Factors Involved in High-Temperature Drilling Fluids
- D.J. Weintritt (Baroid Div., National Lead Co.) | R.G. Hughes (Baroid Div., National Lead Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- June 1965
- Document Type
- Journal Paper
- 707 - 716
- 1965. Society of Petroleum Engineers
- 7 in the last 30 days
- 820 since 2007
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Statistics show an increase in the average depth of wells drilled in recent years. As a corollary to this trend, drilling fluids have been improved in an effort to meet the problems inherent at temperatures approaching 500F. Of importance are (1) deterioration of mud components and (2) the effect of solids on filtration and rheological properties. High-temperature, stable water-base and oil-base muds are discussed. Those areas in which differences exist are pointed out. Results are based on data taken from the Fann consistometer, rheometer and shear-strength measurements, static and dynamic filtration tests, methylene blue test for bentonite solids and specific heat measurements of muds.
Higher well temperatures go along with the fact that the average depth of wells continues to increase. Recent data by Gardner lists 137 completions deeper than 15,000 ft for the first half of 1964 with a record second-half total of 167 wells drilling or proposed, In addition, there has been an increase in drilling for steam for power production or mineral recovery. In this application the depths are modest, but the mud may approach the critical pressure and temperature of water. Scearce and Magnon report drilling mud used at temperatures of about 700F in the Salton Sea area of California. Most deep wells have been drilled with water-base muds. In recent years, however, there has been a substantial increase in the use of oil-base muds because of technological advances in effective additives. The significance of this development was dealt with in considerable detail by Simpson and his co-workers. Additional field data have now been obtained to indicate that oil muds are competitive in control, performance and cost with the best types of water muds for use at high temperature. This parallel offer of two very different fluid systems, each offering a similar variability in performance, cost and convenience, has created the need to evaluate the merits of these fluids under specified conditions so that the advantages and disadvantages of each can be weighed in relation to the over-all drilling program. This paper is not intended as a review of all the factors. Rather, it attempts to emphasize: (1) important conditions and facts peculiar to high-temperature drilling muds, (2) that more than one imposed test condition or testing method is necessary to describe the quality of a mud at high temperature and (3) that elaborate experimental precautions are necessary whenever laboratory data are used in selection of a mud for field use.
WHAT IS A HIGH-TEMPERATURE DRILLING FLUID?
For the purpose of this discussion, a high-temperature drilling fluid is any system so formulated or treated to economically minimize the effects of temperature on the properties of the fluid. Our experience in drilling fluids suggests that these effects become obvious for many mud materials at temperatures of 300F or higher. It is understood that hydrolysis of starches, depolymerization of certain organic thinners, or irreversible chemical reactions (such as that of clay and lime) can affect filtration, viscosity and shear strength at less than 300F. However, the temperature level is not a serious point and in no way affects the precautions and techniques used in this study. An up-to-date review of the literature on high-temperature drilling fluids and the many variations was treated by Rogers in 1963.
EXPERIMENTAL REQUIREMENTS TESTING EQUIPMENT AND PROCEDURES With the advent of deeper drilling and increased demand for temperature-stable drilling fluids, new testing equipment and laboratory techniques were devised for the evaluation of drilling fluids subjected to elevated temperature and pressure. While the equipment has not been standardized, it is in widespread use. Milligan et al. describe a filtration cell for determining the filtration properties of drilling fluids at temperatures in excess of 300F. They showed the effect of variations in temperature and pressure on oil and water muds filtered in the 300 to 400F range. The dynamic filtration apparatus described by Simpson permits the study of the filtration properties to temperatures of 350F for drilling fluids circulated over sandstone cores. Watkins et al. describe the use of pressure bombs for studying the effect of prolonged periods of elevated temperature upon the gelation or solidification of drilling fluids. Chisholm et al. describe the use of a modified cement consistometer adapted for use in drilling fluid evaluations. A similar consistometer is used in this study, although the application and data-recording method have been changed. The consistency of a mud sample is measured by timing the movement of a soft iron bob which is magnetically moved up and down in the sample container.* Changes in the time of travel and the temperature of the mud at that moment are plotted with a two-point Brown Electronik Recorder. A 10-in. chart with a speed of 4-in./hr is used.
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