technique should be implemented in general development strategies, including the optimization of infilling and refracturing programs, child well lateral spacing, and control of fracture propagation to minimize undesired fracture hits or other interferences.