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This paper evaluates fundamental differences in depletion performance of wells producing from ultra-low permeability 1 ("shale") reservoirs and wells producing from conventional reservoirs, with the ultimate goal of defining what differentiates "conventional" from "shale" performance. It attempts to answer the question -what permeability range defines "ultra-low" depletion performance and what permeability range defines "conventional" depletion performancewith the intermediate permeability range being a transition from ultra-low to conventional behavior. We "map" the transition from conventional depletion performance to "shale" depletion performance in terms of formation permeability.In this study we compare depletion performance for reservoir permeabilities ranging from 10 nD to 100 md, with PVT, relative permeability functions, and other rock properties being the same for all simulation cases. Four reservoir fluid systems, ranging from rich gas condensate, near-critical oil to light oil, were used in this study. A one-section drainage area was used even though we are aware that shale resources are often developed with smaller well spacing (typically 80-or 160-acre strips, ~ one mile long).Depletion performance of conventional gas condensate and oil reservoirs -where oil recovery and producing gas-oil ratio (GOR) are independent of permeability and flowing BHP, is valid for k > 0.1 md. At permeability levels of ~ 0.001 md (1000 nD) or less, the depletion performance of shale and ultra-tight reservoirs is characterized by that producing GOR is a strong function of flowing bottomhole pressure (BHP) and degree of undersaturation (Whitson and Sunjerga, 2012).Our results from this study show that conventional reservoir performance, depending somewhat on the reservoir fluid system, is observed for k > 0.5 md, while ultra-tight "shale" performance is found for k < 1000 nD (0.001 md), with a gradual transition between these permeability values and shale-like depletion performance appearing already at 0.01md.

Wireline formation fluid sampling in weakly consolidated, heavy oil reservoirs has been unsuccessful in appraisal wells in the Bohai Bay area, offshore China. Poor sampling and prolonged testing time were unacceptable from both operational and formation characterization points of view. The challenges involved the production of solids during fluid sampling, contamination as well as poor and unreliable pressure testing. An integrated study was conducted to build a fit-for-purpose geomechanical model for the study field using drilling data, well logs, formation and drill stem testing data and sanding observations in several offset wells. An analytical sanding evaluation methodologywas used and calibrated with the observed sand production in the study wells. The calibrated model was then used in a near-real time basis for new wells to optimize the sampling depth points and drawdown pressures to avoid sanding while sampling and also to speed up the sampling time to reduce operation time and costs. The aim was to use higher drawdowns and faster testing while also avoiding intervals where sand-free drawdown may not be possible. Using the workflow in new wells has resulted in sand-free sampling at higher drawdownsas well as faster sampling speeds. In contrast, in wells where the rock mechanical aspects of fluid sampling and the root cause of sanding while sampling were not incorporated into the logging and formation testing operations, the sampling failed again due to sanding issues despite the moderate drawdown and slower sampling rate. Real-time integrated geomechanical and formation evaluation analysisresulted in delivering sand-free fluid samples, saving 30% rig time, and more successful and reliable pressure and fluid sampling for accurate reservoir and fluid characterization.

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