Progress Report on Spraberry Waterflood Reservoir Performance, Well Stimulation and Water Treating and Handling
Authors: Elkins L.F. , Skov A.M. 
Published: December 2007

Comparison of long term decline in oil production during cyclic waterflooding or pressure pulsing of part of the Driver Unit with steady injection-imbibition flooding in the Tex Harvey area led to large expansion of flood in the Driver Unit on the steady injection basis. While the flood has been successful, the major problem has been attainment of satisfactory oil production rates in most of the wells. Large volume fracture treatments of low capacity wells were unsuccessful in achieving sustained increases in production. A two-section area in the Driver Unit has already recovered 620 bbl of oil per acre by waterflood but other areas have not performed so well.

San Andres water containing 300 to 500 ppm H2S is sweetened to 0.5 to 1 ppm H2S by extraction with oxygen-free flue gas. This prevents contamination of gas produced in the area and apparently it has reduced corrosion in minimum investment, thin-wall. cement-lined water distribution systems. Cement-lined tubing in injection wells has mitigated corrosion as effectively as thick polyvinyl chloride films have, and at less cost.

Introduction

As reported in the literature, the Spraberry field of West Texas has presented unusual problems for both primary production and waterflooding. Earlier information from the Spraberry Driver Unit included conception and evaluation of cyclic waterflooding or pressure pulsing in a nine-section pilot test as an aid to extraction of oil from the tight matrix rock and as a boost to normal capillary imbibition forces. An additional 5 years operation in that area, and performance of expanded steady injection water-flood, now covering a total of 68 sq miles, are reported herein. In addition, since the Driver Unit is one of the largest waterfloods in areal extent in the U. S., many operating experiences are presented for the benefit of engineers concerned with operation of other Spraberry floods or with other waterfloods where this reservoir technology and/or water handling technology may be adaptable in part. These include:attempts to improve producing well capacity through large volume fracture treatments,long-term performance of water treating plants utilizing oxygen-free flue gas to extract H2S from sour San Andres water,performance of thin-wall cement-lined pipe in water distribution systems including comparison between those sections carrying raw San Andres water and those carrying treated water, andcomparison of performance of various lining materials and subsurface equipment in water supply and water injection wells.

These experiences are reported without regard to whether results are good, bad or indifferent. Since the operations reported are limited to the techniques, materials, and equipment actually used in the Driver Unit, no comparison is possible with results of other approaches used in other Spraberry floods or in waterfloods generally under different conditions. However, an attempt is made to quantify these experiences as much as possible in the space available to permit other engineers to select those parts applicable to their problems.

Background

The Spraberry, discovered in Feb., 1949, is a 1,000-ft section of sandstones, shales and limestones with two main oil productive members-a 10- to 15-ft sand near the top and a 10- to 15-ft sand near the base, having permeabilities of 1 md or less and porosities of 8 to 15 percent. Extensive interconnected vertical fractures permitted recovery of oil on 160-acre spacing from this fractional-millidarcy sandstone, but they made capillary end effects dominant. Primary recovery by solution gas drive is less than 10 percent of oil in place, with most wells declining to oil production of a few barrels per day when reservoir pressures are still in the range of 400 to 1,000 psi. Partial closing of the fractures with declining reservoir pressure is believed to be the cause of such low production rates at these relatively high reservoir pressures.

In 1952 Brownscombe and Dyes proposed that displacement of oil by capillary imbibition of water from the fractures into the matrix rock might significantly increase oil recovery from the Spraberry, overcoming otherwise serious channelling of water through the fractures. A pilot test conducted by the Atlantic Refining Co. during 1952 through 1955 indicated technical feasibility of the process; but low oil production rates averaging 15 to 20 bbl/well/D failed to create significant interest in large-scale waterflooding at that time.

JPT

P. 1039ˆ