Evaluating Barite as a Source of Soluble Carbonate and Sulfide Contamination in Drilling Fluids
- George G. Binder Jr. (Exxon Production Research Co.) | Louis A. Carlton (Exxon Co. U.S.A.) | Robert L. Garrett (Exxon Production Research Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- December 1981
- Document Type
- Journal Paper
- 2,371 - 2,376
- 1981. Society of Petroleum Engineers
- 2.2.3 Fluid Loss Control, 1.10 Drilling Equipment, 1.11 Drilling Fluids and Materials, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 6.1.5 Human Resources, Competence and Training, 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 1.6 Drilling Operations
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Even when drilling-grade barites meet all current API specifications, they frequently are contaminated sufficiently with alkaline-soluble carbonate and sulfide minerals to cause serious drilling fluid problems. This paper describes in detail a new supplementary quality paper describes in detail a new supplementary quality control test that can identify many of these problem barites. Widespread use of this new test should facilitate a significant improvement in the quality of barite used in drilling operations.
Barite is the overwhelming, choice as a material to build density in drilling fluids. In 1980, more than 3 million tons of barite were used in the U.S. for this purpose. A single barrel of high-density drilling fluid may contain more than 500 lbm of barite so that even small concentrations of impurities in barite can put significant contamination into the drilling fluid.
Pure barite is barium sulfate (BaSO4) and is insoluble throughout the pH range encountered in drilling fluids. Commercial barites meeting current API specifications frequently contain from 10 to 30 wt% of a complex mixture of water-insoluble mineral impurities, but some of these impurities are soluble in alkaline drilling fluids. The cations from these solubilized impurities usually are precipitated as insoluble hydroxides and probably cause precipitated as insoluble hydroxides and probably cause little trouble. The anions, however, usually remain in solution, and when these anions are carbonates or sulfides, they can cause serious drilling fluid problems such as lost circulation, stuck pipe, and even problems such as lost circulation, stuck pipe, and even catastrophic loss of the well.
Because of the complex composition of commercial barites, chemical analysis is of limited value in identifying barites that have the potential to cause serious drilling problems. Consequently, a simple screening test has been developed that can identify; those barites that have the potential to generate harmful quantities of soluble carbonate or sulfide ions. It is hoped that this test will be used widely by suppliers to select quality ores and by users to ensure receipt of quality material and to provide early warning of incipient field problems related to carbonate or sulfide ions. Guidelines for interpreting test results in terms of barite quality are highly dependent on specific drilling fluid formulations, and it is beyond the scope of this paper to suggest absolute standards that could be used to qualify a given barite for general use.
This paper discusses (1) Exxon Co. U.S.A.'s field experience with carbonate and sulfide contamination from barite, (2) the sensitivity of a barite caustic extraction test to temperature, reaction time, and sodium hydroxide concentration, (3) test precision, and (4) recommended test use. A detailed test procedure is given in the Appendix.
Field Experience with Carbonate and Sulfide Contamination From Impure Barite
The first clearly documented case of high levels of carbonate ion contamination derived from caustic-soluble materials in a commercial barite meeting current API specifications occurred in 1977 in an Exxon drilling operation at a Laterre well in the Lirette field in southern Louisiana. In addition to the usual rheological, filtration, and chemical tests, the drilling fluid at this well was being monitored by the Garrett Gas Train (GTT) method for carbonates, a new test in 1977. Excessive gel strengths were being encountered on this Laterre well but were not seen on an almost identical offset well.
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