Permeability Reduction Through Changes in pH and Salinity
- Necmettin Mungan (Sinclair Oil And Gas Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- December 1965
- Document Type
- Journal Paper
- 1,449 - 1,453
- 1965. Society of Petroleum Engineers
- 6 in the last 30 days
- 1,074 since 2007
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Formation damage, i.e., reduction in permeability, has been generally attributed to clay minerals which expand or disperse upon contact with water that is less saline than the connate water. Laboratory studies show that permeability reduction can also occur in formations containing only nonexpandable clays, such as illite or kaolinite, and can be caused also by changes in pH. Furthermore, pH changes can damage even formations that are essentially free of clay. It is suggested that permeability reduction is due to the small passages being blocked by particles, which may be dispersed clays, cementation material or other fine particles. These particles are dislodged by dispersion of clays due to changes in salinity or by dissolution of calcareous cement by acids, or of silicaceous cement by alkaline solutions. In working with reservoir cores, it was found that extracted cores damaged more easily and extensively than nonextracted cores. The extent of damage depended also on temperature.
Permeability is an important property of porous media and has been the subject of many studies by engineers and geologists. Many of these studies are concerned with formation damage, i.e., reduction in permeability, resulting from exposure of oil-producing formations to water substantially less saline than the connate water. This effect causes understandable concern since during drilling, completion and production phases formations are often exposed to fresh water. The damage resulting from contact with relatively fresh water bas been attributed to expansion and dispersion of clay minerals. During laboratory investigation of the use of NaOH as a wettability reversal agent to increase oil recovery from oil-wet reservoirs, several cores used in the displacement studies suffered loss in permeability. Despite the traditional usage of NaOH for conditioning aqueous mud systems, the role of the caustic filtrate in wellbore damage seems to have been overlooked. Browning has recently reported on the effects of NaOH in dispersing clay minerals but he was concerned only with complications that may arise in drilling massive shale beds. The following study was made to examine the role of pH and salinity changes in core damage. Where corns from reservoirs were used, tests were performed with extracted and nonextracted cores both at room and reservoir temperatures, since it was felt that the test environment and core condition may affect the results. Because of its limited coverage and exploratory nature, this study is not intended to provide answers to field formation damage problems. It is hoped that it will encourage research into new aspects of the permeability reduction problems, particularly those allied to new recovery and production processes.
In all permeability tests, fluids were pumped through the cores at a constant volumetric rate. Only deaerated fluids and reagent grade chemicals were used. The fluids were passed through two ultrafine filters before injection to remove any entrained particles. The cores, with the exception of the unconsolidated cores, were mounted in Hassler holders. Water was used to transmit pressure to the sleeve. The inlet endpiece had two entry ports which permitted scavenging one fluid with another to avoid any mixing in the small holdup volume. The cores were flushed with CO2 gas, evacuated for 5 to 6 hours and saturated with the first liquid at a pressure of 1,000 psi for 24 hours to eliminate any free gas from the cores. Pressure differences up to 20 psi were measured by transducers, calibrated in inches of water and continuously recorded. For greater pressure drops, gauges were used. All reservoir cores were cleaned with a light refined mineral oil, then with heptane, and finally dried with CO2. Compatibility tests showed that no precipitates formed when mineral oil and the crudes were mixed. Some cores were extracted in Dean-Stark-type solvent extractors using xylene and trichloroethane and dried in a vacuum oven at 450F. Each test consisted of a sequence of water, test solution, and again water flow.
RESULTS AND DISCUSSION
STUDIES IN BEREA CORES
Berea cores 2-in. in diameter and 12-in. long were cut from sandstone quarried in Cleveland, Ohio. The clay minerals were identified by X-ray diffraction to be chlorite, kaolinite, illite and interlayered illite. Flow of fresh water or 30,000 ppm brine does not cause any permeability reduction (Fig. 1). However, after injection of brine the core is readily damaged by fresh water. Damage starts almost instantly as the fresh water injection is begun, and at a cumulative injection of 1.2 PV fresh water, the permeability has dropped from 190 to 0.9 md. Upon continued injection, the effluent contains clay minerals dislodged from the core.
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