New Nondamaging and Acid-Degradable Drilling and Completion Fluids
- R.N. Tuttle (Shell Oil Co.) | J.H. Barkman (Shell International Petroleum Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- November 1974
- Document Type
- Journal Paper
- 1,221 - 1,226
- 1974. Society of Petroleum Engineers
- 3 Production and Well Operations, 4.1.2 Separation and Treating, 2.2.3 Fluid Loss Control, 3.2.4 Acidising, 1.8 Formation Damage, 2 Well Completion, 2.2.2 Perforating, 2.7.1 Completion Fluids, 2.4.3 Sand/Solids Control, 5.1 Reservoir Characterisation, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 1.6.9 Coring, Fishing, 3.1.3 Hydraulic and Jet Pumps, 4.3.4 Scale, 1.6 Drilling Operations
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Tests showed that the guar gum and unfiltered bay water contained in some completion fluids were the probable cause of irreversible formation damage. Accordingly, several new fluids were tested. Those systems that have proved successful and are now in routine field use are calcium carbonate-brine and calcium carbonate-hydroxyethylcellulose-brine.
The necessity for higher production rates to supply the increased demand for oil and gas in the U. S. implies a need for unimpaired wells. Most research and development have been directed at simply reducing drilling and workover costs. The energy need is changing this situation by removing prorationing and increasing the value of the oil. Thus we are now more concerned about the effects of drilling and completion practices on well productivity. Although this concern practices on well productivity. Although this concern is not new, until recently its economic significance was insufficient to justify an extensive effort to solve the problem. problem. During 1967, Shell became aware that sand control failures in the Gulf Coast area might be related to well impairment caused by the completion fluids in use at that time. As a result, research and field testing were initiated in order to define the problem and to obtain solutions. We shall describe here some of the results of that research, including the development and testing of several acid-degradable and nondamaging completion fluids.
Evaluation of Previous Completion Fluids
The completion fluids commonly used by Shell in the Gulf Coast area when the tests were begun were (1) bay water containing 5 percent sodium chloride, (2) filtered bay water containing 5 percent sodium chloride, and (3) bay water containing guar gum and 5 percent sodium chloride. These fluids were used because they were inexpensive, the ingredients were easily obtainable, and they appeared to work satisfactorily. The term "bay water" as used here refers to any untreated surface water available at the well location. It varies from fresh to saline and from clear to brown and turbid in appearance. Salt was added to prevent possible damage to fresh-water-sensitive formations. possible damage to fresh-water-sensitive formations. Guar gum was added for viscosity control to remove sand and drill cuttings from the hole and to reduce fluid loss to the formation.
Impairment by Bay Water Solids
Laboratory and field tests were conducted on both filtered and unfiltered bay water. It was found that the bay water, which contained clays and other fine solids, severely reduced the permeability of the test core as a result of filter cake formation on the inflow face and deep particle invasion. In general, only 10 to 30 percent of the initial permeability could be regained by simply backflowing with clean brine. Not more than 50 percent of the original permeability could be restored by large-volume treatments of mud acid (over 100 PV). Filtration tests were conducted in the field using 50-, 25-, 10-, 5-, and 2-micron cotton cartridge filters. The tests showed that the 2-micron filters resulted in the lowest rate of impairment, except for water that was filtered with a sand pack.
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