No abstract

The Montney gas play in NE British Columbia and NW Alberta is undergoing intense development utilizing multi-stage fracturing of horizontal wells. Problems persist in determining an optimal development strategy for each area within the Montney. For the Groundbirch area, operators are in the early stages of development. As a consequence they have invested significantly in well monitoring including microseismic, pressure build-ups, real time rate and pressure measurements and offsetting pressure observation wells. Conventional core analysis indicates that reservoir rocks have permeability in the micro-Darcy range. Lab experiments indicate permeability is also a function of the changing effective stress. Effective stress increases and permeability decreases as production occurs. A coupled geomechanical/reservoir study was performed after 400 days of production history in order to match behavior and determine the sensitivity of conventional production forecasts to the changing stresses within the reservoir. This paper focuses on the performance analysis of a single Upper Montney well in the Groundbirch area. The approach is staged, with the analysis proceeding from the simple to the more complex. The first step involved an improved version of production analysis. After the identification of linear flow, the utility of a long neglected plot, dm/q versus superposition linear time is illustrated. The ability of this plot to accurately split production well performance into reservoir properties and skin effects introduced by the fracture treatments is shown. This has wide ranging implications for the industry. Finally a simple practical method has been found to compare performance of various types of horizontal multi-stage fracture treatments where the impact of reservoir properties has been removed.In the second step of the study various descriptions of the study well were developed for all the processes the well encountered. These reservoir simulation models successfully matched treatment placement, an early build-up test distorted by clean-up effects and long term production behavior. Models types ranged from constant reservoir permeability through stress dependent permeability variation. Techniques were developed that eliminated the need to perform the time consuming geomechanical calculations. This allows the use of conventional reservoir models with pressure dependent permeability functions of a special form, to be used in day to day analysis. Sensitivity of the predicted production response with these models was then quantified.

The advances in hydraulic fracturing technology and horizontal well completions have led in recent years to rapid rise in exploitation and development of tight gas and shale plays all over the world, and particularly in North America. The popularity of new field technology has in fact raised many new questions. In particular, for forecasting the productivity and EUR of multifractured horizontal wells, it is not clear if conventional reservoir simulation concepts can be adapted for modeling or if extra physics must be included to obtain realistic solutions.

The behavior of reservoir rocks that are subjected to varying stress regimes throughout the life of a producing field has major impact on critical aspects of development and production including (1) reservoir drive and depletion planning, (2) wellbore stability and integrity, and (3) subsidence and overburden deformation. The subdiscipline of geomechanics straddles a zone that overlaps the geosciences and engineering and includes the study of the mechanisms and consequences of various models of reservoir compaction. Coupling geomechanical modeling with classical reservoir simulation honors the links between changes in the internal stress field and flow properties-allowing us to better estimate the long-term behavior of producing reservoirs. This paper reviews some underlying aspects of coupled simulation and provides references for further study.

Upscaling of properties for reservoir simulation has reached a stage of maturity and uses sophisticated techniques. In contrast, little work has been done on upscaling of mechanical properties for coupled modeling, and the geomechanical model is usually assumed to be representative (upscaled) without actually being subjected to the same rigor of process or scrutiny. Compacting reservoirs often contain fine sand-shale sequences on sub-grid scale (compared to flow modeling grid) and are typically represented in simulators by the net-to-gross (NTG) concept, while being ignored in geomechanical modeling.In this work, we present a method to upscale shales in the geomechanical component of a coupled simulation by computing dynamically changing equivalent moduli. The method is based on estimating the depletion of interbedded shales, coupled with analytical solutions for equivalent moduli under the assumption of uniaxial deformation. The technique has been verified by sub-grid scale simulations and requires geometric characterization of the shales but is relatively simple and can be easily implemented in coupled simulators. The analysis shows that the inclusion of the shales generally reduces computed compaction, with the controlling variables being NTG, dimensionless pressure depletion of the shales (which in turn depends on their flow properties) and mechanical properties of the shales.The approach developed was incorporated in the subsidence and compaction analysis over a complex offshore oil reservoir. The reservoir zone consisted of a number of intervals that included relatively undeformed as well as highly deformed layers, and on reservoir model scale had significant NTG ratios. A comprehensive study (based on coupled flow and geomechanics simulation) was conducted to evaluate well integrity, fault slip (reactivation) and compaction drive. A large full field model was built using data from a multitude of sources and production data was modeled and history matched, allowing us to estimate the magnitude of reservoir subsidence and the contribution of the NTG effect on predictions. The study presented here showed that in the absence of any consideration of the NTG effect, predictions (for compaction and subsidence) could be significantly overestimated. In addition, the method can be used to study the phenomena of "time-lag" of subsidence which has been observed in some reservoirs.