No stone unturned: Exploration for new resources mitigates other supply challenges

The country’s reliance on natural gas, needed to play an increasing role in meeting both its own energy needs as well as its continued use as a cash-generating export, leaves little doubt that the country will need to use any and all means available in securing new domestic supplies. While there are still substantial amounts of conventional areas to explore throughout the country, recent advances in techniques and technology are fuelling interest in unconventional reserves such as those locked up in shale gas formations or coal bed methane (CBM) deposits. In fact, unconventional gas resources are predicted to be substantially greater than conventional reserves, with the Ministry of Energy and Mineral Resources (MEMR) estimating shale gas potential of approximately 574trn sq cu feet (tscf) along with CBM projections of 453.3 tscf, compared with proven and probable conventional natural gas reserves of around 150 tscf. Yet in spite of this potential, a number of barriers to tapping into these energy sources remain in place including regulatory challenges as well as the relatively more expensive extraction costs compared to conventional measures.

Playing The Long Game

“CBM takes time to develop, longer than conventional gas,” Christopher Allen, the CBM appraisal manager of Vico Indonesia, told OBG. “There are different completion technologies, which require quite a learning curve that is only solved through trial and error. As exhibited in the US with shale gas and in Australia with CBM, once the early stages of trial and error have refined the process and created efficiencies, production is expected to proceed at an increasingly rapid pace. The challenge for the Indonesian CBM industry at the moment is how to push through these early risk and cost barriers in order to begin producing more efficient projects which are economically viable enough to stand on their own.”

Some of this increased technical difficulty and higher cost of production lies in the composition of the projects, which, unlike conventional oil and gas fields that generally tap into large contiguous reserves using few wells, instead require numerous wells tapping different sources. As is the case in the shale gas trend sweeping North America, the multitude of wells required means that extraction and utilisation of the gas is only economically viable due to the associated conventional oil also extracted from the site, and early efforts have also been aided by government financial assistance.


As a result of the longer lead time, the sector will not –at least initially – be able to provide both cheap gas and rapid progression in terms of supply. The US solved this through tax breaks that allowed shale gas producers to drill thousands of wells without losing money, thus developing expertise and scales of economy which were able to sustain the sector after these tax incentives expired. In Australia the government required power producers to purchase natural gas which led to an increased demand in CBM as it was still less expensive than imported liquefied natural gas (LNG). For its part, the Indonesian government has made its own concessions in a bid to jump-start the sector and has offered private companies a 45% production share for CBM projects which compares favourably to the usual 15% granted to petroleum contracts and 30% for conventional natural gas. Another solution could be to price CBM gas at or closer to parity for export pricing rather than at domestic levels.

With regional LNG priced higher than domestic gas, the country could benefit from paying more for CBM and still save, given international LNG costs. This strategy would also boost government coffers, which take a cut of production, as well as stimulate the local economy through investment and employment. To compensate for long exploration periods and the dewatering phase, which can take years, the industry would welcome an extension of the 30-year limit on CBM production sharing contracts (PSCs).


Still in its infancy, the fledgling CBM sector’s output has so far been limited primarily to production derived from dewatering and production test wells. In 2012 a total of eight wells situated in the Sekayu, Sanga-Sanga and Muara Enim contract areas combined to produce 0.98m standard cu feet per day (mmscfd), up from 0.27 mmscfd produced by two wells in two contract areas in 2011, according to SKK Migas. As of the end of 2012 there were a total of 54 active CBM PSCs accounting for a little more than 16% of all PSCs in the country. Moving towards practical utilisation of the gas, Vico Indonesia began producing 0.5 mmscfd of CBM gas for the PLN power plant at Sanga-Sanga in 2013.

Although CBM PSCs call for the drilling of hundreds of exploratory and developmental wells over the next few years, the aforementioned economic and technical hurdles as well as other regulatory barriers have slowed progress in some areas. As is the case with other extractive industries, the sector faces an uphill regulatory battle with issues like land accessibility due to forestry regulations, protected areas, government oversight and purview, rig access, lack of financial incentives, among others.

“In order to achieve the exploration commitments outlined in the PSCs, the government needs to make the projects financially viable, get rid of regulatory barriers, and sort out the land issues,” said Allen. “If they can do those three things, we could see significantly more development because the potential is really there.” Due to the challenges facing the sector, only three CBM PSC contractors succeeded in fulfilling their developmental commitments in 2012: Newton Energy Capital (which is working the GMB Kutai contract area), Vico CBM Indonesia (working the GMB Sanga-Sanga contract area operator), and Medco CBM Sekayu ( working the GMB Sekayu contract area). The combined efforts of these firms resulted in 16 new core hole drillings, 14 exploration drillings, 10 dewatering-production tests and 33 G&G (geological and geophysical) studies according to SKK Migas. While these efforts were an improvement, they represent just a fraction of stated commitments from the industry.


A lesser explored option to date, activity in shale gas exploration has only recently begun to gather momentum in the past couple of years. Early studies have indicated that the country’s potential shale gas reserves are located primarily in six basins around the country including the Baong, Telisa and Gumai shale basins in Sumatra (with a combined 233 tcf) with additional potential located in Java (48 tcf), Kalimantan (194 tcf) and Papua (90 tcf) with the remaining 9 tcf dispersed among other areas, according to the Indonesian MEMR’s directorate of oil and gas. While the 574 tcf reserve is impressive along the project CBM total of 453.3 tcf, the actual technically recoverable reserves will undoubtedly be less than these initial projections.

Technology first refined in the well-documented shale gas boom of the US could similarly be brought to bear in Indonesia, and Chevron Pacific Indonesia already uses hydraulic fracturing (fracking) techniques in Duri, Sumatra — the country’s largest oil field — while Australia’s NuEnergy Gas also initiated fracking operations at five new untested coal beds in West Java starting in 2013. Pertamina has also stated that it would be working with Canada’s Talisman Energy to tap into its previous shale experiences in the US in the Eagle Ford and Marcellus shale plays although no formal partnership arrangement has been announced.

Efforts to explore and exploit these resources are still in the early stages with the government receiving 75 shale gas development proposals for potential shale gas blocks in Riau and Central Kalimantan provinces through a direct offer procedure as of May 2013, according to the directorate. State-owned energy company Pertamina is taking the lead in the sector and inked a PSC for the Sumbagut block in North Sumatra in May 2013. Sumbagut is estimated to contain shale gas potential of 18.56 tcf, according to Pertamina, and the firm is targeting initial production in year seven of the PSC, at 40-100 mmscfd for the $7.8bn project. Pertamina’s move into shale comes on top of its substantial participation in the CBM sector where it holds 14 CBM PSCs located in Sumatra and Kalimantan in which it most recently completed the drilling of two exploration wells in Tanjung Enim Block, while exploratory drilling of two other wells in Muara Enim Block continues into 2013.

The agreement signed by Pertamina is the first of its kind in Indonesia to make use of the new Government Regulation 5, issued in January 2013 which outlines procedures for selecting and offering non-conventional oil and gas contracts.

The regulation was created to address the higher investments requirements and risks association with unconventional oil and gas exploration from reservoirs formed with low permeability such as shale oil and gas, tight sand gas, coal bed methane and methane hydrate.


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The Report: Indonesia 2014

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