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2 Geothermal Resources Council Transactions, Vol. 2 6, September 22-25, 2002 Enhanced Permeability by Chemical Stimulation at the Berlin Geothermal Field, El Salvador 1. A. Barrios', J. E. Quijanol, R. E. Romerol, H. Mayorgal, M. Castrol and J. Caldera2 lgeot6rmica Salvadoreiia S.A. de C.V., El Salvador Km 11 '/z Carretera al Puerto La Libertad, Col. Utila, Santa Tecla, La Libertad *Schlumberger - Dowell Company, Houston Texa Keywords Chemical stimulation, enhanced permeability, Berlin El Salvador ABSTRACT In 2001, the Berlin Geothermal Field experienced injection problems owing to intrinsically low permeability of injection wells exacerbated by silica scaling in the wellbore. Pressure transient tests were performed to quantify well damage and to determine the scope for improvement of injection and production wells. Following the chemical stimulation program of two production wells, the productivity essentially doubled. The increase was approximately 16 MWe. Furthermore with chemical stimulation, the injection capacity of three wells increased by 87 kg/s. Owing to capacity constraints only 6 MWe are utilized in the Berlin Power Plant bringing the production capacity from 50 to the maximum of 56 MWe, by connecting one production well with 10 MWe on standby. The improved capacity for injection, however, already declines slowly probably due to the high potential for silica scaling of the injection fluids. Silica inhibition will be performed to maintain the injection capacity. continental Caribbean plate. The field measures 4 by 6 km in areal extent with an estimated potential of 85 MWe. The production field is located towards the south of the field within the Berlin Caldera. The caldera is open to the north, possibly associated with the NW-SE trending Berlin Graben, which is interpreted to have been formed by a collapse along older, reactivated NW-SE structures. The injection wells are located to the north of the production field, outside the Berlin Caldera. The production and injection zones only differ in the degree of permeability and natural fracture density. The permeability of production wells located inside the caldera depression is greater than the permeability of wells outside the caldera. The natural low permeability of the injection zones is attributed to self-sealing and healing of fractures by quartz and calcite precipitation. The drilling success for production zone was 90% and for the reinjection zone 45% (for the reinjection zone success is defined as adequate natural permeability for reinjection. The Berlin Geothermal Field The Berlin Geothermal Field located in eastern El Salvador lies on the northern slope of the Berlin-Tecapa volcanic complex situated in the Southem Fault system of the E-W trending Central American Graben. The Graben is related to the subduction process of the oceanic Cocos Plate underneath the Figure 1. Location of stimulated wells Berlin Geothermal Field. 73

3 Barrios, et. a/. n o deep vertical wells (TR-2 and TR-3) were drilled during the late 1970s. A 'deep' geothermal reservoir was intersected at 1800 m depth with a temperature of 300 "C. In , another three wells (TR-4, TR-5 and TR-9) were drilled to a depth of 2300 m suggesting a potential for small-scale power generation of 5 to 12 MWe. Two well head units were on line from 1994 to 1999 and two-phase fluids were extracted from wells TR-2 and TR-9, and residual water injected into wells drilled in the early 1990s (TR-14, TR-8 and TR-10). With financial assistance of the International Development Bank, 18 new wells were drilled from 1997 to A single flash condensing power plant with an installed capacity of 56 MWe was commissioned in July 1999 and generation using wellhead units was discontinued. Directional drilling technology was used in 24 wells drilled from existing pads (TR-4, TR-5, TR-8 and TR-1). Vertical wells also drilled from three new sites (TR- 11, TR- 12 and TR-7). Due to injection problems in 1999 and 2000, gross generation varied between 51 and 53 MWe. Average values for total and residual water produced are 360 and 262 kg/s respectively, for steam flow and dryness 98 kg/s and 28%, and steam consumption is approximately 2 kg/s per MWe. Produced water flow rates from eight production wells range from kg/s and ten injection wells are used to dicharge the residual water. A first chemical stimulation performed in 2000 in three injection wells resulted in satisfactory improvements in permeability and injection capacity. The interpreted results shows the success of the chemical treatment to efficiently remove drilling muds and removal of silica scale in the near well bore and possibly further in the formation. Encouraged by those results and by the desire to increase power plant output, a second chemical stimulation treatment was programmed for the year Based on the experience gained in 2000, the chemical design and method was modified to improve both the capacity of other injection wells and for the first time production wells were consi dered. Well Selection To enhance the permeability of the injection wells in Berlin Geothermal Field, five wells were selected for the chemical treatment (two production and three injection). Currently the injection system is designed to discharge spent fluids rather than pressure-support the production zone. Wells lo- and losszone thickness obtained from PTS measurements (where available) and thermodynamic data of target wells. Also included in the design consideration were, analyses of trends in the injectiordproduction flow rates for reinjection and production wells and data from pressure transient, injectivity and acid dissolution test. Pressure transient tests data were analyzed using a well test interpretation software (Saphir of Kappa Engineering, 2000) to determine reservoir parameters prior to stimulation such as skin (s) and APskin and transmissivity. Table 1 lists the candidate wells and the amount of mud losses during the 8 '/2" drilling stage. All these wells had positive skin value, which gives evidence of damage and possible recovery. Formation damage usually termed as skin (s) was created when viscous mud during drilling entered the wellbore, producing a seal that retards fluid flow. The skin effect is usually observed as an area of lower permeability adjacent to the wellbore that adds hydraulic resistance to the flow of the reservoir fluid. (Malate, et. al., 1998) Three injection wells (TRl4, TR1 A and TR-12 A) and two production wells (TR-5C and TR-4 B) were chemically stimulated. The injection capacity of wells TR-14 and TR-1 A, had continuously declined since the first condensing power plant was commissioned in Silica deposition in the fluid disposal system has been observed and also mud damage was interpreted following the analysis of the data obtained during drilling process. Well TR-14 was first stimulated in July/August of 2000, and now the only well to be stimulated for a second time. The injection rate declined after three months of operation - mostly likely because of silica deposition. The two production wells were interpreted to have been damaged by high viscosity drilling mud. These two wells had less output capacity than the surrounding wells nearby, although the same formations and structures were encountered. Other low permeability injection wells (TR-1B and TR-8A) were not considered. Their DPskin value and skin(s) were negative, therefore the expected gain in injection capacity was evaluated to be only minor. Table 2 lists the pressure transient results for the injection and production wells selected. A high positive value of skin(s) is observed in all of them. The effect of the injection fluids is observed through the injectivity index of well TR- 14. The value prior to stimulation in 2000 was 0.2 kg/s per bar versus a post stimulation value of 1.98 kg/s per bar. The silica deposits continued to lower the permeability during the following year of injection decreasing to 0.9 kg/s per bar. in the reinjection area were chosen with the aim Table 1. Candidate wells: mud injected into the 8 borehole. to discontinue injection into two wells TR-4A and TR- 3 located within the production area. Well TR-4A was Depth of last Depth of first Well Stage Circulation subsequently used to monitor reservoir pressure, and loss Total Mud ( m MD) (m MD) volume bbl TR-3 may be converted to a production well at a later Injection stage. TR-I A (mud damage/silica scaling) I TL 2929 In designing a mud removal treatl"x!nt, Several fac- ~ ~ -A 1(mud 2 damage/silica scaling) No losses 4406 tors were considered such as a) type of mud used during TR- I4 (mud damage/silica scaling) PL 6450 drilling operation, b) acid solubility of the formation, c) Production type of formation and d) feed- and losszone thickness to TR-5C mud damage N/A* N/A N/A be stimulated. Following an analysis of mineralogical TR-43 mud damage and lithological data, depth of circulation losses, feed- *N/A: data not available PL: Partial circulation losses 74

4 Barrios, et. a/. Table 2. Pressure transient results of candidate wells (prior to stimulation). Wells Injectivity Injection (Mud damage (kg/s per bar) capacity (kg/s) /silica scaling) WHP /ProductionMWe Injection wells: TR-1 A 1.6 (zero) 26 TR-12 A 1.4 (zero) 36 TR- 14 (2000) 0.2 pre/ 1.98 post (2000) 11 pre/35 post (2000) TR-14 (2001) 0.9 (zero) pre Production wells: TR-5C TR4B *by Saphir 2.8 (zero) 1.65 (zero) Feedzones in wells TR- 1 A, TR- 14, TR-5C and TR-4B were characterized using a PTS (pressure-temperature-spinner) tool. The feedzones in well TR-12A were determined with a Kuster tool and their thickness was estimated to be similar to those of the production wells. Table 3 lists date of the stimulation job; interval stimulated thickness feedzone and total amount of acids injected. Table 3. Feedzone thickness and intervals stimulated. Interval stimulated Feedzone Total HCl and Date of acid (Through PTS data) Thickness Mud Well stimulation (m) (m) Iniected (m3) TR- 1 A November, / TR- 12 A November, TR-14 October 2001 * / (August 2000") / TR-5 C September, / TR-4 B January, / I5/ I / "Tdentical interval stimulated in year 2000 and Treatment Method The method used to chemically stimulate comprised preparation, mixing and injection of fluids stored in several tanks - hydrochloric acid (HCl) at 10% and Mud (a mixture of lo%hcl-s%hf). Mud is frequently used for stimulation in oil and geothermal wells and is generally prepared by dissolving ammonium bifluoride (HN,HFJ in HCl. In the 2000 acid stimulation treatment, regular Mud was used, while in 2001 a HC1 10% MSR-100 (Mud and Silt Remover) was used to keep precipitates and small particles in suspension, created by the chemical reaction between acids and formation minerals. These particles are usually either discharged from the production wells during clearing or in the case of injection wells are discharged from the wellbore along with the displacement fluids. (Kalfayan, 2000). A typical acid treatment was performed in three stages: a) A preflush, usually Hydrochloric acid (HCl). b) A mainflush hydrochloric (HC1)-Hydrofluoric (HF) acid mixture treatment. c) A postflush/overflush usually by either HCl, potassium chloride (KCI), ammonium chloride (lvi&cl) or freshwater. HCl as a preflush was used to displace the formation brine and to remove calcium and carbonate materials in the formation. The preflush acid minimized the possibility of insoluble precipitates. An acid mixture of HC1-HF commonly reacts with the rock matrix and formation (mud) damage and thus is highly effective in stimulating and removing damage from sandstone reservoirs. (Economides, et. ul., 2000) A treatment design of 75 gal/ft of mainflush acid of feedzone interval with a concentration of 1 O%HCI-S%HF was applied. A 50 gal/ft of feedzone thickness of preflush volume was also programmed for the wells-all at injection pressures below the fracture pressure of the formation, (Malate, et. al., 1998). Injection and Discharge Procedure After the stimulation the well was first traversed with a 3'/2" diameter drill pipe In all the injection wells, about m of silica deposits and mud (together with small fine cuttings) were encountered at the bottom of the wells. Therefore a soaking treatment to the well was done to dissolve those materials deposited at the bottom with the ultimate aim to clean the well. Figure 2. Feedzone thickness in wells TR-4 B andtr-1 A determined by PTS logs. PRESSURE, BARa Tcmpratu..'C 75

5 ~~~ ~~ ~~ Barrios, et. a/. The drill pipe was set at bottom hole near Table 5. Stimulation results in injection and production wells. the top of the deposits and 50 bbl of Mud Increment Absorption Time of Potential injected at 2-4 bbl/min. After soaking, the pro- Well hot injection / Cold Hot injection Gain Improvement grammed preflush and the mainflush were in- Name Water -Product injection Injection decline Hot injection iected into-the feedzones. Usually three or four wells Post stim Post stim (Number Poststim feedzones (stages) per well were stimulated (kg/s) (kg/s) (kg/s) ofdays) (MWe) with an average thickness of 25 to 50 meters (Figure 2). TR-I A TR-12A 24 I The average pump rate varied between 8 and TR I2 bpm, reaching sometimes around 14 bpm, de- Total 87 I84 pending on the well and stage of injection. The Production average treating pressure varied from TR-SC 38 9" 225 psi. The maximum injection pressures (165 bar) TR4B 38 7' 233 were reached in the injection wells TR- 1 A, TR- Total A andtr-14.usudy this when two Note: Steam consumption 2 kg/s per MW. or three stages of diverting agents (foam) were used - probably associated with the low permeability of the well. Results of Stimulation Treatment In comparison, wells TR-5 C and TR-4B had maximum pressures of bars, even though two or three diverting stages were After each acid treatment several tests were performed to applied. This observation is consistent with the differences in per- determine injectivity by cold injection tests in reinjection Wells meability of the production and injection wells. and by monitoring pressure/temperature. Reservoir parameters Diverting agents were used to ensure that the acid mixture Were re-calculated using Saphir (Table 4) and stimulation reis distributed over the targeted production or injection interval. sults are summarized in Table 5. Without this method, most of the acid will enter the most per- The pressure falloff data for the wells were analyzed to meable zone and partly the least production-permeable sections stablish the post skin effect and reservoir parameters such as of the formation, leaving portions of the targeted internal not transmissivity (kh) were determined. A homogeneous reservoir stimulated. Foam diverting technique was used, because mechanical divertion REINJECTION WELL TR12-A REINJECTION WELL TR-1A is difficult to achieve due to the slotter liner completion. (Kalfayan, 2000). After the injection in TR-SC, clearing of the discharge was performed (flowback test). Nitrogen was used to lift the well and to clear solids and waste acid deposited at the bottom of the well. The well recovered quickly and within a couple of hours the well naturally flowed. The well was shut in after five days, and after ten more days was connected to the power plant. Well TR-4B was discharged one month after the injection to allow the waste acids to degrade. Figure 3. Injection history of injection wells TR-1 A and TR-12 A. Table 4. Summary of acid stimulation results. TR- I A 1 TR-12A TR- 14 (2000) TR-14 (2001) TR4B 1 Skin (s) I +I Allskin (bar) Pre Post Injectivity Index (kg/s per bar) Pre Post Transmisivity (Dm) Pre. Post ~ ~ ~~ ~ Note: These parameters were calculated after the injectivity tests and fall off was performed. Well TR-5C was soon discharged and the injection tests were not conducted. model with wellbore storage, skin and infinite boundary conditions was considered. Reservoir temperature of 220 C, pressure of 120 bars and average porosity of 10.0% was used for the injection wells data. The skin (s) was reduced in most of the stimulated wells, equivalent to damage reduction. DPskin is the pressure differential required to maintain fluid flow through the mud cake caused during drilling. The skin damage (APskin) was greatly removed after the acid treatment. Figure 3 and 4 shows the injection gain in wells TR-1 A, TR-12 A and TR-14. Figure 5 shows the production improvement in well TR-5C. 76

6 ~~ Barrios, et. a/. Well test analysis presented above was done to determine skin damage and permeability pre and post stimulation skin damage and permeability. Nodal analysis was used to model and forecast well improvement with stimulation. In Nodal analysis, permeability and skin are input data together with pressure and formation parameters to calculate well performance and simulate specific injection or production conditions. Once the field behavior of the wells is matched, this approach becomes a powerful tool to estimate well behavior after stimulation. As an example, excellent results were observed in wells TRlA and TR14. Pre stimulation injection rates matching on wells TR- 1 A and TR- 1 4 were useful to estimate post stimulation skin. Well TR- 1 A improved from 26 l/s (2246 m3-d) to 59 l/s (5097 m3-d). (Caldera, 2001). In TR-1 A, the nodal analysis was matched with a post stimulation skin of (s) 1.0. TR-14 improved from 18 Vs (1555 m3-d) to 44 Us (3801 m3-d). Nodal shows the two injection curves before and after stimulation job, estimated post stimulation. The increase in water rate injection was achieved at the same injection pressure once the skin was removed. Figure 6, overleaf. I REINJECTION WELL TR14 Figure 4. Injection history of injection wells TR-14. Environmental Considerations The 2001 stimulation program was performed to ensure and conform with all Health, Industrial Safety, Security and Environmental standards. With that in mind, careful preventive measurements were taken in all processes during the acid stimulation. The supervision started during the mobilization of the rig, transportation of injection equipment from the contractors and chemicals, followed by pre-stimulation tests, storagekandling of liquidholid chemicals, and the mixing and injection of chemicals. Discharge of wells TR-5C and TR-4B did not cause any damage to the environment. There were no claims or incidents involving company staff and third parties. Minor adverse impacts included temporary vapor emissions during mixing of acids, and malodorous smells during discharge, but did not cause any harm or disturbance a ' L 1 I I I I I I I I I I I I I I I I I I I Discussion The instantaneous injection capacity increase was 87 kg/s. In terms of the production wells, the output gain was approximately 16 MWe. It is important to emphasize that the gain in injection is only temporary owing to the high silica content of the injection fluids (total silica content of ppm). Also the total dissolved solids are at the upper permissible limits for injection. We have observed already a decline in their injection capacity. After the Figure 5. Production data for well TR-5C before and after stimulation. first stimulation of TR-14 in 2000 it was observed a reduction in injection capacity from 35 to 18 kg/s at 25 bar wellhead pressure over a period of 144 days. After the stimulation in 2001, the injection capacity declined from 44 kg/s to 36 kg/s over 60 days. Similar conditions are observed in wells TR- 1 A and TR- 77

7 Barrios, et. a/. 12 A. The observations suggests that despite a highly effective acid stimulation treatment the gain is only temporary. From a commercial point of view the payback of the investment is rapid and might justify repeats, we are currently evaluating other alternatives to minimize the decline in injection capacity. One short-term measure under consideration is the implementation of a silica inhibition in well TR-14. Such measures may be complimentary to an acid stimulation treatment. Conclusions We have achieved the objectives of the acid stimulation program in the Berlin Geothermal Field. By acid stimulation of two production wells in the Berlin field we have doubled the available amount steam for power generation from those wells - estimated be equivalent to 16 MWe. Similarly the improvement in injection capacity ranged from in three wells. HCl MSR-100 proved to be effective in the wells of the Berlin Geothermal Field, allowing the discharge of well TR-4B, without any damage to the well. The mixture 10% HCl-S%HF proved effective for volcanic rocks of andesitic composition, with a high content of quartz and low content of calcite (less than 5%) in the formation, and in the removal of significant mud damage in the wells. References Caldera, J., 2001, Nodal analysis of wells TR-I A, TR14. Berlin Geothermal Field. Shclumberger s contracting report to GESAL. Economides, M., Nolte, K., 2000, Reservoir Stimulation, Schlurnberger Educational Services, Third Edition, Houston Texas, USA. Kalfayan, L., 2000, Production Enhancement with Stimulation, Penn Well Corporation, USA. Kappa engineering, 2000, Saphir version 12.0, Paris, France. Malate, R.C., et al., 1998, Matrix Stimulation Treatment of Geothermal Wells Using Sandstone, Proceeding twenty-third Workshop on Geothermal Reservoir Engineering, Stanford University, Stanford, Cal. 78