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The Malampaya Depletion Compression Platform (DCP) was conceived by Shell Philippines Exploration B.V. (SPEX) to provide additional gas compression to account for the future expected decline in well pressure from the Malampaya field. The Malampaya project is very important to the ongoing prosperity of the Philippines, with the exported gas feeding three power stations which provide up to 45% of the power needs of Luzon, the largest and most populous island in the Philippines. The DCP consists of a sealed barge structure which is rigidly connected to four cylindrical legs, each of which is supported on individual strut-linked hexagonal pad footings. The DCP arrangement uses cylindrical rather than truss legs and the base comprised a series of linked pad footings rather than a skirted baseplate. The leg configuration was selected in an attempt to simplify the leg fabrication; whilst the use of pad footings was a result of the site geotechnical conditions. One of the key structural innovations on the project was to design a barge to leg connection which could accommodate both the required vertical movement of the circular leg during installation, as well as form a rigid moment connection at the final design level of the barge without excessive offshore works. One of the key geotechnical innovations was to eliminate the need for a dedicated scour protection layer around the footings, yielding savings in procurement and offshore placement. This was achieved by selecting a foundation fill material capable of resisting self-scour in the 100-year return period cyclonic storm. The use of this larger sized material was agreed in advance with potential offshore Contractors to ensure that the required surface tolerances could be readily achieved. Offshore work prior to the arrival of the DCP consisted of seabed excavation to remove the in-situ carbonate sand and reef limestone, and replacement with the engineered rock fill to form a sufficiently level surface for placement of each of the four pad footings. Installation of the DCP at the Malampaya site commenced after a 3 day wet-tow from the fabrication yard in Subic Bay. Base lowering commenced on the morning of 12 February 2015, with touchdown occurring on the seabed some 26 hours later. Barge raising commenced immediately thereafter with the barge clearing the water around midday on 13 February 2015. Barge raising to the final elevation was completed in the early hours of 14 February 2015, less than 2 days after initial touchdown. As well as providing a general overview, this paper will describe some of the geotechnical and structural innnovations which ensured a successful outcome of the project.
Rao, K. V. (Shell India Markets Private Ltd) | Brinsden, M. S. (Shell International E&P Co.) | Gilliat, J.. (Baker Hughes) | Tan, K Y. (Sarawak Shell Berhad) | Bhagwat, M.. (Sarawak Shell Berhad) | Harvey, N.. (Sarawak Shell Berhad) | Bhushan, V.. (Sarawak Shell Berhad)
Abstract This paper describes the operational planning and process safety due diligence performed to ensure safe and successful operations in the world's first deepwater propellant perforation in a carbonate reservoir. The Malampaya gas field in the Philippines is a depleted carbonate reservoir with five subsea development wells. The Malampaya Phase 2 Project that concluded in Q2 2013 involved drilling two new infill wells MA-11 and MA-12. Given the uncertainty in prognosis (Carbonate K-Phi) and the greater risk of not securing wells with high deliverability as per the well objectives, it was decided to use some form of near wellbore stimulation to bypass the near well bore damage zone caused by cement losses and cuttings lost to the formation while drilling the 300 m reservoir section. Propellant perforation technology solution was selected based on optimization of rig time, ineffectiveness of acid jobs in a karstified, fractured carbonate and process safety considerations of acid handling on a dynamically positioned rig. 200 m reservoir section was perforated safely and successfully with 3–3/8″ propellant perforation gun with 30% propellant loading on a 2″ coiled tubing in each of these two subsea wells. A standard 6 SPF shot density and 60 degree phasing was adopted with deep penetrating charges to bypass the damage zone suspected from drilling and cementing losses in this depleted carbonate. Both the wells delivered finally in excess of 100 MMscf/day during the well test on the rig as expected. This paper outlines the expected vs. actual well performance; process safety due diligence with an elaborate modeling focus on the worst case scenario (i.e. no cement behind the 7″ liner). Static and dynamic coil modeling results are shared along with an overview of the transient modeling conducted to optimize the final perforation interval on both the wells based on the actual lithology information.
Castellini, Alexandre (Chevron ETC) | Vahedi, Arman (Chevron Australia Pty. Ltd.) | Singh, Updesh (Chevron Australia Pty. Ltd.) | Sawiris, Ramzy Shenouda (Chevron Australia Pty. Ltd.) | Roach, Thomas (Chevron Australia Pty. Ltd.)
This reference is for an abstract only. A full paper was not submitted for this conference. Abstract Description The paper presents a method to tackle complex inverse problems where highly non-linear responses are involved. Geological models are built within an experimental design framework and are characterized by an objective function that estimates the quality of the history-match. The goal is to efficiently find combinations of parameters that minimize the objective function. Genetic algorithms are the main optimization tool in the workflow. In order to reduce the number of actual simulations and to accelerate the overall procedure, non-linear response surfaces, built with kriging interpolants at each iteration of the optimization routine, filter out unnecessary combinations of parameters. The models that reasonably honor the historical data are selected via cluster analysis techniques and provide an estimate of future production. The final distribution of the prediction variables defines the range of uncertainty conditioned to production history. Application The practicality of the workflow is demonstrated on the Malampaya field, a Gas Condensate reservoir in the Philippines. The field is a Tertiary Carbonate build-up situated offshore, below 800–1200m of water. It has been supplying gas from five subsea production wells since 2001 to three Gas-to-Power plants. Available subsurface data include a high resolution 3D seismic survey, five production wells with downhole pressure gauges and six appraisal wells with wireline and borehole image data, pressure and well test data. Results The strategy ensures multiple and significantly different history-matched models that provide estimation of the future performance of the reservoir. The coupling of space-filling sampling strategies, optimization algorithms, non-linear response surfaces and high performance computer clusters proved efficient in addressing the issue. In addition to a robust assessment of ranges in production forecast, representative P10, P50 and P90 individuals were selected from the portfolio of models for further analysis including optimization of development plan. Significance Understanding the impact of subsurface uncertainties on production responses is an integral part of the decision making process. A more accurate quantification of the uncertainty band around production forecasts contributes to better business decisions. Traditional experimental design workflows might be well suited for new field developments. However, when a field has been produced for several years, all models have to be conditioned to available production data in order to obtain meaningful predictions. This paper addresses the limitations of conventional techniques and provides a practical, structured workflow to reconcile the processes of data integration and uncertainty assessment.
Vahedi, Arman (Chevron Australia Pty Ltd) | Gorgy, Faryar (Chevron Australia Pty Ltd) | Scarr, Kynan David (Chevron Australia Pty Ltd) | Sawiris, Ramzy (ChevronTexaco Australia Pty Ltd) | Singh, Updesh (ChevronTexaco Australia Pty Ltd) | Montgomery, Paul (Chevrontexaco Australia) | Clinch, Simon (ChevronTexaco Australia Pty. Ltd.) | Sawiak, Angela (ChevronTexaco Australia Pty. Ltd.)
Overview of Malampaya Field: The Malampaya-Camago Gas-Condensate field is a Tertiary Carbonate build-up that is situated offshore to the northwest of Palawan Island (Philippines) below 800–1200m of water. It was discovered by Occidental in 1989 (Camago-1) and is operated by Shell (45%) with Chevron (45%) and the Philippines National Oil Company (10%) as equity partners. The field has been supplying gas from five subsea production wells since late 2001 to three Gas to Power plants on Luzon Island. Available subsurface data include a 2001 high resolution 3D seismic survey, five production wells and six exploration/appraisal wells with wireline and borehole image data, including spot core in selected wells, pressure and well test data. A schematic of the Malampaya gas to power project is shown below. Overview of Experimental Design (ED) Methodology An extensive reservoir characterisation study was carried out by Chevron on a non-operated asset in 2004 to determine gas-in-place and reserves distributions. This paper outlines the Experimental Design (ED) methodology used in the study which using material balance models integrated the static and dynamic reservoir uncertainties with the excellent reservoir pressure history data that exists for the field. The methodology incorporated a unique and "state-of-the-art" method for screening over 20,000 reservoir realisations to allow only those realisations that showed a close match to the pressure history to be included in the generation of GIIP and reserves distributions. This aspect of the ED methodology proved to be very powerful in generating reserves distributions in a "hands-off" approach without the requirement for traditional manual adjustment of reservoir parameters to get a "history match".
Abstract A fundamental problem with the characterization of fractured reservoirs is that there is a scale of structure that is difficult to identify - that between fractures detected in the well bore and faults/fractures interpreted from seismic. A new workflow for structural characterization is presented here based on the application of Shell's proprietary software:-Van Gogh" filtering for the highlighting of structural discontinuities from 3D seismic, called Stopper-Voxels, FaultWorld" for analyzing the Stopper-Voxels, for characterisation and modelling of fractured reservoirs. The result is several field-wide discrete fracture/fault scenarios, based on detection rather than prediction. Introduction Stopper-Voxels are representations of discontinuities generated from 3D seismic and can, in some circumstances, be related to faults and fracture zones. The larger connected Stopper-Voxels typically represent faults, which can be confirmed by displaying with the seismic; however, the smaller bodies may represent fractures, with no easily discernible offset. FaultWorld is used to dissociate true structural discontinuities within the 3D seismic data from artificial discontinuities, whilst SVS is used to establish correlation of Stopper-Voxels with other data. Stopper-Voxels have been generated over two carbonate fields, the Malampaya Field in the Philippines (see Figure 1), a Miocene age carbonate build-up, and a giant Shuaiba reservoir in the Middle East. In Malampaya, Stopper-Voxels are used to:-pick faults semi-automatically provide a basis for fracture scenarios within the carbonate reservoir assess the connectivity of the water and gas legs via the oil rim, which would have implications for future gas development. Furthermore the Malampaya Field provides a unique example of the validation of Stopper-Voxels as structural discontinuities rather than artificial discontinuities, because the same features are detected and co-located in two different vintages of seismic surveys, which have different acquisition directions. In the Middle Eastern field the combination of Van Gogh, FaultWorld and SVS technologies enables us to quickly differentiate features in the 3D seismic related to sedimentary processes from those related to faults. Further fracture detection work, following the Malampaya integrated approach, is recommended as accurate and reliable fracture detection has obvious benefits for water flood and EOR projects, which are becoming increasingly relevant for many Middle Eastern countries.
Buchner, B. (Maritime Research Institute Netherlands) | Loots, G.E. (Maritime Research Institute Netherlands) | Forristall, G.Z. (Shell International Exploration and Production Inc. ) | van Iperen, E.J. (Shell International Exploration and Production Inc. )
ABSTRACT The concrete Gravity Based Structure (GBS) is an attractive concept for shallow water oil and gas developments. The present paper discusses 3 subjects related to the concept:Wave amplification by the large elements of a GBS causes significant problems in setting deck elevations. Physical model tests have usually been required for accurate results. Linear diffraction theory combined with second order simulations of crests heights gives predictions of crest heights with useful accuracy. The simulations tend to be somewhat conservative since they ignore the effects of wave breaking. The hydrodynamics of LNG carriers moored to GBS type structures are complex: this relates to the multi-body interaction in the wave forces, added mass and damping, but also to the drift forces in shallow water. With an optimum orientation of the GBS, a shielding can be achieved for the moored LNG carrier, reducing the weather downtime. However, a wave field still exists behind the GBS due to diffraction, which depends on the wave direction and wave period. For some motions (such as roll) there is very little shielding. A GBS used as an LNG terminal will be oriented to shelter the carriers from the dominant sea direction. The survival conditions will often be beam to the GBS as well. This means that the wave run up and possible green water on the deck of the GBS is a problem that needs serious evaluation. With the improved Volume Of Fluid (iVOF) method it is possible to simulate the run up again the side of a GBS. INTRODUCTION A concrete Gravity Based Structure (GBS) for offshore oil production usually consists of a base caisson supporting several vertical columns which in turn support a deck containing productions facilities. A GBS has many advantages when used in the proper situations. Some of the first were built for deep water fields in the Norwegian sector of the North Sea. The Troll platform in 303 m water depth remains the tallest object ever moved over the face of the earth. The Norwegian fjords provided a perfect and almost unique location for the construction of these platforms. Their deep, sheltered waters allowed for slip-forming the columns as they were gradually ballasted lower in the water. Soils in the Norwegian sector were strong enough to support the massive structures and their mass is sufficient to resist the overturning forces caused by environmental loads. Since the base of a GBS is large, it is easy to adapt it for oil storage. Production can then be stored until a load large enough to fill a tanker is accumulated. This method of transportation can be the most cost effective solution in remote areas far away from existing pipelines. Figure 1 Gravity Based Structure as LNG import terminal (Available in full paper) Malampaya is a good example of the advantages of a GBS in shallow water (Chudacek et al., 2002 ). The Malampaya gas field is actually in water about 820 m deep, but the production is sent from the subsea wells by pipeline to the GBS in 43 m depth where it is processed.
Abstract Conventional 3-D seismic mapping is not an ideal predictive method when attempting to characterise carbonate reservoirs due mainly to the complexity and heterogeneity of carbonate systems. In carbonates, the combined effect of variations in depositional facies and diagenetic alterations plays a key role in controlling variations in sonic velocities and thus in acoustic impedance. As seismic facies are delineated by acoustic impedance contrasts, the depositional facies may be rather poorly defined for various carbonates environments (e.g. shallow-water platform carbonates). Accurate 3-D imaging of seismic facies and geometries is critical to construct a realistic, seismically constrained reservoir model. 3D image-processing techniques of stacked and migrated data incorporate all three dimensions, which when combined help to identify/highlight events of significance in the data. The result is an attribute cube or volume that can be analysed and interpreted more objectively by the interpreter than the conventional horizon-based interpretation. We have applied various 3-D image-processing techniques to produce filtered seismic reflectivity data and volume attributes to better visualise and delineate seismic facies, geometries and the structure of heterogeneous carbonate reservoirs. Image filtering techniques were applied to improve signal-to-noise ratios and to suppress random noise to obtain a better reflection definition. Combined volume dip and azimuth was calculated from the seismic cubes to detect subtle stratigraphic features such as low-angle progradation units and shoal-type mounded seismic facies in the Permian Khuff and Upper Cretaceous Natih E reservoirs. Semblance volumes were used to highlight reflection terminations and helped to distinguish between stratigraphic and structural features. Texture mapping was applied to 3-D attribute-generated volumes to extract different seismic facies and properties, which can be related to potential good reservoir zones in the Malampaya field. 3D visualisation tools were used to image both horizons and faults of a complex inverted structure of a deep Upper Cretaceous lacustrine carbonate reservoir in the Yacoraite Fm. Argentina. Seismic facies and geometries interpreted from the attribute analyses, combined with interpretation of the original seismic and core/log data, allowed us to construct robust structural and depositional models of carbonate environments that were used as input for static reservoir models. Approach To better image and interpret heterogeneous carbonate reservoirs we have approached the data analysis in two different ways. The first approach is to improve the signal-tonoise ratio of the seismic data so that the traditional horizonbased interpretation method can be better followed. This may be realised, for example, by applying noise reduction techniques to improve the quality of the seismic data or by making depositional geometries explicit rather than implicit features. The second approach is to highlight specific geological features that have a three dimensional extent, and a geometry of which may have little in common with the orientation of the 3-D grid of seismic data. For example, in an environment of hydrocarbon-bearing shoal complexes, there is an immediate focus to the interpretation by initially isolating high amplitude mounded-like structures within the dataset. With both these approaches, combined with well calibration, it is possible to speed up the interpretation process (both in absolute and user time), limit the potential model-bias of an interpreter, and improve the quality of the interpretation. The results show that the use of 3-D visualisation and processing methods dramatically improved the quality of the seismic data resulting in an essential predictive tool for carbonate reservoir characterisation.
Abstract The Malampaya field development comprises subsea wells in 820 metres water-depth producing via a subsea manifold and two 16 inch diameter inconel clad flowlines to a shallow water platform 30 km distant. Condensate is removed on the platform and the dry gas is then transported via a 504 km long 24 inch export pipeline to an onshore gas plant at Tabangao (Batangas, Luzon Island) for extraction of H2S. The condensate is stored in the platform from CGS caisson prior to export via a short 3 km long 24 inch diameter pipeline and CALM buoy (Fig. 1). A digital process automation system with FOUNDATION? Fieldbus devices is used to support the Malampaya project goals 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 as the technology for the Process Automation System (PAS) both offshore and onshore, since Foundation Fieldbus technology offers better measurement, more robust process control and remote diagnostics for field devices, The project requirements pushed the envelope of the existing host system functionality and an extensive development programme was jointly agreed with the system supplier in order to meet the project requirements. This paper will address the experience gained in applying Foundation Fieldbus in the execution of the Malampaya Development and provide some pointers for future Projects wishing to apply this technology on a similar scale. Introduction The selection, nearly four years ago, of FOUNDATION? Fieldbus for the control communications for the Malampaya Project was recognised at the time as providing significant technical challenges to the engineers and designers of Shell Philippines Exploration B.V. (SPEX) and their contractors. The benefits to be gained however were seen to be worthy of the challenge and Foundation Fieldbus technology was therefore selected for the Malampaya Project. The Malampaya offshore platform accommodates an installation control center, which is intended to have the minimum of manning during the day and normally remain unattended at night, allowing platform personnel to perform combined roles of maintenance and operations assistance, as necessary. The onshore gas plant (OGP) and the offshore platform Process Automation System (PAS) are connected via a 512 kb/sec satellite link, forming a wide area network (WAN) to share data (Fig. 2). The automation system at the OGP is capable of monitoring, control, and operational managementof all essential functions, both offshore and onshore. In addition to its measurement, control, display, and alarm capabilities, the PAS supports the full functionality of an asset management system, enabling the remote instrument calibration, diagnostics, and troubleshooting possible with FOUNDATION Fieldbus devices.
Abstract The Malampaya field development comprises subsea wells in 820 metres water-depth producing via a subsea manifold and two 16 inch diameter inconel clad flowlines to a shallow water platform 30 km distant. Condensate is removed on the platform and the dry gas is then transported via a 504 km long 24 inch export pipeline to an onshore gas plant at Tabangao (Batangas, Luzon Island) for extraction of H2S. The condensate is stored in the platform CGS caisson prior to export via a short 3 km long 24 inch diameter pipeline and CALM buoy. The Malampaya Onshore Gas Plant (OGP) at Batangas is a vital part of the overall Shell Philippines Exploration B.V. (SPEX) Malampaya Deep Water Gas-to-Power Development. The plant 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 project awarded the main Engineering Procurement and Construction (EPC) contract ahead of final design optimisation. To ensure an optimised design and to reduce cost without scarifying the functional requirements, the project executed a Value Engineering exercise prior to start of detail design. The exercise not only resulted in a reduction of overall cost of20%, it also produced a better design. In addition to discussing the benefits gained through the Value Engineering process, this paper will address the fast track nature of the Project and the application of the conceptof Flawless Start-Up to meet the tight schedule. This involved the necessary up front work in detailed engineering, procurement and construction, as well as commissioning, start up planning and risk analysis to support a short and trouble free start up. The paper also addresses key aspect of HSE management in construction and start up for this green field project in Batangas, Philippines. The OGP executed some 11.3 manhours without a Lost Time Incident (LTI) utilising mainly local, in most cases unskilled, labour. The project was also certified to ISO 14001 from start of construction and through until start up and full operation. Introduction The OGP facilities are designed to take the sour dehydrated gas from the Malampaya gas export pipeline, which lands at Batangas and process up to 500 MMscf/d of natural gas. The treated gas feeds three power stations with a cumulative capacity of 2700 MW of electric power for domestic consumption (Fig. 1). The OGP 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.
Abstract The Malampaya field development in the South China Sea comprises subsea wells in 820 metres water-depth producing via a subsea manifold and two 16 inch diameter inconel clad flowlines to a shallow water platform 30 km distant in 43metres water-depth. Condensate is removed on the platform and the dry gas is then transported via a 24 inch diameter, 504km long export pipeline to an onshore gas plant atTabangao (Batangas, Luzon Island) for extraction of H2S. The condensate is stored in the platform concrete gravity structure (CGS) caisson prior to export via shuttle tanker from a catenary anchor leg mooring (CALM) buoy located 3km from the platform. Two umbilicals are installed between the Malampaya platform and the ten slot subsea production manifold. Each umbilical provides methanol injection, annulus vent service and electric and hydraulic control. The dual umbilical solution for Malampaya is perhaps unique in that the cross sections are identical and the system design features redundancy within each umbilical and between the two umbilicals. The services are routed subsea to facilitate safe isolation and permit limited production in the event that all services in one umbilical are not available. This availability objective was driven by the high priority placed on cost effectively minimizing downtime across the entire system and the discipline to concentrate on lifecycle cost rather than capital expenditure (this subsea development is the sole source of gas to a major electrical power generation network and downtime is a major concern). The majority of steel tubes in the cross section were required for methanol service to the subsea manifold for injection at the manifold headers and the trees. Unlike common methanol injection lines for hydrate prevention, the tubes were required to transport regenerated methanol with potential H2S carryover from the produced gas stream. To prepare for the installation campaign in a region with minimal supporting infrastructure, contingency planning was emphasized and included an onshore full scale evaluation of vessel tensioner holding capacity in order to safely increase the operating envelope of the vessel lay spread. The paper concentrates on the numerous challenges associated with design and logistics; material selection, the novel procurement strategy for steel tubes, delivery logistics for 768km of tubes, the extensive welding campaign and the remote installation. Introduction The service requirements for the Malampaya subsea umbilicals were to support the five Phase I subsea wells plus a contingency sixth well with redundancy for all services. Table 1: Umbilical Service Requirements (SCM: Subsea Control Module)(Available in full paper) Malampaya required dedicated methanol injection to each subsea xmas tree and both manifold headers for hydrate inhibition. Methanol is regenerated on the platform and contains up to 70ppm H2S. Annulus vent service was required for xmas tree annulus monitoring/maintenance, hydraulic service for valve control and power/communications for the subsea control system.