A high-pressure, high-temperature acid permeameter constructed to investigate the reaction of HCl-HF on sandstone cores at reservoir conditions is providing new insight into the reservoir and treatment variables that control the acidizing process. Introduction The literature has contained much discussion of both the theory and the practice of acid stimulation of oil-bearing formations. Of the hundreds of published papers dealing with the hydrochloric acid-limestone papers dealing with the hydrochloric acid-limestone reaction, a few notable ones are listed as Refs. 1 through 3. More recently in vogue is the matrix stimulation of sandstone reservoirs with hydrochloric and hydrofluoric (HCl-HF) acid mixtures. The reaction of HCl-HF on a sandstone matrix was studied in the laboratory by Smith and Hendrickson. Also, laboratory data were used to improve field techniques of matrix acidizing. Though these works contributed significantly to acidizing technology, there remain many unexplored facets of this complex stimulation mechanism. Our purpose here is to describe an apparatus developed to investigate the reactions of HCl-HF on the sandstone matrix at reservoir conditions and to discuss the application of experimental results to field treatment design. Description of Apparatus The high-pressure, high-temperature acid permeameter was designed to handle concentrated acid permeameter was designed to handle concentrated acid mixtures at temperatures to 250 degrees F. The working limits for overburden pressure and injection pressure are 10,000 psi and 4,000 psi respectively. The equipment was fully automated to reduce the hazards of handling hot HCl-HF under pressure and because of the long duration of some experiments. The corrosivity of the acids required that parts of the equipment be constructed of Hastelloy B. The apparatus was designed to have both research and technical service capabilities. Experimental versatility was incorported into the design. The apparatus can be programmed to perform a number of sequential steps (listed in Appendix A) -measure initial oil permeability at irreducible water saturation for the untreated core sample,measure damage of the core sample by drilling mud,evaluate the degree of damage by measuring return permeability to oil,evaluate treatment with acid, and finally,measure return permeability to oil following stimulation. Data are monitored automatically during an experiment and are processed and presented graphically by means of a high-speed digital computer and a plotting program. plotting program. The high-pressure, high-temperature acid permeameter shown in Fig. 1 is located in a special building permeameter shown in Fig. 1 is located in a special building that is divided into two sections, a control room containing low-pressure control and data-logging equipment and a room containing the high-pressure equipmentData that are logged automatically are processed by computer programs. One program plots the permeability data as a function of cumulative throughput permeability data as a function of cumulative throughput and labels the steps of interest. A typical plot is presented in Fig. 2. presented in Fig. 2. JPT P. 433

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One of the most important factors affecting success of waterflood performance is maintenance of water quality. Determining minimum water quality is difficult because water quality requirements are as varied as the formations to be flooded. Previously, attempts have been made to set quantitative standards based on simple tests for water quality. However, injection water quality is best measured by formation core flooding at conditions that model fullscale injection operations. While acceptability of source water can be determined in the laboratory by flooding formation core material, it is difficult to acquire representative water samples because of water instability. On-site core flooding at sand face injection temperature with water from a pilot treating plant minimizes water quality uncertainty and permits continuous, on-line screening for development of treating and filtering requirements. Water injection acceptability and pilot plant evaluation provide determination of corrosivity, filtration efficiency, treatment additive compatibility and treatment economics. This source water evaluation method improves waterflooding economics in two important ways:minimum treatment cost to maintain continuous injection without permeability decline is established; andthe possibility of injection well damage is reduced. Introduction An evaluation study of an injection water source is described. In addition to the usual determinations of bacterial activity and corrosivity, this on-site pilot plant study evaluated particle plugging tendency, scaling tendency, treating chemical compatibility and potential clay problems by formation core flooding at sand face injection temperature. The purpose was to provide an economic means of maintaining injectivity in West Montalvo field, Oxnard, Calif., by developing a chemical treatment and filtration system from core flood tests. Injection History Water injection in the West Montalvo field began in 1963, with the injection of produced brine into the McGrath pool. Immediate injection problems resulted from inadequate water treatment. In mid-1964, a shallow source well was drilled on the ocean shore to supply saline injection water for both the McGrath and Colonia pools. Water analysis and injection tests performed in the laboratory indicated the new water to be suitable after minor chemical treatment and filtration. Injection into a Colonia zone well began in Sept., 1964, at an average rate of 600 BWPD at 3,000 psig. However, the rate declined to 440 BWPD at 4,600 psia within 3 months. Injection wells continued to plug and required repeated acid stimulations to maintain injection (Fig. 1). Injection in the initial injector could not be maintained economically, and in April, 1966, the well was shut in. Reservoir characteristics peculiar to the Colonia zone were apparently part of the problem because injectivity was much better in the McGrath pool. The Colonia zone is a thick, non-marine, Oligocene section comprising a series of thin oil- and water-bearing sand lenses interbedded with shales. Petrographic analysis of core material indicated sufficient kaolinite. illite and montmorillonite to cause permeability damage from clay migration. Clay sensitivity and poor water quality were probable causes of damage to Colonia zone injectors; therefore, a flow test program was designed to evaluate injection problems. JPT P. 683ˆ

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