Performance of Oilwell Cementing Compositions in Geothermal Wells
- J.P. Gallus (Union Oil Co. of California) | L.T. Watters (Halliburton Services) | D.E. Pyle (Union Oil Co. of California)
- Document ID
- Society of Petroleum Engineers
- Society of Petroleum Engineers Journal
- Publication Date
- August 1979
- Document Type
- Journal Paper
- 233 - 241
- 1979. Society of Petroleum Engineers
- 4.3.1 Hydrates, 1.14.3 Cement Formulation (Chemistry, Properties), 1.14 Casing and Cementing, 1.11 Drilling Fluids and Materials, 5.9.2 Geothermal Resources, 4.1.5 Processing Equipment, 4.1.2 Separation and Treating, 2.4.3 Sand/Solids Control, 5.2 Reservoir Fluid Dynamics
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Just a few years ago, there existed a great uncertainty regarding the durability of oilwell cements in geothermal wells. Limited, and at times apparently unreliable, information suggested that conventional well cements may not be sufficiently resistant to geothermal well fluids and temperatures for the expected 20- or 30-year service life of the average geothermal well. Therefore, we began to investigate the performance of numerous oilwell cementing compositions in actual geothermal environments. Duplicate samples were exposed to actual geothermal well temperatures and fluids in the Baca, NM, and Imperial Valley, CA, geothermal fields for periods of up to 1 year. A novel testing procedure for geothermal cements was developed and successfully applied in these experiments. Laboratory evaluation of the exposed samples measured the durability of various compositions. The work indicated that some oilwell cements apparently can be rendered sufficiently resistant to geothermal well conditions for the service life of a geothermal well.
The research completed and reported here was prompted primarily by uncertainty about the durability of any cement to be applied in geothermal wells with bottomhole temperatures ranging from 400 to 750 deg. F (204 to 399 deg. C) or produced flashing brine. The required well-service life ranged from 20 to 30 years.
Several problems existed. First, the literature contained little applicable information about high-temperature hydrothermal cement chemistry. Prediction of the service life of cements in geothermal environments on the basis of known cement chemistry clearly was impossible. Prediction was of vital concern to operators responsible for safe, as well as competent, geothermal wells, particularly when serious cement-strength retrogression and deterioration generally was known to occur at elevated temperatures. Second, results of an early field test [which exposed samples of oilwell cements as 2-in. (5-cm) precured cement cubes to 600 deg. F (316 deg. C) brine in a geothermal well for periods up to 1 year] strongly suggested that even the three best cementing compositions tested might deteriorate to less than minimum acceptable compressive strengths within 3 to 9 years during geothermal well service. Other field experiments with oilwell cements in contact with produced geothermal fluids also yielded information showing extremely rapid (30- to 60-day) cement deterioration in strength and permeability. Thus, an API Class G cement (without silica) completely disintegrated (to granular size) in 30 days when exposed to 460 deg. F (238 deg. C) steam. Significantly we found that this sample contained (on X-ray diffraction analysis) both dicalcium silicate hydrate and large amounts of calcium hydroxide and carbonate. In another sample of this cement, compressive strength degraded by 77% from 5,050 to 1,150 psi (34.8 to 7.93 MPa) and permeability increased from 0.012 to 8.3 md in 60 days of aging in a produced geothermal brine of only 320 deg. F (160 deg. C) temperature.
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