Ajisafe, Foluke (Schlumberger) | Thachaparambil, Manoj (Schlumberger) | Lee, Donald (Schlumberger) | Flack, Ben (Schlumberger) | Hemsley, Kim (Schlumberger) | Ejofodomi, Efe (Schlumberger) | Taylor, Christopher (Schlumberger)
The objective of this study is to prove the concept of using a seismically derived discrete fracture network (DFN) calibrated with borehole measurements, for complex hydraulic fracture modeling. This study was successfully applied on a two-well horizontal pad in the Avalon shale located in the Delaware basin, New Mexico.
The interaction of propagating hydraulic fractures with natural fractures plays a crucial role in defining the complexity and extent of the hydraulic fracture geometry. In a multi-well pad and infill-well scenarios, a good understanding of the effective drainage area of the hydraulic fracture created is essential for optimum well spacing to reduce interference between wells. In multi-stacked laterals, an understanding of the fracture height is necessary for placing the next well to avoid hydraulic fracture interference vertically and to avoid water wet zones. A DFN model built from borehole image logs is limited in its ability to account for the lateral variability of the natural fracture network properties away from the wellbore; these variations have a significant impact on the created hydraulic fracture geometry, and thereby drainage, away from the wellbore.
In this study, the DFN model was created from depth-converted 3D narrow azimuth seismic data. The seismic discontinuity plane (SDP) extraction and fracture characterization method was used to extract the seismic-scale fractures out of the best matching seismic attribute cube. Using orientation, P32 density (fracture area/unit volume), and fracture length distribution per individual seismic-scale fracture sets, a corresponding subseismic population of discrete fractures was stochastically modeled. Then the extracted seismic-scale fractures and the modeled subseismic fractures were combined to form a comprehensive multi-scale DFN model. The result was then incorporated into a state-of-the-art unconventional fracture model (UFM) that models the explicit interaction of the hydraulic fractures with natural fractures, to determine a good representation of the created complex fracture geometry observed from microseismic data.
Available microseismic data was used to validate the DFN and UFM models. The DFN model showed natural fracture intensity variation along and away from the wellbore and for the most part agreed with the footprint of the microseismic events. This variation was also captured by the UFM simulator, while modeling the hydraulic fracture geometry with the observed treating pressure profiles.
The workflow presented in this paper shows the successful application of seismic data in creating discrete fracture networks required to model hydraulic fractures in unconventional reservoirs. This workflow is critical for understanding the variation of the natural fractures along a planned well, within a pad, or at a basin scale in a predictive manner. Prior knowledge of the in-situ 3D natural fracture network, and its spatial variability and anisotropic stress profile is key to optimizing the overall completion and development strategy of an unconventional resource in a cost-effective way.
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.
This paper briefly describes a process developed to reduce drilling risks and well costs and gives details on its application to three deviated development wells in Camisea, Peru. Previous offset vertical and deviated wells in this area encountered wellbore instability, drilling fluid loss, and reactive shales. In some cases these events made it necessary to drill multiple sidetrack wells.
The process provided specific advantages while drilling technically difficult trajectories. Integral to the process was development of a mechanical earth model (MEM) for prediction of drilling events and down hole drilling risk management. The model, created using data from multiple disciplines (seismic, drilling, geology, wireline logs, core testing), enabled the drilling team to understand potential drilling hazards and quickly act to mitigate risks, as well as to make rapid informed decisions while drilling. Examples demonstrate how the process compared forward predictions with actual results and how the model was updated during drilling.
The first well reached total depth (TD) 5 days ahead of schedule even though the trajectory was in a difficult stress azimuth and several nondrilling problems occurred. Teamwork and communication among the drilling location and four offsite offices played a critical role in the decision process. Predrill predictions matched post-drill information in most cases. Lessons learned from the first well were applied to subsequent well plans.
This process can be applied to any exploratory or development well, but high-risk, high-cost wells receive maximum benefit. Although wellbore instability resulting from tectonic stress was the main risk in this field, the process is equally valid for drilling issues such as overpressured regimes, underbalanced drilling or extended-reach wellbores.
Many of today's well construction projects are technically and economically challenging. Examples include deepwater exploration wells in the Gulf of Mexico, offshore field development projects such as Hibernia, Newfoundland, Canada and onshore field development projects in tectonically active regions such as the Cusiana field in Colombia. Minimizing non-productive time associated with wellbore instability and unexpected pore pressure regimes reduces the risk of dangerous accidents and is required to complete the well on time and within budget. Minimizing non-productive time is a complex task that requires thorough pre-spud planning to identify drilling risks and geological hazards and to develop contingency plans for handling those risks. Building a mechanical earth model during the well planning phase and revising it in real time has proven to be extremely valuable in delivering complex wells safely while minimizing unplanned well construction costs. Monitoring and revising the model while drilling requires geomechanics expertise, teamwork, data management and excellent communications among service companies and their client.
This paper defines a mechanical earth model, explains why it is important, how it is developed and how it is applied to well construction and field development. We will discuss sources of information and the multi-disciplinary team approach required to: generate, revise and maintain an earth model. Three examples of the application of the earth model concept are discussed.
More of today's well construction and field development projects are both technically and economically challenging. Understanding the geomechanics of well construction is becoming increasing important in order to drill technically and economically challenging wells on budget.
Wells with hostile pore pressure and fracture gradient profiles require a good pre-drill pore pressure and fracture gradient prediction in order to design a suitable casing program. A casing program designed on a profile significantly less hostile than that encountered may compromise the attainable TD of the well. The cost of materials and rig time spent running extra casing significantly adds to the cost of the well. The risk of taking kicks which can be both costly and dangerous can also be reduced by a more rigorous pre-drill pore pressure prediction coupled with real-time pore pressure analysis from LWD measurements. In the deepwater Gulf of Mexico there are examples of wells which require a good mechanical earth model (MEM) in order to be drilled at all.
Despite decades of industry attention, wellbore instability is responsible for many costly stuck pipe incidents. Stuck pipe is responsible for lost BHAs and considerable NPT spent freeing pipe, performing additional wiper trips and hole cleaning. In cases where wellbore stability problems are severe, the economics of developing a field can become challenging, for example the Cusiana field in Colombia, S.A. Other fields where lesser wellbore stability problems may still challenge the field economics are found where the cost of drilling is very high, e.g. the Hibernia field offshore Canada and or fields in the North Sea.