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Collaborating Authors
Results
Assessing Stimulation of Complex Natural Fractures as Characterized Using Microseismicity: An Argument the Inclusion of Sub-Horizontal Fractures in Reservoir Models
Urbancic, Ted (Engineering Seismology Group) | Baig, Adam (Engineering Seismology Group) | Goldstein, Shoshana (Engineering Seismology Group)
Abstract The inclusion of fracture networks in reservoir models is generally based on the concept of failure associated with sub-vertical fractures. In general, it is surmized that fractures can grow irregularly in a stress field that is perturbed by a hydraulic fracture injection. It has also been considered that structural weaknesses in the rock such as pre-existing fractures and naturally occurring laminations commonly found in shale-gas reservoirs can be conduits for fracturing during stimulation and active pathways for fluid flow. We postulate that local stress perturbations through stress transfer allows for fractures to propagate and initiate failure along pre-existing fracture sets, which include sub-vertical and sub-horizontal fractures. Additionally, the degree of fracture interconnectivity and the type of fracturing will play a role in whether effective proppant transport is achieved. Through moment tensor inversion of microseismic events related to stimulation in the Horn River Basin utilizing well-conditioned geophone arrays, we have been able to define a three dimensional discrete fracture network consisting of sub-horizontal and sub-vertical fractures. Geologic data from the site provided corroborative evidence to the validity of the observed discrete fracture network, the presence of sub-horizontal fractures and fracture orientations in-line with current regional stress field. The fracture intensity and complexity appeared to be directly related to the degree of interaction between the sub-horizontal and sub-vertical fractures. Regions dominated by sub-horizontal fractures were also regions exhibiting poor fracture intensity and complexity. Based on these observations and moment tensor derived failure modes (opening component of failure), we were able to identify regions of enhanced fluid flow, further identifying regions of effective fluid transport. Regions with poor connectivity and dominance of sub-horizontal fractures also were identified as regions of poor fluid flow; these then become regions for potential re-stimulation. Based on these analyses, it can be suggested that sub-horizontal fractures can play an important role in the overall fracture development.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.48)
Field Development Study: Channel Fracturing Increases Gas Production and Improves Polymer Recovery in Burgos Basin, Mexico North
Valenzuela, A.. (PEMEX) | Guzmán, J.. (PEMEX) | Chávez, S.. (PEMEX) | Mondragón, G. García (PEMEX) | Gutiérrez, L.. (Schlumberger) | Exler, V.. (PEMEX) | Ramírez, C.. (Schlumberger) | Parra, P.. (Schlumberger) | Peña, A.. (Schlumberger)
Abstract The channel fracturing technique combines fracture modeling, materials and pumping methods to generate a network of highly conductive channels within the proppant pack. These channels aim at expediting the delivery of hydrocarbons from the reservoir to the wellbore (Gillard et al., 2010). This paper provides a comprehensive summary of the implementation of this novel technique in the Burgos basin, Mexico North. The Eocene Yegua formation in the Palmito field near Reynosa, Mexico was selected for this study. This formation comprises sandstone layers with average permeability of 0.5 mD and Young’s modulus in the order of 2.5 Mpsi. Key historical issues for the stimulation of this formation using conventional fracturing materials are limited polymer recovery and the consequential fracture conductivity impairment. Use of resin-coated proppants has also been implemented to prevent proppant flowback from these operations. Gas production, treating pressure and polymer recovery data from a twelve-well campaign in the Palmito field (six wells treated via channel fracturing, six offset wells treated conventionally and aiming for similar fracture geometry) are summarized in the manuscript. Results indicate that the implementation of the channel fracturing technique improved fluid and polymer recovery, thus leading to increases in initial gas production by 32% and 6-month cumulative gas production by 19%. Such improvements in production were obtained with 50% less proppant per stage and smaller proppant particles. These observations are consistent with the hypothesis that the channel fracturing technique promotes the decoupling of fracture conductivity from proppant pack permeability. Positive features that were also observed during this campaign such as absence of proppant flowback issues without the use of resin-coated sand and non-occurrence of near-wellbore screen-outs are also reported and discussed. The study concluded that the channel fracturing technique is a viable alternative to conventional fracturing methods for the stimulation of wells in the Burgos basin.
- North America > Mexico > Tamaulipas (1.00)
- North America > Mexico > Nuevo León (1.00)
- North America > Mexico > Coahuila (0.94)
- North America > United States > Texas (0.69)
- Overview (0.86)
- Research Report > New Finding (0.66)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.51)
Abstract Hydraulic fracturing is a stimulation technique essential for economical development of tight gas and shale gas reservoirs. Analysis of the performance of fracturing jobs and optimization of the treatment design requires modeling which accounts for all important features of the process and ideally covers both the treatment and post-stimulation production of the well. It is now well established that the productivity of the wells is due not only to the classical tensile single plane fracture (SPF), but to the development of an enhanced permeability region (stimulated reservoir volume or SRV) around it due to shear fracturing and/or stimulation of existing dual porosity. The shape and size of the SRV depends not only on the injection process but also on the geomechanics of the reservoir. Current techniques are not able to predict its dependence on frac job parameters, which precludes any meaningful optimization. Typically the SRV size is assumed (e.g., from microseismic) in production forecasting. In this work we have developed a new coupled geomechanical and flow model for analysis and optimization of tight and shale gas treatments. The formulation includes the propagation of a tensile (SPF) fracture and dynamic development of the shear failure. Non-fractured blocks are assumed to be of linear elastic material; whereas in the failed blocks, fractures and rock compliance matrices are homogenized to form an equivalent compliance matrix. Simple Mohr-Coulomb and tensile failure relationships were used as the criteria for detecting fracture creation. Hyperbolic functions are used to describe the fracture normal and pre-peak shear deformations while the post-peak shear behavior follows an elasto-plastic model. The permeability enhancement during the fracturing process is computed and is the principal coupling between the flow and geomechanics. The model is 3-dimensional and treats both normal and shear behaviour of fractures. The simulation results reveal that shear fracturing will be the dominant fracturing mechanism in cases where the rock cohesion is low and the deviatoric stress is high, whereas tensile fracturing prevails in other conditions. The new model will be a realistic tool for analyzing the dependence of the well productivity on design parameters such as stage volume and pumping rate, spacing between stages, etc. It can be also used to screen shale plays for the most favorable geomechanical conditions.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.81)
Abstract Due to the low permeability of many shale gas reservoirs, multi-stage horizontal well completions are used to provide sufficient stimulated area to make an economic well. Furthermore, access to, and stimulation of, the natural fracture system is often critical to an economically successful well. During a given hydraulic fracture stimulation, the physical displacement of the fracture alters the stress field around it. Numerous authors have suggested that this altered stress field is beneficial to the stimulation of the natural fracture system; however, other authors have shown the potential to stabilize the natural fracture system - making it less likely to shear - due to the presence of a created hydraulic fracture. In this paper, we present the results of a detailed parametric evaluation of the shear failure (and, by analogy, the microseismicity) due to the creation of a hydraulic fracture as a function of fracture length within two different fracture networks (DFNs) using the 2D Distinct Element Model (DEM), UDEC. Simulations were conducted as a function of: 1) fracture strength; 2) DFN orientation within the stress field; 3) stress ratio (the ratio of the maximum horizontal stress to the minimum); 4) Poisson’s ratio of the shale; and 5) Young’s modulus of the shale. The results show the critical impact that changes in the hydraulic fracture length and the DFN orientation have on the shear of the natural fracture system. In contrast, the simulations suggest that stress ratio, Poisson’s ratio, and Young’s modulus have, at best, a second-order effect on the shearing - and likely the stimulation - of the natural fracture system. The results of the study provide a further, quantitative assessment of the critical parameters affecting shale gas completions and aid in the understanding and optimization of hydraulic fracture stimulations in very low permeability, naturally fractured reservoirs.
- North America > United States > Texas (0.69)
- Asia (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
abstract Just-In-Time-Perforating (JITP) was developed by ExxonMobil over a decade ago to improve multi-zone stimulation in vertical and S-shaped wells in the Piceance basin, Colorado. With this technology, multiple single-zone fracture stimulations are performed on a single wireline run using ball sealers and perforating guns that remain downhole during the fracturing treatment. This results in substantial cost reduction and productivity uplift because perforation intervals are individually and effectively treated one at a time with less horse power, smaller number of frac plugs, and fewer wireline runs. The method has been successfully implemented by ExxonMobil in more than 350 wells and over 10,000 treatments and is licensed to a number of service companies. There is substantial business incentive to implement the JITP technique in horizontal wells, extensively used in unconventional gas developments. With XTO Energy joining ExxonMobil, the global gas portfolio incremented by 45 trillion cubic feet. This includes conventional gas, shale gas as well as other unconventional resources, such as tight gas, coal bed methane, and shale oil. This paper presents the first application of JITP in horizontal wells. Operations were conducted in the Fayetteville Shale, Arkansas. The paper discusses advantages and disadvantages of the method as well as lessons learned from pre-field trials and full-well implementations. Critical to the success of the initial technology application was the enforcement of a structured approach which included technical feasibility studies, contractor qualification, pre-field trials, well candidate selection, and a deployment plan to capture learnings and best practices. Pre-field trials were executed in several wells to test potential technical/operational concerns, such as sand build-up around perforating guns, fluid diversion with buoyant and non-buoyant ball sealers, and the ability to move guns through the lateral. Preliminary field costs and production performance in horizontal wells are promising and support continued deployment of the technology.
- North America > United States > Colorado (0.69)
- North America > United States > Texas (0.69)
- North America > United States > Arkansas > Washington County > Fayetteville (0.26)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.66)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.48)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Oklahoma > Arkoma Basin > Fayetteville Shale Formation (0.99)
- North America > United States > Colorado > Piceance Basin > Williams Fork Formation (0.99)
- (2 more...)
Abstract The Austin Chalk formation has seen several active development booms over the past 35 years due to new technologies. Recently, a program was undertaken to test multistage fracturing technology in the Giddings Austin Chalk field to determine if sufficient additional reserves could be unlocked to spark another development boom. This paper highlights the challenges encountered during the project from the initial reservoir simulation and well candidate selection through system design and installation and treatment design. The Austin Chalk formation has seen considerable horizontal development across Texas as operators chased areas of concentrated natural fractures. Significant quantities of hydrocarbons are apparently trapped in the tight carbonate matrix between the widely spaced fractures along the proven productive edge of the field. Many of the wells in these areas have poorly drained the Austin Chalk due to limited natural fracturing. Multistage fracturing has the potential to reach the insufficiently drained matrix blocks by isolating portions of formation between the natural fractures. A total of 16 openhole multistage hydraulic fracturing completion systems have been run in the Giddings Austin Chalk field across four different counties in an effort to increase EUR’s from existing wells and to extend the economic boundaries of the formation. Simulation work done at the outset of the project pointed towards economic incremental recoveries from multistage hydraulic fracturing. This work also helped validate initial candidate selection. It was found that openhole multistage systems can be run into the Austin Chalk, but it was learned that due to high formation friction factors, careful design work was necessary to ensure that the completion equipment could be run to the desired depth. Results to date have shown that multistage fracturing can increase recovery from existing wells in poorly fractured areas as well as allow for economic development of previously uneconomic fringe areas.
- North America > United States > Texas (1.00)
- North America > United States > Mississippi (1.00)
- North America > United States > Louisiana (1.00)