Summary
In this paper, we will present workflows that incorporate two traditionally distinct disciplines within the petroleum engineering and geological domains: rigorous single-well completion optimization and field geocellular and simulation modeling. We explore the details of this workflow and discuss the benefits of tightly linking the two disciplines. This paper describes an example of the workflow application to a commingled stacked tight gas play in the Rocky Mountains of the United States.
In commingled stacked tight gas pay, gross intervals of thousands of feet are completed to enable maximum productivity. Typically seen are interbedded sequences of fluvial sandstones intermixed with shales, coals, and silty-sand deposits. Because of the heterogeneity seen on various scales, field modeling provides value in deciding optimum well drilling density, determining well location geometry based on hydraulic fracture azimuth and drainage pattern, and modeling various economic scenarios of development.
Models were built by integrating the seismic, petrophysical, geological, and hydraulic fracture data generated by different disciplines. The vertical and areal resolutions of the model were dictated by sand body sizes, reservoir gross thickness and heterogeneity, and fracture stages. The size of the hydraulic fracture jobs and well spacing were critical considerations in the selection of simulation cell sizes. Major challenges included upscaling both the geological features and the hydraulic fracture properties to simulation model scale in a reasonably accurate manner.
A streamline-based flow model was utilized to upscale geological features. The model that best captured both the volumetric and the flow characteristics was chosen for further simulation modeling. Single-well and sector models were used to approximate the fracture properties that would be used in the final simulation model. The models were calibrated to the behavior of the wells and then used for forecasting performance after stimulation. A software program that took into account production and economic information was used for well and field development planning.
Introduction
Traditionally, single-well completions optimization and fullfield development simulation have occupied distinct and unique domains within the oil and gas industry. Different teams of personnel with different job skills would attack these two areas separately, often having very little interaction between one another. Because of the very large dollar impact in each domain, i.e. in single-well completion costs and in multi-well development on ìoptimizedî acreage patterns, and because of the obvious hook-up between hydraulic fracture job size and its impact on drainage area, and thus on drilling density needs, it seemed obvious that significant value could be realized through effectively linking up these domains so that the range of potential outputs of one domain, along with its associated costs, could drive the simulation process in order to optimize well drilling density, patterns, and cash flow.
New technology in characterizing the hydraulic fracturing process is instrumental in allowing this new workflow to be possible. Through newer technologies including microseismic hydraulic fracture mapping[1], rigorous rate-transient production decline analysis[2,3], and better data and modeling routines for hydraulic fracturing simulation[4], a much clearer picture is available for both the true dimensionality (height, length, azimuth) and the capacity (conductivity, proppant distribution) of that hydraulic fracture. This in turn lends itself to simulation, where the hydraulic fracture is then modeled numerically on an upscaled geocellular grid.
