Jeremy Beckman - Editor, Europe
Output is building at Ca Ngu Vang, the first field in Vietnam’s Cuu Long basin to be developed as a third-party tieback to the Bach Ho offshore complex.
Ca Ngu Vang (CNV), in Cuu Long basin block 9-2, was discovered by the Hoan Vu Joint Operating Co. (JOC), comprising PetroVietnam, PTTEP, and London-based SOCO International. At peak, the field should generate 20,000 boe/d of oil and wet gas, partly offsetting natural decline at Bach Ho, where the facilities currently operate at less than half their process capacity of 400,000 boe/d.
To the west in block 16-1, the same partners are active as the Hoang Long JOC. Here they have established a major Miocene/Oligocene play fairway, and a potentially more prolific and deeper high-pressure/high-temperature play.
Fractured basement granite is the setting for CNV, Bach Ho, and a series of other fields trending northeast to Su Tu Den and Su Tu Vang in block 15-1. Bach Ho is by far the biggest, having delivered well over 1 Bbbl of oil to date.
The CNV platform with the PVD-1 jackup alongside.
Mobil, which operated most of this acreage in the early 1970s, was the first to recognize the potential for major structures following an extensive 2D seismic program. After the company’s forced exit in 1975, the Russian/Vietnamese venture Vietsovpetro took sole charge of exploration.
According to Edward Story, SOCO CEO, “Vietsovpetro first developed the conventional Miocene reservoirs at Bach Ho. While drilling one unsuccessful Miocene well, they decided to keep on drilling into basement, where they discovered the unconventional granite basement that became the heart of the Bach Ho development and much of the excitement that followed in the Cuu Long basin.”
When the first wave of European companies returned to Vietnam in the late 1980s, they focused on conventional reservoir targets in this basin and were largely unsuccessful. In the 1990s, the US lifted the trade embargo, and a further wave of exploration began. At that time PetroVietnam actively encouraged basement exploration, which led to discoveries such as JPVC’s Rang Dong in block 15-2.
Cuu Long basin map shows CNV-Bach Ho export route in block 9-2 and discoveries in block 16-1.
Later on, ConocoPhillips transferred pre-stack depth migration (PSDM) seismic techniques deployed to look through salt in the Gulf of Mexico to improve well placement in fractured basement prospects in block 15-1. “They also introduced deviated wells to basement development,” Story adds.
None of these technologies were available early on for Bach Ho, where mounting water production has necessitated several re-development phases over the past two decades. Eventually Vietsovpetro was able to supplement its vertical wells with horizontal producers paired with injectors, and according to Antony Maris, SOCO’s vice-president, Operations & Production, learned how to pair these to stem water breakthrough.
In 2004, following mixed basement drilling results, the block 9-2 partners turned to PSDM to re-process seismic over the CNV structure. The resultant appraisal well, CNV-3X, was much more productive, testing over 9,000 b/d of oil and 22 MMcf/d of gas from a granite basement interval of 2,000 m (6,561 ft). Two years later, the partners executed another successful test on CNV-4X, in the process setting a measured depth record 6,330 m (20,767 ft) for a Vietnamese well.
Work on the $280-million development started in earnest early in 2007, with yards in Vietnam assembling CNV’s unmanned shallow water wellhead platform. Specialist vessels were then brought in to install the platform and the 25-km (15.5-mi) multiphase pipeline taking the field’s well stream to Bach Ho’s CPP3 process platform.
In August that year, PetroVietnam’s newly commissioned jackup PVD-1 started drilling the first of six first-phase development wells. Four were on line when oil and wet gas started flowing in July 2008, with the fifth well due to be completed last month. “We may add a seventh,” says Maris, “although that will depend on production performance.” The partners have no plans for further exploration on or around CNV, he adds, following an unsuccessful attempt to prove further reserves to the east.
Drilling operations onboard the PVD-1.
“These are standard deviated basement wells nothing fancy,” Maris explains, “and the associated gas acts as a pump, so there is no need for downhole lift.” However, a water injector line has been put in alongside the multiphase line from CPP3 to provide pressure support.
The Bach Ho CPP3 process installation controls operations on the CNV platform, also opening and shutting the wells. The third-party arrangements which include a metering allocation system with a tariff mechanism are all new to PetroVietnam, says Maris. “They do accept gas already from JVPC’s Rang Dong field in block 15-2, but that simply flows through the Bach Ho trunkline system.”
“CNV’s oil is more gaseous,” adds Story, “but for the Bach Ho team it is just a case of making slight adjustments to their process facilities.” Post-processing, the crude is stored on an FSO (there are three permanently on station at Bach Ho) before being sold on the international market.
The processed gas stream heads through an existing pipeline to the Ding Ho terminal in southern Vietnam, where the liquids are stripped out for sale as LPG. “Ours is a very different, rich gas stream,” Story points out, “so we have had to set up gas allocation procedures with Vietsovpetro.”
A sales agreement for the gas has still to be concluded, he adds. “However, in our case, the price for the gas is not as sensitive as what we are paid for the liquids.” SOCO expects 150 MMboe to be recovered from the field over its anticipated 20-year lifespan.
Block 16-1, in average water depths of around 50 m (164 ft), has taken longer to appraise. Initially, the Hoang Long partners targeted shallower basement structures in the west of the block. Ngua-0-1X, their first exploratory well, tested minor quantities of oil while drilling through multiple fracture systems. A well on the Voi Trang structure was more promising, flowing 3,500 b/d of oil mainly from Oligocene and basement intervals, although a follow-up well was abandoned after encountering only oil shows in the Upper Oligocene.
In 2005, the JOC turned its attentions to the Miocene/Oligocene potential in the eastern part of block 16-1, with immediate payback. The TGT-1X well on the Te Giac Trang (TGT) prospect tested oil and gas at over 9,000 boe/d from the Miocene Lower Bach Ho (LBH) formation. An up-dip appraisal well flowed at almost double that rate 17,500boe/d from Miocene LBH 5.2 and Oligocene intervals.
These and five further wells through mid- 2008, with average oil and gas flow of around 11,300 boe/d each, confirmed a potentially major structure. “TGT could be well north of 300 MMboe recoverable,” Story claims. The field comprises stacked clastic reservoirs in five fault blocks extending over 15 km (9.3 mi) from north to south within an 80-km (49.7-mi) long play fairway. In 2006, the Thang Long JOC in block 15-2/0-1 to the north, led by Talisman Energy, also proved a very small extension of TGT into its south-eastern waters.
The next, and probably final, appraisal well on TGT could be a step-out on the flank of one of the fault blocks, says Maris. “This is a very subtle structure, with a large number of pay sands, so understanding what we have on the flanks is critical for injection capacity design for the development.”
Concurrent with this program, in April 2007, the JOC decided to test the unrelated “E” prospect to the south of TGT, targeting a HP/HT Oligocene structure identified from new 3D seismic. This structure, also known as Te Giac Den (TGD), had been recognized in the early 1990s from 2D data acquired by Mobil two decades earlier.
“It was thought to be gas, so it did not attract the same level of interest at the time as other prospects in the area,” Story explains. “But ConocoPhillips had shown more recently with discoveries such as Su Tu Den and Su Tu Trang in block 15-1 that the oil window in this play starts to widen the deeper you drill.”
The TGD-1X well was also the first drilled by the then newly commissioned PVD-1 drilling rig. It encountered oil and gas in two Oligocene clastic sequences separated by a volcanic layer, with 30 m (98.4 ft) of pay logged in the upper sequence. But operations had to be halted 22 m (72.2 ft) into the lower sequence after penetrating a high pressure zone beyond the rig’s safe operating capacity.
Later that year the jackup Adriatic XI was brought in, fitted with a 15,000-psi BOP, to re-enter the well and drill a sidetrack towards fractured basement, where seismic interpretation had indicated a further 300 m (984 ft) of sediment. En route, the well had to be cased three times as it intersected different sands to prevent further downhole pressure problems.
Operations continued well into 2008, progress towards the basement proving to be more time-consuming and costly than expected. Eventually the side track well was plugged back to 4,820 MD to allow two DSTs to be conducted in the HP/HT Oligocene interval. The first of these, below the volcanic layer, flowed gas and condensate; the second, higher up, recovered black oil, condensate, and gas with similar characteristics to output from CNV.
Testing was hampered by downhole damage and limitations of the perforations, rendering flow rates meaningless. But the well did identify the presence of a working hydrocarbon system. “We were doing rank wildcat drilling in a difficult, high-pressure/high-temperature environment,” Story points out, “with no geological benchmarks to go on.
“Also, we were working with specialized equipment that had to be brought in from different parts of the world. And in this environment, you’re obliged to use either a brand new rig that hasn’t been shaken down, or an old rig. Having said, the PVD-1 has performed really well since re-deploying to CNV for development drilling.”
“Throughout the Cuu Long basin,” Story explains, “there is a very rich, thick D-shale that serves as a source and seal for the whole basin. Pre-drilling, the risk on this project was having early migration of hydrocarbons to preserve reservoir porosity during burial.
“Within the TGD structure, there are two different reservoirs above and below the volcanics separated by a volcanic interval. The reasons for our excitement are twofold: in the upper section, above the volcanics, we have black oil, with gas and condensate underneath. The hydrocarbons here are similar to those found in CNV. Beneath the volcanics, it is more like the gas-condensate present in Su Tu Trang.”
Reservoir quality was poor as the well approached the sealing point in the structure, Story adds. “There appears to be a stratigraphic element, with a sedimentary fan thickening to the north towards the TGT structure it is hugely exciting.” He cites as analogies Buzzard and Jubilee in the UK North Sea and offshore Ghana, both stratigraphic fans which were not immediately obvious on seismic.
“Downdip to the crest, these fan sediments thicken quite quickly. We know that the interval above the volcanics has a) black oil, b) plenty of pressure, and c) adequate reservoir properties for a very acceptable flow rate from wells. So in that one area, we have identified three different geological plays: on top, supra-volcanics, in the middle, sub-volcanics, and below that, basement.
“This year, following award of the appraisal area, we will apply pre-stack depth migration to the existing 3D seismic to better image the fan channel system. Then we plan to drill a well to test as much as we can the fan structure to the north, and to confirm the interval above the volcanics, but in a more user-friendly environment without the pressure gradients of the previous wells.
“The structural setting on TGD indicates a potentially vast reservoir, but we need to prove continuity of the fan system. What we learn on TGD could also have a big impact on the TGT development.”
According to Maris, TGT’s reserves are large enough to warrant a standalone development, with a first phase likely based around a jacket platform on the northern part of the field, exporting its well stream to an FPSO. Another platform would be installed in a central part of the structure under a second phase with the option of potentially handling black oil from TGD. Ideally, the partners would like to get first production in 2010.
Processing TGT’s Miocene and Oligocene crude should not present problems, he adds. Both are high quality, typically 43-45° API, and waxy, with a high paraffin content, making them ideal for use as aviation fuel. As for the gas from both fields, there is ullage available nearby in the Bach Ho trunkline to the Vietnamese mainland, where supplies are urgently needed for power generation and LNG/LPG. In time the deeper-lying gas-condensate might be suitable for a proposed LNG scheme tying in various fields in the Cuu Long basin.
Recently, PetroVietnam, recommended that the Vietnamese government also approve the Hoang Long JOC’s application for an appraisal area covering 100 sq km (39 sq mi) around the Voi Trang discovery and several nearby leads. The award is conditional on a successful reserves assessment report.