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2 ~ ~ Resources ~ Cu~ffcj~ ~raff5ac~iuffs, ~ evol. 23, October r , ~ 1999 ~ The Application Of G~~che~istry In Sustaining The Operation Of The Palinpinon-I Geothermal Production Field, Philippines, For The First 15 Years B.C. Vidal Jr., D.Z. Hermoso, O.T. Jordan, and P.1. Pamatian PNOC-Energy Development Corporation, Ft. Bonifacio, Makati City, P~ilippines ABSTRACT Sustaining the steam supply for the MWe Palinpinon- I Geothermal Power Plant of the Southern Negros Geothermal Field was the main thrust of the management strategies of the reservoir and the Fluid Collection and Disposal System (FCDS) implemented during the 15 years of exploitation. Rapid reinjection fluid returns, reservoir and well bore pressure ~awdown, mineral deposition in some production and reinjection wells, and in~sion of acid sulfate fluids in some production wells were the major constraints affecting adequate steam production. This paper discusses the major geochemical trends associated with the above-cited constraints, and the strategies implemented to address them. The latter include: (1) shift of the bulk reinjection away from the production area to reduce the impact of rapid reinjection fluid returns; (2) eli~nation of in-field injection; (3) drilling and prioritization of high enthalpy wells; and (4) deeper injection of reinjection fluids to mini~ze the rate of pressure drawdown by providing pressure support and heated recharge to the production sector. Other operating constraints, such as power-plant interface chemistry limits for sustaining turbine efficiency, are also discussed. The development, and first few years of operation of the 4x20 MWe modular Palinpinon-I1 geothermal production field, commissioned between 1993 and 1995, was guided by the Palinpinon-I experience. Introduction The Southern Negros Geothermal Field (SNGF') is located in Negros Island, central Philippines. The field is subdivided into two geographical areas: the operating fields Palinpinon-I (Paln- 1) and Palinpinon-I1 (Paln-2) (Figure 1 and inset, overleaf). The Paln "We power plant was commissioned in May 1983, while the Paln-2 modular power plants, consisting of the Balas-balas 1x20 W e, Nasuji 1x20 MWe, and Sogongon-I and I1 2x20 MWe power plants, followed between December, 1993 to January, As of this writing, a total of 75 wells (exploration, production and reinjection) have been drilled in the Palinpinon field. (The exploration and development history, and the field hydrological model have been published by several authors, and will not be dealt with here.) This paper summarizes the major chemical response of the Paln-1 geothermal reservoir in the past 15 years of exploitation, from 1983 to 1998; and the operating strategies that were consequently formulated with the primary objective of sustaining adequate supply of quality steam to the power plants. The development and operating strategy of Paln-2 was subsequently based on the experience gained in the operation of Paln- 1. Reservoir Response To Exploitation Reinjection Breakthrough Reinjection (RI) fluid returns were already detected as early as 1983 from the increase in the C1 concentration of well discharges. A subsequent tracer test (Iodine ) conducted on RI well PN9RD was able to demonstrate a mean transit time for the RI return flow to the production sector of 5.4 to 18 days (Le., the time required for half of the tracer amount recovered to reach the production wells). From the same study, the Ticala and Puhagan Faults were established as major conduits of the RI returns (Urbino et al, 1986) I z f' 2R 1.00 RI tine 317 CI I m 2? ooo I f : i8 j9 i0 il Figure 2. RI Line 317 Cl concentration and Paln-1 Non-Condensible Gas concentration. i5 z a 407

3 Vidal Jr., eta/. Figure 1. Location map of the Palinpinon Geothermal Field. Inset: The Philippines. Due to temperature and output declines in heavily affected wells (e.g., OK7 and PN26), reinjection was promptly moved farther north of the reservoir, in the Ticala-~alaunay sector, in The immediate response of the field was one of recovery, as may be seen in the abrupt decrease in RI-line chloride concentration (Figure 2, previous page). Apparently though, the recovery was short-lived, as RI-line C1 again increased by mid- 1990, this time the returns coming mostly through the Ticala Fault, affecting central and southwestern Puhagan production wells. The RI returns peaked by 1993, with the increase in mass extraction and injection after the Negros-Cebu grid interco~~tion, which then persisted until 1995, With the cutt~g-out of highly communicative wells, along with other well-utilization strategies, a second wave of recovery ensued, which continues up to this writing (Hermoso and Mejorada, 1997). The nearly stable RI-line C1 level starting the later half of 1997, reflects the steady-state condition of the reservoir (Le., natural recharge and reheated RI returns balancing mass withdrawal), owing to the effect of the adopted strategies, and the low mass extraction and reinjection during the two-unit load in Paln- 1. Pressure Drawdown Decrease in reservoir pressure results in boiling, and due to the preferential movement of gases to the steam phase, the most immediate chemical effect on the well fluid is an increase in gas concentrations. A typical example is shown in Figure 3, where CO2 in the total discharge of wells OKlOD and PN2OD went up by 1994, after the Negros-Cebu grid interconnection was instated and mass with~awal reached as high as 700 kgls. The process is apparently reversed with the ingress of reinjection fluids, as would be seen in the non-condensible gas (NCG) trend with time-an average measurement of the gas concentration in the total produced steam (Figure 2, previous page). High values in 1990 to 1992, and 1996 to 1997, conespond to major modifications in reinjection strategies that have decidedly reduced the magnitude of Rf returns to the production c 1200 E, + PN2OD F 0 E Figure 3. CO, in the total discharge of wells OK1 OD and PN22D

4 Vidal Jr., eta/. sector. Conversely, the low-ncg periods of pre-1990, and , correspond to periods of observed RI breakthrough. The decline in 1998 is attributed to the natural recharge and heated FU returns coming through Odlumon Fault, consistent with the presently observed thermal and chemical stability of the reservoir. A generally increasing trend in the NCG with time could be taken to indicate progressive pressure drawdown, and an increasing preference for the utilization of high-enthalpy wells (e.g., PN32D, LG3D, and LG4D). These wells were primarily drilled to tap the reservoir s two-phase zone, which was generated by reservoir boiling. Cool Acid Inflow A process closely associated with pressure drawdown is the incursion of cool, acid-sulfate-bearing waters which have been formed from H2S oxidation in shallow-lying aquifers, into locally-boiling, near-well producing zones. Affected wells are easily recognizable by their increasing SO4 and Mg, and declining C1 (Figure 4) s I O-O Figure 4. Mg and SO, concentration in well OK1 OD. This process is highly localized, because of its structurallycontrolled nature: acid-sulfate inflows in Palinpinon are confined mostly within the Lagunao and Nasuji sectors, with main controlling structures being Mailig and Odlumon Faults (Seastres et al, 1995). Given this fact, a strategy for displacing the acid inflow by concentrating RI return flows in the affected structures was implemented. Increasing the return flows along Odlumon Fault has so far been proven effective, with wells PN13D, PN22D and OKlOD returning to more neutral ph. This is evident in Figure 4, where Mg and SO4 levels went down late in 1990, because of the migration of RI brine into Odlumon Fault from the Ticala RI sector. Apparently though, the southernmost portion near Lagunao was not susceptible to the said strategy, likely because of the diminished distal effect of the RI returns. Thus, acidic wells in Lagunao and Nasuji (e.g., NJ2D, NJ6D and LGlD) had to be decommissioned because of high corrosion rates. Mineral Blockage Anhydrite (CaS04) and calcite (CaCO3) deposition in production wells, and silica (Si02) deposition in reinjection wells are a common occurrence since the start of steam production. Increased Ca++ activity because of cooler RI returns, plus reservoir fluid flashing as a result of pressure drawdown, has caused increasingly higher calcite oversaturation in the reservoir. Wells PN13D, PN17D and PN33 were among those found to have calcite deposition from their scraper samples. Anhydrite deposition has been inferred to result from the mixing of acid-sulfate waters with the Ca++-rich deep reservoir fluid. Wells with acid-sulfate inflows (e.g. PN20D, PN22D and OKlOD) usually form this mineral during shut conditions, when cooler, heavier acid-water flows down the well. Silica (mostly anhydrous silica) is the most common type of deposit in RI wells. The silica saturation index (SSI) of the RI fluid in Paln-1, is around 4.0 to 1.3, changing very little over the years, and indicating slight oversaturation or deposition potential. Deposition of silica in the formation around RI sectors are suggested by capacity declines in RI wells which have recovered their original capacities after acidizing, e.g., PN2RD, TClRD, TC2RD and OK3R. Application of Stable Isotope Chemistry In conjunction with the chemical trends of major fluid elements, stable isotopes provide evidence of the reservoir s response to exploitation. Gerard0 et al., 1992, was the first to characterize the isotopic signature of the Palinpinon pre-exploitation fluid, as having 20% magmatic and 80% meteoric component, based on 6I8O and tj2h fluid compositions. Displacement of well compositional values from the baseline mixing line (62H= ) were interpreted as resulting from the major reservoir processes of RI returns, pressure drawdown and iz,i 40.0 Go a e0 (%.I Figure 5. 6l80 and 6*H isotope trends showing the deviation from the baseline mixing line as a result of field exploitation (Seastres, et a/., 1996). 409

5 Vidal Jr., et a/. acid-sulfate inflow. In Figure 5, RI return manifests as a shift towards the isotope-enriched (-2.80%~ 6 I80) reinjection fluid. Acid fluid dilution is shown by shifts towards the local meteoric line, due to the addition of isotopically-lighter (-8.1 to -7.0%0 6 l80) groundwater component. Steam addition, resulting from the expansion of the two-phase zone, shifts composition towards isotope-depleted steam (-6.0%~ 6I8O), and could be made more evident by relating 6I80-depletion with C02-enrichment. FCDS - Power Plant Interface Chern istry Constraints Efficient operation of the Palinpinon-I 3 x 37.5 MWe turbines has been constrained by the interface chemical limits set by the turbine manufacturer, and the National Power Corporation (NPC), primarily for turbine protection and condenser vacuum efficiency. These include a maximum of 5 ppm Total Dissolved Solids (TDS), 1 ppm chloride (representing steam purity), and 3.0 percent by weight of ffon-condensible Gases (MCG) in the steam phase. High TDS (35 ppm) has been encountered in well BLlD, as confirmed from the results of a target plate testing, resulting to the well not being initially accepted for utilization in the Balasbalas 2 ~ modular ~ power ~ plant e (Paln-2). As a remedy, heated spring water was injected into the well in order to entrain the suspended or dissolved solids, and subsequently separate them into the liquid water phase. This was successfully implement^ for a period of over three years, during which time, the well continuously supplied steam to the power plant without causing any apparent damage to the steam turbines. An on-line, steam purity monitoring set-up which is capable of a 24 hour, in situ and unbroken monitoring of steam purity (measured in terms of total sodium), has been conceived, and subsequently developed by site geochemists (Barroca et at., 1998). The performance of this system, which was in operation in Paln-1 and 2 since 1997, has been rigorously tested both under normal and abnormal steam purity conditiuns. The daily average sodium level of Paln- 1 steam is less than 0.1 ppm, with values becoming slightly higher in 1996 and later years, likely as a combined function of the separator and drainpot scrubbing efficiency deterioration. Paln-1 steam has generally met the NCG limit of 3.0 percent by weight. The overall NCG trend showed an initial decline to el percent by weight due to RI fluid returns, then increased to about 1.4 percent when reservoir pressures started to decline and shallow two-phase zone formation was enhanced in most of the production wells. Reservoir Management Strategy S M of ~e;n~e~ion Load Away From the Production Sector 1989, with the RI load in Puhagan reduced to about 100 kgls. Two of the Ticala RI welis (TC3R and N3R), however, were also proven to be communicative with the production sector, with the injected fluids channeled along the Ticala Fault. Reinjection into these wells was thus minimized. By the last quarter of 1996 and the first quarter of 1997, all the hhagan RI wells and the communicative wells in Ticala (N3R and TC3R) were shut. TC3R was re-drilled, deviated towards the Odlumon Fault, and re-utilized as TC3RD beginning in February 1997 to increase the RI capacity in Ticala. At this time the RI fluid was injected only into the Ticala and Malaunay wells. A suspected resurgence of RI breakthrough, however, was detected in the southeastern and western Puhagan production wells by the last quarter of 1997, with the RI fluid believed to have come from TC3RD. The load into this well was subsequently reduced beginning in January Other Well Utilization, Modification and Opera ting 5~rategies Another measure to address RI fluid returns was the utilization of high-enthalpy production wells to reduce the waste brine load. This strategy was behind the drilling of wells PN32D, PN33, and the Laguna0 wells (LG3D and LG4I)), prim~ly to tap the shallow two-phase zones and the boiling upflow area. From chemical indications that deep reinjection causes slower RI fluid returns, later RI wells (e.g., Ticala wells including the redrilled TC3RD) were aimed at deeper fault intersections, primarily with the Odlumon Fault. This strategy was also found to be effective in displacing acid fluids along this fault. Attempts were also made to cement-plug the shallower zones of RI wells PN2RD and PN3RD, but their success was unde~ined by inherent pr~edura~ di~culties, such as isolating the annular space between the slotted liner and the formation. Wells that have substantially lost output due to mineral deposits were cleared by mechanical work-over, and in the case of deposits extending to the surrounding formation, by acidizing. Deposition along certain sections of the waste water lines have been addressed by mechanical removal of the silica scales, spooling of selected RI-line sections coinciding with low flow velocity, and cons~ction of redundant RI lines. Although these measures have been generally effective, more economical solutions, such as on-line chemical treatment, are being researched on. Applications in the Paln-2 Development The 10-year experience of continuous exploitation in Paln- 1, particularly in the area of RI-well siting, greatly influenced the Paln-2 reinjection strategy. RI wells in Nasuji and Sogongon sectors were drilled far north as possible to minimize RI fluid returns to the production sector. RI mass front was observed in 41 0

6 Vidal Jr., eta/. SG2RD, and SG3RD) and, to a lesser extent, from Nasuji (NJlRD) back to the production sectors. Drilling and utilization of NJ2RD since March 1997 has enabled the reduction of load in the Sogongon RI sector, particularly in SG3RD, which was shut since August Summary and Conclusions The 15 years of exploitation of the Palinpinon Geothermal Production Field has resulted in four major reservoir processes: (1.) reinjection fluid returns; (2.) wellbore and field pressure drawdown; (3.) influx of cooler and acidic fluids; and (4.) mineral deposition in wellbores and surface pipeline facilities. These processes were successfully deduced and monitored using geochemistry tools, employing both well-fluid major element and isotope chemistry. The negative impact of these processes on sustaining the steam supply to the power plants were addressed mainly by the choice of RI wells, and by drilling and priority-utilization of high enthalpy wells. These mitigating measures contributed to the successful management of the reservoir for the past 15 years. These experience and success gathered by PNOC-EDC will undoubtedly be of benefit for geothermal fields all over the world being developed or commissioned. References Barroca, G.B., Ferrolino, W.L., Jaculbe m, I.C., Jordan, O.T., and Reyes, R.L On-Line Steam Quality Monitoring, Applications, Experience and Innovations in the Southern Negros Geothermal Production Field, Philippines. Proceedings of the 19 Annual PNOC-EDC Geothermal Conference. pp Gerardo, J.Y., Nuti, S.,D Amore F., Seastres, J.S. and Gonfiantini, R Isotopic Evidence for Magmatic and Meteoric Water Recharge and the Processes Affecting Reservoir Fluids in the Palinpinon Geothermal System, Philippines. Geothennics, v pp Harper, R.T. and Jordan, O.T Geochemical Changes In Response to Production and Reinjection, Palinpinon-I Geothermal Field, Negros Oriental, Philippines. Proceedings of the 7fh New Zealand Geothermal Workshop. Hermoso, D.Z. and Mejorada, A.V The Palinpinon 1 Production Field: A Case Study for Reinjection Breakthrough. Proceedings of the Geological Society of the Philippines Seastres, J.S., Hermoso, D.Z. and Gerardo, J.Y Application of Stable Isotopes in Evaluating the Reservoir Changes at Palinpinon Geothermal Field During Exploitation. Proceedings of the ltyh Annual PNOC-EDC Geothermal Conference. pp Urbino, M.E.G., Malate, R.C.M., Garcia, S.E., Hermoso, D.Z., Jordan, O.T., Bueza, E.L., Zaide, M.C PN-9RD Tracer Test. An Integrated Report. Southern Negros Geothermal Field. PNOC- EDC Internal Report. pp