STIMULATION AND DAMAGE REMOVAL OF CALCIUM CARBONATE SCALING IN GEOTHERMAL WELLS: A CASE STUDY

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1 Evanoff et al. STIMULATION AND DAMAGE REMOVAL OF CALCIUM CARBONATE SCALING IN GEOTHERMAL WELLS: A CASE STUDY Jerry Evanoff, Valerie Yeager (Halliburton Energy Services S. 2nd Duncan, OK and Paul Spielman (California Energy Co., Inc N. Heritage, Building D, Ridgecrest, CA 93555) Key words: geothermal wells, scaling, calcium carbonate, acid treatment ABSTRACT As geothermal activity in the Western United States continues, most problems associated with well production have centered around mechanics, drilling, and cementing. However, decreases in production in California Energy s Geothermal Area have required damage removal and/or actual stimulation as a result of calcium carbonate scaling. This paper addresses three categories of problem geothermal wells: wells with calcium carbonate scale in the wellbore wells that require stimulation of the producing zone or that have calcium carbonate scale in the formation wells where treatment may eliminate non-condensable gas (NCG) surges This paper contains background characteristics, treatment design information, and production histories for each of the three well types. It also examines the success and cost-effectiveness of acid treatments for each well type. 1. INTRODUCTION As with many geothermal reservoirs, the reservoir fluids are saturated with calcium carbonate. In addition, supersaturation occurs because of production-induced boiling. As a result, most of the wells have significant calcium carbonate scaling potential, which can result in reduced production. Various methods have been tried to prevent scaling in geothermal wells, including varying pressure, changing the temperature profile or seeding, and using scale inhibitors. While scale inhibitors have solved many problems, scale is still necessary in many wells 1995). One promising alternative to these methods is acidizing. Hydrochloric acid hydrofluoric acid or both have been tried by a few companies with limited success (Lindal, 1989; Vetter, 1987; Featherstone, 1979; Ungemach, Auberbach, 1983; Asperger, 1986; Harrar, 1982; DaSie, 1984). The hesitancy to use acidizing is generally based on the following concerns: significant corrosion rates with the mineral acids HF) at the temperatures encountered in geothermal wells possible interference with surface processes As shown in Figure the Geothermal Area is located in County, California in the southwest comer of the Great Basin adjacent to the southern part of the Sierra Nevada and north of the Mojave Desert provinces (Plouff, 1980). It is operated by California Energy Company, Inc. (CECI), who initially contracted with the U.S. Navy to explore the geothermal potential of certain Navy-owned land within the China Lake Naval Weapons Center. The company later acquired additional leases from the U.S. Bureau of Land Management. In 1981, several wells were drilled that revealed a fracture-controlled, hot-water geothermal resource relatively near the surface. This resource had temperatures ranging from 200 to 350 C (Brophy, 1984). Scale formation is one of the primary problems associated with geothermal well production. Generally, three basic classes of scale can cause problems: silica and silicates sulfates and sulfides carbonates (Corsi, 1986) Figure I--location of Range. 2481

2 Evanoff et placement problems resulting from large intervals of completion In addition, wellbore characteristics have seldom been evaluated in relation to success and cost-effectiveness. 2. DETERMINATION OF PROBLEM Almost all geothermal systems contain dissolved carbon dioxide in a water solution at equilibrium. The amount of CO, present is proportional to the partial pressure of the gas in contact with the solution according to Henry s Law (Corsi, 1986). The low of the fluids under reservoir conditions caused by the presence of the carbon dioxide in solution keeps scaling from occurring in the reservoir. However, as fluid is produced and carbon dioxide comes out of solution, the increases, liquid volume decreases, and the solubility of various ions in solution changes. Often, these changes cause the precipitation of calcium carbonate scale. With the extreme changes in pressure and temperature that are usually encountered in geothermal wells, other researchers have documented the loss of 80% of the calcium present in solution to scales formed in the casing before the fluid reaches the surface (DaSie, 1984). In many cases, while significant levels of calcium exist in the reservoir fluids, the calcium contents at surface never exceed a few hundred because most of the calcium precipitates as it comes to the surface, and is deposited on tubulars as scale (Giannimaras, 1989). This low calcium level is consistent with laboratory analysis (Reed, 1989) (Benoit, 1989). There is less calcium in the surface water from the CECI wells than the amount present in the unflashed reservoir water or in surface water from wells that have scale inhibitor systems in place. Although samples from the surface or in flowlines seemed to indicate the presence of silica materials (Halliburton, the formation of calcium carbonate scale was eventually determined from downhole samples. These samples were obtained during mechanical cleanouts and workovers to drill out scale blockages. A few drops of indicated 25,000 - [counts] 30,000-20,000-15,000-10,000-5, I Calcite Figure 2-X-ray Diffraction Scan of Downhole Scale Sample from Well X that the scale is readily soluble. Confirmation with X-ray diffraction (Figure 2, Table 1) of a downhole sample from Well A indicates that the scale is predominantly calcite (calcium carbonate) with a trace of strontium sulfate. Table 1-Laboratory Analysis Results Mineral Calcite Celestite Chemical Name Percentage of Sample % 1% 3. GENERAL TREATMENT DESIGN To prevent the excessive corrosion rates expected at these temperatures, large cooling preflushes were injected before the acidizing job. Based on temperature surveys, the target temperature of 120 Ccould be achieved with preflush volumes of 151 (40,000 gal) of cold, fresh water with a friction reducer. Similar overflush volumes were used to displace the acid. Nitrogen gas was then used to lift or jet the fluid volumes and return the wells to production. Additives in the acid were limited to an iron sequestrant and appropriate amounts of corrosion inhibitor. Such corrosion inhibitors can effectively withstand corrosion at the cool-down temperature. The placement problems resulting from long completion intervals have been at least partially prevented through the use of large volumes of acid pumped at high rates. However, the upper part of the completion interval still receives the bulk of the treatment. Attempts to pump acid through tubing to the bottom of the well have been unsuccessful because of insufficient cool-down at the restricted rates. After treatment, the wells were flowed to a sump until the gas and returned to normal. This process was performed to reduce the interference with surface processes. 4. EXAMPLE 1-REMOVAL OF SCALE FROM WELL A Deposits of calcium carbonate scale in the wellbore have been a serious problem in both producing and injection oil, gas, and geothermal wells for many years. In at least one study on geothermal scaling, scale thicknesses ranged from 0.7 to approximately 3 cm and resulted in costly fluid restrictions of 10to 45% (Vetter, 1987). In several wells, scale has completely restricted 33.9-cm (13 casing. Well A, drilled and completed in 1987, was one of the first wells acidized in This particular job marked the first time that acid was used to remove scale from a wellbore in this field. Scale blockage was indicated in the wellbore 2482

3 during a wireline run with a gauge ring. Production before acidizing was 0.3 megawatts (MW). After the 151 (40,000 gal) 15% treatment, production increased 400% to 1.5 and as of December 1993, it continued to maintain this increased output of power. Figure 3 shows the production history of this well. The success of the treatment can be seen by an increase in wellhead pressure and production rate Acid Treatment High-pressure Steam Time, Days -Wellhead Pressure I Evanoff et In addition, geothermal wells may have some carbonate minerals naturally occurring in the formation. As the reservoir pressure declines, wells having low permeability will stop producing because of the low-flowing wellhead pressure. When there is no scale in the wellbore and inflow to the well is single-phase, the only remedy is to reduce hydraulic pressure drawdown by opening flow paths in the formation. One method by which either of these objectives can be achieved is to chemically dissolve the calcite, whether it exists as scale or as a naturally occurring mineral. Removing either form of calcite could increase the production of a well. However, because the amount of calcite present and its effect on production are both unknown, the results of this type of treatment are usually less predictable. One well may respond very favorably, while the next has poor response or no response. Well U was drilled and completed in It was the first well acidized for CECI in 1993 and acidizing was done to remove scale from the formation. Before the well was acidized, rates were 2.3 After treatment, production increased by 3.4 or 148% to 5.8 MW. While this treatment only lasted 5 months, it was considered a success. Payout occurred in 5 days of increased production. Because this problem recurs, the need for additional or riodic acidizing may need to be considered (although a second acid treatment on this well 6 months later did not result in an increased output). Figure 4shows the production history for this well. Figure 3-Production History for Well A One factor that should be noted is the use of mechanical cleanout in conjunction with acidizing. An acid treatment usually costs less than a rig cleanout and may also result in formation scale In many cases, however, the use of both mechanical and chemical removal resulted in better treatments. These results may be caused in part by large volumes of scale that have limited contact with the acid or possibly combination scales that have limited solubility in one layer Acid Treatment 5. EXAMPLE 2-SCALE REMOVAU STIMULATION OF WELL U Scales have long been suspected of depositing in fractures and in the formation some distance from the wellbore. Traditional mechanical methods of scale removal will have no effect on scale being deposited in the formation area. In geothermal wells, calcium carbonate scale is often left in the formation of high-enthalpy, high-drawdown wells as a result of production flashing before it reaches the wellbore. Scale in the formation is often indicated by a production decline in two-phase or steam-entry wells with an increase in downhole flowing pressure drawdown. This increased pressure drawdown was evident in Well U High-pressure Steam Time, Days Figure 4-Production History for Well -Wellhead Pressure In general, wells with scaling problems respond favorably to acidizing. In the absence of scale, a treatment that is designed only for stimulation (removal of naturally occumng carbonates), the results are generally less encouraging. Of the five acid treatments performed in 1993 for that purpose, only one resulted in a production improvement and increased the wellhead pressure sufficiently to allow the well to produce to the pipeline system. While the overall results of these five stimulation procedures were disappointing, the payout required only 27 days from the one well that was successful. 2483

4 Evanoff et 6. EXAMPLE 3-TREATMENTS TO REMOVE NCG SURGES IN WELL R Table 2-Production Increase Survey Surges in NCG, such as carbon dioxide from producing geothermal wells, result in difficulties at the power plant. In some cases, surges are extreme enough that the well must either be shut-in or produced only a few hours at a time. In addition to the problems associated with individual wells, surges can result in NGC spikes great enough to shut down the power plant and interrupt the supply of power. NCG spikes limited Well R to 6 hours of production per day. It and a sister well (Well C) were acidized with the hope that the surges would be eliminated, or at least moderated by changes in the reservoir hydraulics. The acid treatment successfully reduced the surging enough to produce both wells full time and Well R gained 3.1 MW of power (388%).While the cause of the surges and the mechanical changes that result from the acid treatment are not fully understood, a well shut-in for this reason should be evaluated for acidizing. Figure 5 shows the production response of this well Acid Treatment 1200 producing at elevated rates Table 3-Success Rates and Payout Days High-pressure Steam -WellheadPressure 7. SUMMARY OF 1993 TREATMENTS As of the end of 1993, 30 treatments had been performed on 27 wells for CECI. All of these treatments were done with and 24 of the treatments were considered successful. of the acid treatments were considered successful but produced gains that lasted only an average of 2 months. Ten of the wells acidized continue to produce at elevated rates. The overall gain in production from the acid treatments was 66%. Total increase in production was 53 with an overall payout time of 9 days. Table 2 lists the acid treatments by well, results, and current status. Figure 6, Page 5 shows the change in production of all 30 treatments. Table 3 summarizes the economics of the program results. 8. CONCLUSIONS Acidizing with in geothermal wells is economical and can result in significant production increases. can be used effectively to remove damage from calcium carbonate scaling, either in the wellbore or the formation. Use of HCI to reduce NCG surging can result in a sufficient decrease in the surges to allow longer or continuous operation of that well. Acid treatments designed to stimulate the formation have a lower success rate and need to be carefully evaluated and compared to alternative solutions. Even with the lower success rate, payout times are still brief. 2484

5 Evanoff et Before Output After Acidizinq Figure Increase Summary for 1993 Geothermal Treatments Acidizing is more effective after a mechanical well- trict Heating Applications, Geothermics, Vol. 18, bore cleanout to remove a large quantity of the scale. 2, , tact with any remaining scale in addition to contact with 6. Vetter, O.J., et al.: Test and Evaluation Methodology for Scale Inhibitor Evaluations, paper SPE 16259, the formation. International Symposium on Chemistry, San Antonio, TX, Feb. 4-6, 1987, pp REFERENCES 7. Featherstone, John L.: Stabilization of Highly Saline Geothermal Brines, paper SPE 8269, SPE Annual 1 Plouff, D., and Isherwood, W.F.: Aeromagnetic and Technical Conference, Las Vegas, Nevada, Sept. Gravity Surveys in the Range, California, Jour- 26, nal of Geophysical Research, Vol. 85, No. B5, pp 8. Ungemach, P. and Turon, R.: Geothermal Well Damage in the Paris Basin: A Review of Existing and Sug- 2501, May 10, Brophy, Paul: Structural Analysis of Pre-Cenozoic gested Inhibition Procedures, paper SPE Rocks, Geothermal Area, California, Geother , SPE Formation Damage Control Symposium, mal Resources Council, Transactions, Vol. 8, August 1984, 9. Bakersfield, CA, Feb. 8-9, Auberbach, Michael H., et al.: A Calcium Carbonate 3. Corsi, Riccardo: Scaling and Corrosion In Geothermal Equipment: Problems and Preventive Measure, Scale Inhibitor for Direct-Contact Binary Geothermal Service, Journal of Petroleum Technology, August, Geothermics, Vol. 15, No. pp , , Osborn, L. and Spielman, P.: Measurement of Velocity 10. Asperger, R.G.: Rapid, High-Temperature, Field Test Profiles in Production Wells Using Wireline Spinner Surveys and Rhodamine WT Fluorescent Method for Evaluation of Geothermal Calcium Carbonate Scale Inhibitors, SPE Production Engineering, Tracer; Geothermal Field, 1995, World Geothermal September, 1986, pp Conference, Florence Italy, May Harrar, et al.: Field Tests of Organic Additives 5. Lindal, Baldur, et. al: The Scaling Properties of the for Scale Control at the Salton Sea Geothermal Field, Effluent Water from Power Station, Turkey, Society of Petroleum Engineers Journal, February. and Recommendation for a Pilot Plant in View of 1982,

6 Evanoff et al. 12. DaSie, W.: Chemical Stimulation Treatment of a Well in the Geothermal Field, Geothermal Resources Council, Transactions, Vol. 8, August 1984, Giannimaras, E. K.: et al., Calcium Carbonate Scale Formation and Prevention, EEC Contract No. Proceedings of the Fourth International Seminar on the Results of EC Geothermal Energy Research and Demonstration, Florence, Italy, April 30, Reed, Marshall J.: Thermodynamic Calculations of Calcium Carbonate Scaling in GeothermalWells, Dixie Valley Geothermal Field, U.S.A., Vol. 18, NO , Benoit, Walter R.: Carbonate Scaling Characteristics in Dixie Valley, Nevada Geothermal Wellbores, Geothermics, Vol. 18,No. pp , Halliburton Internal Report, , Bakersfield Division Laboratory. 17. Halliburton Internal Report, S30-F012-91, ACKNOWLEDGMENTS The authors thank the management of Halliburton Energy Services and California Energy Company, Inc., and the Geothermal Program Office of the US Navy for permission to publish these results. 2486

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