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2 Geothermal Resources Council, TRANSACTIONS Vol. 6, October 1982 DOWNHOLE CEMENT TEST IN A VERY HOT HOLE Roland A. Pettitt, George G. Cocks, Donald S. Dreesen, James R. Sims, Robert W. Nicholson,* and Billy G. Boevers** Earth and Space Sciences Division, Los Alamos National Laboratory, Los Alamos, New Mexico *Well Production Testing, Carlsbad, California **Dowell Division of The Dow Chemical, Tulsa, Oklahoma ABSTRACT Completion of the commercial-sized Hot Dry Rock Geothermal Energy Project requires that hydraulic fractures be created between two inclined wellbores at a depth of about 4 km (15,000 ft). Isolation of a section of the open wellbore is necessary for pressurization to achieve the fracture connections. A cemented-in liner/pbr assembly is one of the methods used for zone isolation near the bottom of the injection well. A downhole, pumped cement test was firgt condpted at a wellbore temperature of 275 C (525 F) to determine if a suitable slurry could be designed, pumped, and later recovered to assure the success of the cemented-in liner operation. *-=I I--,INTRODUCTION In the development of the first Hot Dry Rock (HDR) geothermal energy extraction system at Fenton Hill, west of Los Alamos, New Mexico, man-made reservoirs were created by connecting two holes in hot, impermeable crystalline rock with hydraulically-produced fractures. This initial system consists of two near-vertical 9-5/8-in. diameter holes approximately 3 km (10,000 ft) deep in Precambrian basement rock, at a bottom-hole temperature of 2OO0C (400'F). Figure DISTANCE (rnl Schematic cross section of wellbores EE-2 and EE-3, showing area of the commercial-sized reservoir. Drilling of the first hole for the deeper, commercial-sized reservoir was begun in 1979 at the same site (Pettitt et al., 1982). The second hole was completed in 1981 (Rowley et al., 1982). This reservoir system consists of two boreholes drilled to a8proximately 4 km (15,000 ft) at an angle of 35 from the vertical, which will be connected by multiple, hydraulic fractures. The bottom-hole temperature of the deeper injection well (EE-2) is 335OC (635OF) (Figure 1). Both wells are cased with 9-5/8-in. 0.d. casing to within napproximately 1220 m (SO00 ft) of total depth; the 8-3/4-in. drilled diameter open hole sections will constitute the reservoir area. The first connecting fractures were planned to be created from the bottom portion of EE-2, extending upward to EE-3. Methods of isolating sections of the borehole for fracturing operations included the use of open-hole packers (both stradd1.e and single), and a cemented-in scab liner/pbr assembly. Since suitable cement, cement placement procedures, and elastomeric materials are required to successfully cement-in and fracture below the cemented-in scab liner, an investigative program was undertaken to (a) test cement mixtures in the laboratory and (b) to test the ttbesttt slurry and a special wiper plug under downhole conditions at the extreme temperature to be encountered. ST OBJECTIVES The use of a cemented-in permanent scab liner/pbr assembly, set at about the 15,000 ft depth in EE-2 for zone isolation for hydraulic fracturing below it, was decided in December At that time, investigations were also started to determine suitable cement mixes, elastomeric seals and wiper plugs, and an appropriate method to adequately test them. In January 1982, a cement test procedure was designed to test the proposed slurry under real downhole conditions at the depth, temperature, and pressure that the scab 223

3 Pettitt et al. liner would encounter in EE-2. Concurrently, the Dowell Research Laboratory in Tulsa, Oklahoma was requested to start conducting tests on these three proposed slurries and downhole conditions: A. B. C. D. 1. Class H cement, with 40% silica 2. Class H cement, with 60% silica 3. Class J cement, with 60% silica equivalent ProDerties: 48 hour compressive strength = >4000 psi Slurry density = >15.0 ppg.. Placement Condltlon.s: BHCT = 275OC (525OF) Pumping time: 4 hours Depth: 14,500 ft Pipe: 3-1/2-in. drill pipe, 13.3 lb/ft Fluid in the hole: water Possible ContamWts in the Hole: Big Cat commercial detergent: 2% solution Friction reducer: polyacrylamide, l/40% solution. placement times. The cement test results are listed below and in Tables 1 and 2. The final mixes of the three cement systems were: 1. Amarillo Class H cement 40% D66 (silica flour) 5.5% Retarder/Dispersant (XE67565) * 2. Amarillo Class H cement 60% D66 (silica flour) 6.0% Retarder/Dispersant (XE67565)* 3. Unadeep Class J cement 20% D66 (silica flour) 2.5% Retarder/Dispersant (XE67565)* *The XE67565 is an experimental Dowell retarder/dispersant which was premixed in the mix water. ELASTOMER TESTING PROCEDU RES Table 1. Cement Properties The Dowell station in Farmington, New Mexico (200 miles from Fenton Hill) reserved 200 sacks of Amarillo Class H cement, plus appropriate amounts of admixtures, to assure that the testing and placement mixes would consist of the same ingredients. Samples of each were sent to the Dowell Regional Lab in Casper, Wyoming, to the Dowell Research Lab in Tulsa, and to Los Alamos for independent testing. A silo of Class J cement was also reserved in Waco, Texas, with samples being obtained and sent to the three laboratories. In order to keep the three laboratories informed of testing progress, a weekly progress update memo was written in Los Alamos, and sent to the Dowell Farmington station, the Denver office, and to the two Dowell laboratories. After a suitable mix design had been obtained by the Tulsa Laboratory, replicate tests were planned in Casper and Los Alamos to check for consistency of results. Testing in Tulsa continued through February and March, Trial mixes were first made with an experimental retarder/dispersant admixture (designated XE67565) in a powder form. The efficiency of the powder was later tested by being added to the mixing water, with the result that reduced amounts of retarder/dispersant were required when added in this manner. By the end of March, testing was completed by the Tulsa Laboratory on the three mixes. The cement systems had a thickenini time of 4 to 5 hours at a BHCT of 275OC (525 F), and a minimum com ressive strength of 4000 psi in 48 hours at 3158 C (60OOF). Cement testing was accomplished by standard API procedures, except that the heat-up times were accelerated to more closely simulate Density Yield Mix Water TT* System PPG cu ft/sk gal/sk hrs:min : : :37 *Samples for these thickening time tests were heated as fast as possible in the Dowell consistometer. Normal heat up time from 80 to 525'F was 65 to 75 minutes with a maximum pressure of 6300 psi. Table 2. Compressive Strengths, PSI 48 hours System Temp OF 48 Hours Contaminated* *The samples were contaminated with 2% by volume of a detergent (Calgon Big Cat) supplied by Los Alamos. Dowell wiper plugs (made of EPDM Y267, formulated by L'Garde, Inc.) and Brown Oil Tool (BOTJ darts were statically tested at 300 C (572 F) and 4400 psi in the Los Alamos autoclave. BOT molyglass chevron seals for the permanent scab liner/pbr assembly were also statically and 224

4 Pettitt et al. dynamically tested at 30Ooc (572 F), withstanding 3300 psi differential pressure before failure, in the Los Alamos autoclave. (Only two seals were dynamically tested, whereas a large number of seals will be used in the actual downhole assembly. ) The bottom-hole assembly (BHA) for the downhole cement test is shown schematically in Figure 2. Basically, this BHA consisted of 742 ft of 2-7/8-in. tubing, containing a dart catcher sub, and a pressure and temperature (Kuster) gauge holder ( Figure 3). Run-in of the cement test assembly was completed on April 18, with the pressure and temperature gauge sub being located at a depth of 14,%80 ft, 4jhere the in-situ rock temperature is 305 C (580 F) (Figure 4). As the design thickening time temperature of the mix to be used (Sygtem No6 1, containing 40% silica flour) was 275 C (525 F), the hole was cooled by circulating through the BHA for 3 hours with the rig pumps at 5.4 bbls/min.? 3 112" DRILL PIPE t '' JTS TUBING T Et P GAUGE SUB1 t' 2 JTS ' TUBING L 11 JTS. T 2 718' 7 1 q5' 175 BBL CEMENT PUMPED 1.23 BBL CEMENT IN PIPE 0 53 BBL CEMENT "LOST" BROWN LIQUID ABOVE CEMENT WIPER PLUG (??INTO JT 14) WIPER PLUG IN CATCHER TUBING 21* NO CEMENT TOP OF CEMENT (JT 11) (STRINGERS) POOR, WEAK CEMENT GOOD CEMENT Figure 3. Photo of Kuster gauge holder sub. A 6-ft 8-in.-long slot, 1-1/2-in. wide by 1-3/4-in. deep, was cut in a 6-in. diameter drill collar. The Kuster gauge was held in place by set screws, tapped into the side of the slot, on 8-in. centers. A representative from Brown Oil Tool supervised the loading and release of the darts (wiper plugs), as this same type of dart would be used in the permanent liner/pbr assembly. After the lower dart was released, 1.75 bbls of cement slurry were pumped downhole. The upper plug was then released, followed by 100 bbls of displacement water. Pumping pressure was 500 psi; after the lower dart bumped into the dart catcher, the pressure raised to 1500 psi. The pressure was held without leakage for 5 minutes; then the cementing head was rigged down, and the pipe string pulled up one stand. During the 48-hr waiting period for the cement to set, the pipe string was reciprocated for 15 ft at 30 minute intervals for the first six hours. Later, during the waiting period, the reciprocating interval was increased to 60 minutes and then to'90 minutes. - - E EE-2 STATIC TEMPERATURE IDCI vs MEASURED WELLBORE DEPTH 5ooo - 10 OOO 15 om SOME CEMENT IN BULL PLUG Figure 2. Bottom-hole assembly for the downhole cement test, indicating occurrence of cement upon retrieval. Figure 4. EE-2 wellbore depth. TEMPERATURE (OCI static temperature vs measured 225

5 Pettltt et al. On May 20, the cement test assembly was started out of the hole, after having set at depth for 48 hours. The first 10 joints of 2-7/8-in. tubing contained no cement; the rest of the joints down to the dart catcher contained cement which was progressively harder with depth. There was no cement below the dart catcher, except for a small amount in the bull plug. The Kuster temperature gauge apparently leaked, giving no data after 24 hours. A maximum reading thermometer, algo inclgded in the Kuster package, indicated 293 C (558 F) at 14,580 ft. Figure 2 shows the occurrence of the cement in the cement test assembly. Approximately 1.23 bbl of cement remained in the pipe, leaving 0.53 bbl unaccounted for, presumably leaking by the plug in the dart catcher. However, there was no indication of cement in the bottom of the hole when it was later cleaned out to bottom. The top plug, expected to be recovered at the top of the cement column, was actually found 105 ft down from the top of the cement. Sledge hammers were required to break the tubing connections of the joints containing hard cement, during removal from the hole. It was noted that small bubbles appeared immediately on the fresh broken surface of the hard cement at the tubing connections, indicating that the cement still contained water at pressure and that the cement-to-tubing bond was extremely good. The condition of the darts after retrieval was very revealing. The bottom dart still retained some resiliency, but the top dart (when it was cut out of the tubing) was extremely brittle and decomposed. Compressive strength of the hardened cement retrieved from the tubing was 5270 psi. The downhole cement test successfully answered questions that had worried the designers of the liner/pbr assembly operation. These points were definitely and positively made: A cement slurry was designed, laboratory tested and pumped downhole. The retarder acted within the temperature and time constraints. The cement set and gained strength under the downhole conditions. The test provided confidence in the darts and dart catcher. An indication of the amount of cement slurry leaking by the darts was provided. It is possible to verify the actual downhole temperature and pressure that the cement slurry encountered. The cement test gave assurance that a satisfactory cementing operation could be performed for the liner/pbr assembly. ACKNOLEDGMEN TS AND DISCLAI MER Reference to a company, product, name, service, tool, or equipment item does not imply approval or recommendation of the product, service, or tool by the University of California (Los Alamos) or the U.S. Department of Energy to the exclusion of others that may be suitable. The project described in this article was funded by the U.S. Department of Energy, Division of Geothermal Energy. Thanks are due the Los Alamos workover managers, WPT consultants, Dowell, Brown Oil Tool, and Brinkerhoff-Signal Company people who contributed so much personal effort to these operations. Special appreciation is also due these Dowell individuals: Ron Root/Denver, Richard Jones/Tulsa, Sid Christensen and Mark Stewart/Farmington, and Don Mitchell/Casper. PEFERENCES Pettitt, R., Helmich, C., Koczan, S., 1982, Planning and drilling geothermal energy extraction hole EE-2, Los Alamos National Laboratory Report LA-9302-HDR. Rowley, J., Carden, R., 1982, Drilling geothermal energy extraction hole EE-3, Los Alamos National Laboratory Report, in preparation. 226