Unconventiona estimated world hat the volum recovery factorTo help unlock fracturing in ho geometry (not state in the dra geomechanical fractured tight g Traditionally, t system to a pla presented in th orientation and pressure deplet are ignored.
A major key to rejuvenating mature oil and gas fields for improved recovery is the ability to characterize the reservoir between existing wells: currently practised methods for surveying inter-well properties are generally costly. A recent project has combined three technologies which utilize readily available fluid production histories to produce a process for identifying inter-well reservoir communications in producing oil or gas fields. Fluctuations in the well production and injection rate histories are analyzed in the context of coupled geomechanical-flow processes involving activated faults and fractures through (i) the Statistical Reservoir Model (SRM), (ii) conventional correlation analysis and a new technique for extracting rate diffusivity tensors, and (iii) coupled geomechechanical-flow modelling. These technologies have been applied to five oilfields located in the North Sea from the North Viking graben to the Central graben with the key results that (i) the general long-range nature of rate correlations is consistent with some dependence on hydro-mechanical changes near a critical point, and (ii) the patterns of orientational distributions of rate correlations from all five fields are consistent with induced shearing on faults or fractures as an inherent mechanism of reservoir communication. Identification of major reservoir pathways is of substantial advantage to efficiency in reservoir management, leading to benefit for practical issues of well placements and configurations, injectivities, productivities, sweep efficiencies, short-term and longer-term forecasting. In particular the techniques can be used in a time-lapse fashion in order to monitor changes in reservoir behaviour and provide real-time updating of reservoir models. Together, these techniques can directly assist rejuvenation of mature fields; additionally, albeit tentatively, the improved understanding of fundamental reservoir mechanisms can lead to better planning of ‘green’ fields.
Summary Unconventional gas is stored in extensive areas known as basin-centered continuous-gas accumulations. Although the estimated worldwide figures differ significantly, the consensus among the studies relating to unconventional gas resources is that the volumes are gigantic. However, the low permeability in these types of reservoirs usually results in a very low recovery factor. To help unlock these resources, this paper presents a new and more accurate way of simulating multistage hydraulic fracturing in horizontal wells in three dimensions by use of single- and dual-porosity reservoir models. In this approach, the geometry (not necessarily symmetric) and orientation of the multiple hydraulic fractures are driven by the prevailing stress state in the drainage volume of the horizontal well. Once the hydraulic-fracturing job is accurately modeled in three dimensions, two-way geomechanical coupling is used to history match the produced gas from a horizontal well drilled in the Nikanassin naturally fractured tight gas formation of the Western Canada Sedimentary Basin (WCSB). Traditionally, the most widely used approaches have their roots in semianalytical calculations simplifying the fracturing system to a planar feature propagating symmetrically away from a line source of injection. In contrast, the computed results presented in this study show that the incorporation of geomechanical effects gives a more realistic representation of the orientation and geometry of hydraulic fractures. Reduction in permeability of the natural and hydraulic fractures because of pressure depletion results in more-realistic production predictions compared with the case in which geomechanical effects are ignored. The telling conclusion, in light of the computed results, is that the field of hydraulic fracturing provides an object lesson in the need for coupled 3D geomechanical approaches. The method presented in this paper will help to improve gas rates and recoveries from reservoirs with permeability values in the nanodarcy scale.
In a recently drilled deviated well in an offshore field in UAE, severe cavings have been produced which led to difficulty in tripping out and stuck pipe events. A comprehensive study has been conducted to understand the chemical and mechanical behavior of the shales in the overburden. This paper focuses on how we approached optimization of drilling design and practices where well construction was concerned (namely casing design and mud formulation). This approach minimized mechanical and time-dependent chemical instabilities in the Fiqa, Laffan and Nahr-Umr shales. After the initial implementation of the optimized drilling practices, a complex multi-discipline study including time-dependent shale stability analysis provided recommendations for the problematic shales should they be kept open for long durations (to reach section TD, log and case). The time-dependent shale stability analysis included three major phases. The first phase was conducted based on the data for several selected existing wells. This phase resulted in obtaining so called field-based mud design criteria together with customized laboratory measurements. The second phase is to conduct a comprehensive geomechanical model to understand the mechanical behavior of the formations. In this study both 1D and 3D geomechanical models have been constructed honoring the anisotropic nature of the shales. The third phase was focused on selecting best mud system and optimizing the mud designs to prevent/minimize both mechanical and time-dependent chemical instabilities for shales layers with long exposure time. The problematic shales were penetrated at relatively high angles, requiring high mud weights and therefore leading to relatively high overbalance pressures which can cause high pore pressure increase in the shales with time. However, it is still feasible to select an optimum drilling fluid design for the desired mud system by optimizing salinity for the required high mud weights to avoid time-dependent instability. The Nahr-Umr shale, in general, was deemed to be more susceptible to mechanical and time-dependent chemical instabilities due to higher required mud weights and overbalance pressures. The Fiqa, Laffan and Nahr-Umr shale formations could be drilled using the recommended mud weights together with best mud formulations to avoid both mechanical and chemical time-dependent wellbore instability problems in the planned wells. The outcome of the study helps in keeping the shales open for longer period in highly deviated wells without any wellbore instability before casing runs. The workflow utilized for the shale stability analysis for Fiqa, Laffan and Nahr-Umr included an approach innovative for UAE to understand mechanical and chemical (osmosis-related) behavior of the problematic shales to develop recommendations for cases when the shales needed be kept open for long durations.
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