Copyright 2002, Offshore Technology Conference This paper was prepared for presentation at the 2002 Offshore Technology Conference held in Houston, Texas U.S.A., 6–9 May 2002. This paper was selected for presentation by the OTC Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Offshore Technology Conference or its officers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented.

Abstract The Malampaya Deep Water Gas to Power Project (the Malampaya project) reached a major milestone when the Declaration of Commerciality for the project was signed in May 1998. In just less than 31/2 years, Shell Philippines Exploration B.V. (SPEX), as Operator, successfully completed this remote deep water gas project, and successfully accomplished two additional major milestones by landing gas for power plant commissioning to its downstream buyers by October 1st 2001 and commencing commercial sales deliveries shortly thereafter on January 1st 2002. This paper describes the history behind this landmark undertaking, the trade-off between alternative deep water development solutions, the contracting strategies employed as well as the many venture management, technical, HSE, commercial and sustainable development challenges that were undertaken by SPEX to successfully transform this exciting deep water project from a vision into a reality. The Malampaya project marks the dawn of the natural gas industry in the Philippines, illustrating the crucial importance of integrating the development of gas markets with the rapid construction and successful operation of the necessary deep water and onshore infrastructure. The Malampaya development comprises five novel subsea wells in 820 metres of water, producing via a subsea manifold and two 30 km long, 16 inch flowlines to a concrete gravity platform located in 43 metres water depth. These wet gas flowlines, with their large vertical displacements and mixture of gas and liquids have pushed deep water subsea gas development technology

to higher levels. The platform production facilities were installed on a concrete gravity substructure that was built in Subic Bay, Philippines and completed some 3 months ahead of schedule. The topsides facilities were fabricated in Singapore and were towed over 2200 km to the Philippines on March 1st 2001. The gas and condensate is treated on the platform to export specification. Gas is compressed and transported via 504 km long 24 inch pipeline to an onshore gas plant at the site of the Shell Refinery at Tabangao (Batangas, Luzon Island). The condensate is stored in the platform concrete substructure caisson and exported approximately every two weeks via shuttle tankers. The Malampaya pipeline is a major engineering accomplishment in its own right, traversing rugged sea floor topography through seismically active and environmentally sensitive regions. An onshore gas treatment plant, built to remove the H2S content of the gas will serve as the delivery point to the buyers. The project schedule to meet the 1st October 2001 first gas flow commitment to the gas buyers was very tight from the outset. The project goals were achieved by continued attention to the six project tenets of cost containment: schedule attainment, use of innovative technology, high system availability, exemplary Health, Safety, Environment and Security (HSES) management, and Sustainable Development. As the very demanding and challenging Malampaya Project development phase has now drawn to a close, the memories of the many successes achieved throughout this intense period of activity are still vivid. A large number of substantial gains have been achieved on the technical, operational, contracting, organisational, human resources and reputation-management fronts which are considered to be of great value to other major projects being planned or implemented in developing countries. At the same time, the structures, procedures and shared staff values necessary to successfully complete a major deep water project safely, on time and within budget in an environment with very limited E&P history or infrastructure have been successfully implemented. The lessons gained from this particular project should not be forgotten as they will hopefully be of great value to future deep water projects in remote locations and to the E&P industry at large.

OTC 14038

Malampaya Deep Water Gas To Power Project - An Overview - Powering The Philippines Into The New Millennium David J. Greer, C.Eng. FIMechE Malampaya Project Director

2 D. GREER OTC 14038

INTRODUCTION In 1989, Occidental Philippines, Inc (Oxy) discovered gas in the Camago-1 well in the area covered by Service Contract No. 38 (SC-38), offshore Palawan in deep water and 500 km away from the nearest potential market (Fig.1). The area was known to be gas prone: Shell itself had been involved in two earlier gas discoveries elsewhere in the block, which were then considered uncommercial. In 1990, Shell Philippines Exploration B.V. (SPEX) farmed-in taking a 50% interest and operatorship of Block SC-38 thereby providing the necessary deep water technology, and financial strength to develop this resource. As part of the farm-in deal, Shell drilled three wells, the second discovering the large Malampaya gas field with its 400 to 600 metre gas column and 56 metre oil rim, connected to the Camago structure. The promising discovery was further appraised by three additional wells. An integrated petroleum engineering study was carried out using the latest proprietary 3-D carbonate reservoir modeling techniques and incorporating the Pre-Stack Depth Migrated (PSDM) re-processed 3-D seismic data set. By 1995, it had been demonstrated that Malampaya, with proven recoverable volumes of 2.5 Tscf gas and 85 MMstb condensate, represented a significant opportunity for a commercial gas development for Shell and the Philippines. These volumes were declared commercial on 14th May 1998. Shell acquired 100% interest in SC-38 following the global Shell-Oxy asset swap executed on 15th September 1998. Subsequently on 5th November 1999, Texaco Philippines Inc. farmed-in, to acquire a 45% working interest in SC-38. PNOC farmed-in to acquire a 10% working interest on SC-38 on 22nd December 1999.

HISTORY The Malampaya field, located some 80 km NW of the Island of Palawan, is an elongated structure consisting of two culminations separated by a saddle some 12.5 km long with a width that varies between 1.5 and 3.5 km (Fig.2). The reservoir is a high relief Oligocene to Early Miocene carbonate build-up (Nido Formation) at a depth of some 3,000 metres subsea, developed over tight platform carbonates of Late Eocene age.

Two exploration wells (Camago-1 and the Malampaya-1) and three appraisal wells (Malampaya-2, 3, and 4) delineated the field prior to development, which has a maximum gas column of some 600 metres and proven reserves of 2.4 Tscf. The expectation reserves are 3.2 Tscf, with a P15 of 4.1 Tscf. The gas column is partly underlain by a 56 metres oil rim with a STOIIP of 244 - 378 MMbbls. Exploitation of the Malampaya reserves was a recognised deep water challenge and Shell’s unrivalled experience in this arena enabled the company to pursue the commercial development of Malampaya. Initially, three development concepts were evaluated. For the combined

development of oil and gas, a Tension Leg Platform (TLP) and a Floating Production Storage and Off-loading (FPSO) facility were considered. During the appraisal campaign, it became evident that the oil development was marginal from an economic perspective given the thickness of the oil rim. The FPSO option was rejected on the grounds of the technical complexity associated with the number of gas risers and swivel design particularly for the large diameter high pressure gas export pipeline. A TLP option was also rejected in favour of a less expensive capital cost alternative for the gas only development, comprising a deep water subsea tieback to a shallow water platform, thereby resulting in the most competitive landing price for the gas. The subsea tieback to a shallow water platform could also be brought on stream one year earlier than the TLP alternative thereby enhancing the project economics. A further major technical concern with the TLP was the unknown behavoiur and reliability of tension piles in calcareous soils with respect to creep. Although the oil rim was not part of the original field development, efforts are now being made to dynamically test the oil leg of the reservoir to assess the viability of an independent oil development with gas export combined with that of the main gas development. Test results to date have been encouraging.

Aside from the technical, logistical and development cost challenges, the commercial challenge of developing a gas market in the Philippines remained. The economics of developing such a remote deep water gas field were always known to be marginal and therefore the venture needed to establish a market that could off-take high volumes as soon as the gas would flow. Only the power sector could provide such a market. A study in 1994 confirmed that there would be a requirement around 2000-2002 for 3,000 MW of gas-fired power generation at base load. At this throughput level, the gas could compete with alternative fuels, including its main competitor, coal. Gas plants cost less and required less time to build and, using combined cycle gas turbine technology, have a higher efficiency than coal plants. The outcome of the study was endorsed by the Philippines’ Department of Energy (DoE) who assumed responsibility for the promotion of a 3,000 MW market for Malampaya gas.

The DoE allocated 1,500 MW to the National Power Corporation (NPC), a Government owned corporation and the main power generator in the Philippines, and 1,500 MW to Meralco, the main distributor of electricity in Metro Manila and the industrial growth area south of Metro Manila. NPC and Meralco, in turn, set out to appoint independent power producers (IPP) who would build the power plants and supply electricity to them. NPC, being a Government owned entity enacted to resolve the power crisis that almost crippled the Philippines economy in the eighties, proceeded under the Build-Operate-Transfer law. NPC awarded a competitively tendered Energy Conversion Agreement to the successful IPP and, in early 1995, issued its

MALAMPAYA DEEP WATER GAS TO POWER PROJECT - AN OVERVIEW- OTC 14038 POWERING THE PHILIPPINES INTO THE NEW MILLENNIUM 3

invitation to tender for a 1200 MW power plant to be constructed at Ilijan, Batangas (the Ilijan plant). NPC selected Korea Electric Power Corporation (Kepco) to build and operate the Ilijan plant in December 1996. Meralco, as a private company, did not need to follow the BOT route and could appoint an IPP of choice; choosing First Gas Power Corporation (FGPC) a joint venture between the First Philippine Holdings Corporation (60%), which is also involved in the management of Meralco, and British Gas (40%). FGH incorporated two subsidiaries, one to build a 1,000 MW power plant at Santa Rita, Batangas, the other to build the adjacent 500 MW San Lorenzo power plant. By the beginning of 1995, the key players that would transform this deep water gas to power project from a vision into reality had been identified. THE COMMERCIAL CHALLENGES At the outset, it was recognised that the Malampaya Deep Water Gas to Power project could only succeed if the upstream project was fully integrated with the three downstream power projects. This meant aligning the interests of the Government (involved in both the upstream and through NPC in one of the key downstream projects); SPEX in the upstream; NPC, the Lopez Group and British Gas in the downstream, and synchronising investment decisions of about $US 4.5 billion in total value. The Department of Energy (DoE), in view of its involvement in several aspects of the project, declined an active role in the negotiating process. It did, however, organise a forum for all relevant departments and Government agencies through which it would oversee progress and support the project as required. The upstream project’s viability depended entirely on the realisation and dispatch of the power projects. By contrast, the power project developers were less dependent on the upstream as their plants are dual-fired, i.e. they can run on liquid fuel and gas; furthermore, their combined purchasing power could support a LNG importation scheme. In favour of the upstream option was the fact that the development of the indigenous resources of Malampaya best serves the national interest and economy. SPEX marketed the gas on the basis that its price would have to underpin the upstream economics. At the same time, gas would have to be competitive with coal-fired power generation, on a total cost basis, and cheaper than LNG, taking into account the price of LNG, its shipping cost and the cost of storage and re-gasification in the Philippines. The agreed gas price adjustment formula furthermore links the gas price to oil price fluctuations, thus providing a measure of competitiveness with oil based power plant fuels.

In view of the limited time between final agreement of the GSPA’s in May 1998 and the planned first gas to platform in June 2001, a contracting strategy was adopted that incorporated the six project tenets described earlier. Separate contracts were placed for the five main upstream project components: pipeline fabrication, coating and installation; platform engineering, procurement, construction, installation and commissioning; subsea engineering detailed design, fabrication and procurement, drilling rig rental for development drilling and the onshore gas plant detailed design and construction. Project components with a precise definition of scope and well identified risks, such as pipelines, were awarded as lump sum contracts. Areas such as the production platform, onshore gas plant and subsea facilities in which significant challenges remained in respect of technological innovation, meeting availability and schedule targets, were awarded under reimbursable contracts. These contracts were structured using a combination of traditional reimbursable payments combined with risk reward mechanisms, with system availability and life cycle costs taking precedence over capital cost.

THE UPSTREAM PROJECT The upstream project development plan comprises nine subsea gas wells connected to subsea manifolds located on the seabed over Malampaya, at a water depth of approximately 850 metres (Fig. 3). Five wells were drilled initially to ensure delivery of commissioning gas on 1st October 2001 and first commercial gas sales on 1st of January 2002 (gas for the commissioning of onshore power plants was delivered 3 months prior to commercial sales gas delivery to Buyers). Development drilling started in February 2000 and progress achieved throughout the programme was excellent. The first group of five wells have been clustered around a subsea manifold located between the Malampaya-1 and Malampaya-4 wells. The drilling of the subsequent four wells is planned for 2009 and may involve a second manifold near the Camago area. It is expected that two of these four wells could be drilled from the initial northern manifold, while the two other wells may be tied back from a southern manifold, targeting the Camago area of the accumulation. The plans for the number and phasing of wells for the second phase of reservoir development will be subject to reservoir performance during early years of production. The wells are of a 7 inch mono-bore design with horizontal Christmas trees, providing high production capacities with a simplified design for long service life. The wells will have permanent downhole gauges to accurately monitor reservoir performance and facilitate effective reservoir management.

The wells have been tied-back to the platform via two 30 km long 16 inch corrosion resistant alloy clad flowlines. The platform and associated condensate storage and loading facilities are located on the NW Palawan Shelf, some 50 km west of Palawan Island and 400 km Southwest of Luzon

4 D. GREER OTC 14038

Island in a water depth of 43 metres. The high CGR well stream, which contains CO2 and H2S, is separated and treated by the platform process to meet transport specifications for gas and condensate. The gas is conditioned to water and hydrocarbon dew point specifications ( 0 deg.C) by a simple Joule Thompson process followed by re-compression and export via a 504 km long, 24 inch carbon steel gas export line to the onshore gas plant located at Tabangao, Batangas on Luzon Island. There, the dry gas is treated to Buyers’ quality specifications. Condensate is stabilised to a RVP of 10 psia for storage and transport requirements. The platform has a capacity to process 508MMscf/d of gas and 32,800 b/d of condensate. Methanol storage, recovery and injection facilities for hydrate prevention are a significant, additional feature of the platform process. The platform comprises an integrated deck of three levels for process, utilities and living quarters installed on a Concrete Gravity Substructure (CGS) with condensate storage in the base. Condensate storage is based on the dry-cell principle to avoid any contamination of the marine environment and has a working capacity of 385,000 bbls. Condensate is exported via shuttle tankers, which connect to a Catenary Anchored Leg Mooring (CALM) offshore loading system, approximately every two weeks.

Maintaining sufficient deliverability capacity from the field will require additional compression around the year 2015 and installation of an additional 16 inch flowline from the subsea manifold to the platform in the year 2020 to reduce flowline back pressure and wellhead pressures. The last stage of development prior to abandonment will consist of re-wheeling the compressors to accommodate lower suction pressures. THE TECHNICAL CHALLENGES Malampaya will deliver gas for the generation of some 2,700 MW of electrical power for which natural gas will be the primary fuel source. As such, the total Malampaya production facilities from the deep subsea wells to onshore gas plant will require high system availability. The principal technical challenge is therefore to ensure continuous delivery of sales specification gas throughout the production chain whilst containing costs and maintaining HSES standards.

Development Well Planning

Each of the five earlier Exploration & Appraisal (E&A)

wells for Malampaya yielded geological surprises that changed the view of the field, leaving significant residual subsurface uncertainties at the start of development drilling.

The crestal reservoir drainage philosophy is exposed to the

risk of vertical compartmentalisation. This risk was assessed with scenario modeling with a detailed 3D reservoir model. A significantly improved 3D PreSDM seismic dataset was used to provide excellent velocity control within the reservoir and more accurate determination of the depth of a tight, and potentially vertical barrier, the Intra Nido layer. The heavily

fractured Intra Nido was an anticipated drilling hazard believed to be prone to losses from the high mud overbalance at depth. Using a seismic inversion derived reservoir model and simulation, paths were identified within the Intra Nido to facilitate sufficient vertical reservoir communication

In planning to meet the well objectives, a fit for purpose approach for the well design and data gathering was adopted. The up-front process of rationalisation and prioritisation was very effective in steering the design and execution efforts in delivering safe and cost effective high rate gas production wells. A minimum inflow performance criterion was developed, based on a draw-down threshold that would not unduly accelerate future field development activities. This allowed the definition of the minimum reservoir penetration required for each well, thus minimising the exposure to losses whilst drilling long intervals in a large gas column with increasing overbalance.

The locations of the five initial gas development wells were targeted within the “proven” area of good reservoir so as to ensure high well deliveries with access to large gas volumes. The first three wells (MA-5, 6 and 7) were located in the most likely area for high porosity zones and were expected to be capable of producing at initial rates in excess of 200 MMscf/day each. Additionally MA-5 was located to appraise the oil rim in an area where good porosities were expected in the water leg, lying equidistant between MA-1 and 2, where the maximum difference in oil rim thickness had been observed. With confidence that these wells would secure the initial demand, the last two wells (MA-8 and MA-9) were placed in less well-defined areas of the field, where there were facies or connectivity uncertainties. The first phase wells, therefore, provide complete coverage of the northern Malampaya culmination for drainage and depletion monitoring using tandem permanent down hole gauges in each well. Deep Water Well Engineering

A number of very special challenges had to be tackled and

overcome to deliver the five initial deep water subsea gas wells in accordance with the tight Malampaya Project schedule. These challenges related to the deployment of leading edge technology well systems in an environmentally pristine and remote area within a country which has an extremely limited upstream E&P infrastructure for support and very long logistics and supply lines. The definition and management of good performance within this context and the management of the many interfaces with all other disciplines working in parallel towards the same project end-goal required unique ways of working to be established. Within the technical arena, many novel solutions were adopted with respect to rig equipment and modifications, deep water carbonate gas reservoir drilling procedures with total losses, management of hydrates, subsea Xmas trees, well completions and well test clean-up programmes.

MALAMPAYA DEEP WATER GAS TO POWER PROJECT - AN OVERVIEW- OTC 14038 POWERING THE PHILIPPINES INTO THE NEW MILLENNIUM 5

The casing design revolved around a requirement for 7 inch mono-bore completions, to drill 8½ inch hole through the reservoir and to complete with a 7 inch liner. This would allow both high production rates and left the option open to deepen any of the wells if required. The production casing was set above top reservoir to avoid drilling with large hole size into the loss prone reservoir.

Corrosion Resistant Alloys (CRA) were selected for all

“flow wetted” areas including the liner, tubing, accessories and a section of 9 5/8 inch casing between the liner top and the production packer. A tapered production casing string was required to accommodate the large bore TRSSSV.

The perforation philosophy was based on the use of the

latest deep penetrating charges with the largest gun size to ensure the maximum inflow performance from the interval available for perforation. This approach facilitated a single perforation run, to minimize hydrate risks associated with well interventions in this deep water environment.

Deep set permanent gauges were justified for field wide

monitoring to confirm connected gas reserves. The production casing was set above top reservoir to avoid drilling with large hole size into the loss prone reservoir.

The reservoir development of the deep water Malampaya

gas field has been a success, as the subsurface objectives have been met and well deliverability targets exceeded. The wells have been flowed clean to rates of up to 120 MMscf/day and have demonstrated initial potential in excess of 250 MMscf/day. With permanent down hole gauges installed in each well, field wide monitoring has commenced with very favourable indications of good lateral connectivity. The down hole gauges will provide key data required for ongoing production surveillance and planning Phase 2 development, currently envisaged in 2009. In addition, the reservoir model based on the five appraisal wells, 3D seismic acquired in 1991 and the extensive Integrated Petroleum Engineering Study carried out in 1994/ 95, proved to be a very robust tool for planning the surface development.

Subsea Engineering

The Malampaya Subsea System (Fig. 4) is unique in that it

is located in a remote deep-water environment and is the sole gas supply to power generation stations located 500 km away on Luzon Island. Many challenges had to be overcome to realise this latest advance in the development of deep-water subsea production capability i.e.

• High reliability and system availability requirements; • Difficult flow assurance requirements including

hydrate prevention and management of liquid hold-up in flowlines;

• High production rate, high H2S and CO2 content of produced fluids requiring CRA materials;

• Installation in an area devoid of customary E&P support infrastructure.

The subsea system design focused on achieving the highest

levels of overall system availability. This was achieved by a combination of using existing field proven technology, simplifying the design where possible, providing suitable levels of redundancy, proper material selection, applying the highest levels of quality assurance, equipment testing and verification. Confidence in the attainment of the required availability was gained through detailed availability analysis and modeling. In addition, emphasis was placed on ensuring that the experience and lessons learnt from other global subsea systems have been incorporated into the design of the Malampaya subsea system.

The wet gas subsea tieback of Malampaya required the use

of the latest modeling and flow assurance strategies. With seabed temperatures as low as 5 °C, hydrates could easily form in the individual well flowlines and in the 16 inch hulk flowlines. Hydrate formation is inhibited by injecting methanol in the individual well flowlines and in the common subsea manifold. In the event of a hydrate blockage, the dual flowline configuration will allow for round trip pigging to clear the lines and provide the flexibility to produce through one line whilst blowing down the pressure in the blocked line to melt any hydrate plugs.

The 820 metre water depth at the location of the

Malampaya manifold and the remoteness of the location from other oil-field infrastructure and resources presented unique challenges during the installation phase for the subsea system. Emphasis was placed on careful planning of installation tasks and preparation of contingency plans and procedures.

In addition, a full integration test of the subsea system was undertaken on land prior to installation of the system offshore. This test was used to verify that the system operated correctly and to train and familiarise personnel who would be involved in the installation and operation of the system. Production Platform

The Malampaya platform Topsides were fabricated in

Singapore and weigh over 13,000 tonnes when in operation. To maximise onshore completion and minimise offshore hook-up in the remote platform location, the Topsides were designed as a single integrated deck with a dry weight of 11,500 tonne. Mobilisation costs of suitable heavy lift vessels from either the Gulf of Mexico or the North Sea would have been prohibitively expensive and the Project Team therefore opted to adapt the float-over installation technique for what was to be the largest Topsides ever to be installed in the South East Asian waters. A critical activity for the success of the

6 D. GREER OTC 14038

float-over operation was the raising of the Topsides some 20 metres above grade in the fabrication yard prior to load-out onto the transportation barge. The Topsides sailed away on schedule on the 1st of March 2001 after a 22-month fabrication programme.

The Topsides facilities (measuring 40m x 92m in plan)

were then set on their concrete base as a complete integrated deck in the South China Sea, on 17th March 2001 with a loss of only 2 days for weather downtime during the whole operation (Fig. 5).

The supporting base, the Malampaya Concrete Gravity

Structure, which was built in Subic Bay, had already been installed three months ahead of schedule on 2nd June 2000. The CGS/dry-cell storage substructure concept was selected for its constructability in a remote location using local resources and as an economic way of providing the necessary condensate storage without impacting the pristine marine environment of Palawan. In addition to these challenges, the CGS had to be designed to withstand extreme loading generated by seismic events and typhoons. The calcified coral seabed at the platform site had to be levelled to provide a suitable foundation for the CGS. This was achieved by controlled dumping of gravel over the entire base area of the CGS: another industry-first.

The platform operating philosophy is to have minimum

personnel working offshore. This strategy will reduce the risks associated with personnel traveling to and from the offshore platform as well as minimise operating costs. To complement this strategy, the platform processes will be controlled automatically with surveillance provided from a manned onshore control room. This in itself is not new, however, the vast amount of electronic data that will be transferred from the platform to the onshore control room will be transferred via satellite, requiring high integrity systems and the latest telecommunications technology. The platform control system relies on field bus technology, which has led to a substantial reduction in the amount of platform cabling required via the use of high speed fibre data lines.

Handling the liquid which accumulates in the long bulk

flowlines (a mixture of condensate, water and methanol) at low flow rates was a major consideration in the design of the platform, especially when ramping-up gas production following a period of low production. The traditional solutions of a slug catcher and/or providing significant margins in the sizing of the liquid handling vessels was discarded in favour of state-of-the-art dynamic process modeling of the likely 3-phase fluid behaviour in the flowlines to provide the basis for optimising the platform’s inlet process control system. The application of advanced process control solutions to high integrity, fast response inlet control valves meets most of the required operating envelope supplemented by an operating procedure for periodically sweeping the liquid out of the

flowlines in the event of prolonged periods of very low offtake. This solution has eliminated the need for surge protection whilst maintaining the reliability of supply to the gas Buyers. Thus a major reduction in facilities weight was achieved, with a resultant reduction in the cost of the topsides. A state of the art dynamic model of the complete production system from wells to Buyers was developed to aid control of operations during these transient conditions.

Availability of gas supply is crucial to the project. A detailed availability model of the Malampaya production system from reservoir to delivery was instrumental in analysing the weak points in the chain and arriving at the best sparing philosophy for achieving high availability. The availability requirements were translated into the procurement packages of all the major items of equipment. The most important of these related to the onshore gas plant, as any shutdowns in these facilities could have an immediate impact on supply to Buyers. The offshore facilities, unlike those onshore, have the benefit of the long gas export pipeline being operated at high pressure which can then be de-pressurised to compensate for any short duration disruption in the topsides process.

Digital automation systems and Foundation Fieldbus were

used to support the Malampaya project goal of high availability, precise control, and predictive maintenance on minimum intervention. Given the national importance of Malampaya, the facilities must be able to produce gas virtually all year round, without interruption of supply. Consequently, the Process Automation System (PAS) target availability was set at 99.98%. In order to achieve the high availability and to support the minimum-manning concept, the time between planned major maintenance shutdowns is set at five years. These stringent requirements motivated the use of Foundation Fieldbus (FF) as the technology for the Process Automation System both offshore and onshore, since FF technology offers better measurement, more robust process control and remote diagnostics for field devices. The project requirements stretched the envelope of existing host system functionality and an extensive development programme was jointly agreed with the system vendor in order to meet the project requirements. The resultant system comprises of around 1500 FF devices, which is one of the most extensive uses of FF in the Oil and Gas industry. The extensive use of Foundation Fieldbus and emphasis on high system availability has enhanced the capability of available technology and supporting software particularly in the area of the Asset Management applications to enable extensive predictive maintenance and remote diagnostics. Flowlines and Pipelines

The field flowline and gas export pipeline route selection,

design and installation are at the forefront of deep water pipeline technology. The pipelines traverse structurally complex terrain with varied seabed characteristics and sea

MALAMPAYA DEEP WATER GAS TO POWER PROJECT - AN OVERVIEW- OTC 14038 POWERING THE PHILIPPINES INTO THE NEW MILLENNIUM 7

bottom relief. Fig. 6 illustrates a compressed cross-section of the route illustrating the varied relief, from the subsea manifold to the pipeline-landing site at Batangas.

The Philippine archipelago is recognised as being one of

the most seismically active areas in the world. The gas export pipeline crosses active faults, an extensive system of submarine channels and areas susceptible to mass gravity flows and other soil instabilities. In addition, the pipeline route was selected to avoid environmentally sensitive areas such as coral reefs and pearl farms.

The pipeline route was surveyed in several extensive

offshore campaigns to gather geophysical, geotechnical, environmental and metocean design data. Advanced satellite technology and computer visualisation tools allowed the Project Team to make rapid and informed routing selections and decisions. An environmental consultant was involved at an early stage to ensure all potential environmental concerns were identified, eliminated or mitigated. The latest generation of dynamically positioned lay-barges was employed for the pipeline installation to place the pipe precisely along the seabed route whilst minimising any disturbance to the seabed.

A specialist group, working as part of the pipelines design team, systematically addressed seismic hazards within a limit state design framework. A seismic hazard analysis was commissioned to provide seismic design criteria such as fault locations, displacements and ground movements.

A separate mass gravity flow study investigated potential

pipeline loading as a consequence of submarine gravity slides. Finite element models of soil behaviour and pipeline response were developed to validate the design. Onshore Gas Plant

Geochemical studies and zonal mapping of the H2S in the

Malampaya reservoir determined that concentrations could vary across the field between zero and a maximum of 1,000 ppm for an individual well but the produced gas to the platform is not expected to exceed 500 ppm. The smooth, continuous, operation of the onshore gas plant over a wide range of flow rates and variable H2S concentrations meant that the process design had to be determined as much by operational and availability criteria as capital cost. The plant configuration and sparing philosophy should provide the required high on-stream availability. The challenge in detailed design, procurement and construction was to realise this high availability target through the quality of the engineering design and by continuing to strive for low-intervention design and turnarounds.

In order to provide a facility that is designed for long-term

availability and high reliability, it was critical that the Contractors involved in the work shared this goal. Incentive

performance-based contracting strategies were therefore used and co-operative alliancing promoted to realise these goals.

The Onshore Gas Plant (OGP) (Fig.7) is designed to

remove up to 1000 ppm H2S from the gas, using an amine process and deliver specification gas (less than 20 ppm H2S) to the customers. The facility also includes fiscal metering for the three customers, a sulphur recovery unit and various utilities. The plant has two process trains with common inlet and outlet facilities. To prevent formation of hydrates, substantial volumes of methanol are continuously injected offshore, some of which reach the OGP and are removed in the processing of the gas. The onshore control room is the main control point for both onshore and offshore facilities. The control system for both onshore and offshore activities is integrated and is based on the Foundation Fieldbus open architecture technology. The plant is located next to the existing Shell refinery and some utilities are shared.

The Malampaya OGP is the “revenue valve” between the

upstream development and the gas Buyers. The three power plants feed up to 30% of the electricity demand on Luzon (including metro Manila) and continuity in operation of the OGP is essential to maintain power supplies. From the plant there are two approx. 10-km long pipelines to the power plants. Due to the short delivery lines, there is no buffer between the plant and the power stations. Thus very high availability and reliability of the plant, from initial production and throughout its life, is an essential success factor for the whole Malampaya development.

The OGP design and execution schedule was from the

outset extremely tight, mainly due to uncertainties during the definition stage on the exact requirements for H2S removal. Consequently, the main EPC contract was awarded with a target price mechanism only in April 1999, and ahead of final design optimisation studies. The contract scope also included commissioning, start up and initial operation, as well as preparation of complete operations and maintenance documentation and operator training. Following further Front-End Engineering Design (FEED) work through Q2/Q3 1999, the project moved into detailed design in Q4 1999. Initial gas delivery was planned for 1st October 2001 in preparation for long-term gas supply to commence 1st January 2002.

The project was delivered in a record time of 22 months

from the start of detail design to the first gas delivery. Start-up of the plant was achieved in only 7 days from the opening of the gas inlet valves to commencement of reliable delivery of specification gas to the customers. The plant was delivered within budget and some $50 million lower than the estimate at end of the FEED phase. The project achieved 11.3 million man-hours without a single LTI, whilst utilising workers mainly from the surrounding communities. The construction site was certified to ISO 14001 at the start of the site construction and the certification was retained and updated prior to commissioning and initial operation.

8 D. GREER OTC 14038

This achievement was made possible through strict and focused project management, tight management of the significant overlap between detailed design, procurement and construction, strict application of change management, excellent co-operation between SPEX and the EPC contractor and subcontractors, the application of Value Engineering and Flawless Start Up Principles. ENVIRONMENTAL COMPLIANCE The gas export pipeline route passes through an environmentally fragile region that includes coral reefs as well as commercial fishing grounds, pearl farms, tourist areas, sites of archaeological interest and ancestral domains. Obtaining project approvals within such areas called for a highly responsible approach and SPEX committed itself from the very start of the project to minimise environmental and social impact and involve key stakeholders in addressing issues of concern.

SPEX commissioned detailed, independent, environmental baseline studies to assess potential impacts and recommend measures for their mitigation. These included the use of state-of-the-art underwater survey techniques to map and assess coral cover and bio-diversity. An inventory of fauna living in the corals was made, as well as marine surveys of the mangroves and sea grasses. In addition, detailed socio-economic and cultural studies of the area were conducted.

Key stakeholders were consulted at regular intervals. Initially, scoping workshops were held to introduce the project and identify issues and concerns. Following the environmental assessment, validation workshops were held to share the results of the studies and to explain and discuss the mitigation measures on the identified impacts. Participants included local governmental agencies, NGOs and representatives of indigenous communities. To encourage wide participation in the consultation process with the key stakeholders and raise awareness, booklets, posters and video, were used in addition to public hearings and workshops. The work of the SPEX team was helped by the well-established and highly respected Pilipinas Shell Foundation, Inc. which has been working with local communities since 1982. Communities were assured that the Foundation would receive funds from the project to enlarge the scope of its continuing activities, which include training farmers and young people and all promises made in this regard have been delivered. SUSTAINABLE DEVELOPMENT In addition to complying with the law and fulfilling all obligations and conditions associated with approved Environmental Compliance Certificates, SPEX remained committed to promoting Sustainable Development throughout all project activities.

Within the Philippines, project activities covered four provinces viz. Palawan, Mindoro Oriental, Batangas and Subic Bay. Every effort was made in each of these areas to minimise the impact of construction activities on local communities. Prior to project implementation, social and environmental impacts were identified as part of the Environmental Impact Assessment(EIA) process and mitigating measures implemented to prevent or minimise the effects on local communities. Aside from establishing measures to avoid and mitigate any negative social and environmental impacts during project implementation, compensation was provided to those members of the communities directly impacted. In addition, a social management process involving the provision of social investment programmes to surrounding communities was undertaken to provide additional support over and above that provided by Government as a means of addressing their social needs. Social management efforts implemented by SPEX also helped explain the project to local communities and enabled further dialogue and co-operation. Concern and resistance from local communities to the Malampaya project reduced and enabled greater dialogue and co-operation. After a series of consultations, people in the locality were able to understand the economic importance of the project, not only to their locality, but the whole country. The improved social climate that developed out of SPEX’s communications programme, as well as the support provided to communities in their efforts to improve their socio-economic and environmental conditions, was a key element in enabling the project to be completed on time. SPEX’s policy from the outset of the project was to support sustainable development programmes as a form of social investment to catalyse improvement of socio-economic conditions in communities affected by the project. This not only brought benefits to local communities, but also helped the Company avoid delays in the implementation of the project. Sustainable development projects established open communication, co-operation, trust and confidence of local communities in SPEX. The success of SPEX’s social management programmes can be attributed to the following key factors a) establishment of a wide portfolio of projects; b) rapid response to critical issues and problems before they could escalate; c) continued dialogue and communication with local governments and local organisations affected by the project operations; d) active participation by senior management in the Sustainable Development programme to promote the concepts, and facilitate timely evaluation and approval of project proposals; e) strong support for the Malampaya project provided by the local government executives (Governors of Subic, Mindoro, Palawan and Batangas) helped to influence a positive reception by local people.

MALAMPAYA DEEP WATER GAS TO POWER PROJECT - AN OVERVIEW- OTC 14038 POWERING THE PHILIPPINES INTO THE NEW MILLENNIUM 9

MALAMPAYA: A KEY LINK IN ANY FUTURE TRANS-ASEAN GRID Linking the Philippines to the proposed Trans-ASEAN Gas Pipeline (TAGP) may not be as far-fetched as currently projected by some. The Malampaya field facilities are strategically located to serve as a link to the TAGP. They are very close to Sabah in Malaysia, with estimated reserves of 6 - 8 Tscf, which have currently no immediate market. Additional gas demand prospects in the Philippines beyond the Malampaya Deep Water Gas to Power project appear to be positive, as alternatives for energy diversification and increasing self-reliance remain limited. Moreover, the inherent instability of crude oil prices enhance the economics of gas substitution. Governments must exert every effort to sustain or even enhance such interests by providing a more favourable environment that will encourage further gas exploration, reduce regulatory risks for long-term investments and enhance the competitiveness of gas compared to other fuels. The recent ASEAN Council on Petroleum (ASCOPE) forum on Trans-ASEAN Gas Pipelines provided a venue for discussion among all the relevant regional players and highlighted the opportunities for gas trading, both by pipeline and LNG.

As ASEAN’s gas industry continues to evolve, and developments such as Malampaya provide a foundation for possible links with ASEAN neighbours, some lessons may be drawn from the European experience which may have some relevance for the ASEAN gas industry. Despite the diversity of the EU member states, European gas companies have been able to develop a large gas market, characterised by a high level of security of supply. An integrated European gas grid has developed by a step-by-step "bottom-up" approach, with each stage corresponding to new sources of supply and development of new markets. At each stage, Governments have set the framework to ensure that the necessary infrastructure would be developed on a commercially and financially robust basis. If creation of the Trans-ASEAN grid follows this approach, then the timing of each link will depend on decisions made by the large number of players involved and, as such, the rate of development is difficult to predict. For the longer term, however, it is clear that the Malampaya facilities will open the gateway to implementing and integrating the Philippine leg of any future Trans-ASEAN pipeline.

TRANSFORMING THE VISION INTO REALITY This landmark deep water project was recently completed on schedule and under budget. It represents the largest industrial undertaking in Philippines history with a combined investment of $US 4.5 billion ($US 2 billion in the upstream sector). Over the life of the project, it is estimated that the Philippines

Government will receive some $US 10 billion in revenue whilst saving a similar amount in foreign exchange transactions. Malampaya marks the birth of the Philippines gas industry, paving the way for cleaner and more efficient power generation in the new millennium. The Malampaya Project is a live example of climate-friendly technology transfer. The gas supplied from Malampaya will mainly replace oil-fired power generation, with oil’s share in power generation reducing from 47% to 9% based on DoE forecasts. This will significantly reduce greenhouse gas emissions in the Philippines mainly because the lower carbon intensity of gas compared to oil.

The project was executed in a trailblazing style, with good co-operation between Government and private enterprise and a determined focus by the downstream and upstream sectors to surmount all challenges. The globally distributed SPEX Project Team with its “can do, must do, will do” spirit remained committed to Sustainable Development and environmental compliance as well as delivering a “fit for life” development to power the Philippines into the next Millennium with Malampaya natural gas. A springboard for future growth in the Philippines gas market has therefore been established thus providing infrastructure to serve as a link in any future Trans-ASEAN grid.

Arguably, the most notable milestone in the history of Malampaya was the availability of Malampaya Gas to Gas Buyers on October 1st 2001. Many people offered much toil and sweat to help in the attainment of this milestone and had to endure many, many long months of struggle and challenge. Throughout this period, they demonstrated not only tremendous passion but a sustained capability to work professionally, safely, effectively and responsibly against very tight deadlines and to cope with many additional burdens. They also showed the flexibility to cope with the unexpected and unprecedented. To develop and form the global Malampaya Project Team from its early beginnings in early 1998 to execute such a challenging deep water project of this scale and complexity, so rapidly, was a very serious undertaking. After all, the team was tasked with embarking upon one of the greatest industrial undertakings in the history of the Philippines. In the furtherance of this object of national interest, many E&P contractors played a very, very important role. Thanks to their efforts, SPEX went on to meet the all-important date of first commercial Gas Sales on January 1st 2002.

The Malampaya Project rapidly advanced from a near standing start after the Declaration of Commerciality on 14th May 1998 to its current state of completion. All hardware, infrastructure, staff resources and systems are now in place and the power plants have been commissioned. A large number of substantial gains have been achieved on the technical, operational, contracting, organisational, human

10 D. GREER OTC 14038

resources and reputation-management fronts which are considered to be of great value to other major projects being planned or implemented in developing countries. At the same time, the structures, procedures and shared staff values necessary to successfully complete a major deep water project safely, on time and within budget in an environment with very limited E&P history or infrastructure have been successfully implemented. The principal project tenets of HSES, Cost, Schedule, Availability, Innovation and Sustainable Development and the relentless focus by all parties on these themes, which underpin the project logo, the Malampaya Flame (Fig. 8), served the Project Team very well.

For staff involved in project development activities, the Malampaya story has just ended. In reality, for the vast majority of SPEX staff and SPEX’s customers however, the Malampaya story is just about to begin. Like a ship that passes over the horizon, whilst it may no longer be visible, the efforts of all its crew will never be forgotten. Similarly, the lessons gained from this particular project should not be forgotten too readily as they will hopefully be of great value to future deep-water projects in remote locations and to the E&P industry at large.

MALAMPAYA DEEP WATER GAS TO POWER PROJECT - AN OVERVIEW- OTC 14038 POWERING THE PHILIPPINES INTO THE NEW MILLENNIUM 11

24" Dry gaspip eline

2 x 16” CRA w et gas

5 Develop ment w ells4 Addit ional d evelopm en t w ells (2009)

Sub seaman ifold

U p strea m D o w n stream

Condensatestorage

Condensateexport

- 820 m

- 43 m

28 km 5 04 km

- 0 m

3rd flow line(2021)

Gas d ehydratio nGas d ewp oint ingCon densate stabilisatio nExport co mpression

Sulp hur Reco veryH2S remo valMet erin gSup ply base

Caten ary Anch oredLeg Mo oring ( CALM)buo y for tan kerloadin g of cond ensate

AlternativeFuel

PowerStations

Onshore GasPlant

Fig. 1: Location Map of the Malampaya Field Fig. 2: The Malampaya Field

Fig. 3: Project Schematic Illustration Fig. 4: Subsea Facilities

12 D. GREER OTC 14038

0 100 200 300 400 500700

600

500

400

300

200

100

0

KP position (km)

Wat

er d

epth

(m)

100

CGS Location

South of Mindoro Batangas

Manila Trench

Figure 5: Malampaya Production Platform Figure 6: Gas Export Pipeline Route Profile

Figure 7: Malampaya Onshore Gas Plant

Figure 8: The Malampaya Flame The Malampaya logo is inspired by Shell Philippines’trail-blazing vision of the Malampaya Deep WaterGas to Power Project. It portrays the essence of thislandmark Philippine energy project and depicts anatural gas flame from the deep blue waters ofPalawan intertwining with the sun, stars and coloursof the Philippine national flag. The logo symbolizesthe commitment of the Philippine Government andProject Stakeholders to secure – for the first time inthe Philippine history – an indigenous, clean, anddependable source of power for the nation at thedawn of the new Millennium.