New exploration model proves productive
Jeremy Beckman
Editor, Europe
Years of perseverance in Vietnam’s Cuu Long Basin have finally paid off for SOCO International. This summer, the London-based independent announced the outcome of productive well tests in blocks 9-2 and 16-1. One confirmed the 100-150 MMbbl potential of the granitic basement at Ca Ngu Vang, while the other revealed a significant discovery in the previously unknown Miocene/Oligocene play fairway with additional upside potential along a well-defined trend.
Both wells were drilled by joint operating companies, comprising the block partners Thailand’s PTT Exploration and Production Co. (PTTEP), state oil company PetroVietnam, and SOCO’s 80%-owned subsidiary SOCO Vietnam. Discussions are already underway for fast track developments, potentially via under-employed platform infrastructure in neighboring blocks.
SOCO was established in the early 1990s by current President and CEO Ed Story. Both he and Executive Vice President Roger Cagle have worked together for over two decades, initially at Exxon, then at Superior Oil, at one time the world’s leading independent. The company’s policy is to recruit specialists reared by majors.
“This is what differentiates SOCO from its peers,” Cagle says. “The majors always instill a disciplined approach to running a business.”
Over the past 15 years, the company has built up E&P interests in Russia, the Middle East, the Far East, and more recently the Republic of Congo. It entered Vietnam in 1997, on the recommendation of an expatriate Vietnamese, formerly employed by Mobil in Midland, Texas.
“We had a reputation for giving people a free rein,” Cagle explains, “so he came to us, suggesting we pay him to go to Vietnam to scout for opportunities. During the course of repeated trips, he developed excellent relationships with the state petroleum authorities. This led to the creation of our subsidiary company, in which he retains a minority stake to this day.
Having a small registered company got them past the introductory stage with Vietnam’s authorities, Cagle said. “We also had the benefit of having worked in Russia’s Permoblast region, west of the Urals, in partnership with Lukoil and Neftegaz, where we had put in two pipelines and 60 onshore wells. The Vietnamese had a lot of seismic data and logs written in Russian, so being able to understand and use that data gave us a leg up. And we had left Russia with good relations, which later led to Gazprom joining SOCO as a minority shareholder.”
Slow start
The first blocks that became available were 16-1 and 16-2, both in the Cuu Long basin. SOCO bid for 16-1, in competition with Amerada Hess and Exxon. “In the event, we were awarded 30%,” Cagle explains, “with the other two offered 10% each, the remainder to be held by PetroVietnam. But Exxon were not keen on that arrangement, and the bigger companies in general were averse at that time to working under Vietnam’s joint operating company (JOC) structure.”
In the event, Exxon exited immediately; Amerada stayed put a while longer, participating in early seismic acquisition and processing, before departing to pursue other interests in the Asia-Pacific region.
Block 16-1 is located 50 km off Vietnam’s southeast coast, in water depths of around 50 m and adjacent to acreage containing Bach Ho, the country’s largest and longest-producing oilfield.
Map shows locations of discoveries to date in blocks 9-2 and 16-1 and their proximity to prospective host platforms (Rong Do, Bach Ho).
“Our primary targets at that point were shallower basement structures in the western part of the block,” says Cagle. During the 1980s, Vietsovpetro, the Vietnamese/Soviet joint venture, drilled the Ba VI 1 well in 16-1, testing 380 b/d of oil from a Miocene sand interval. However, the well made only slight contact with the granitic basement, which has provided most of the prolific finds in this part of the basin, including Bach Ho.
In May 1999, SOCO and PetroVietnam signed a heads of agreement, establishing the terms of a petroleum contract for block 16-1, which would be operated by the Hoang Long JOC. At the same time Mobil had signed a similar agreement for block 9-2. A year later, Exxon pulled Mobil out of block 9-2 as part of a global asset overhaul, following the merger between the two companies. After an open bidding process, SOCO also won a 50% interest in this block, with PetroVietnam retaining its 50% interest. The block operator is the Hoan Vu JOC.
Picking up the pace
Without major involvement, funds were limited for exploration. The situation changed early in 2002, when PTTEP farmed in to both blocks, also agreeing to fund drilling costs. Under the country’s hydrocarbon law, PetroVietnam is only obliged to pay its share from the development phase.
In fall that year, the initial drilling campaign brought basement discoveries in both blocks. All were vertical wells, designed to be abandoned, regardless of the outcome. Basement development wells in this region, in contrast, are often deviated, to achieve better flow rates from the more productive fractures.
First up was Ngua O-1X, a well on the C prospect in block 16-1, which encountered multiple fracture systems. A drillstem test within the basement interval recovered 250 b/d over 18 hours. Next was Ca Ngu Vang-1X (CNV-1X) in block 9-2, which terminated in the basement at 4,567 m. This well flowed 2,500 b/d of oil and 6.6 MMcf/d of gas from an unstimulated open-hole test, partly hindered by a collapsed section at the top of the basement interval. Log analysis also revealed oil shows within the Miocene. The third success was Voi Trang-1X in block 16-1, which flowed 3,500 b/d of 42° API crude, mainly from Oligocene and basement intervals.
The 2003 campaign did not start off as well, with Ca Ong Doi-1X (COD-1X) in block 16-1 only yielding oil shows from interbedded Oligocene sands and shale source rocks. A subsequent appraisal well on Voi Trang, designed as a basement test, was also abandoned after encountering only oil shows from the upper Oligocene. Later that year, the run was resumed with a successful vertical appraisal well on Ca Ngu Vang (CNV-2X), 2 km from the original discovery.
This well encountered basement at a TVD of 3,940 m and intersected a 1,000 m oil column, double that of the original discovery, and at a location 500 m deeper. There was also less evidence this time of basement fracturing. A follow-up horizontal section was then drilled from the well’s upper section in a northeasterly direction, towards Japan Vietnam Petroleum Co. Ltd.’s (JVPC) producing Rang Dong field nearby in block 15-2. Although the horizontal section had good shows, again fracturing was limited.
While drilling on both blocks had brought results, the finds were mostly small, particularly in 16-1.
“With exploration costs of $20,000 per well, you’re looking for returns of at least 50 MMbbl,” Cagle says. The wells drilled did, however, provide important information about the reservoir that would be used to process the seismic using the prestack depth migration (PSDM) techniques employed to ‘see’ through salt in the GoM. According to Cagle, “this seemed to have unlocked the way into the basement.”
Maintaining momentum
In 2004, SOCO and its partners focused on reprocessing existing and acquiring new seismic, ahead of their next planned multiple well campaign. WesternGeco acquired a total of 650 km of 3D seismic over both blocks, while existing data over the CNV structure was reprocessed using PSDM.
“The key in the basement is intersecting the more productive fractures. With the benefit of our prestack depth migration seismic, we produced 13,000 boe/d from our first well this year.”
Cagle is referring to the third appraisal well on Ca Ngu Vang in block 9-2, spudded in January by the jackupAtwood Beacon. After reaching its targeted depth of 6,123 m, which is the longest measured depth drilled off Vietnam,CNV-3X tested 9,010 b/d of oil and 22.6 MMcf/dof gas from an un-stimulated test from a granitic basement interval of 2,000 m. TVD was 4,425 m, at an average angle of 82° from the vertical through the basement. The well was then suspended as a potential producer.
The rig moved on to 16-1 to explore Te Giac Trang (TGT), one of the Miocene/Oligocene prospects in the eastern part of the block identified from the previous year’s 3D campaign. In June, after reaching a measured depth of 4,480 m, the well went on to test several Lower Miocene and Upper Oligocene intervals previously undrilled in this part of the block. TGT-1X tested 9,430 b/d of 36° API oil and 4.85 MMcf/d of gas.
The drillstem test was conducted from the Lower Bach Ho formation in the Miocene interval between 2,700 and 2,760 m. Net pay from the tested interval was estimated at 31 m; a further 33 m of net pay interval was not tested, due to time and equipment constraints, but this is also thought to be oil-bearing. A brief test over a deeper Oligocene interval generated reasonable oil shows, but the formation appeared to be tight, and therefore not capable of commercial flow rates.
After completing the current appraisal (fourth) well on Ca Ngu Vang, the partners plan to return to 16-1 for an appraisal well just north of TGT-1X. Cagle believes the structure may contain up to 370 MMbbl, with additional potential within the block. The oil quality looks to be high, with a very low gas-oil ratio.
New 3D seismic will be acquired early in 2006 in an attempt to delineate further leads in 16-1. To secure an extension of the permit, the Hoang Long JOC may be obliged to drill another commitment well. But discussions are already underway with third-party operators to develop both Ca Ngu Vang and TGT. UK analysts Teather and Greenwood forecast possible capex of $350 million for each project.
“Development work will be the responsibility of the JOCs,” Cagle says. “They’ll contract the relevant specialists, some from PTTEP and us. In turn, I’m sure SOCO will bring some people in at the sharp end of the development stick.” Ca Ngu Vang will likely go forward first: “This field doesn’t need a lot of deviated wells,” Cagle says. “It could be brought onstream with two or three.”
Teather and Greenwood estimate recoverable reserves at 100 MMboe. The oil is rated at 42° API, with a high gas-to-oil ratio. The logical option looks to be taking the field through JVPC’s Rang Dong facilities to the northeast in block 15-2. JVPC is partnered here by ConocoPhillips and PetroVietnam.
“They are very keen, because the Rang Dong platform is currently operating with spare capacity,” Cagle says. “The puzzle for us is if we go across their platform, we may limit our production. But we might be able to bring the field on stream in 2007. If we build our own kit, we could have higher output; however, we would come onstream later.”
By the end of the year, the partners should know if Rang Dong is an option. “We’re also keen on taking CNV’s gas into the Cuu Long basin gas trunkline to Vung Tau. However, the Rang Dong field doesn’t have nearly as much associated gas, so that could mean a major add-on for us, in terms of new process facilities. Front-end studies are already in the works.”
As for TGT, spare capacity could be available on Bach Ho to the east, where production has declined recently to 230,000 b/d. This field has produced over 1 Bbbl of oil to date through three fixed platforms, mainly via vertical wells, in turn necessitating large-scale water injection. “On the eastern side of 16-1, we have some shallow discoveries we could factor into the development, and we could drill our wells a lot cheaper and faster.”
The partners currently have this year’s rig, theAtwood Beacon, contracted for three more wells and hope to secure it for up to another two, if an agreement ahead of its assignment offshore India can be rearranged.•
