Kambuna offshore development restoring power to North Sumatra

Serica claims that North Sumatra is facing a gas market shortfall of around 100-200 MMcf/d (2.8-5.7 MMcm/d) by 2010. There is a severe shortage at present, causing frequent disruption to power supply. Local power stations depend on associated gas from onshore oilfields operated mainly by Pertamina, but most of these are now in decline. Despite Indonesia’s reputation as gas rich, the majority of its large natural deposits are in thinly populated regions and generally are allocated to LNG export.

However, as Serica’s CEO Paul Ellis points out, the government has moved in recent years to address the energy shortfall. These moves include investments to upgrade the country’s onshore gas distribution network, to capture gas previously flared; and to give investor incentives to develop some smaller gas fields neglected due to low domestic prices.

All these factors helped persuade Serica’s board to commit to Kambuna, which is also the company’s first operated development project. Progress has, however, been slower than expected, but most of the technical and commercial issues now have been resolved.

Development issues

Serica, named after a 19th century tea clipper, was formed in 2000 by mainly ex-ARCO E&P professionals. They left the company following its merger with BP, and their areas of experience account for Serica’s initial focus on the UK and Indonesia.

During 2003-05, management secured operating interests in two production-sharing contracts offshore northern Sumatra and the Java Sea (Asahan and Biliton), and in the Glagah Kambuna technical assistance contract (TAC) adjoining Asahan. The TAC, extending over 380 sq km (147 sq mi), contained two discoveries: Glagah, drilled by Caltex in 1985, and Kambuna, drilled by Bow Valley the following year.

Late in 2005, Serica successfully appraised Kambuna via a well drilled by the semisubmersibleGalaxy Driller to TD of 7,963 ft (2,427 m). This tested gas at over 17.5 MMcf/d, and 1,500 b/d of condensate. Having demonstrated commercial potential, Serica submitted a development plan to Pertamina shortly afterwards. As part of this plan, it commissioned a 3D survey from Veritas-DGC in mid-2006 over Kambuna and other prospects in the TAC.

The same rig earlier drilled the small Togar gas discovery for Serica in the Asahan block. And another seismic study suggested the Tanjung Perling gas accumulation to the south of Kambuna in Asahan also might be commercial. Thoughts of a joint development had to be put on hold when the PSC term expired, forcing relinquishment. The block is not available for re-tender.

In April 2006, Pertamina approved Serica’s plan for Kambuna, which targeted first production in 2008.

“When I joined the company in 2005, there were high hopes of being on production in 2007,” says Ellis, “but this proved to be unrealistic for several reasons. Front-end engineering design studies, for instance, could not start without approval for the plan of development – without this we would have lost the TAC and it would have reverted to Pertamina.”

Some internal problems also had to be resolved, and progress was disrupted further by cancellation of a rig contract. The originally designated jackup,Seadrill 5, was due to arrive in February last year following an assignment nearby for Premier in the Natuna Sea. But it suffered punch-through after setting down the legs during rough weather.

“Also,” Ellis points out, “it generally takes much longer than you expect to negotiate contracts in Indonesia. There is a very strong, anti-corruption system of scrutiny in place. Before going out to tender for equipment and services, you have to get approval for your tender process by demonstrating how you will determine the winner.

“Before that, however, you must have Pertamina approval (AFE) for your estimate of the contract value. And if the tender bids are more than 10% different from the AFE number, you must then re-tender. In the case of drilling contracts, this can be quite frustrating, as you risk losing the rig to another operator.

“But the authorities in Indonesia have become more flexible in recent times. So, for example, when we suggested ‘let’s try sharing a rig that another operator has on contract, relying on their tender process,’ they accepted our plan. It was just unfortunate that this was the rig that suffered a punch through and was therefore not ultimately available to drill for us.”

After this, Serica secured the jackupGSF 136 on a five-well contract, which started with two exploration wells on the Biliton PSC last December, followed by development work on Kambuna, scheduled for February-April this year.

Production potential

Kambuna’s Upper Belumai reservoir contains an estimated 26 MMboe gross of wet gas, with a condensate/gas ratio of 100 bbl/MMcf. Under the first-phase plan, production will build to a plateau rate of 50 MMcf/d of gas and 5,000 b/d of condensate. Based on known reserves, this rate could be sustained for two to three years. Later on, production could be supplemented by tie-ins from other discoveries – Serica has tentative plans to resume exploration drilling in the area in 2009.

The platform, completed recently at the H&H Utama yard in Batakan Kecil, Balikpapan, at a cost of $6 million, is an Icon Engineering design, tripod wellhead support tower weighing 160 metric tons (176 tons) and 48 m (157 ft) high. According to Ellis, Australian operator Santos has built several similar wellhead towers for various shallow water projects in the region.

To cut costs, theGSF 136 also will install Kambuna’s platform before embarking on the wells – Serica’s project manager knows what to expect, having managed similar installations previously for Santos. He is leading a 15-strong project team at Serica’s offices in Jakarta, comprising a mixture of Indonesians and ex-pats.

The platform will be able to accommodate up to four development wells, although only three will be needed during the initial production phase. Weather permitting (there have been monsoon rains in the region recently), drilling was due to get under way this month, starting with a re-completion of the 2005 appraisal well. Once the platform has been installed, two new deviated wells will be drilled from the tower. “The first will go quite close to the location of the original discovery,” says Ellis, “while the other will be in a new area of the field.

“Initially, our Phase 1 plans included an FPSO. We considered separation offshore, with the gas piped to a reception point on land, and the condensate offloaded to a shuttle tanker. But in 2006, we decided this was not the way to go, for two main reasons. Firstly, the lease price for an FPSO went up – we had been thinking in terms of $60,000/day, but were being quoted up to $120,000/day.

“Also, based on interpretation of our 3D seismic survey in 2006, we found that the Kambuna field was probably two accumulations, not one. So we decided to develop the proven part first, setting the other aside as appraisal upside.

“From our knowledge of the proven area of the field, a five-year commitment to an FPSO was not economic, so we had to revise our plans, which was another cause of delay. However, we made provision to bring in an FPSO later if this made economic sense.”

The two-phase, 14-in. (35.56-cm) pipeline has been designed to handle 50-60 MMcf/d of wet gas. “But if we find more gas in the area and opt to increase production, we could convert the pipeline to accommodate dry gas at up to 100 MMcf/d, with the condensate being separated and exported offshore using an FPSO.”

Pipeline tender pending

Serica is about to issue invitations to tender for supply and installation of the pipeline. This will extend 40 km (25 mi) offshore, in 46 m (151 ft) water depth, followed by a 6-8 km (3.73-4.97 mi) onshore section tracking existing rights of way to the town of Pangkalan Brandan. Here Pertamina operates an LPG plant, which currently is mothballed – Serica is looking at the possibility of this being re-opened using supplies from Kambuna.

It is also negotiating with Pertamina for land next door to build gas treatment facilities, including a slug-catcher and condensate separation equipment. There is plenty of existing tankage available for storage.

Ellis estimates the overall cost of the development offshore and onshore at $108 million, and expects payback within the second year of production. “We get up to 80% of production for cost recovery in the first year,” he adds, “and 75% in the second year.

“Under our initial concept, the field was thought to be larger than we now believe the main area to be. That’s why we originally planned four wells, but only three are now needed to produce 50 MMcf/d for export. However, each of those wells should be capable of producing 30 MMcf/d; if the reserves prove to be greater than expected, we could negotiate to supply more gas, but we would need to demonstrate that we were not harming the ultimate recovery.

“We expect plateau production for two to three years. What we do next depends on what happens in the reservoir – we still don’t know how deep the gas-water contact is, for example. Will pressure decline, reducing well rates, or will there be aquifer support, which would maintain reservoir pressure and well rates but might lead to water production. My guess is that there will be pressure decline and that water breakthrough will not be a major issue.”

Expansion options

Serica operates the Glagah-Kambuna TAC with a 65% interest, the remainder being held by Houston-based GFI, currently the subject of a takeover bid by Salamander Energy. In other licenses Serica has been working with local partners.

In the Java Sea, the company operates the 6,575 sq km (2,539 sq mi) shallow water Biliton PSC, between the islands of Java and Kalimantan. This area had only one exploration well drilled by Ashland Petroleum in 1974. However, BP did conduct a seabed survey in the 1990s that revealed the presence of nine potential oil seeps in the Biliton block.

After acquiring 2D seismic during 2004-05, Serica brought in the GSF 136 to drill two large prospects, Batara Ismaya and Batara Indra, but both were dry. “The jury is still out as to whether sufficient hydrocarbons were generated in this area,” says Ellis. “Ashland’s well had oil shows, but if there has been migration, it hasn’t reached our prospects. This was always a high-risk area, which is why we sought a farm-in partner to pay most of the drilling costs.”

Serica also operates the Kutai PSC with 52.5%, in partnership with PT Ephindo. The PSC comprises five separate areas in the Kutai basin, onshore and offshore. These have been relinquished over the years by operators of nearby gas fields in East Kalimantan’s Mahakam delta that provide feedstock for the Bontang LNG terminal.

“It’s a standard Indonesian PSC,” Ellis explains, “30 years in duration, with a 10-year exploration phase. Currently we are in the process of obtaining existing data, a lot of it 3D seismic, from the government. Then we will interpret the seismic and draw up our priorities for drilling.”

Serica may drill the onshore tract first. “Offshore, we will be looking for prospects of 30-80 MMboe in size to tie into the extensive infrastructure that already exists in the area.” Serica has also proposed participating in a new Total-operated 3D survey south of the Peciko field in the south-western corner of the PSC.

Serica plans to pursue further PSCs in specific areas of interest in Indonesia. “There is a licensing round under way at the moment that we are evaluating,” Ellis points out.

“We would also like to go in for oil exploration in the right areas, but not deepwater, which is technically challenging and costly to drill. We tend to prefer acreage with prospects close to existing areas of demand, and therefore not economically difficult to develop, or areas known to the industry but not well explored.”