The subject reservoir is a heterogeneous carbonate formation in a giant field located offshore Abu Dhabi. Five gas injection pilots were initiated in late 2001 in the Eastern, Central and Western parts of the field both as secondary and tertiary recovery methods to evaluate the benefit of gas injection for pressure support and for recovery improvement. With less than 10% of HCPV gas injection, the pilots to date have provided valuable insight on production performance and pressure support, gravity override, swelling effect and flow assurance issues (such as asphaltene deposition) in the field. Using a 3D compositional model, a sector modeling study was carried out for comprehensive evaluation of the pilot performance to date and to predict definitive results within reasonable time frame (3-5 years) which will have ramifications on long-term full field development decisions. Additionally, the objectives of simulation efforts were to evaluate different recovery processes (gas/water/WAG) and assess key reservoir uncertainty (volumetric sweep) due to reservoir heterogeneity (high permeability streaks). Initially, the sector model was history matched with nine years of pilot performance while both reservoir heterogeneity and well spacing sensitivities were tested in the model. The history matched sector model was utilized to predict performance under different operating conditions using both gas, water and water alternating gas (WAG) injection methods. This paper describes the pilot performance, field observations and results of a sector model study including history match, sensitivity and predictions under different injection scenarios on two of the pilots. Based on the performance and surveillance data gathered on the two pilots and sector modeling study, it was established that both pilots have met their objectives and can be concluded. Through the integration of field observations and sector modeling work, the study provided valuable insight on optimum recovery processes, well spacing and well completion requirements for long-term field development.
This Middle East case study addresses the modeling of a green carbonate reservoir which production is controlled by fractures. The workflow integrates 3D seismic, cores, logs and production data to assess and minimize the production forecast uncertainties. The 3D seismic was used both for the characterization of layer-bound fractures, by means of fracture-related attributes, and to locate sub-seismic faults and associated fracture corridors. The extraction of seismic lineaments was performed using edge-enhancing and automated interpretation techniques. A simple approach was introduced to identify the most persistent lineaments and increase the confidence in their structural nature. The distribution and properties of small scale fractures was constrained by a combination of image logs, cores, drilling logs, seismic attributes and petrophysical model. Outside the corridors, the vertical variability of the fracture density was derived from the interpretation of electrical images, whereas its lateral variations could be correlated to petrophysical changes. Two consistent sets of orientations could be identified from image logs, while a detailed comparison between seismic attributes and flowing fractures from well data showed that the most open fractures were located in the vicinity of the faults. Multi-point statistics (MPS) were then used to constrain the location of the most effective fractured zones while retaining spatial consistency and maximum accuracy at the well locations. The final discrete fracture network (DFN) honored all measurements and computed trends and was upscaled to effective fracture properties (porosity, permeability and shape factor) in the reservoir grid. A dual porosity simulation model was generated and the fracture properties were calibrated against dynamic data. The mismatch between observed and simulated dynamic data was ascribed to the uncertainty in the input to the DFN modeling process. To avoid local modifications while preserving the original fracture property distribution and contrast in the model, history matching was performed by iteratively conditioning fracture intensity to dynamic data and subsequently recomputing the effective fracture properties based on the new modified fracture intensity distribution.
Geomechanics plays a significant role in hydraulic fracture initiation and propagation and in the interaction between hydraulic fractures and natural fractures, especially in unconventional reservoirs. This paper provides a detailed description of a geomechanical characterization and modeling study for evaluating the impact of geomechanics on completions and hydraulic fracturing stimulations optimization in the Montney resource play, Canada. Following an integrated workflow, 1D mechanical earth models (MEM) for ten wells were constructed in the study area. These 1D MEMs include elastic and strength properties, pore pressure, direction and magnitude of in-situ stresses. Extensive rock mechanics core testing data were used to calibrate the elastic and strength properties. Pore pressure and fracture closure pressure data from diagnostic fracture injection tests were also available to calibrate pore pressure and minimum in-situ stress. Maximum horizontal stress was constrained by modeling wellbore stability and matching it with caliper logs and wellbore stability features on wellbore image. A 3D mechanical earth model was subsequently constructed using a 3D geological model, the 1D MEMs, and seismic inversion data. Elastic properties from seismic inversion were used to populate mechanical properties in the 3D model. In-situ stresses were numerically simulated to account for the impact of faults and structural and mechanical property variation on in-situ stress distribution. The geomechanical analysis shows that there is a decreasing trend in Young’s modulus from upper Montney to lower Montney while Poisson’s ratio is relatively constant in the Montney. The pore pressure in some parts of the field is high and varies across the field. Stress regime is predominantly strike-slip with relatively large stress anisotropy, and this has implications on the hydraulic fracture network that would be simulated, shearing of natural fractures and the stimulated reservoir volume. Rock elastic and strength properties, pore pressure, and in-situ stresses were found to be heterogenous across the whole field. The relatively large variation in pore pressure in the study area and the structural complexities have large impact on the distribution of stresses. Faults alter the stress distribution locally and could affect hydraulic fracture propagation. Hydraulic fracture simulations were subsequently performed, and the geometry of the simulated hydraulic fractures and the stimulated reservoir volume were validated with microseismic events. The effects of geomechanics on fracture geometry and ultimately reservoir production were evaluated. Because of the significant impact of geomechanics on hydraulic fracturing, it is critical to characterize and model geomechanics accurately. This paper provides a comprehensive approach and application to a field in the Montney, showcasing the integrated method of geomechanical characterization and hydraulic fracture simulation and production modeling using various data. The analysis provides an interrelationship among geomechanical parameters, microseismicity and stimulated reservoir volume.
With increased drilling activity associated with development of unconventional reservoirs, many operators are reporting both stimulation and production interference between wells. Interference between existing production wells (parent wells) and newly completed infill wells (child wells) is often associated with production impairment (Marongiu-Porcu et al. 2015; Ajisafe et al. 2017; Defeu et al. 2018 and Manchanda et al. 2018a). The objective of this work is to develop guidelines concerning infill wells completion scheme to minimize parent-child wells interference in a typical pad, with infill drilling in the Duvernay formation. The area of interest selected within the Duvernay formation consists of three parent wells and two child wells. An integrated mechanical earth model (MEM) was constructed for the area using public databases. The created 3D-geological model included petrophysical and geomechanical properties along with a 2D discrete natural-fracture network representing the distribution of natural fractures in the reservoir. Hydraulic fractures in parent wells were modeled using original stress settings from the 3D-MEM. Then, a dynamic model was constructed for the three parent wells and production simulation was run for five years. Pressure distribution at the time when child wells came into production was extracted and 3D depleted stress distribution was computed using a finite element method that included the effect of pore pressure decrease and principal stress magnitude and orientation changes. Then, hydraulic fracture modeling was performed for the two child wells using the new depleted stress distribution, and finally a five-well dynamic model was created. Sensitivity analyses were performed on the hydraulic fracture parameters of the child wells with the objective of maximizing recovery by accessing more virgin reservoir area between the parent wells. Hydraulic fracture modeling followed by dynamic simulation was done in the pad for multiple cases. Fracture geometry, hydraulic/propped surface area, and fracture conductivity in child wells were extracted and analyzed against production performance of the wells. This study shows a holistic approach in modeling the impact of completion modifications on the child wells performance in an infill drilling scenario. A 3D-geomechanical model coupled with reservoir simulation allowed simulating the propagation of hydraulic fractures in the presence of pressure depleted regions. Results confirmed that the main reason for under-performance of child wells in Duvernay is the stress change induced by the reservoir pressure depletion associated with the parent wells production hence, influencing the child wells hydraulic fractures propagation patterns.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.