Deeper Completions Really Lower Water-Oil Ratios!
Authors: Wadleigh E.E. , Paulson C.I. , Stoltz R.P. 
Published: December 2007

Optimum oil recovery from massive carbonate reservoirs depends not only on maximum oil rate, but largely on minimization of costly associated fluid production. Field examples are presented to illustrate the range of results and economic value of completion placement beneath the fracture water-oil contact (WOC) of massive carbonate reservoirs. Conclusions are based on a review of realistic reservoir flow features, a range of field results, and computer simulation. Cooperative geologic-engineering assessment of flow feature connectivity and wellbore liquid production limits is critical to completion design. Well profitability can be maximized and water-oil ratio (WOR) reduced by establishing optimally deep completions. The completions are categorized by ease of dewatering for strategic completion placement. Field data confirms the physical theory that oil rate can be increased while lowering producing gas-oil ratios (GOR's) and WOR's. Consideration is given to aquifer energy, formation layering, and fracture heterogeneity.

Introduction

Singhal, early in, 1996 provided a technology overview of water and gas coning and commented on the scarcity of published field data demonstrating improved oil rate and recovery efficiency of deep completions. The theory of unconfined oil column (oil beneath gas and above water) behavior was reviewed in detail by Couri (1993) in a discussion of mathematical modeling of free surface gravity drainage. VanLookeren (1965) and Singh (1975) provided experimental and analytical approaches to quantify the opportunities for efficient oil capture from a vertically unconfined oil column.

Several field studies have been reported that rely heavily on conceptual simulation, but report only minimal data from individual completions. Gallagher et al (1993) presented simulation of well coning while producing a vertically unconfined oil column of a fractured Oman reservoir. Dual porosity was utilized in a manner similar to that presented by Cheung et al (1992) for a Canadian carbonate reservoir. The presented technology appears valid and well documented with minimal published technical objection. However, there is a noted lack of documented field applications with assessment of realistic variables that impact their success. This paper will focus on operational sensitivity of the applied technology through individual and summarized well performance with a review of nomenclature, simulation, and theory as required for clarification of opportunity. Fractured reservoir performance has been assessed throughout the western United States with the presented data on massive carbonates drawn from the Permian Basin of West Texas.

Massive Carbonates

The theory of utilizing deep completions to improve oil rate and economic production efficiency has been actively discussed in literature for at least the last sixty years (Muskat 1935). Much of the available field testing has unfortunately been performed in formations where the impact of completion placement is minimal. The important factor for consideration in obtaining a significant test of the concept is the variance in oil phase drawdown with completion placement. Three testing requirements are 1) A thick vertically communicated zone to generate significant flow variance between shallow and deep completions, 2) High vertical effective permeability (kve) relative to effective horizontal permeability (khe) and 3) High well productivity allowing lucrative production at low drawdown (as a function of liquid head). Massive carbonates provide a high probability of encountering all three when completed in a non-limiting and non-damaging manner.

Why are massive carbonates the place to exploit completion placement technology? Massive carbonates are thick, providing a reservoir setting in which an original or depleting oil zone may achieve an unconfined condition. Massive carbonates provide a relatively brittle formation. P. 91^