Quantitative Analysis of Infill Performance: Robertson Clearfork Unit
Authors: Barbe J.A. , Schnoebeien D.J. 
Published: December 2007

Summary
This study analyzed the results of 218 infill wells drilled in the Robertson Clearfork Unit (RCU), Gaines County, TX. This program increased ultimate recovery by more than 23 million bbl [3.7×106 m3]. The individual well performance, as a function of reservoir continuity, was analyzed quantitatively with pressure correlations, numerical analyses, and geologic study.

Introduction
Infill drillrig has significantly increased the cumulative production, conventional remaining reserves, and EOR prospects in RCU. This paper documents the successful infill program and the techniques used to quantify reservoir performance under various well spacings and injection patterns.
RCU is a highly stratified, lenticular dolomite reservoir. Continuity of pay between wells is unusually poor, and the reservoir was only partially drained by wells on 40-acre [16-ha] spacing. Ultimately, 10-acre [4-ha] wells and 40-acre [16-ha] inverted ninespot patterns were required for an effective waterflood. Expected recovery from the unit has been increased by more than 23 million bbl [3.8×106 m3] by the drilling of 218 infill wells and an increase in the number of water-injection wells to form the 40-acre [16-ha] inverted nine-spot patterns. (Throughout this paper, 10-, 20-, and 40-acre [4-, 8-, and 16-ha] spacing refers to the nominal spacing of wells, although the exact areas vary.)
Three approaches were used to quantify reservoir continuity as a function of horizontal distance: geologic correlation, pressure-transient benavior, and regression analysis of infill performance. All three techniques indicate that 10-acre [4-ha] spacing can effectively drain 80 to 85 % of the reservoir volume by primary production (solution gas drive). On this spacing, however, reservoir discontinuities limit the floodable volume to only 60 to 65 % of the total reservoir.
These studies have permitted the operator to project the results of further infill drilling quantitatively. They also permit a realistic assessment of EOR potential based on actual floodable reservoir volume calculations.

Background
RCU became effective Jan. 1, 1970, and injection began in the first six injectors almost immediately. By mid-1971, the waterflood had been expanded throughout the unit. Full-scale injection averaged 20,000 to 30,000 BWPD [3.2×103 to 4.8×103 m3/d water] throughout the 1970's, and by 1974, a degree of reservoir fill-up caused an oil production increase. The response peaked briefly in 1974 at 3,500 BOPD [560 m3/d oil] and then began a rapid &gt;25%/yr decline (see Fig. 1). This precipitous decline, and the low ultimate secondary recovery it foretold, prompted the first major reservoir performance review in 1975 and 1976. This marked the beginning of the successful infill drilling program described here.
The first RCU discovery within the unit boundary was in 1946. The field was subsequently named the Doss (Upper Clearfork) field. In 1970, after additional new zone discoveries and various field consolidations by the Texas Railroad Commission, the unitized reservoir consisted of two separate regulatory fields: the Robertson, North (Clearfork 7,100) field, which included the RCU Lower Clearfork, and the Robertson field, which included the Glorieta formation and the Upper Clearfork.
The two reservoirs were first flooded under a "confluent production" program in which dually completed injectors flooded each zone separately while production was commingled in the producers. Then in 1977, the injection wells were commingled, and the entire unitized formation has been operated as a single reservoir since. Reservoir performance studies, as well as injection profile tests, indicate that the waterflood conformance was no worse under the commingled mode than under the previous operation.
The 1976 reservoir study identified two major problems in waterflood performance: inadequate completions and poor reservoir continuity. Extrapolation of production curves forecast an ultimate recovery of only 30 million bbl [4.8×106 m3], 8.3% of the original oil in place (OOIP), with the initial operating scheme. This could be improved to 42 million bbl [6.7×106 m3] by an extensive workover program of perforating additional intervals and selective stimulation. The problem of poor reservoir continuity, however, could be overcome only by infill drilling on closer spacing. Detailed zone-by-zone geologic correlations of porous intervals were developed with techniques reported by George and Stiles.1 These were used to evaluate continuity between wells and thus to estimate recovery from 20-acre [8-ha] infill wells.

Reservoir Geology

Regional Overview.
Geologically, the Robertson field is located on the northeastern edge of the Central Basin platform, which separated the Delaware and Midland basins during the Permian Age (Fig. 2). Production is from Permian Leonardian carbonates of the Glorieta, Upper Clearfork, and Lower Clearfork formations.
The 13 Clearfork fields shown in Fig. 2 have many similar geologic features and demonstrate the effect the Central Basin platform had on Permian carbonate development and stratigraphy. The uplift of the Central Basin platform provided a shallow platform where prolific biological activity could occur, thereby allowing the accumulation of absent carbonate sediments. Progressive deepening of the basin and growth of a marine bank along the margin of the basin accentuated the environmental differences between the basin and shelf areas. An idealized block diagram, shown in Fig. 3, illustrates a shelf margin complex similar to the environment that produced the Robertson carbonates. Hypersaline waters were more common shoreward of the marine bank, with several areas periodically subaerially exposed. Near-normal marine conditions prevailed farther basinward along the platform. Carbonate deposition would tend to build upward and basinward, subject to later dolomitization.

Trapping Mechanism.
The Robertson field is situated on a large northwest/southeast-trending anticline, though most of the trapping of hydrocarbons is controlled by lateral and vertical limits of porosity and permeability. Most Clearfork reservoirs on the Central Basin platform exhibit a similar stratigraphic trapping mechanism.2

Regional Overview.
Geologically, the Robertson field is located on the northeastern edge of the Central Basin platform, which separated the Delaware and Midland basins during the Permian Age (Fig. 2). Production is from Permian Leonardian carbonates of the Glorieta, Upper Clearfork, and Lower Clearfork formations.
The 13 Clearfork fields shown in Fig. 2 have many similar geologic features and demonstrate the effect the Central Basin platform had on Permian carbonate development and stratigraphy. The uplift of the Central Basin platform provided a shallow platform where prolific biological activity could occur, thereby allowing the accumulation of absent carbonate sediments. Progressive deepening of the basin and growth of a marine bank along the margin of the basin accentuated the environmental differences between the basin and shelf areas. An idealized block diagram, shown in Fig. 3, illustrates a shelf margin complex similar to the environment that produced the Robertson carbonates. Hypersaline waters were more common shoreward of the marine bank, with several areas periodically subaerially exposed. Near-normal marine conditions prevailed farther basinward along the platform. Carbonate deposition would tend to build upward and basinward, subject to later dolomitization.

Trapping Mechanism.
The Robertson field is situated on a large northwest/southeast-trending anticline, though most of the trapping of hydrocarbons is controlled by lateral and vertical limits of porosity and permeability. Most Clearfork reservoirs on the Central Basin platform exhibit a similar stratigraphic trapping mechanism.2