The field tests for rheology, mud density, and gel strength are accomplished in the same manner as outlined for water-based muds. The maindif-ference is that rheology is tested at a specific temperature, usually 120°F or 150°F. Because oils tend to thin with temperature, heating fluid is required and should be reported on the API Mud Report.
Sand Content Sand content measurement is the same as for water-base muds except that the mud's base oil instead of water should be used for dilution. The sand content of oil-base mud is not generally tested.
HPHT Filtration The API filtration test result for oil-base muds is usually zero. In relaxed filtrate oil-based muds, the API filtrate should be all oil. The API test does not indicate downhole filtration rates. The alternative high-temperature-high pressure (HTHP) filtration test will generally give a better indication of the fluid loss characteristics of a fluid under downhole temperatures (Figure 1.8).
FIGURE 1.8 HPHT fluid loss testing device.
The instruments for the HTHP filtration test consists essentially of a controlled pressure source, a cell designed to withstand a working pressure of at least 1,000 psi, a system for heating the cell, and a suitable frame to hold the cell and the heating system. For filtration tests at temperatures above 200°F, a pressurized collection cell is attached to the delivery tube. The filter cell is equipped with a thermometer well, oil-resistant gaskets, and a support for the filter paper (Whatman no. 50 or the equivalent). A valve on the filtrate delivery tube controls flow from the cell. A non-hazardous gas such as nitrogen or carbon dioxide should be used as the pressure source. The test is usually performed at a temperature of 220 -350°F and a pressure of 500 psi (differential) over a 30-minute period. When other temperatures, pressures, or times are used, their values should be reported together with test results. If the cake compressibility is desired, the test should be repeated with pressures of 200 psi on the filter cell and 100 psi back pressure on the collection cell. The volume of oil collected at the end of the test should be doubled to correct to a surface area of 7.1 inches.
Electrical Stability The electrical stability test indicates the stability of emulsions of water in oil mixtures. The emulsion tester consists of a reliable circuit using a source of variable AC current (or DC current in portable units) connected to strip electrodes (Figure 1.9). The voltage imposed across the electrodes can be increased until a predetermined amount of current flows through the mud emulsion-breakdown point. Relative stability is indicated as the voltage at the breakdown point and is reported as the electric stability of the fluid on the daily API test report.
Liquids and Solids Content Oil, water, and solids volume percent is determined by retort analysis as in a water-base mud. More time is required to get a complete distillation of an oil mud than for a water mud. The corrected water phase volume, the volume percent of low-gravity solids, and the oil-to-water ratio can then be calculated.
The volume oil-to-water ratio can be found from the procedure below:
Oil fraction 100
% by volume oil or synthetic oil % by volume oil or synthetic oil - % by volume water
Chemical analysis procedures for nonaqueous fluids can be found in the API 13B bulletin available from the American Petroleum Institute.
Alkalinity and Lime Content (NAF) The whole mud alkalinity test procedure is a titration method that measures the volume of standard acid required to react with the alkaline (basic) materials in an oil mud sample. The alkalinity value is used to calculate the pounds per barrel of unreacted, "excess" lime in an oil mud. Excess alkaline materials, such as lime, help to stabilize the emulsion and neutralize carbon dioxide or hydrogen sulfide acidic gases.
Total Salinity (Water-Phase Salinity [WAF] for NAF) The salinity control of NAF fluids is very important for stabilizing water-sensitive shales and clays. Depending on the ionic concentration of the shale waters and of the mud water phase, an osmotic flow of pure water from the weaker salt concentration (in shale) to the stronger salt concentration (in mud) will occur. This may cause dehydration of the shale and, consequently, affect its stabilization (Figure 1.10).
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