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Abstract This paper introduces a 3D hydraulic fracturing propagation model (3D-HFPM) for evaluating fracture extension, geometry, stress response, fracture spacing, and potential for refracturing. The model is illustrated with data of the Horn River shale of Canada. The model is developed using a combination of finite element method (FEM) and boundary element method (BEM) for evaluating fluid-flow, fracture deformation, and stress change in the reservoir. The model is calibrated using a limited amount of microseismic observations and recreate the fracture network when microseismic data are unavailable. An adapting meshing algorithm is incorporated to improve the capacity of the model to handle large and complex fracture networks such as the ones found in low permeability reservoirs. The continuity of fracture propagation and fluid leak-off during stimulation may be high enough to connect different production intervals and to create interference between stages, especially in wells with small path fracture spacing and multi-level completions. The comparison between the propagation model and microseismic data shows good agreement as the number of events increases as the fracture propagates into the reservoir. However, using only microseismic data to calculate the extension of the hydraulic fracture results in an overestimation of the fracture length. The model quantifies the altered stress zone, which is helpful to determine possible fracture reorientation and spacing. The evaluation of stress shadow and fracture reorientation reveals the advantages of refracturing using new over old perforations. The operation restores fracture conductivity and increases the fracture network as well as the drainage areas leading to an economic operation. The model improves the characterization of the Stimulated Reservoir Volume (SRV) in tight and shale reservoirs in those cases where microseismic data are scarce. Furthermore, the model is a viable tool for evaluating potential refracturing candidates.
Quirein, John Andrew (Halliburton Energy Services Group) | Kessler, Calvin W. (Halliburton Energy Services Group) | Zannoni, Stephen A. (Halliburton Co.) | Trela, James M. (Halliburton Energy Services Group) | Cornish, Bruce Edward (Halliburton Energy Services Group) | Brewer, Robert | Young, R. Paul | Walker, Cynthia E. Black (OXY) | Laney, John A. (Occidental Permian Ltd.) | Gordy, Darrell (Halliburton) | Pettitt, William (Applied Seismology Consultants Ltd.)
Abstract The results of a microseismic monitoring of a multi-stage re-fracturing treatment of a Permian Basin San Andres dolomite interval in an open-hole horizontal well will be presented in this paper. The treatment well has a horizontal well trajectory of approximately 3,000 feet within the reservoir section and had been extensively acid fractured during earlier production enhancement operations. The microseismic mapping objectives of the re-fracturing treatment for each of the stages were to characterize the azimuthal orientation of the fractures, the length of each wing, fracture height, and overall stimulation effectiveness. The study discusses mapping microseismic events in a challenging re-fracturing environment. The microseismic activities generated during a re-fracturing treatment may be very low in acoustic energy and detection may be problematic, compared to the acoustic energy released during initial hydraulic fracture propagation. In this study, few microseismic events were detected, and this data indicates that the previously propagated fractures created preferential paths for fluid flow thus reducing the propagation of a new fracture network. In fact, for the stage located the furthest from the monitor well, no microseismic events were detected. This was consistent with an Instrument Magnitude Analysis performed on the located microseismic events from the other stages that showed events further than 1,400 feet away from the monitor well were not detectable. A chemical packer was used for zonal isolation, and ball-activated sliding sleeves were used for selective injectivity for each stage along the horizontal well in the re-fracturing treatment. The operation of the sliding sleeves, for each stage and the ball drops, generated compressional and shear events which were detected by the geophone array in the monitor well. This confirmed that the instrumentation was able to detect events between the treatment well and monitor well in this job and that the microsesimic events induced during the re-stimulation treatment were at a much lower energy. The low-energy events that were located confirmed the ball-activated sleeve worked correctly and the induced fractures stayed in zone. However, the source locations detected did not delineate clear linear propagation of hydrofractures from the wellbore but described a complex fracture network. Introduction Reservoir microseismic monitoring provides insights into spatial and temporal variations in the stress field.1 Microseismic activity can be induced by stimulation, production, injection and regional tectonic processes. The microseismic mapping results for a 3,000-ft open-hole horizontal well trajectory with a stimulation treatment target of five fractures located 700 to 1000 ft apart are discussed in detail in the sections below. The target well trajectory is along a 75-ft San Andres dolomite interval possessing porosity in the range of 5–15%. The goals of the mapping were to characterize the azimuthal orientation of the fractures, the length of each wing, fracture height, and overall stimulation effectiveness. The characterization, conducted during Octocber 2006, was difficult since this portion of reservoir had been extensively acid fractured during earlier production enhancement operations, decreasing the number of microseismic events which could be located. Overview of the Permian Basin San Andres Dolomite West Welch Unit West Welch Unit is in one of four large waterflood units in the Midland Basin Welch Field in the northwestern portion of Dawson County, Texas.2 The Welch Field was discovered in the early 1940s and produces oil from a stratigraphic trap under a solution gas drive mechanism from the San Andreas Formation at approximately 4,800 ft. The field has been under waterflood for almost 40 years and a significant portion has been infill-drilled on 20-acre spacing.
This paper presents a case study of fracture interaction mitigation in a multistage horizontal stimulation of an offshore Black Sea well. A multi-faceted approach in applying lessons learned and pre-job geo-mechanical analysis of depletion-induced stress differential and its effects on fracture interactions will be discussed. Details of on-the-job, real-time bottom-hole pressure monitoring of nearby wells, with the effort of on-the-fly pumping schedule changes, will also be provided.
An analysis was conducted on past fracture interactions observed from multistage stimulation jobs in the area. Depletion, distances between producing wells, and a stress analysis was performed using fracture simulation software, and a consequent analysis of fracture geometry was applied. A bottom-hole gauge pressure profile assessment of nearby wells, including the pre-stimulation, shut-in, and post-stimulation period of the targeted well, was completed. A redesigned treatment was applied, considering a mitigation plan for potential on-the-fly changes during pumping. A holistic tracer analysis of production contribution between stages and wells was performed, with the goal of understanding possible crossflow of production fluids.
Past-fracture interaction events have been analyzed, and clear drivers for fracture hit communication were observed. Extreme depletion effects were a primary factor in enabling fracture communication. The preferential fracture growth was further enabled owing to the continuous production of nearby wells and no shut-in implementation. The 3D geo-mechanical model was built using pertinent data from the targeted and nearby wells. The model was further optimized using fracture geometry outputs, and constraints were input to limit the fracture growth and avoid communication. The outcome of the analysis showed a clear driving force behind the interactions was depletion. An on-the-job assessment of diagnostic tests yielded a heterogeneous behavior of the horizontal segment, further proving stress differentials along the lateral. An overall chemical tracer analysis of the targeted and nearby wells was completed using pre- and post-stimulation fluid samples. The results were crucial in understanding the stimulation approach and possible crossflow effects due to fracture communication. Additionally, using bottom-hole temperature readings, a rudimentary cool-down and heat-back analysis was performed to better understand possible fluid interactions with nearby wells and optimize fluid design.
Intra-stage fracture interference presents unique events and challenges that are typically managed on a case-by-case basis, and this work presents the critical analyses that are paramount to planning stimulation treatments in highly depleted segments and reservoirs with wells in close proximity.
Abstract This paper presents construction and validation of a reservoir model for the Niobrara and Codell Formations in Wattenberg Field of the Denver-Julesburg Basin. Characterization of Niobrara-Codell system is challenging because of the geologic complexity resulting from the presence of numerous faults. Because of extensive reservoir stimulation via multi-stage hydraulic fracturing, a dual-porosity model was adopted to represent the various reservoir complexities using data from geology, geophysics, petrophysics, well completion and production. After successful history matching two-and-half years of reservoir performance, the localized presence of high intensity macrofractures and resulting evolution of gas saturation was correlated with the time-lapse seismic and microseismic interpretations. The agreement between the evolved free gas saturation in the fracture system and the seismic anomalies and microseismic events pointed to the viability of the dual-porosity modeling as a tool for forecasting and future reservoir development, such as re-stimulation, infill drilling, and enhanced oil recovery strategies.
Abstract Recently two multilateral horizontal wells have been completed offshore using dedicated multistage hydraulic fracturing completions. The first well, located in the Central North Sea (referred to as ML-CNS), was stimulated using acid fracturing; while the second well, located in the Black Sea (referred to as ML-BKS), was stimulated using proppant fracturing. This paper presents the different drivers, challenges and lessons learned for each well while emphasizing the well construction and stimulation methodologies developed for the different reservoirs and field characteristics. The field development drivers for drilling and completing these offshore hydraulic fractured multilateral wells, a first of their kind globally, was different for each case. The objective of the first project, initially considered uneconomic, was to engineer a technical solution for completion and production of two separate reservoirs with only one subsea well. The second project was seeking to optimize infill drilling from the last available slot on the offshore platform to maximize reservoir contact and production in the same reservoir. ML-CNS was a TAML Level 2 completion with a 14-stage, 5 ½" multistage completion run in each lateral and set-up for sequential acid fracturing. Operationally, the first lateral was drilled and stimulated, followed by the drilling and stimulation of the second lateral, using the drilling whipstock to navigate through the multilateral junction. ML-BKS was a TAML Level 3 completion that had a 6-stage, 4 ½" multistage completion installed in each lateral, which were proppant fractured following a sequence designed to minimize the jack-up rig time required. Both legs were drilled and completed prior to starting the stimulation, access to either lateral was achieved with the existing workover unit on the platform by manipulating a custom designed BHA. The lessons learned from the first project executed in the North Sea were able to be transferred and applied to the second project in the Black Sea to allow for a more efficient and confident completion solution. Led by varying economical and regional constraints, the key factor for both wells centered on delivering operationally simple and reliable multilateral completion designs to economically meet the field development strategy in place. To the knowledge of the authors and following subsequent literature research, both wells are a worldwide first for an offshore multilateral well completed with multistage acid fracturing and multistage proppant fracturing, and together they represent a new trend in cost-effective offshore field development through well stimulation. The successful case studies for both wells with the combined analysis of the benefits, challenges, and lessons learned will provide a guide and instill confidence with operators who find this approach beneficial with a view to applying it in other assets.