malampaya an overview

8/10/2019 Malampaya an Overview

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2 D. GREER OTC 14038

INTRODUCTION

In 1989, Occidental Philippines, Inc (Oxy) discovered gas inthe Camago-1 well in the area covered by Service ContractNo. 38 (SC-38), offshore Palawan in deep water and 500 kmaway from the nearest potential market (Fig.1). The area was

known to be gas prone: Shell itself had been involved in twoearlier gas discoveries elsewhere in the block, which werethen considered uncommercial.

In 1990, Shell Philippines Exploration B.V. (SPEX) farmed-intaking a 50% interest and operatorship of Block SC-38 therebyproviding the necessary deep water technology, and financialstrength to develop this resource. As part of the farm-in deal,Shell drilled three wells, the second discovering the largeMalampaya gas field with its 400 to 600 metre gas column and56 metre oil rim, connected to the Camago structure. Thepromising discovery was further appraised by three additionalwells. An integrated petroleum engineering study was carriedout using the latest proprietary 3-D carbonate reservoir

modeling techniques and incorporating the Pre-Stack DepthMigrated (PSDM) re-processed 3-D seismic data set. By1995, it had been demonstrated that Malampaya, with provenrecoverable volumes of 2.5 Tscf gas and 85 MMstbcondensate, represented a significant opportunity for acommercial gas development for Shell and the Philippines.These volumes were declared commercial on 14thMay 1998.Shell acquired 100% interest in SC-38 following the globalShell-Oxy asset swap executed on 15 th September 1998.Subsequently on 5thNovember 1999, Texaco Philippines Inc.farmed-in, to acquire a 45% working interest in SC-38. PNOCfarmed-in to acquire a 10% working interest on SC-38 on 22 ndDecember 1999.

HISTORY

The Malampaya field, located some 80 km NW of the Islandof Palawan, is an elongated structure consisting of twoculminations separated by a saddle some 12.5 km long with awidth that varies between 1.5 and 3.5 km (Fig.2). Thereservoir is a high relief Oligocene to Early Miocenecarbonate build-up (Nido Formation) at a depth of some 3,000metres subsea, developed over tight platform carbonates ofLate Eocene age.

Two exploration wells (Camago-1 and the Malampaya-1) and

three appraisal wells (Malampaya-2, 3, and 4) delineated thefield prior to development, which has a maximum gas columnof some 600 metres and proven reserves of 2.4 Tscf. Theexpectation reserves are 3.2 Tscf, with a P15 of 4.1 Tscf. Thegas column is partly underlain by a 56 metres oil rim with aSTOIIP of 244 - 378 MMbbls. Exploitation of the Malampayareserves was a recognised deep water challenge and Shellsunrivalled experience in this arena enabled the company topursue the commercial development of Malampaya. Initially,three development concepts were evaluated. For the combined

development of oil and gas, a Tension Leg Platform (TLP) anda Floating Production Storage and Off-loading (FPSO) facilitywere considered. During the appraisal campaign, it becameevident that the oil development was marginal from aneconomic perspective given the thickness of the oil rim. TheFPSO option was rejected on the grounds of the technical

complexity associated with the number of gas risers andswivel design particularly for the large diameter high pressuregas export pipeline. A TLP option was also rejected in favourof a less expensive capital cost alternative for the gas onlydevelopment, comprising a deep water subsea tieback to ashallow water platform, thereby resulting in the moscompetitive landing pricefor the gas. The subsea tieback to ashallow water platform could also be brought on stream oneyear earlier than the TLP alternative thereby enhancing theproject economics. A further major technical concern with theTLP was the unknown behavoiur and reliability of tensionpiles in calcareous soils with respect to creep. Although theoil rim was not part of the original field development, effortsare now being made to dynamically test the oil leg of the

reservoir to assess the viability of an independent oidevelopment with gas export combined with that of the maingas development. Test results to date have been encouraging.

Aside from the technical, logistical and development costchallenges, the commercial challenge of developing a gasmarket in the Philippines remained. The economics odeveloping such a remote deep water gas field were alwaysknown to be marginal and therefore the venture needed toestablish a market that could off-take high volumes as soon asthe gas would flow. Only the power sector could provide sucha market. A study in 1994 confirmed that there would be arequirement around 2000-2002 for 3,000 MW of gas-fired

power generation at base load. At this throughput level, thegas could compete with alternative fuels, including its maincompetitor, coal. Gas plants cost less and required less time tobuild and, using combined cycle gas turbine technology, havea higher efficiency than coal plants. The outcome of the studywas endorsed by the Philippines Department of Energy (DoE)who assumed responsibility for the promotion of a 3,000 MWmarket for Malampaya gas.

The DoE allocated 1,500 MW to the National PowerCorporation (NPC), a Government owned corporation and themain power generator in the Philippines, and 1,500 MW toMeralco, the main distributor of electricity in Metro Manila

and the industrial growth area south of Metro Manila. NPCand Meralco, in turn, set out to appoint independent powerproducers (IPP) who would build the power plants and supplyelectricity to them.

NPC, being a Government owned entity enacted to resolve thepower crisis that almost crippled the Philippines economy inthe eighties, proceeded under the Build-Operate-Transfer lawNPC awarded a competitively tendered Energy ConversionAgreement to the successful IPP and, in early 1995, issued its


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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 beconstructed at Ilijan, Batangas (the Ilijan plant). NPC selectedKorea Electric Power Corporation (Kepco) to build andoperate 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 FirstGas Power Corporation (FGPC) a joint venture between theFirst Philippine Holdings Corporation (60%), which is alsoinvolved in the management of Meralco, and British Gas(40%). FGH incorporated two subsidiaries, one to build a1,000 MW power plant at Santa Rita, Batangas, the other tobuild the adjacent 500 MW San Lorenzo power plant.

By the beginning of 1995, the key players that wouldtransform this deep water gas to power project from a visioninto reality had been identified.

THE COMMERCIAL CHALLENGES

At the outset, it was recognised that the Malampaya DeepWater Gas to Power project could only succeed if theupstream project was fully integrated with the threedownstream power projects. This meant aligning the interestsof the Government (involved in both the upstream and throughNPC in one of the key downstream projects); SPEX in theupstream; NPC, the Lopez Group and British Gas in thedownstream, 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 theproject, declined an active role in the negotiating process. Itdid, however, organise a forum for all relevant departmentsand Government agencies through which it would oversee

progress and support the project as required.

The upstream projects viability depended entirely on therealisation and dispatch of the power projects. By contrast,the power project developers were less dependent on theupstream as their plants are dual-fired, i.e. they can run onliquid fuel and gas; furthermore, their combined purchasingpower could support a LNG importation scheme. In favour ofthe upstream option was the fact that the development of theindigenous resources of Malampaya best serves the nationalinterest and economy.

SPEX marketed the gas on the basis that its price would have

to underpin the upstream economics. At the same time, gaswould have to be competitive with coal-fired powergeneration, on a total cost basis, and cheaper than LNG, takinginto account the price of LNG, its shipping cost and the cost ofstorage and re-gasification in the Philippines. The agreed gasprice adjustment formula furthermore links the gas price to oilprice fluctuations, thus providing a measure ofcompetitiveness with oil based power plant fuels.

In view of the limited time between final agreement of theGSPAs in May 1998 and the planned first gas to platform inJune 2001, a contracting strategy was adopted thaincorporated the six project tenets described earlier. Separatecontracts were placed for the five main upstream projeccomponents: pipeline fabrication, coating and installation

platform engineering, procurement, construction, installationand commissioning; subsea engineering detailed designfabrication and procurement, drilling rig rental fordevelopment drilling and the onshore gas plant detailed designand construction. Project components with a precisedefinition of scope and well identified risks, such as pipelineswere awarded as lump sum contracts. Areas such as theproduction platform, onshore gas plant and subsea facilities inwhich significant challenges remained in respect otechnological innovation, meeting availability and scheduletargets, were awarded under reimbursable contracts. Thesecontracts were structured using a combination of traditionareimbursable payments combined with risk rewardmechanisms, with system availability and life cycle costs

taking precedence over capital cost.

THE UPSTREAM PROJECT

The upstream project development plan comprises nine subseagas wells connected to subsea manifolds located on the seabedover Malampaya, at a water depth of approximately 850metres (Fig. 3). Five wells were drilled initially to ensuredelivery of commissioning gas on 1stOctober 2001 and firscommercial gas sales on 1st of January 2002 (gas for thecommissioning of onshore power plants was delivered 3months prior to commercial sales gas delivery to Buyers)Development drilling started in February 2000 and progress

achieved throughout the programme was excellent. The firsgroup of five wells have been clustered around a subseamanifold located between the Malampaya-1 and Malampaya-4wells. The drilling of the subsequent four wells is planned fo2009 and may involve a second manifold near the Camagoarea. It is expected that two of these four wells could bedrilled from the initial northern manifold, while the two otherwells may be tied back from a southern manifold, targeting theCamago area of the accumulation. The plans for the numbeand phasing of wells for the second phase of reservoirdevelopment will be subject to reservoir performance duringearly years of production. The wells are of a 7 inch monobore design with horizontal Christmas trees, providing high

production capacities with a simplified design for long servicelife. The wells will have permanent downhole gauges toaccurately monitor reservoir performance and facilitateeffective reservoir management.

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


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Island in a water depth of 43 metres. The high CGR wellstream, which contains CO2and H2S, is separated and treatedby the platform process to meet transport specifications for gasand condensate. The gas is conditioned to water andhydrocarbon dew point specifications ( 0 deg.C) by a simpleJoule Thompson process followed by re-compression and

export via a 504 km long, 24 inch carbon steel gas export lineto the onshore gas plant located at Tabangao, Batangas onLuzon Island. There, the dry gas is treated to Buyers qualityspecifications. Condensate is stabilised to a RVP of 10 psia forstorage and transport requirements. The platform has acapacity to process 508MMscf/d of gas and 32,800 b/d ofcondensate. Methanol storage, recovery and injection facilitiesfor hydrate prevention are a significant, additional feature ofthe platform process. The platform comprises an integrateddeck of three levels for process, utilities and living quartersinstalled on a Concrete Gravity Substructure (CGS) withcondensate storage in the base. Condensate storage is based onthe dry-cell principle to avoid any contamination of the marineenvironment and has a working capacity of 385,000 bbls.

Condensate is exported via shuttle tankers, which connect to aCatenary Anchored Leg Mooring (CALM) offshore loadingsystem, approximately every two weeks.

Maintaining sufficient deliverability capacity from the fieldwill require additional compression around the year 2015 andinstallation of an additional 16 inch flowline from the subseamanifold to the platform in the year 2020 to reduce flowlineback pressure and wellhead pressures. The last stage ofdevelopment prior to abandonment will consist of re-wheelingthe compressors to accommodate lower suction pressures.

THE TECHNICAL CHALLENGES

Malampaya will deliver gas for the generation of some 2,700MW of electrical power for which natural gas will be theprimary fuel source. As such, the total Malampaya productionfacilities from the deep subsea wells to onshore gas plant willrequire high system availability. The principal technicalchallenge is therefore to ensure continuous delivery of salesspecification gas throughout the production chain whilstcontaining 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 residualsubsurface uncertainties at the start of development drilling.

The crestal reservoir drainage philosophy is exposed to therisk of vertical compartmentalisation. This risk was assessedwith scenario modeling with a detailed 3D reservoir model.A significantly improved 3D PreSDM seismic dataset wasused to provide excellent velocity control within the reservoirand more accurate determination of the depth of a tight, andpotentially vertical barrier, the Intra Nido layer. The heavily

fractured Intra Nido was an anticipated drilling hazardbelieved to be prone to losses from the high mud overbalanceat depth. Using a seismic inversion derived reservoir modeland simulation, paths were identified within the Intra Nido tofacilitate sufficient vertical reservoir communication

In planning to meet the well objectives, a fit for purpose

approach for the well design and data gathering was adoptedThe up-front process of rationalisation and prioritisation wasvery effective in steering the design and execution efforts indelivering safe and cost effective high rate gas productionwells. A minimum inflow performance criterion wasdeveloped, based on a draw-down threshold that would nounduly accelerate future field development activities. Thisallowed the definition of the minimum reservoir penetrationrequired for each well, thus minimising the exposure to losseswhilst drilling long intervals in a large gas column withincreasing overbalance.

The locations of the five initial gas development wellswere targeted within the proven area of good reservoir so as

to ensure high well deliveries with access to large gasvolumes. The first three wells (MA-5, 6 and 7) were locatedin the most likely area for high porosity zones and wereexpected to be capable of producing at initial rates in excess of200 MMscf/day each. Additionally MA-5 was located toappraise the oil rim in an area where good porosities wereexpected in the water leg, lying equidistant between MA-1 and2, where the maximum difference in oil rim thickness hadbeen observed. With confidence that these wells would securethe initial demand, the last two wells (MA-8 and MA-9) wereplaced in less well-defined areas of the field, where there werefacies or connectivity uncertainties. The first phase wellstherefore, provide complete coverage of the northern

Malampaya culmination for drainage and depletionmonitoring using tandem permanent down hole gauges ineach well.

Deep Water Well Engineering

A number of very special challenges had to be tackled andovercome to deliver the five initial deep water subsea gaswells in accordance with the tight Malampaya Projecschedule. These challenges related to the deployment ofleading edge technology well systems in an environmentallypristine and remote area within a country which has anextremely limited upstream E&P infrastructure for support andvery long logistics and supply lines. The definition and

management of good performance within this context and themanagement of the many interfaces with all other disciplinesworking in parallel towards the same project end-goal requiredunique ways of working to be established. Within thetechnical arena, many novel solutions were adopted withrespect to rig equipment and modifications, deep watercarbonate gas reservoir drilling procedures with total lossesmanagement of hydrates, subsea Xmas trees, well completionsand well test clean-up programmes.


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The casing design revolved around a requirement for 7inch mono-bore completions, to drill 8 inch hole through thereservoir and to complete with a 7 inch liner. This wouldallow both high production rates and left the option open todeepen any of the wells if required. The production casing wasset above top reservoir to avoid drilling with large hole size

into the loss prone reservoir.

Corrosion Resistant Alloys (CRA) were selected for allflow wetted areas including the liner, tubing, accessoriesand a section of 9 5/8inch casing between the liner top and theproduction packer. A tapered production casing string wasrequired to accommodate the large bore TRSSSV.

The perforation philosophy was based on the use of thelatest deep penetrating charges with the largest gun size toensure the maximum inflow performance from the intervalavailable for perforation. This approach facilitated a singleperforation run, to minimize hydrate risks associated with wellinterventions in this deep water environment.

Deep set permanent gauges were justified for field widemonitoring to confirm connected gas reserves. The productioncasing was set above top reservoir to avoid drilling with largehole size into the loss prone reservoir.

The reservoir development of the deep water Malampayagas field has been a success, as the subsurface objectives havebeen met and well deliverability targets exceeded. The wellshave been flowed clean to rates of up to 120 MMscf/day andhave demonstrated initial potential in excess of 250MMscf/day. With permanent down hole gauges installed ineach well, field wide monitoring has commenced with very

favourable indications of good lateral connectivity. The downhole gauges will provide key data required for ongoingproduction surveillance and planning Phase 2 development,currently envisaged in 2009. In addition, the reservoir modelbased on the five appraisal wells, 3D seismic acquired in 1991and the extensive Integrated Petroleum Engineering Studycarried out in 1994/ 95, proved to be a very robust tool forplanning the surface development.

Subsea Engineering

The Malampaya Subsea System (Fig. 4) is unique in that itis located in a remote deep-water environment and is the sole

gas supply to power generation stations located 500 km awayon Luzon Island. Many challenges had to be overcome torealise this latest advance in the development of deep-watersubsea production capability i.e.

High reliability and system availability requirements;

Difficult flow assurance requirements includinghydrate prevention and management of liquid hold-upin flowlines;

High production rate, high H2S and CO2 content oproduced fluids requiring CRA materials;

Installation in an area devoid of customary E&Psupport infrastructure.

The subsea system design focused on achieving the highes

levels of overall system availability. This was achieved by acombination of using existing field proven technologysimplifying the design where possible, providing suitablelevels of redundancy, proper material selection, applying thehighest levels of quality assurance, equipment testing andverification. Confidence in the attainment of the requiredavailability was gained through detailed availability analysisand modeling. In addition, emphasis was placed on ensuringthat the experience and lessons learnt from other global subseasystems have been incorporated into the design of theMalampaya subsea system.

The wet gas subsea tieback of Malampaya required the useof the latest modeling and flow assurance strategies. Withseabed temperatures as low as 5 C, hydrates could easilyform in the individual well flowlines and in the 16 inch hulkflowlines. Hydrate formation is inhibited by injectingmethanol in the individual well flowlines and in the commonsubsea manifold. In the event of a hydrate blockage, the duaflowline configuration will allow for round trip pigging toclear the lines and provide the flexibility to produce throughone line whilst blowing down the pressure in the blocked lineto melt any hydrate plugs.

The 820 metre water depth at the location of theMalampaya manifold and the remoteness of the location fromother oil-field infrastructure and resources presented unique

challenges during the installation phase for the subsea systemEmphasis was placed on careful planning of installation tasksand preparation of contingency plans and procedures.

In addition, a full integration test of the subsea system wasundertaken on land prior to installation of the system offshoreThis test was used to verify that the system operated correctlyand to train and familiarise personnel who would be involvedin 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 operationTo maximise onshore completion and minimise offshorehook-up in the remote platform location, the Topsides weredesigned as a single integrated deck with a dry weight of11,500 tonne. Mobilisation costs of suitable heavy lift vesselsfrom either the Gulf of Mexico or the North Sea would havebeen prohibitively expensive and the Project Team thereforeopted to adapt the float-over installation technique for whawas to be the largest Topsides ever to be installed in the SouthEast Asian waters. A critical activity for the success of the


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

The Topsides facilities (measuring 40m x 92m in plan)were then set on their concrete base as a complete integrateddeck in the South China Sea, on 17 thMarch 2001 with a lossof only 2 days for weather downtime during the wholeoperation (Fig. 5).

The supporting base, the Malampaya Concrete GravityStructure, which was built in Subic Bay, had already beeninstalled three months ahead of schedule on 2ndJune 2000.The CGS/dry-cell storage substructure concept was selectedfor its constructability in a remote location using localresources and as an economic way of providing the necessarycondensate storage without impacting the pristine marineenvironment of Palawan. In addition to these challenges, the

CGS had to be designed to withstand extreme loadinggenerated by seismic events and typhoons. The calcified coralseabed at the platform site had to be levelled to provide asuitable foundation for the CGS. This was achieved bycontrolled dumping of gravel over the entire base area of theCGS: another industry-first.

The platform operating philosophy is to have minimumpersonnel working offshore. This strategy will reduce the risksassociated with personnel traveling to and from the offshoreplatform as well as minimise operating costs. To complementthis strategy, the platform processes will be controlledautomatically with surveillance provided from a manned

onshore control room. This in itself is not new, however, thevast amount of electronic data that will be transferred from theplatform to the onshore control room will be transferred viasatellite, requiring high integrity systems and the latesttelecommunications technology. The platform control systemrelies on field bus technology, which has led to a substantialreduction in the amount of platform cabling required via theuse of high speed fibre data lines.

Handling the liquid which accumulates in the long bulkflowlines (a mixture of condensate, water and methanol) atlow flow rates was a major consideration in the design of theplatform, especially when ramping-up gas production

following a period of low production. The traditional solutionsof a slug catcher and/or providing significant margins in thesizing of the liquid handling vessels was discarded in favourof state-of-the-art dynamic process modeling of the likely 3-phase fluid behaviour in the flowlines to provide the basis foroptimising the platforms inlet process control system. Theapplication of advanced process control solutions to highintegrity, fast response inlet control valves meets most of therequired operating envelope supplemented by an operatingprocedure for periodically sweeping the liquid out of the

flowlines in the event of prolonged periods of very lowofftake. This solution has eliminated the need for surgeprotection whilst maintaining the reliability of supply to thegas Buyers. Thus a major reduction in facilities weight waachieved, with a resultant reduction in the cost of the topsidesA state of the art dynamic model of the complete production

system from wells to Buyers was developed to aid control ofoperations during these transient conditions.Availability of gas supply is crucial to the project. A

detailed availability model of the Malampaya productionsystem from reservoir to delivery was instrumental inanalysing the weak points in the chain and arriving at the bestsparing philosophy for achieving high availability. Theavailability requirements were translated into the procuremenpackages of all the major items of equipment. The mosimportant of these related to the onshore gas plant, as anyshutdowns in these facilities could have an immediate impacon supply to Buyers. The offshore facilities, unlike thoseonshore, have the benefit of the long gas export pipeline beingoperated at high pressure which can then be de-pressurised to

compensate for any short duration disruption in thetopsides process.

Digital automation systems and Foundation Fieldbus wereused to support the Malampaya project goal of highavailability, precise control, and predictive maintenance onminimum intervention. Given the national importance ofMalampaya, the facilities must be able to produce gas virtuallyall year round, without interruption of supply. Consequentlythe Process Automation System (PAS) target availability wasset at 99.98%. In order to achieve the high availability and tosupport the minimum-manning concept, the time betweenplanned major maintenance shutdowns is set at five years

These stringent requirements motivated the use of FoundationFieldbus (FF) as the technology for the Process AutomationSystem both offshore and onshore, since FF technology offersbetter measurement, more robust process control and remotediagnostics for field devices. The project requirementsstretched the envelope of existing host system functionalityand an extensive development programme was jointly agreedwith the system vendor in order to meet the projectrequirements. The resultant system comprises of around 1500FF devices, which is one of the most extensive uses of FF inthe Oil and Gas industry. The extensive use of FoundationFieldbus and emphasis on high system availability hasenhanced the capability of available technology and

supporting software particularly in the area of the AssetManagement applications to enable extensive predictivemaintenance and remote diagnostics.

Flowlines and Pipelines

The field flowline and gas export pipeline route selectiondesign and installation are at the forefront of deep waterpipeline technology. The pipelines traverse structurallycomplex terrain with varied seabed characteristics and sea


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

The Philippine archipelago is recognised as being one ofthe most seismically active areas in the world. The gas export

pipeline crosses active faults, an extensive system ofsubmarine channels and areas susceptible to mass gravityflows and other soil instabilities. In addition, the pipelineroute was selected to avoid environmentally sensitive areassuch as coral reefs and pearl farms.

The pipeline route was surveyed in several extensiveoffshore campaigns to gather geophysical, geotechnical,environmental and metocean design data. Advanced satellitetechnology and computer visualisation tools allowed theProject Team to make rapid and informed routing selectionsand decisions. An environmental consultant was involved atan early stage to ensure all potential environmental concernswere identified, eliminated or mitigated. The latest generation

of dynamically positioned lay-barges was employed for thepipeline installation to place the pipe precisely along theseabed route whilst minimising any disturbance to the seabed.

A specialist group, working as part of the pipelines designteam, systematically addressed seismic hazards within a limitstate design framework. A seismic hazard analysis wascommissioned to provide seismic design criteria such as faultlocations, displacements and ground movements.

A separate mass gravity flow study investigated potentialpipeline 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 theMalampaya reservoir determined that concentrations couldvary across the field between zero and a maximum of 1,000ppm for an individual well but the produced gas to theplatform is not expected to exceed 500 ppm. The smooth,continuous, operation of the onshore gas plant over a widerange of flow rates and variable H2S concentrations meant thatthe process design had to be determined as much byoperational and availability criteria as capital cost. The plant

configuration and sparing philosophy should provide therequired high on-stream availability. The challenge in detaileddesign, procurement and construction was to realise this highavailability target through the quality of the engineeringdesign and by continuing to strive for low-intervention designand turnarounds.

In order to provide a facility that is designed for long-termavailability and high reliability, it was critical that theContractors involved in the work shared this goal. Incentive

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

The Onshore Gas Plant (OGP) (Fig.7) is designed toremove up to 1000 ppm H2S from the gas, using an amineprocess and deliver specification gas (less than 20 ppm H2Sto the customers. The facility also includes fiscal metering forthe three customers, a sulphur recovery unit and variousutilities. The plant has two process trains with common inleand outlet facilities. To prevent formation of hydratessubstantial volumes of methanol are continuously injectedoffshore, some of which reach the OGP and are removed inthe processing of the gas. The onshore control room is themain control point for both onshore and offshore facilitiesThe control system for both onshore and offshore activities isintegrated and is based on the Foundation Fieldbus openarchitecture technology. The plant is located next to theexisting Shell refinery and some utilities are shared.

The Malampaya OGP is the revenue valve between the

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

The OGP design and execution schedule was from theoutset extremely tight, mainly due to uncertainties during thedefinition stage on the exact requirements for H2S removalConsequently, the main EPC contract was awarded with atarget price mechanism only in April 1999, and ahead of finaldesign optimisation studies. The contract scope also includedcommissioning, start up and initial operation, as well aspreparation of complete operations and maintenancedocumentation and operator training. Following further Front-End Engineering Design (FEED) work through Q2/Q3 1999the project moved into detailed design in Q4 1999. Initial gasdelivery was planned for 1stOctober 2001 in preparation forlong-term gas supply to commence 1stJanuary 2002.

The project was delivered in a record time of 22 monthsfrom the start of detail design to the first gas delivery. Start-up

of the plant was achieved in only 7 days from the opening ofthe gas inlet valves to commencement of reliable delivery ofspecification gas to the customers. The plant was deliveredwithin budget and some $50 million lower than the estimate aend of the FEED phase. The project achieved 11.3 millionman-hours without a single LTI, whilst utilising workersmainly from the surrounding communities. The constructionsite was certified to ISO 14001 at the start of the siteconstruction and the certification was retained and updatedprior to commissioning and initial operation.


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This achievement was made possible through strict andfocused 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 wellas 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 socialimpact and involve key stakeholders in addressing issues

of concern.

SPEX commissioned detailed, independent, environmentalbaseline 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 assesscoral 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 environmentalassessment, validation workshops were held to share the

results of the studies and to explain and discuss the mitigation

measures on the identified impacts. Participants includedlocal 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 ShellFoundation, 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 regardhave been delivered.

SUSTAINABLE DEVELOPMENT

In addition to complying with the law and fulfilling all

obligations and conditions associated with approvedEnvironmental 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 communitiesPrior to project implementation, social and environmenta

impacts were identified as part of the Environmental Impact

Assessment(EIA) process and mitigating measuresimplemented to prevent or minimise the effects on loca

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, asocial management process involving the provision of social

investment programmes to surrounding communities was

undertaken to provide additional support over and above tha

provided by Government as a means of addressing theisocial needs.

Social management efforts implemented by SPEX also helpedexplain the project to local communities and enabled further

dialogue and co-operation. Concern and resistance from locacommunities to the Malampaya project reduced and enabled

greater dialogue and co-operation. After a series o

consultations, people in the locality were able to understandthe economic importance of the project, not only to their

locality, but the whole country. The improved social climate

that developed out of SPEXs communications programme, awell 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 completedon time.

SPEXs policy from the outset of the project was to suppor

sustainable development programmes as a form of sociainvestment to catalyse improvement of socio-economicconditions in communities affected by the project. This no

only brought benefits to local communities, but also helped

the Company avoid delays in the implementation of the

project. Sustainable development projects established opencommunication, co-operation, trust and confidence of loca

communities in SPEX. The success of SPEXs social

management programmes can be attributed to the followingkey factors a) establishment of a wide portfolio o

projects; b) rapid response to critical issues and problem

before they could escalate; c) continued dialogue and

communication with local governments and loca

organisations affected by the project operations; d) activeparticipation by senior management in the Sustainable

Development programme to promote the concepts, and

facilitate timely evaluation and approval of project proposalse) strong support for the Malampaya project provided by the

local government executives (Governors of Subic, Mindoro

Palawan and Batangas) helped to influence a positivereception by local people.


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MALAMPAYA: A KEY LINK IN ANY FUTURE TRANS-ASEAN GRID

Linking the Philippines to the proposed Trans-ASEAN GasPipeline (TAGP) may not be as far-fetched as currentlyprojected by some. The Malampaya field facilities are

strategically located to serve as a link to the TAGP. They arevery 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 beyondthe Malampaya Deep Water Gas to Power project appear to bepositive, as alternatives for energy diversification andincreasing self-reliance remain limited. Moreover, theinherent instability of crude oil prices enhance the economicsof gas substitution. Governments must exert every effort tosustain or even enhance such interests by providing a morefavourable environment that will encourage further gasexploration, reduce regulatory risks for long-term investmentsand 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 fordiscussion among all the relevant regional players andhighlighted the opportunities for gas trading, both by pipelineand LNG.

As ASEANs gas industry continues to evolve, anddevelopments such as Malampaya provide a foundation forpossible links with ASEAN neighbours, some lessons may bedrawn from the European experience which may have somerelevance for the ASEAN gas industry. Despite the diversityof the EU member states, European gas companies have beenable to develop a large gas market, characterised by a high

level of security of supply. An integrated European gas gridhas developed by a step-by-step "bottom-up" approach, witheach stage corresponding to new sources of supply anddevelopment of new markets. At each stage, Governmentshave set the framework to ensure that the necessaryinfrastructure would be developed on a commercially andfinancially robust basis.

If creation of the Trans-ASEAN grid follows this approach,then the timing of each link will depend on decisions made bythe large number of players involved and, as such, the rate ofdevelopment 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 ofany future Trans-ASEAN pipeline.

TRANSFORMING THE VISION INTO REALITY

This landmark deep water project was recently completed onschedule and under budget. It represents the largest industrialundertaking in Philippines history with a combined investmentof $US 4.5 billion ($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 revenuewhilst saving a similar amount in foreign exchangetransactions. Malampaya marks the birth of the Philippinegas industry, paving the way for cleaner and more efficientpower generation in the new millennium.

The Malampaya Project is a live example of climate-friendlytechnology transfer. The gas supplied from Malampaya wilmainly replace oil-fired power generation, with oils share inpower generation reducing from 47% to 9% based on DoEforecasts. This will significantly reduce greenhouse gasemissions in the Philippines mainly because the lower carbonintensity of gas compared to oil.

The project was executed in a trailblazing style, with good co-operation between Government and private enterprise and adetermined focus by the downstream and upstream sectors tosurmount all challenges. The globally distributed SPEXProject Team with its can do, must do, will do spiritremained committed to Sustainable Development and

environmental compliance as well as delivering a fit for lifedevelopment to power the Philippines into the nextMillennium with Malampaya natural gas. A springboard forfuture growth in the Philippines gas market has therefore beenestablished thus providing infrastructure to serve as a link inany future Trans-ASEAN grid.

Arguably, the most notable milestone in the history ofMalampaya was the availability of Malampaya Gas to GasBuyers on October 1st 2001. Many people offered much toiand sweat to help in the attainment of this milestone and hadto endure many, many long months of struggle and challengeThroughout this period, they demonstrated not only

tremendous passion but a sustained capability to workprofessionally, safely, effectively and responsibly against verytight deadlines and to cope with many additional burdensThey also showed the flexibility to cope with the unexpectedand unprecedented. To develop and form the globaMalampaya Project Team from its early beginnings in early1998 to execute such a challenging deep water project of thisscale and complexity, so rapidly, was a very seriousundertaking. After all, the team was tasked with embarkingupon one of the greatest industrial undertakings in the historyof the Philippines. In the furtherance of this object of nationalinterest, many E&P contractors played a very, very importantrole. Thanks to their efforts, SPEX went on to meet the all-

important date of first commercial Gas Sales on January1st 2002.

The Malampaya Project rapidly advanced from a nearstanding start after the Declaration of Commerciality on 14 th

May 1998 to its current state of completion. All hardwareinfrastructure, staff resources and systems are now in placeand the power plants have been commissioned. A largenumber of substantial gains have been achieved on thetechnical, operational, contracting, organisational, human


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resources and reputation-management fronts which areconsidered to be of great value to other major projects beingplanned or implemented in developing countries. At the sametime, the structures, procedures and shared staff valuesnecessary to successfully complete a major deep water projectsafely, on time and within budget in an environment with very

limited E&P history or infrastructure have been successfullyimplemented. The principal project tenets of HSES, Cost,Schedule, Availability, Innovation and SustainableDevelopment and the relentless focus by all parties on thesethemes, which underpin the project logo, the MalampayaFlame (Fig. 8), served the Project Team very well.

For staff involved in project development activities, theMalampaya story has just ended. In reality, for the vastmajority of SPEX staff and SPEXs customers however, theMalampaya story is just about to begin. Like a ship that passesover the horizon, whilst it may no longer be visible, the effortsof all its crew will never be forgotten. Similarly, the lessonsgained 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 industryat large.


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24"D r y gaspipeline

2 x 16 CRA wet gas

5 Development wells4 Additional development wells (2009)

Subseamanifold

U p strea m D o w n stream

Condensatestorage

Condensateexport

- 820 m

- 43 m

28 km 504 km

-0 m

3rd flowline(2021)

Gas dehydrationGas dewpointingCondensate stabilisationExport compression

Sulphur RecoveryH2S removalMeteringSupply base

Catenary AnchoredLeg Mooring (CALM)buoy for tankerloading of condensate

AlternativeFuel

PowerStations

Onshore GasPlant

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

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


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0 100 200 300 400 50700

600

500

400

300

200

100

0

KP position (km)

Waterdepth(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 Philippinestrail-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.

malampaya an overview

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