Elementos del IVA que grava servicios utilizados en Chile

The industrial development of explored Indonesian geothermal resources was rather slow prior to 1995. Power plants with a total generating capacity of about 305 MWe had been con-structed at Kamojang, Awibengkok, and Darajat. A complex local energy market and inflation made it difficult to secure overseas funding for partial developments. Fixed contracts were intro-duced from 1994 onwards to allow for development of IPP where steam field development, steam production, and electricity generation were awarded, often as a package, to large, mainly foreign investors who were tied by energy sales contracts (in terms of foreign currency) to PLN. Eleven such contracts were signed. Many contract developments began with additional exploration surveys, followed in rapid succession by accelerated exploration and production drilling. Parallel to these developments, geothermal exploration by Pertamina, PLN and VSI continued.

7.1. Power station developments

Extension at Awibengkok led to sequential increases of 55 MWe(Unit II) in 1997 and 165 MWe

(Unit III) in the same year. The first large plant at Dieng (60 MWe) was completed as an IPP in 1998; the plant capacity at Darajat was increased by 80 MWe (Unit II) in 1999. The last plant during the 1990s was completed at Wayang–Windu (G. Malabar) with a capacity of 110 MWe

in 1999. Thus, within the short span of 4 years, the generating capacity of the geothermal plants had been increased by a total of 470, 415 MWeof which were mainly funded by private foreign investors.

Geothermal developments came to a halt as a result of the financial crisis affecting Asian countries in 1997–1998, which led to a massive devaluation of the local currency. The electricity sales contracts with foreign investors could no longer be fulfilled and two presidential decrees (PD 39/1997 and PD 5/1998) led to the closure of most projects under contract. This was followed by a long period of re-negotiation of sales contracts, changes in ownership of plants, fields and prospects, and litigations that have now been settled except for one (Ibrahim et al., 2005; Saptadji, 2006). The situation also caused some stagnation of geothermal development with the exception of the completion of the Lahendong 20 MWemodular plant in 2000 and an increase by 47 MWe

to a total of 377 MWecapacity at Awibengkok in 2002.

7.2. Exploration on Sumatra after 1995 (for localities seeFig. 3)

Exploration drilling in the Sarrulah Block prospects continued after 1994. The discovery well at Namora-I-Langit (NIL 1-1) was drilled in 1997 to about 1500 m depth (T∼ 275^◦C) and encountered a liquid-dominated system. Three additional deep exploration wells were drilled sub-sequently, one of which bottomed in a large, deep-reaching body of acid-altered rocks (Gunderson et al., 2000).

At Silangkitang four more wells were drilled between 1995 and 1998 to a maximum depth of about 2300 m. Completion tests showed that the prospect was also a liquid-dominated sys-tem. Three of the wells were deviated and drilled to intersect the main fault zone; one (SIL 1-2) encountered a maximum temperature of 310^◦C at the bottom. Most of the wells were produc-tive and one was capable of producing∼130 t/h of fluids with an enthalpy of about 1400 kJ/kg through a 0.18 m diameter liner. The NCG content of the produced fluids was 2–3% (by wt.). The Silangkitang reservoir appears to be a fracture zone-type reservoir associated with an active mega shear zone.

Three more deep wells were drilled directionally through strands of the Great Sumatra Fault at Sibualbuali between 1995 and 1997. The wells were deviated towards G. Sibualbuali, intersected the fault zone, and encountered a liquid-dominated reservoir with a temperature between 218 and 248^◦C in the production zone (Gunderson et al., 2000). All exploration activities came to a halt in early 1998.

Geothermal exploration of the Suoh and Sekincau prospects was renewed in 1997, involving a private developer. The studies comprised geological, geochemical and geophysical fieldwork (MT and gravity surveys). The 1997–1998 financial crisis also brought this development to a premature end.

7.3. Exploration on Java (seeFig. 2)

Exploration drilling at Wayang–Windu, renewed after 1995, confirmed the existence of the thick ‘vapour-dominated layer’ already encountered by the first well in 1991. Several additional deep wells were drilled to depths where temperatures are between 280 and 300^◦C in the underlying brine-saturated region at depths of 2000–2500 m. A three-dimensional reservoir model of the system has recently been presented (Asrizal et al., 2006). Drilling of production wells was stopped in 1998. At that time sufficient steam flow was available to drive a single 110 MWeturbine of the first power plant, which was completed in 1999 (Murakami et al., 2000).

Exploration continued in 1994 at Karaha–Telaga Bodas when the project was taken over by the private Karaha Bodas Company. Detailed geophysical (MT) studies indicated that K.

Karaha and Telaga Bodas are part of the same geothermal system (Anderson et al., 1999);

this was confirmed by deep drilling, which showed that the Talaga Bodas sector hosts a mag-matic geothermal system (Allis et al., 2000). Nineteen deep (>1 km) holes were drilled within a ∼30 km² target area between 1995 and 1998. Most were fully cored slim holes, but eight were completed as exploration and production wells. One, near the acid Lake Telaga Bodas, reached ∼2300 m depth and encountered a vapour-dominated reservoir with a maximum tem-perature of about 353^◦C; another well, about 2800 m deep with a bottom temperature of about 316^◦C, found neutral-pH NaCl fluids in the Karaha sector (Allis et al., 2000; Powell et al., 2001).

The Telaga Bodas part of the reservoir was interpreted in terms of a magmatic vapour ‘plume’

that changes gradually towards the Karaha sector to a ‘neutral-pH condensate layer/vapour layer/liquid substratum’ type reservoir, similar to the Wayang–Windu system. Development of the project was suspended after 1998. Financial support by the US Department of Energy, however, allowed analysis and interpretation of the exploration data, which were published in a num-ber of papers (Tripp et al., 2002; Raharjo et al., 2002; Moore et al., 2002a,b,c; Nemˇcok et al., 2007).

Rapid exploration drilling was also employed at Patuha between 1996 and 1998 when 17 deep temperature–gradient holes (slim holes) were drilled to depths ranging between 650 and 1200 m within a roughly 40 km²target area. The inner sector was probed by 13 deep wells down to depths between 1000 and 2150 m (Layman and Soemarinda, 2003), avoiding the area sur-rounding the acid Lake K. Putih (Sriwana et al., 2000). The deep wells encountered a∼0.5 km thick vapour-dominated (natural two-phase) layer below 1 km depth at temperatures between 200 and 240^◦C. The layer is underlain by a hot, liquid-saturated region that produced hot water with very low mineralization (of unknown pH) in one deep well (PPL-02), indicative of a ‘heat pipe’ setting (Bau and Torrance, 1982). The first productive well was the ∼1000 m deep PPL-01 well drilled in the SE part of the field near K. Ciwiday (bottom T∼ 200^◦C);

the well lies roughly 8 km east of the Cibuni discovery well CBN-1. The system has affinity with that encountered at Karaha–Telaga Bodas and Wayang–Windu, except for the composition of the liquid beneath the vapour-dominated cap. Vapour pressure, and hence vapour tempera-ture, increase at constant level towards K. Putih. Exploration here was also brought to a halt in 1998.

Fast developments also occurred at Dieng when a private developer (HCE) started operation.

Eighteen deep production wells were drilled between 1995 and 1998, with sixteen wells drilled in the new Sileri field, 3–5 km NNW of the centre of the Sikidang field. Almost all HCE wells produce from depths between 2000 and 2300 m, where bottom-hole temperatures are in the 300–335^◦C range. The wells discharge neutral-pH, two-phase fluids with an enthalpy between 1400 and 1750 kJ/kg. The TDS of the dilute brine was between 15 and 25 g/kg, and the NCG content low (<1% by wt. in separated steam). Some input of magmatic fluids was detected in two wells located between the two fields (Layman et al., 2002).

A 60 MWe plant (Unit 1) was built in the Sikidang sector to use steam from a few nearby Pertamina wells, at the time still accessible, with additional fluids coming from HCE wells in the Sileri bore field. However, the Sikidang wells failed and all fluids had to be sourced from the Sileri field. The Sikidang plant was commissioned in early 1998 but did not start operation since HCE withdrew from further developments as a result of the financial crisis. After settling of insurance claims and returning the Dieng Project to the

Indonesian Government in 2001, the Dieng power plant (Unit 1) was re-commissioned in 2002.

7.4. Exploration on Bali and Flores

Exploration started again on Bali when access problems were solved and a JOC was signed between Bali Energy (a joint venture involving a major US developer and a local company) and Pertamina at the end of 1994. The Bratan Caldera prospect became the Bedugul geothermal project (Fig. 2). Some geophysical surveys (TDEM-MT) were repeated and exploration pro-gressed rapidly to the drilling of six (1–1.6 km depth) slim holes and three deep exploration wells (BEL-01, BEL-02, and BEL-03). The latter wells were drilled to vertical depths of about 2400 m where a maximum temperature of 310^◦C was measured (Hochstein et al., 2005). They could not be properly tested after completion in early 1998 and the project was suspended as a result of the 1997–1998 financial crisis. Recently, two of the three deep wells have been discharged suc-cessfully, confirming the existence of a deep, productive, liquid-dominated system, which might present two-phase fluid zones beneath the Bratan Caldera (Mulyadi et al., 2005).

A New Zealand Aid programme was extended in 1997 to allow for an assessment of the Sokoria prospect on Flores (Harvey et al., 1998). Another bilateral aid project (between the Indonesian and Japanese Governments) led, after 1997, to the exploration of the Bajawa prospects, also on this island (seeFig. 4).

The Sokoria (Sukaria) prospect lies on the SW slopes of Keli Mutu volcano (summit height:

1640 m), known for its three acid crater lakes below the summit (Pasternak and Varekamp, 1994).

Over its flanks and at elevations of <900 m, there are widespread thermal springs that discharge magmatic condensate, steam condensate, and mixed reservoir fluid (Harvey et al., 2000). On the SE slopes and in the SW sector, about 10 km from the summit, neutral-pH NaCl water dis-charges at elevations of about 500 and 300 m, respectively. Cation-equilibrium temperatures of 200–250^◦C were obtained for two outflows of neutralized fluids, derived presumably from a magmatic geothermal system centred on Keli Mutu; the Sokoria prospect may be associated with one of its SW outflows.

In the greater Bajawa area on Flores, there are active thermal areas over the northern and eastern slopes of the high-standing Inerie stratovolcano (2245 m summit height), whose latest eruptions are of Holocene age. Impressive thermal areas can be found at Keli (840 m elevation) and Nage (530 m elevation), roughly 5 and 6 km east of Inerie volcano, respectively. Here, hot acid sulfate–chloride waters discharge with temperatures of up to 70^◦C at Keli and up to 80^◦C at Nage. For the latter area, a total discharge rate of about 500 kg/s has been quoted (Takahashi et al., 2000). It has been inferred that the manifestations at Keli and Nage are derived from a magmatic geothermal parent system (Nasution et al., 2000).

Another high-temperature prospect in the greater Bajawa area occurs at Mataloko, at an eleva-tion of about 1000 m, roughly 13 km NE of Inerie Volcano. Acid sulfate water, with temperatures up to 95^◦C, discharge within a large (∼0.35 km²) area of steaming ground showing acid surface alteration. Gas geothermometry indicates a temperature of about 250^◦C at depth. The Mataloko area was explored as part of an Indonesia–Japan aid project and the first two shallow exploratory wells were drilled inside a steaming ground area in 2000. The second well (MT-2) encountered a productive layer with an inferred bottom temperature of about 197^◦C at 180 m depth (Sitorus et al., 2001). Two additional wells (MT-3 and MT-4) were recently drilled to 540 m and about 755 m depth, respectively and found a maximum temperature of 205^◦C (Kasbani et al., 2004); the two wells produced minor amounts of steam.