No abstract

In this paper, we present the results of an elaborate simulation study from the Eagle Ford shale by integrating rate transient analysis (RTA), microseimic interpretation and rock typing to quantify the well recovery factors. First, we builda fine-scale geocellular model to represent the lithology of Eagle Ford Shale (EFS)in interest. A fully compositional fluid model wasthen integrated into the geocellular model. The stimulated rock volume (SRV) is based on microseimic data interpretation. The permeability of the system is calibrated from rate transient analysis (RTA) using the methodology suggested by (Suliman et al. 2013). Historical production data of a 500'conventional spacing 3-well PAD is then matched and the sensitivity to well spacing is then carried out using the history-matched model in two configurations. These are same layer completions and staggered well completions. Recovery factors are then quantified with the help of expected ultimate recovery (EUR) calculated from simulation forecasts and original gas in place (OGIP) calculated with the help of volumetric calculation. Our results show that the conventional 500'spacing is not optimal in the rich condensate area of the Eagle Ford shale. Additionally, there were little to no difference in the predicted EUR's in staggered or same layer completions. Microseismic data suggests that the fracture grows up to the top of EFS and is not limited to the lower EFS. We also perform sensitivity studies with respect to drawdown that show minimal or no condensate banking with choke management. Early-time condensate banking is however very sensitive to higher drawdown pressures.

Well operation is one of the key foundations for optimal production of hydrocarbons from unconventional shale plays. However, optimal production practices do not follow the versatility of "one size fits all" phenomenon. Completion strategy, Pressure-Volume-Temperature (PVT) properties and petrophysical properties vary from play to play. Hence, the well operating practices should be custom tailored to suit the completion and fluid properties. In this paper, we propose optimal shut-in practices for dry gas shale reservoirs. We elaborated our study from a Marcellus shale dataset. Marcellus shale dry gas window has in place fluid properties that differ from liquid rich reservoirs like Eagle Ford and Wolfcamp shales. Therefore, production best practices borrowed "as-is" from liquid rich reservoirs and applied to dry gas reservoirs (or vice versa) may not affect the well ultimate recoveries in a positive manner and in some cases, may even reduce the expected ultimate recoveries (EUR's). We show that the practice of "well conditioning", "resting" or "soak-in" i.e. shutting in the well for a significant time after hydraulic fracturing and before connecting to pipeline as well as frequent shut-in impedes the water unloading from the dry gas reservoirs. This leads to reduction in matrix permeability with an additional skin introduced by water imbibition. Our methodology by simultaneously history matching gas rate, flowing bottomhole pressure (FBHP) and water rates in a reservoir simulator. We observe that after shut-in, water to gas ratio (WGR) decreases and gas rate increases. However, this increased gas rate is accompanied with higher declines in rates and pressures and ultimately leads to lower EUR's. The reduction in EUR in our case is modeled as a function of water saturation increase in the matrix due to imbibition. Thus, EUR in our study is a function of duration of shut-in and the time in well life at which the shut-in occurs.

fax 01-972-952-9435. AbstractThe paper demonstrates how to establish a compositional gradient in Dhirubhai-26 (MA) retrograde gas-condensate reservoir situated in a deep water territory of KG Basin, India, with the help of real-time Downhole Fluid Analysis (DFA).The reservoir consisted of an oil rim sandwiched by a large gas cap and bottom water. Very low contamination samples were captured downhole, using a Wireline Formation Tester (WFT), in Single Phase PVT bottles. This success was achieved through the combined use of DFA results, PVT data and a tuned Equation of State (EoS).PR Peneloux (T) EoS was tuned to the PVT data and used to populate the PVT properties of the reservoir. The resultant fluid composition versus depth was correlated to the DFA results to verify the EoS simulated compositional gradation. Subsequently a reliable GOC was established using the combined result of WFT pretest derived gradients, PVT property derived gradients and saturation pressure curves. Establishing the existence or non-existence of compositional gradient and reservoir compartmentalization in this reservoir were key prerequisites for the formulation of an optimum Field Development Plan (FDP) and estimation of the associated financial implications.The methodology adopted in this paper is applicable to any gas-condensate reservoir that exhibits similar PVT properties. It would help to evaluate a more accurate in-place reserve estimate and reduce the reservoir risk, which in turn would lead to an optimum FDP (that would maximize the oil recovery and returns).The paper highlights the value of wireline conveyed DFA tools and latest wireline sampling methods coupled with a tuned EoS for an accurate PVT description of complex reservoir fluids. It can not only detect the presence of compositional gradients at an early time but also help refine the PVT model to establish the gradation in composition, thus providing a cost-effective solution for deep water ventures.

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