A high pH buffer-regulated acetic acid hydrofluoric acid system was used to stimulate the Norphlet sand in the Cox Well No. 5, Piney Woods, Mississippi (BHP = 18,500 psi; BHT >365 deg. F; sour gas). An HF-acid treatment was indicated when a possible cause of low productivity was detected by possible cause of low productivity was detected by scanning electron microscope (SEM) examination of the formation rock. Photographs showed illite clay distributed as an interwoven filamentous network in the pores of the rock. Conventional low pH HF acids could not be used because of potential severe corrosion problems. Corrosion tests at simulated reservoir problems. Corrosion tests at simulated reservoir conditions showed that the buffer regulated acid (pH = 5.2) could be used in this application without corrosion inhibitors, thereby eliminating possible permeability impairment from inhibitors. permeability impairment from inhibitors. Flow tests on Norphlet core material showed that the acid treatment increased permeability by factors varying from two to more than 100. SEM photographs indicated that the illite clay was removed photographs indicated that the illite clay was removed by the treatment.
The well was treated with the high pH acid system without significant problems. Stimulation resulted, but the production rate was still too low for the well to be an economic producer.
The Cox No. 5, Piney Woods field, Mississippi was completed in the Norphlet sand, a "tight" sour gas-bearing sandstone (k less than 0.5 md) at a depth of 21,411-21,727 feet. Bottom hole temperatures were in excess of 365 deg. F. The production performance of the well was below expectations. A performance of the well was below expectations. A laboratory investigation was undertaken to evaluate the applicability of several of Shell's high pH buffer regulated-HF acid systems for stimulating this well. The severe corrosion problems at bottom hole conditions eliminated use of regular HCl-HF acid systems.
The usual sources of impairment resulting from well operations were considered. A detailed examination of the geological and petrophysical properties of the sandstone, however, revealed a more properties of the sandstone, however, revealed a more likely cause for the poor production performance. SEM (scanning electron microscope) photographs showed the presence of illite clay in the pores. This clay formed a network which could be a cause of the low permeability. It was recognized that if the clay was permeability. It was recognized that if the clay was the sole cause of the low permeability, its removal from the near well bore region would not result in a large productivity increase. Candidate acids were screened and qualified by conducting flow and corrosion tests at simulated downhole conditions.
The purpose of this report is to review the testing which led to a recommendation for stimulation with a high pH buffered HF acid, BRHFA-A* (using acetic acid and ammonium acetate for buffering), and to review the treatment and results of its application to Cox No. 5.
POSSIBLE SOURCES OF LIMITED PRODUCTIVITY POSSIBLE SOURCES OF LIMITED PRODUCTIVITY This study was concerned primarily with those factors which might affect productivity through near well bore effects, such as drilling and completion fluids, solid salt, clay, etc. Questions relating to whether the sand could be produced economically with the removal of production limiting effects near the well bore are beyond the scope of this report.
Impairment Due to Operation Fluids
In the drilling and completion of the well, considerable attention was devoted to minimizing the effects of impairment which might result from drilling, completion, and workover fluids. Acid-soluble solids were used whenever possible. Nevertheless, it was necessary to use barite to weight the oil-base drilling muds and a combination of ferrous phosphide (insoluble in HCl or HCl-HF) and calcium carbonate in the perforation pills. The pill formed a mud cake which perforation pills. The pill formed a mud cake which was about 65-70 percent (volume) soluble in 12 percent formic acid.