Vietnam ready with master gas plan for province
The agreement spells out the framework for gas production from BP/Statoil/ONGC's discoveries in Nam Con Son Basin block 06.1. Issues covered include profit gas, recovery gas and PetroVietnam's level of participation in the PSC as well as the associated infrastructure projects. Field development and construction of a new export pipeline to the mainland depend on commitments to build gas-fired power and urea plants and other factories in southern Vietnam.
BP and its partners discovered 2 tcf of non-associated gas at the Lan Tay and Lan Do Fields in Block 06.1 in 1994. BP/Statoil added to their gas base with further finds in Block 05.2, just to the north, but for the time being, Lan Tay will be the centerpiece development.
Early this decade, Vietnam's authorities had been preoccupied with the search for oil. However, these and other associated Nam Con Son gas strikes prompted formulation of the country's Master Gas Plan. In 1994 PetroVietnam initiated a study into a regional gas pipeline and processing system. A year later, BP and other successful operators co-opted onto this study submitted their draft proposals. BP/Statoil's gas transportation manager Sverre Lund outlined plans for the Nam Con Son Pipeline (NCSP) project at the Vietnam Oil & Gas '96 summit in Hanoi, and a further update will be presented at PetroVietnam '97.
Production schemeLan Tay is the first gasfield committed through the NCSP. BP's current thinking for the development involves a central processing, drilling and quarters platform, mainly due to the nature of the carbonate reservoir housing the gas. Lan Do, which contains just 20% of the block 06.1 gas, will likely be tied back to this platform via a subsea completion.
Supplies will head initially to Long Hai on the southern Vietnamese coast through a 365 km long, 24-in. two-phase pipeline, at a possible maximum combined rate from the two fields of 350 MMcf/d. There would also be spare capacity in this line - possibly 200 mcf/d-plus - to tie in supplies from future fields en route. From Long Hai, further pipelines would be built traveling inland to Vung Tau and the planned new power plants at Phu My.
Around 40 km to the north of Lan Tay/Lan Do in Block 05.2, BP also has an oil and gas discovery, Kim Cuong-Tay, as well as a more recent gas/condensate find called Hai Tach. The latter was plugged and abandoned last summer by the West Delta rig having tested good quality gas at 30 MMcf/d and condensate at 4,000 b/d.
Despite high and complex pressure regimes, the well reached its planned T/D, according to BP, through careful pore pressure observations and the use of additional casing strings. BP has not announced any further work program for the block, and it is not clear yet how the gas might be developed.
Other candidates for NCSP gas throughput, lying close to the pipeline's intended route, are associated gas of 600 bcf from JVPC's Rang Dong oilfield in block 15.2; Mobil's Thanh Long in Block 05.1; and Pedco's discoveries in Block 11.2. There is also thought to be a commercial gas discovery in EDC-operated block 05.3, in which BP has a 14% stake.
Vietnam needs more gas-fired power to fuel its own economic growth, and thereby attract foreign industry to invest. Plateau rates of 3 bcm/yr are forecast through the NCSP, mainly serving three of the new 600MW power plants planned for Phu My. But other sectors such as agriculture could use indigenous gas for urea production. Other possible markets on the mainland include methanol production.
But as Sverre Lund pointed out in Hanoi last year, these scenarios are uncertain, and on the downside, supplies may be constrained by presently proven offshore gas reserves. The Nam Con Son Basin operators will delay committing their fields to a new trunkline until a critical mass of gas is committed to the market.
There have been other questions for the NCSP study team to ponder. Gases from the various fields discovered may have widely varying properties, from lean non-associated gas with some condensate to richer associated gases from oil fields, and in some cases high CO2 content - necessitating strict corrosion control. The transportation system must be flexible enough to carry most types, but without incurring overly high costs.
As Lan Tay will be the first exporting field, its characteristics have become the basis for the initial pipeline development stage. BP and partners discounted multiphase and dense phase operations. They felt a multiphase line of the length envisaged would be at the limit of present technology, and might not cope with the effects of the CO2-laden gas. Dense phase mode, which involves gas transport at high pressures, would have the knock-on effect of also keeping condensate from non-associated gas in its liquid state.
The choice then was down to single or two-phase operations. Studies were performed for both options based on the same capability for transporting hydrocarbon liquids, but limited to volumes and characteristics typical of both associated gas and non-associated gasfields with low condensate/gas ratios. In the two-phase system, liquids would head through the gas line before ending up in the slug catcher at the onshore reception terminal in Long Hai; while single-phase operation assumed the need for a piggy back line to convey the liquids.
The two-phase system won because costs were considered slightly lower, even though capacity would be reduced by 8% compared to a single phase line of similar diameter and pressure. Rather than raise this capacity through enlarging the line's diameter (which would in turn have meant increasing the slugcatcher size), the partners decided that pressure boosting was a better option. This would be achieved through installation of an export compressor at a later date, with the costs probably borne by the various upstream producers.
Flexibility of the NCSP trunkline in catering for variable-demand users was a major concern. Transient simulations for different operating scenarios suggested that during periods of increased flow, liquid slug production would occur; this would necessitate regular sphering of the line. However, these effects would be manageable provided the system was designed to an agreed operational envelope. A 24-in. diameter two-phase line was chosen with maximum operating pressures of 172 barg.
Route hazardsThe 365 km offshore section of the line is scheduled to come ashore at a landfall at Long Hai, next to the Bach Ho gas line. From there it should head overland 35 km firstly via Dinh Co to Ba Ria, then following the planned Bach Ho pipeline extension to Phu My.
Maximum water depth offshore is 125 meters. Although the route will be basically straight, there are some eight meter high sandwaves that have to be negotiated. Crossing these sand waves would ordinarily entail dredging and trenching to reduce pipeline spanning. However, a delineation survey suggests there is a route that could minimize preparation work in these areas, as well as limiting the need for deviations. Recent analysis suggests the sand waves have at least not moved over the past couple of years.
In his speech last year, Sverre Lund said the line would be trenched for stability reasons along the inner part of the route, with deeper trenching in the landfall area and perhaps some pre-sweeping and post-lay trenching in critical sand wave areas. Coal tar enamels were proposed for the offshore pipeline which should be protected by a concrete weight coating, backed by sacrificial anodes.
As regards future tie-ins from other fields, low-cost tee connections were judged acceptable for two-phase operation provided that the lateral lines were small and short with a low liquid hold-up volume. Two subsea tees look likely to be installed along the line. For the hydrotest, filtered and sea water will be used, probably introduced into the line from the onshore end and discharged at the offshore end for environmental reasons.