Abstract

To reduce the uncertainty in the estimation of hydrocarbon in place and fluid contact in tight gas reservoirs, it is essential to integrate core data and log analysis. A newly developed saturation-height function approach has been successfully applied to calibrate log analysis to better define petrophysical properties such as formation water saturation and free water level in tight gas reservoirs. The application of this approach has played a critical role in exploration and development decision-making processes for tight gas reservoirs.

Unlike most of the models published in the literature, this approach accommodates different forms of J-Sw regressions, which is applicable to different pore geometries and very powerful in tight gas reservoirs. Also, water saturation is calculated continuously from log porosity and free water level without formation resistivity and Archie exponents. In addition, this approach estimates free water level by iterating on water saturations until matching those derived from log data.

In a case of a tight gas "wild-cat" well where the porosity from most of the well logs is much larger than that from core analysis, this new approach reconciled the difference and predicted the rock quality up-dip. The results are confirmed by the pressure transient analysis from the production test. Based on the integrated analysis, the decision to abandon the current well and the up-dip drilling location saved the company millions of dollars.

In the second case, the reservoir simulation failed to get a history match for a tight gas field. The parameters of this new approach were calibrated to several key wells with core data. The results of the calibration were then used to populate water saturation throughout the field. Eventually, the history match was achieved and an infill drilling opportunity was identified for this field.

In summary, this paper proposes an integrated EXCEL-based saturation-height approach. Case studies in tight gas reservoirs using the new approach demonstrated that failures were avoided, and opportunities were realized.

Introduction

There are significant uncertainties in log calculated water saturations (Sw), especially in tight gas, shaly, and heterogeneous reservoirs. In tight gas reservoirs, the transition zone is significant and capillary pressure plays an important role in the distribution of saturation. In reservoirs with large structural relief, a saturation model based on capillary pressure, integrated with log calculated saturation, can help predict the performance of offset wells both up-dip and down-dip and improve economics of step-out drilling.

Capillary pressure is determined by pore throat size, wettability, and inter-phase tension in a pore system. Saturation profiles of the transition zone in hydrocarbon reservoirs show the balance between the opposing forces of gravity (buoyancy) and capillarity. These opposing forces interact to produce a unique saturation profile that can be used to provide a core calibrated Sw to compare to log analysis so that uncertainties may be quantified and accuracy potentially improved.

Water contact is needed for volumetric calculations, well location determination, and reservoir producibility forecast for up-dip or down dip wells. In low permeability reservoirs or where density difference between hydrocarbon and water is small and the transition zone is long, water contact may not be clearly defined. Water contact has historically been defined as a maximum depth with either water-free-production or economical production. Water contact defined by water-free-production-depth may be used when the transition zone is short. However, using the water-free-production-depth for water contact in tight gas reservoirs usually is a cause for underestimation of reserves. Therefore, it is often critical to know free water level in reservoir description.

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