Tight Gas Petrophysical Challenges in Saudi Aramco

Summary Response-surface methodology (RSM) has been widely used in the petroleum industry as an assistive tool for numerical-reservoir-simulation studies. Instead of generating simulation cases exhaustively to solve history-matching (HM) problems, proxy models that are created by RSM provide useful benefits in terms of simplicity and computational efficiency. However, the capability of proxy models to fully capture uncertainty ranges of HM results and production forecasts might be deficient in complex problems if the simplified proxy models only deliver partial solutions. Hence, to decide whether the uncertainty-assessment process by proxy models is complete, the models should deliver as many HM solutions as required to build probability distribution of production forecasts. Therefore, we developed the work flow to combine both processes into an integrated proxy-based approach that searches for the accepted HM solution while probabilistic forecasts are evaluated simultaneously. In addition, the combined work flow is an iterative approach. It gradually modifies the proxy models dependent on the increasing number of completed simulation runs, which continually update the original proxy model into higher degree of polynomial. The use of higher-degree-polynomial equations appears to have the benefit to provide an expanded set of HM solutions inside the uncertain parameter space compared with the commonly used quadratic form. More solutions found from the iterations could eventually approximate wider uncertainty ranges of probabilistic forecasts, which is consistent with the direct Markov-chain Monte Carlo (MCMC) method but with a significant reduction of simulated cases. Finally, this paper applies the proxy-based approach to a reservoir-simulation model containing a horizontal hydraulic-fractured well in the Marcellus Shale formation. This proxy-based approach helps assess the uncertainty of reservoir and fracture properties of unconventional reservoirs. Also, it is useful for evaluating the ranges of ultimate gas recovery.

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The Methods of Correcting NMR Data from Dry Gas Wells Drilled with Formate Based Muds by Advanced NMR Techniques

Kwak

Hursán

Gao

et al. 2017

Day 4 Thu, April 27, 2017

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Formate-based drilling mud is used to improve the performance of drilling and completions of high pressure and high temperature (HPHT) wells due to its properties such as high density (up to 19 lbs/gal), non-corrosiveness, eco-friendliness, high stability, and miscibility with brine and other fluids in the drilling muds. However, these strengths of formate muds pose challenges for formation evaluation due to their unusual properties such as high density, low Hydrogen Index (HI), miscibility with connate brines, and high conductivity. The current work addresses challenges of Nuclear Magnetic Resonance (NMR) logging, which is known to provide capillary bound fluid for producibility evaluation and accurate porosity for reserve estimation, in deep dry gas wells drilled with formate mud. With a carefully designed workflow composed of a suit of laboratory NMR techniques, the needs for the correction of T2cutoff and HI by Formate Mud Filtrate (FMF) invasion have been investigated. To quantify the accurate amount of correction required, FMF invasion has been monitored under reservoir conditions. The experimentally determined NMR T2 cutoff values for FMF saturated samples are always slightly longer than those for brine saturated ones. The difference of bulk volume movable (BVM), however, is less than 5% when T2 cutoff value from brine saturated sample is applied to FMF saturated sample. Thus, T2 cutoff determined by conventional NMR laboratory measurement with brine can be applied to NMR log with the formation invaded by FMF. The HI correction factors for BVM and bulk volume irreducible (BVI) are dependent on pore structures. For brine saturated bi-modal sandstones, all pores are displaced by FMF which corresponds to an HI correction factor of 0.74 for both BVM and BVI. For brine saturated carbonate with tri-modal pore system, however, 100% BVM and 70% of BVI have been displaced with FMF which correspond to HI correction factor of 0.78 and 0.80 for the FMF used in the current study, respectively. The outcome of the current study will help to enhance the usage of NMR logging as powerful formation evaluation tool for gas wells drilled with formate based drilling muds.

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Tight Gas Petrophysical Challenges in Saudi Aramco

Cited by 4 publications

References 10 publications

Introducing new method to improve log derived saturation estimation in tight shaly sandstones—A case study from Mesaverde tight gas reservoir

Introducing new method to improve log derived saturation estimation in tight shaly sandstones—A case study from Mesaverde tight gas reservoir

An Iterative Response-Surface Methodology by Use of High-Degree-Polynomial Proxy Models for Integrated History Matching and Probabilistic Forecasting Applied to Shale-Gas Reservoirs

The Methods of Correcting NMR Data from Dry Gas Wells Drilled with Formate Based Muds by Advanced NMR Techniques

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