Conventional water-base drilling fluids

Of even more economic importance is the rheological impact of the addition of KC1 to conventional water-base drilling fluids. KC1 causes undesirable increases in both yield point and gel strength that can only be eliminated by chemical disperants or by dilution with fresh water. Dilution in turn requires more KC1 for clay inhibition, and the cycle continues with mud costs escalating exponentially. 

The disposal of drilling fluid waste has become a major factor in the use of chemicals in water-based drilling fluids and in the use of oil-based drilling fluids because the dumping of waste from conventional (i.e., non-synthetic) oil-based fluids (drilling fluid and cuttings contaminated with oil from the fluid) is increasingly prohibited. 

Borates are not used to any significant extent today in conventional water- or oil-based drilling fluids/muds. Table 17.7 summarizes the limited published literature in this area. 

Fatty Acid Esters. Defoamers that are more environmentally acceptable than convential products are based on fatty acid esters of hydroxy alcohols, such as sorbitan monooleate [1908] or sorbitan monolaurate in combination with diethylene glycol monobutyl ether as a cosolvent [451]. These defoamer compositions are as effective as conventional materials, for example, those based on acetylenic alcohols are less toxic, especially to marine organisms, and are readily biodegradable. The defoamer compositions are used in water-based hydrocarbon well fluids during oil/gas well drilling, completion, and workover, especially in marine conditions. 

The use of natural gas as the circulating fluid drilling gas in a deep gas formation (rather than air or conventional muds) was reported by Cooley and Dethloff (1985). The gas available for this use was saturated with water and contained 6% CO2 and 3,000 ppm H2S. The CO2 and H2S levels were considered too high so a gas purification system based on membrane permeation was installed. The membrane unit reduced the CO2 content to 2%. The H2S content was reduced to 600 ppm, which then could be economically treated with an iron sponge unit. Operating data are presented in Table 15-14. 

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