Abstract

A new hydraulic fracture screening method has been developed based on quantitative analysis of the mobile oil saturation in the target zone. The traditional selection process was based on analysis of low productivity wells, followed by extensive fracture modeling of leak-off parameters and rock properties. The new screening method defines the best pay zones and uses the saturation profile to govern the size of the fracture treatment.

This method was developed during a 10-acre infill-drilling program on the Central Vacuum Unit during the mid 1990s. Most of the producers were initially stimulated with large, one stage acid treatments. Production declined soon after completion and fell below the levels of offset producers. Texaco analyzed the open-hole logs and discovered a consistent pattern of low in-situ water saturation in the upper San Andres. Log analysis clearly indicated that the infill well production should be much better than the offset wells. Three of the new wells were successfully fracture treated across the entire San Andres interval with excellent results. However, many stimulation candidates were offset by wells producing high water volumes. The new screening method indicated that the upper San Andres should produce nearly water-free after fracturing. The design process also showed that smaller fracs would have substantially better economics and would ultimately produce as much or more reserves as large fracs.

Texaco fractured eighteen more wells in the upper San Andres. Oil production dramatically improved but water production was often unchanged. The new screening method allowed the development of additional reserves that were not recoverable under earlier practices.

Introduction

Hydraulic fracturing technology has continually evolved over the past 50 years. Recent improvements in computers have resulted in extensive fracture modeling capabilities using real-time data. Numerous industry publications have covered all aspects of fluid leakoff and rheology, history matching, proppant transport and rock properties. This has enabled larger treatments in hostile environments and often is the critical factor in the success or failure of a new well.

A waterflood environment presents both unique opportunities and challenges to fracturing1. Close spacing and good log data from infill wells allow detailed reservoir characterization. Rock properties can be accurately modeled and the pay quality is easier to define. However, reservoir pressure may be substantially different in adjacent zones. In extreme cases, long-term injection may alter reservoir pressure to the point that the confining stresses change2. Furthermore, the ultimate success of any waterflood stimulation program is clearly dependent on the degree of injection support. If offset injection wells cannot effectively support the pattern's production, then substantial reserves will not be recovered. Good reservoir pressure will often make up for a poor initial completion.

The Central Vacuum Unit (CVU), in Lea County, New Mexico, Figure 1, has been producing from the Grayburg and San Andres formations since 19373,4.

The San Andres is a shallow-shelf carbonate composed primarily of cyclical evaporates and carbonates. The gross reservoir thickneww ranges from 300' to 550' and is composed of the Grayburg, upper San Andres and lower San Andres formations. The Lovington Sand often separates the upper and lower San Andres zones. This sand is not considered a pay zone although it has been perforated in some wells and is exposed in the open-hole completeions. From San Andres core and log analysis, the net pay porosity averages 11.6% and the permeability averages 22.3 md4.

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