Alain Lepage
Total Myanmar Exploration & Production
Singapore
Despite scheduling complications caused by annual monsoons, the Yadana project to bring offshore Myanmar gas ashore and into neighboring Thailand has met it first-gas target of July 1, 1998.
The Yadana field is a dry-gas reservoir in the reef upper Birman limestone formation at 1,260 m and a pressure of 174 bara (approximately 2,500 psi). It extends nearly 7 km (west to east) and 10 km (south to north).
The water-saturated reservoir gas contains mostly methane mixed with CO2 and N2. No production of condensate is anticipated.
The Yadana field contains certified gas reserves of 5.7 tcf, calculated on the basis of 2D and 3D seismic data-acquisition campaigns and of seven appraisal wells.
Early interest
Total first expressed an interest in Yadana gas field in 1990. Total and the Myanmar Oil & Gas Enterprise (MOGE) 2 years later signed a production-sharing contract for development of the gas fields on blocks M5 and M6 located in the Andaman Sea, 80 km south of the Myanmar coast.Unocal then joined as a partner in July 1993, followed in January 1995 by the Petroleum Authority of Thailand Exploration & Production (Pttep).
In February 1995, signature of the export gas sales agreement between the partners and the Petroleum Authority of Thailand (PTT) triggered the first phase of the Yadana project.
The gas will supply both a domestic market (Yangon and South Myanmar) and a 3,900-mw power plant in Rathaburi located west of Bangkok.
According to the terms of the export gas sale agreement, Yadana field will export gas to Thailand at a rate of 525 MMscfd with a 15% swing factor.
Total Myanmar Exploration & Production (TMEP), operator of Blocks M5 and M6, is responsible for the development of the field and for the transportation of the export gas to the Thai border. Transmission of the domestic gas to the region of Yangon in central Myanmar is the scope of the second phase of development.
In addition to Yadana gas, a smaller accumulation has been discovered in Badamyar field west of Yadana. Tapping this reservoir will be considered in a later phase of development.
Development sequences
Full field development is planned in four phases, the first having been completed (OGJ, July 13, 1998, p. 38).Phase 1. The first phase of development which took place from October 1995 to June 1998 covers engineering, construction, installation, and commissioning of two wellhead platforms, a process platform, a quarters platform, the offshore export pipeline, and the onshore pipeline and associated facilities.
Phase 2. The engineering studies related to Phase 2 commenced in 1997 and entails installation of the domestic gas pipeline running from the field offshore to the vicinity of Yangon.
Phase 3. Approximately 6-7 years from initial start-up, the medium compression platform (MCP) bridge linked to the production platform will be installed to boost the declining reservoir pressure to the level required to maintain a constant gas export flow rate.
Phase 4. It is anticipated that in 2009, the reservoir pressure will have declined even further. At this stage, the low-compression platform (LCP) consisting of two additional compression trains will be installed next to the MCP further to boost the gas pressure for reaching the border.
Offshore platforms
The layout of the complex includes four bridge-linked platforms for gas production, treatment, and personnel accommodation and one remote wellhead platform.For safety, the process facilities are located on a separate platform which, because of prevailing winds, is north of the quarters platform, thereby limiting the potential risks from gas leaks.
Platforms' foundations proved to be problematic because of the harsh oceanographic conditions (strong currents, hurricanes, large-amplitude waves during the monsoon period) compounded with poor soil characteristics resulting from a 25-m thick layer of soft sediments on the sea bed. Also, very unfavorable seismic conditions had to be considered in the design.
Therefore, in only 45 m of water, 72 in. x 110-m penetration piles were necessary to secure the production platform on the seabed.
The process platform accommodates two gas-dehydration trains, each sized for 450 MMscfd, the utilities and pig traps for the 36-in. export pipeline, the 20-in. infield flow line, and 20-in. domestic gas line.
As a basis of design, the H2S content of the gas was set at 50 ppm.
In the long-term, the possible presence of H2S combined with the 4% CO2 renders the gas potentially very corrosive. To exacerbate the situation, the efficiency of corrosion inhibitors is diminished because of the lack of condensate in the gas.
As a consequence, all process piping and vessels upstream of the dehydration trains are made of or clad with stainless steel. Downstream, where the gas is dry, stress-induced corrosion cracking and hydrogen-induced cracking resistant carbon steel has been used.
The quarters platform is designed to be self sufficient and independent of the utilities on the production platform. This has allowed early occupancy of the cabins and restaurant levels of the platform during the final phase of the central complex hook up and commissioning, hence reducing drastically the cost of offshore commissioning and hook up of personnel accommodations.
In consideration of the estimated number of personnel required during operation and maintenance, the quarters platform has been sized for a maximum crew of 96 (allowing for visitors, temporary workers, etc.).
Also, in an effort to reduce the presence of personnel on the production platform, the quarters platform harbors the field control room, the workshops, stores, and offices.
The two almost identical 12-slot wellhead platforms (WP1 and WP2) are designed for jack up-supported drilling. Whereas WP1 is adjacent and bridge linked to the process platform, WP2, located 3.5 km away, is connected via a 20-in. well effluent flow line, a 2-in. corrosion-inhibitor supply line, and a submarine power-control cable.
Therefore, WP2 can be fully controlled from the quarters platform, and the presence of personnel is required there only for maintenance.
Each wellhead platform is equipped with a test separator and WP2 features a cold vent for depressurization. All process piping and vessels are designed to withstand the well shut in pressure of 156 bar.
All seven wells are now drilled on each of the two platforms:
- One vertical well (for gas-water contact monitoring throughout the field life)
- Six horizontal wells with a departure of 1,900 m.
Gas-export pipeline
The exported gas is piped to the Thai border through a 36-in. line with a length of some 345 km offshore and 63 km onshore.The sea line is connected to the process platform via an expansion loop, designed to take the calculated line thermal expansion and welded by hyperbaric technique to the riser preinstalled onto the platform's jacket. It has a design pressure of 109.7 bara and a design capacity of 654 MMscfd. In order to facilitate pigging operations, the corrosion and weight-coated line features a constant internal diameter.
The pipeline route crosses several live seismic faults and two 145-m deep trenches. Special precautions were taken to avoid damage to the line in case of earth tremor during its 30-year lifetime.
The offshore export pipeline lands south of the fishing village of Da Min Seik, 60 km south of the city of Ye on the Gulf of Martaban.
Logistics happened to be one of the major difficulties for installing the sea line in such a remote area. Because of the lack of the necessary facilities near Myanmar, the 27,900 joints of line pipe had to be coated more than 2,000 km away, in Kuantan on the east coast of Malaysia. Each coated joint weighs an average of 17 metric tons.
To support the 4,000 m/24 hr average lay rate of the barge, the transportation spread was sized to deliver on site every day about 6,000 metric tons of pipe. A fleet of nine bulk carriers, pipe carriers, and offshore pipe-transfer support vessels was mobilized for the 109-day duration of the laying activity.
The pipe-supply problem was exacerbated by the fact that joint steel wall and concrete-coating thicknesses vary according to water depth.
Shallow waters near shore have also complicated installation of the first 7 km. A 4.5-km, 70-m wide trench was dredged down to 4.5 m to allow a shallow-draft laybarge access to within 300 m of the beach for pulling the line to shore.
From the sea line landfall, the onshore line runs eastwards through the province of Tennassarim for about 63 km and crosses the border with Thailand near the village of I Tong where it connects with the 42-in. pipeline laid by PTT to the power plant at Ratchaburi.
The route of the onshore pipeline spans undulating terrain including two mountainous ridges culminating at 280 m before reaching Thai territory at an altitude of 920 m. Many slopes with gradients reaching sometimes 100% had to be overcome. Use of a cable-car type of crane was necessary to install the line in those areas.
The onshore facilities associated with the gas line consist of two manned process and control stations, two unmanned safety block-valve stations, and necessary infrastructures such as a service track, a wharf, and an airstrip.
Pipeline center. The pipeline center is located inland, 10 km downstream of the landfall, close to the village of Onbinkwin. Its design allows for future extensions such as gas recompression or tie ins of other gas lines.
It harbors all equipment necessary for controlling the flow of gas to the border and for maintenance of the onshore facilities.
Metering station. The metering station, near the Thai border, consists of two distinct areas, one for gas processing (mainly metering) and the other for utilities and personnel accommodation.
The process area, built 785 m above sea level, includes a fiscal metering skid and a telecommunication system for transmission of the gas-export process data. The control room and workshops are located for safety in the utilities/accommodation area at a lower altitude of 750 m.
Block-valve stations. Two safety block valves, one at the landfall (BV1) and the other (BV2) 31 km downstream of BV1 provide the necessary line sectioning. Both valves are automatic fail-safe close upon low pipeline pressure and can be remotely activated from the control room at the PLC.
Service track. The main purpose of the service track is to provide year-round access to up to sixty 1-metric ton vehicles for inspection and maintenance to all pipeline facilities. It encompasses 18 bridges for crossing three major rivers (Heinze, Dawei, and Mayan) and numerous secondary water runs very active during the monsoon period.
The heavy rainfalls, in excess of 300 mm/24 hr during July and August, constitute the most demanding conditions for design of this tropical road. Because of mountainous terrain, more than 2 million cu m of materials had to be moved and compacted to build the road and tens of kilometers of drains, fascines, berms, and gabions associated with an extensive revegetation program were required to stabilize it and avoid erosion.
Construction of these onshore facilities proved to be a significant challenge not only technically but also from the human and logistical points of view:
- At the beginning of construction, the local people had no experience with modern oil and gas development projects nor any notion of safety, quality, and dependability.
With extensive on site training programs, these necessary skills were quickly learned by the more than 2,500 employees recruited locally and successfully implemented thereafter.
- The construction site was a very remote area of a country with almost no infrastructure. To take best advantage of the short dry season, all equipment had to be swiftly transported by sea, imported, and moved to the site as soon as the monsoon receded.
More than 50 barges and LCT vessels were necessary to bring in all supplies, materials, and equipment required for the construction of the facilities and for supporting the working crews in this remote area of Myanmar.
Safety, environmental steps
During design, Total implemented a "safety concept" to reduce the consequences of accidents during production and ensure the availability of escape routes and evacuation means.In the platforms' fabrication yard, where 3 million man-hr were spent, a specific safety incentive scheme helped to eliminate completely accidents by enhancing workers' awareness of safety.
To ensure personnel safety during pipeline construction in the mountains, safety training was continuous, vehicles' safety devices were inspected frequently, and traffic was constantly monitored to help reduce mishaps on the slopes.
Elsewhere, full environmental baseline survey and environmental impact studies were carried out before final selection of pipeline and service-track routes. These have helped to ensure that all regional legislation and internationally accepted standards were maintained during both engineering and construction.
The studies also set forth a comprehensive drainage, reinstatement, and revegetation program for the pipeline right-of-way to avoid erosion during heavy monsoon-season rainfalls.
To reduce the impact on the environment as the pipeline passed near any area of ecological significance, the selected route traversed degraded vegetation and, for the most part, followed an existing track.
For communities near the proposed pipeline and facilities, Total pursued open communication, ensuring that the local communities were consulted in advance on all that it was planning to do.
Moreover, a code of conduct which clarified ethical standards in working practices was established. Adherence by the contractors was essential in performance of the contract.
Schedule constraints
The annual monsoon, from mid-May to mid-October, governed the overall development schedule: It was clear early that no significant work could take place offshore or onshore during the monsoon periods. This unavoidable discontinuity in construction significantly affected costs.Onshore, the 7 months of good weather prevented completion in a single dry season the entire scope of the planned work: site surveys, mobilization and demobilization of construction equipment, and camps.
Furthermore, there were no bridges, ports, roads capable of handling the heavy construction equipment, or airfield for rapid access to the work site. All had to be built before mobilization of the contractor in charge of the pipeline and associated facilities.
Therefore, from October 1995 to May 1996, topographical surveys, soils investigations, and environmental baseline and environmental impact assessment studies were conducted in parallel with construction of such essential infrastructures as the port, airfield, two bridges over the main rivers, and the pioneer construction camp.
Early access to these facilities proved to be essential for completing pipeline installation during the next dry season, October 1996 to May 1997.
The last dry season, ending in May 1998, was mainly used for completing the service track, building the pipeline center and the metering station, and commissioning all facilities.
Offshore, as a result of prevailing sea-state conditions during the monsoon period, no heavy lift or construction work could take place from May to October. Therefore, all platform installation, hook up, and commissioning were planned for the dry seasons.
Installation of the wellhead platforms and then production-platform jacket took place in April and May 1997, thus allowing drilling to start soon enough for gas production to meet the needs of the facilities-commissioning phase scheduled for 1 year later.
The quarters, flare, and production platforms' topsides were set in place at the beginning of 1998, immediately followed by hook up and commissioning. Gas flow was achieved late May 1998.
For the sea line, it appeared essential that shore-approach construction take place during very calm seas. Because of the lead time required for line pipe supply, the shore approach was planned and performed during first quarter 1997.
For insurmountable scheduling reasons, part of the subsequent high seas pipe installation took place during the monsoon period. This was made possible by the huge size of the laybarge which had to be mobilized from the North Sea.
Most interruptions in the field between offshore pipeline tie-in to production platform, platform installation, hook up/commissioning, and drilling activities could be avoided by careful progress monitoring and numerous scheduling exercises.
The Author
Alain Lepage was project manager for the Yadana project, beginning in 1994. He began his industrial career in 1968 with the Comex Group and subsequently headed a subsidiary of the group involved in offshore environmental data acquisition systems.
In 1975, Lepage became responsible for the activities of Comex in West Africa and then in Norway. In 1980, he joined Total for which he managed the construction of offshore oil and gas production facilities in Abu Dhabi, U.K., and Qatar. In 1990, he was assigned project director for Bongkot field development in Thailand.
Lepage graduated in 1966 from the Ecole Nationale Superieure des Arts et Metiers in Paris.
