04 Project Details

PYRENEES DEVELOPMENT - WA-155-P, WA-12-R 25

Project details 44.1 Introduction

This chapter describes the proposed development in sufficient detail to allow an understanding of all stages and components, and to assist in determining the associated environmental impacts.

Throughout this chapter, various references are made to specific equipment, practices, and technical terms used through the industry. Many of these have been included in the Glossary at the end of the document, to provide the reader with more detail.

The following description of project details describes the proposed development as well as is currently possible. Some details are firm, while for others further information is required and decisions on these are yet to be made. In the case of the latter, a range may be provided to cover possible options. Where a range of alternatives is proposed, the assessment of environmental impact (presented in Chapter 6) has included consideration of the full range of alternatives.

For the purposes of the approval process, BHP Billiton has nominated two areas; the Pyrenees Development Area and the Notional Development Area (refer to Figure 4.1). The surface components associated with the proposed development of the Pyrenees hydrocarbon reservoirs including the FPSO, riser turret and mooring will be located within the Pyrenees Development Area. The Notional Development Area encompasses the Pyrenees Development Area and several locations that are considered to be prospective for hydrocarbon deposits. Should future activities result in the discovery of economically viable oil fields within the Notional Development Area, or other known fields within the Notional Development Area

be appraised as economically viable, then production wells and potentially water and gas re-injection wells, will be drilled into the fields and these will be linked back to the Pyrenees production facility by installed flowlines.

Environmental management of the proposed development will be implemented through a Health, Safety, Environment and Community Management System (HSEC-MS). The HSEC-MS is described in Chapter 8, and includes a discussion of the environmental principles on which the proposed development will be managed.

4.2 Summary of project details

The major features of the proposed development concept are that there will be a single FPSO vessel receiving reservoir liquids (oil and water) and associated gas from the Pyrenees field. The FPSO will be able to disconnect and sail away, for example, prior to a cyclone arriving. On the FPSO, crude oil will be separated from the water and gas, and stabilised crude oil will be temporarily stored in the FPSO cargo tanks and then transferred to trading tankers. Under normal operating conditions, produced water will be re-injected into the oil-bearing reservoir, or other suitable reservoir. Surplus gas will not be routinely flared, with re-injection of surplus gas for disposal into a suitable geological formation.

Wells will be drilled using a Mobile Offshore Drilling Unit (MODU) similar to that used to drill previous exploration and appraisal wells in the area (Figure 4.2).

Figure 4.1: Location of Proposed Pyrenees Development

PROJECT DETAILS

DRAFT ENVIRONMENTAL IMPACT STATEMENT 26

With the exception of drilling and well construction activities, and some offshore activity associated with installation, hook-up and commissioning, virtually all components of the proposed development will be fabricated and assembled away from the proposed development location. Typically only IHUC activities are required at site prior to commencement of production.

The production process is expected to have the design capacity to treat up to 15,100m3/day crude oil, which will be directed to the FPSO tanks for storage. Crude oil will be exported from the FPSO onto trading tankers approximately once every 5 to 10 days initially, becoming less frequent as production declines over the life of the proposed development.

Waste management from the proposed development will give priority to the prevention and minimisation of waste materials. Under normal operating conditions produced water will be re-injected into a proven reservoir. It is estimated that this can be achieved more than 90% of the time. If the re-injection system is unavailable, produced water will be discharged to the ocean at oil-in-water concentrations below the limits that are required by law (24 hour average less than 30mg/L, maximum less than 50mg/L). To ensure compliance with regulations the oil-in-water concentration will be measured constantly by an electronic meter whenever produced water is discharged overboard.

Surplus gas will not be routinely flared, although flaring may be necessary during commissioning, initial production, production re-starts, maintenance, process upsets and equipment down-time. The FPSO will have a safety flare system, which is a normal design feature

of offshore oil and gas facilities. Re-injection of surplus gas for disposal will be into a suitable geological formation.

Greenhouse gas emissions from the proposed development will be mainly associated with combustion of fuel gas used to provide power generation for the facilities. The highest rate of release of greenhouse gases is likely to be during the commissioning period, before gas re-injection systems are fully operational. Following this, the emissions profile is expected to be relatively flat, with emissions in the order of 162,000 t/year CO2eq over the life of the proposed development. The decision not to flare surplus gas will result in an approximately 30% saving of potential greenhouse gas emissions compared to a base case that includes flaring of surplus gas.

Decommissioning will be carried out at the end of the field life, in accordance with prevailing legislation and industry best practicable technology and practices at that time. The aim will be to decommission production facilities, abandon operating areas, and leave sites as near as practicable to their original condition. The proposed use of an FPSO that can be easily removed will help meet this aim.

4.2.1 Hydrocarbon reservoirs

The Pyrenees Development consists of five separate fields, these being, Crosby, Ravensworth, Stickle, Harrison and Moondyne. The fields are located in close proximity to each other some 25km northwest of North West Cape, in northern Western Australia (Figure 4.1). The fields are in deep water, the water depths across the fields range from 180 to 220m, and the reservoir is approximately 1,200m below the seabed. The Pyrenees Development is estimated to contain recoverable hydrocarbon reserves in the order of approximately 20 million m3 (125 million barrels) of crude oil at the most probable (P50) level.

In addition to these discovered fields, there are a number of other exploration prospects near the proposed development area that have either not yet been confirmed by drilling or economically evaluated.

4.2.2 Development approach and timing

Based on the results of the feasibility studies, a phased approach to the development is being taken. Phase 1 of the Pyrenees Development consists of:• Drilling of 13 of subsea production wells into the Ravensworth,

Crosby and Stickle oil reservoirs

• Drilling of 3 wells for the injection of water and 1 well for surplus gas

• Installation of subsea wellheads and flowlines to carry the reservoir fluids and natural gas from the wells to a FPSO vessel, and water and gas back to injection wells

• Installation of moorings

• FPSO installation, commissioning and production

• Export of crude oil from the FPSO to trading tankers

• Decommissioning of the facilities at the end of field life.

Phase 2 consists of drilling of additional production wells and linking other fields within the Notional Development Area back through subsea manifolds and flowlines to the Pyrenees production facility (a process referred to as ‘tie-back’).

Figure 4.2: Example a Semi-Submersible Mobile OffshoreDrilling Unit


The Pyrenees Development could start operating in 2008, with a field life of approximately 20 to 25 years. Future tie-back opportunities (that is subsea connections of new fields within the Notional Development Area to the FPSO using flowlines) that may potentially occur would extend production life of the facilities beyond this time.

An indicative high-level schedule for the proposed development is shown in Figure 4.3.

4.2.3 Costs and revenue associated with the proposed development

To achieve full production capacity for Phase 1 (Pyrenees Development Area), and then potentially for Phase 2 (tie-back of other field, or fields within the Notional Development Area) of the proposed development, capital expenditure in the order of AU$1 to 2 billion will be required.

The annual operating expenditure for the proposed Pyrenees Development would be in the order of AU$50 million per year with an expected field life of 20 to 25 years. Should future tiebacks eventuate then the capital expenditure would increase proportionally and field life may extend.

Based on the predicted volumes of oil for Pyrenees, and assuming an historical average oil price, oil sales from the proposed development can be estimated. Predicted oil sales range from AU$4 to 7 billion over the life of the proposed development.

4.3 Well drilling and construction

4.3.1 Summary

Drilling will be required to install the production, water re-injection and surplus gas re-injection wells. The selected drilling fluid system may either be water-based drilling mud (WBM) or non–water-based mud (NWBM), or a combination of the two. In the event that NWBM are utilised, these would be of the synthetic type. All drill cuttings

and water-based drilling fluids will be discharged to ocean. NWBMs will be recovered and returned to shore for reconditioning and reuse or disposal.

Drilling activities for the Phase One Pyrenees Development are likely to take around 12 to 18 months to complete. Should tie-back opportunities eventuate it is anticipated that production drilling associated with a Phase Two tie-back would take a similar length of time.

4.3.2 Drilling process

The wells will be drilled using a MODU like that shown in Figure 4.2. Similar MODUs have been used by BHP Billiton to drill previous exploration and appraisal wells in the area. During drilling, the MODU will be supported by two supply vessels. A MODU of the size required for the proposed drilling activity normally has a complement of 60 to 100 personnel.

Wells must be customised to suit each field and particular aspects of the development concept such as economic rate of recovery. Consequently the exact well numbers, well design (including hole diameters and lengths) and locations have not yet been finalised. It is currently estimated that 17 wells may be required to develop the field (13 horizontal producers, 3 water injectors and 1 gas injector). Future tiebacks will depend on the field size. It is important to note that as additional sub-surface information or new technology becomes available the well designs described below could change. Assurance of final well design and technical integrity will be assessed by the DoIR (acting as the Designated Authority under powers of the P(SL)A) before drilling activities commence.

Figure 4.3: Indicative Pyrenees Development Schedule

PROJECT DETAILS


4.3.2.1 Well drilling

Wells are drilled down through geological layers in sections of decreasing diameter. After setting a frame on the seabed to guide the drill bit, the first hole section, expected to be 914mm in diameter (36 inch), is drilled with the aid of seawater. Seawater and seawater mixed with a viscosifier such as bentonite (bentonite is a naturally occurring fine clay material) is used to occasionally flush the rock and sand (referred to as ‘drill cuttings’) from the hole directly to the seafloor. On completion of this section, steel casing of slightly smaller diameter, 762mm (30 inch), is inserted into the hole and the space between the casing and the hole is filled with cement.

The next hole section, 445mm in diameter (17½ inch), is also drilled using seawater, and occasionally flushed with water-based mud ‘sweeps’ to clean the hole of cuttings. The cuttings are carried up the bore-hole and discharged to the seafloor. At the design depth, drilling ceases, a casing string is then run into the well-bore from the seabed to total depth and cemented in place. At the top of this casing string, a high-pressure wellhead housing is installed at the seabed.

Once the wellhead is in position, the blow-out preventer (BOP) is installed and latched to the wellhead. The BOP is a large, emergency valve system designed to prevent any accidental escape of gas or fluids from the well. The BOP is connected to the surface by a pipe (called a marine riser). The marine riser is connected to the rig with a flexible joint that allows for rig movement on the ocean surface. This entire arrangement allows drilling mud to be circulated from the well-bore back up to the MODU and facilitates recycling of the drilling mud. Cuttings are separated from the returning drilling mud using a variety of screening and/or centrifugal processes. The cuttings are discharged to the ocean.

Drilling of the middle and lower hole sections can be controlled directionally to intersect reservoir targets some distance away from the well location. While exact hole and casing sizes have yet to be selected, the principle of decreasing hole and casing diameters as the well deepens remains. When conditions within the well, or formation pore pressure dictates, casings are installed in the well-bore and cemented in place to ensure integrity.

4.3.2.2 Completion and clean-up

Once the reservoir target has been successfully drilled and cased, an internal tubing string and Sub-Surface Safety Valve (SSSV) is installed. The marine riser and BOP is then removed and replaced with a subsea valve assembly, commonly referred to as a ‘christmas tree’. The well contents can then be flowed to the MODU for clean-up. Following this, the well is usually shut-in awaiting hook-up to the production facilities.

4.3.2.3 Drilling fluids

Wells will be drilled using drilling fluids (also referred to as drilling muds, which relates to their historical composition of water and clay solids). Drilling muds consist of a base fluid mixed with a range of additives, both solid and liquid, to produce specific mud properties. Broadly speaking, drilling muds fall into two categories; those with water as the base fluid WBMs and those with liquids other than water

as the base fluid NWBM. NWBMs can have a number of different base fluid types, each with varying characteristics. Examples include, synthetic-based (SBMs), or ester-based (EBM) drilling mud systems. Synthetic-based muds are likely to be used for lower-hole sections due to their improved performance relative to WBMs.

Drilling muds have a number of significant functions during the drilling process, including:• Exerting pressure in the well to prevent uncontrolled flow of

formation fluids, mechanical instability and cave-ins

• Forming a relatively impermeable filter to prevent mud loss

• Chemically inhibiting well-bore instability and dispersion of drilled cuttings

• Removing drill cuttings from the drill bit and transport them to surface for separation

• Suspending drilled cuttings and weighting material during extended periods without circulation

• Transmitting hydraulic power to the drill bit and down-hole tools

• Cooling and lubricating the drill string

• Inhibiting corrosion of the drill string and well-bore tubulars.

Drilling mud is mixed, stored and maintained in surface tanks (or pits) on the MODU. The mud is pumped by way of HP pumps down the well and out through the drill bit (which has holes in it), returning to the surface via the annulus between drill pipe and the bore hole or casing.

In a closed circulation system, that is after the riser has been set allowing muds to be carried back up to the MODU, the mud returns to the surface equipment where it is processed using a range of solids-removal equipment. This equipment removes a large proportion of drilled cuttings from the mud and recovers as much drilling mud from the cuttings as practicable.

Presently, the well designs for Pyrenees are too immature to select specific drilling mud systems. However, it is possible to define a range of options. Table 4.1 summarises the range of drilling muds that could be used for each particular hole section. The mud volumes are estimates only and will vary depending on the fluid selections made. Where the circulation system is open, the drilling mud (seawater and seawater based mud sweeps) is discharged directly to the seabed. Where a closed system is used and the drilling mud is recirculated, drilling mud from one section can be recovered for use in subsequent sections. At the end of a well, the entire WBM volume is discharged to the ocean. If NWBMs are used they are recovered and sent ashore for treatment and re-use or disposal. If NWBM is used a small amount of drilling mud associated is retained on the drilled cuttings, typically in the order of 10% of mud per cuttings by weight, and is washed to sea with the cuttings.

A number of additives may be used in very small amounts for bacterial control, corrosion inhibition, or to provide special mud properties as necessary for particular geological formations.


a) All Water Based Muds Per Single Producer Per Vertical injector Total Campaign (13 producers + 4 Injectors)

Hole Size (mm)

Hole TD (mMD) Mud Type Cuttings

(mT) Mud (m3) Cuttings (mT) Mud (m3) Cuttings

(mT) Mud (m3) Comments

914 271 WBM 77 84 77 84 1309 1428 8m3 bentonite pill pumped every ½ stand + sweep volume


311 1350 WBM 69 380 20 301 977 6144 0.239m3/m dilution + hole volume + 159m3 surface volume

216 2881 WBM 147 551 14 273 1967 8255 0.159m3/m dilution +

hole volume + 159m3 surface volume

Total 585 1609 403 1252 9217 25925

b) WBM and SBM Muds Per Single Producer Per Vertical Injector Total Campaign (13 Producers + 4 Injectors)

Hole Size (mm)

Hole TD (mMD) Mud Type Cuttings

(mT) Mud (m3) Cuttings (mT) Mud (m3) Cuttings

(mT) Mud (m3) Comments



311 1350 SBM 69 56 20 12 977 776 0.159m3/m dilution. All SBM transferred and re-used

216 2881 SBM 147 121 14 12 1967 1621 0.08m3/m dilution. All SBM transferred and reused

Total 585 855 403 702 9217 13923

Table 4.1: Summary of drilling mud and volumes of mud and cuttings discharged for two cases: a) all water based muds, b) water-based and synthetic based muds

WBM = Water-based Mud; SBM = Synthetic Based Mud

Figure 4.4: Schematic Illustration of Cuttings and Drilling Muds Treatment and Discharge During Drilling

PROJECT DETAILS


4.3.2.4 Drill cuttings

Cuttings are small fragments of formation rock (typically less than 10mm in diameter) removed from the bottom of the well-bore by the drill bit as the well is progressively deepened. Estimated cuttings volume for a single well are given in Table 4.1. The composition of cuttings can be predicted using lithological data from wells already drilled in the area, which have been found to consist mainly of carbonates, siltstones, claystones and some sandstones.

During the initial stages of drilling, before the marine riser is set, cuttings are carried back up the bore-hole by seawater and seawater based drilling muds to be discharged at the seabed. After the riser has been set, cuttings are carried up the riser to the MODU by circulating drilling muds. There they are separated from the mud using a variety of solids control equipment. Typical mud cuttings separation equipment includes a sequence of vibrating screens (referred to as ‘shale shakers’) that separate solids to about 100mm followed by hydrocyclones that separate solids to about 10mm and centrifuge that separates solids to about 5mm. Almost all of the drill cuttings, with the exception of very small quantities used for geological samples, are washed from the separation equipment to the marine environment via a simple chute. A small quantity of the drilling mud remains adhered to the surface of cutting particles and is washed with the cuttings into the ocean. The recovered drilling mud is recirculated through the drilling system. The industry standard practice for separating drill cuttings from drilling muds is illustrated by Figure 4.4.

Options for disposal of cuttings include:• Discharge into the marine environment

• Cuttings re-injection – this involves on-site ‘slurrification’ (i.e. addition of water to the solids to form a mixture, or slurry, which can be pumped) and injection into a suitable sub-surface formation

• Transport to shore for further treatment and disposal, often referred to as ‘ship-to-shore’.

Each option entails its own environmental effects as well as practical, technical and cost constraints. The ‘base case’ disposal option is discharge to sea. In Australia, drill cuttings from SBM are routinely discharged to ocean.

For cuttings re-injection, the cuttings are transferred from the solids control equipment to a slurrification and re-injection unit. The cuttings are ground to less than 300mm in size, usually with seawater and sometimes mixed with a simple, water-based viscosifier to prevent solids settling. A high-pressure pump is then used to displace and inject the slurry into a suitable sub-surface formation. Injection can be continuous or intermittent depending on the volume for disposal and the achievable rate. This option was not found to be feasible due to a number of technical and commercial constraints, including:• There is no suitable geological formation to re-inject the cuttings

into. The Mandu formation, which would be targeted for cuttings re-injection is extremely unconsolidated, and would allow vertical fractures at relatively low injection pressures. As there is no cap rock above this formation, re-injection could result in vertical fractures running right up to the surface, which would release cuttings onto the seabed.

• The optimal well design, based on the depth and geological constraints of the proposed development, is not compatible with current re-injection systems. Re-injection for the proposed development would require extensive research and design to develop a new re-injection wellhead system that could cope with the well design and water depths of the proposed development. This is not be commercially feasible, and introducing unproven technology would increase the risk associated with the proposed development.

For ship-to-shore disposal, cuttings are transferred via augers or vacuum tubing to skips on the rig. An alternative may include the use of bulk storage bins with transfer using flexible hoses. The skips are back-loaded to supply vessels and transported to shore for processing. Onshore processing may include various techniques, including incineration, thermal desorption, solvent extraction, ultrasonic or steam.

4.4 Installation activities

4.4.1 Summary

With the exception of drilling and well construction activities, virtually all components of the proposed development will be fabricated and assembled away from the proposed development location. IHUC are the main activities required at site, prior to commencement of production.

Installation activities could commence in the field in 2007/2008 for the Pyrenees Development. The installation of moorings, laying of the flowlines, and installation of associated subsea and surface equipment are expected to take in the order of three to six months.

There are several separate activities at the field installation site that must be completed before the FPSO is mobilised for hook-up and commissioning. These relate to both drilling and hook-up of the subsea wells and to the preparation of the FPSO mooring spread and include:• Drilling of subsea wells (refer to Section 4.3)

• Setting anchors and chain/wire lines

• Setting subsea manifolds

• Laying subsea flowlines, umbilicals, and jumpers

• Laying gas and water re-injection lines.

Following completion of these activities, the FPSO hull will be mobilised to the site and connected to the mooring. Several additional activities remain to be completed before start-up, including:• Installation of flowline risers

• Installation of umbilical risers

• Installation of riser for the gas export line

• Proof-loading of moorings

• Subsea well completions.


The spatial relationships between system components and construction equipment selection will influence the timing and sequence of these activities. The layout represented in Figure 4.5 represents a base case for discussing installation, commissioning, operation and decommissioning for this evaluation of environmental impacts and risks.

The FPSO is centred at least 1,500m from the nearest subsea well cluster and each well cluster is located for optimal distance from the reservoir that it services.

In several instances, there are at least two feasible alternative approaches for installation of components of the FPSO system – use of a designated vessel for all installation tasks, or use of multiple or specialized vessels to complete installation. Use of a specific construction vessel for installation of several components would present some advantages, but would require that activities, which might be performed in parallel, be done in sequence. Vessel availability, cost, and a number of other considerations will also influence the final selection of construction equipment. The following combinations are considered to be representative of the base-case scenario:• Mooring anchors and lines - anchor handling vessels (one or two

vessels)

• Flowlines and gas and water re-injection line – dynamically positioned pipelaying vessel

• Umbilicals – dynamically positioned cable/umbilical vessel

• Installation of manifolds, hook-up FPSO, installation of risers and hook-up of gas and water re-injection lines – dynamically positioned construction vessel.

Most activities that are carried out below the water surface will rely on electrically powered remotely operated vehicles (ROVs) to provide visual perspective and to perform certain limited work functions.

Prior to the beginning of installation work at the site, a long baseline acoustic-positioning array will be established on the seafloor. This array provides accurate navigational control for positioning objects on the seafloor and is used for both drilling and construction activities.

4.4.2 Field layout

A proposed field layout has been developed for feasibility studies. This layout, which is shown by Figure 4.5, has been used as the ‘base-case’ for description of actions and assessment of environmental impacts and risks.

The locations of wells and associated subsea facilities (wellheads and manifolds) may vary slightly from that shown depending on:• Reservoir targets (both production and re-injection locations)

• Hydraulic performance of sub-surface and subsea production systems.

Current proposal is for the surplus natural gas to be re-injected to the Macedon gas reservoir, however it is possible that facilities relating to the gas re-injection system (flowlines, injection well and associated systems) could be located outside the Pyrenees Development Area, but still within the Notional Development Area, or directed to a gas export line.

Figure 4.5: Nominal Layout of Pyrenees Development Facilities

PROJECT DETAILS


4.4.3 FPSO configuration

Production from the fields will be via an FPSO. The FPSO will be subject to the requirements of the relevant national and international regulatory and certifying authorities including:• International Maritime Organisation (IMO)

• Australian Maritime Safety Authority (AMSA)

• Western Australian Department of Industry and Resources (DoIR)

• A classification society (i.e. a member of the International Association of Classification Societies, such as American Bureau of Shipping, Lloyds, Bureau Veritas, Det Norske Veritas, or similar).

BHP Billiton have extensive experience in the operation of FPSOs on the North West Shelf and northern Australia. FPSO design will be based on the environmental conditions specified in Section 5.4.

The options currently being assessed for procuring the FPSO hull include:• A new-build FPSO

• Converting a tanker (either new or existing) into an FPSO

• Converting an existing FPSO to suit the specific field requirements.

Before being considered for service as an FPSO, any existing vessels will be subject to thorough pre-purchase inspections to ensure that the condition of the vessel is understood, and that the scope of any refurbishment work required to ensure the vessel is suitable for its intended service is clear. The vessel’s original construction, age, and service and maintenance history will also be considered during the selection process. Strength and fatigue assessments will be conducted to ensure that the hull has the required strength and service life. These assessments will consider the particular environment that the FPSO will see in service, the use of in-water survey (in lieu of dry-docking), and will provide the basis for the in-service inspection programme.

The final size of the FPSO has not been determined at this stage and storage could vary between 110,000 and 175,000m3.

The FPSO will have its own propulsion system and will be disconnectable, allowing the vessel to leave the area prior to extreme weather events or for large-scale maintenance works.

The vessel will be double-hulled which means the bottom and sides of the ship will have two layers.

4.4.4 Anchoring

The FPSO will be held on location by turret mooring and anchor systems, which also allow the vessel to ‘weathervane’ to align with prevailing environmental conditions.

The mooring lines and flexible risers are attached to a mooring buoy, which connects to the FPSO turret system. From 6 to 16 mooring lines may be used in various configurations. The lines may be a combination of chain, and/or wire, synthetic rope and elements.

The anchors are expected to be drag embedment anchors or piles. Drag embedment anchors are similar to those used by large ships, but would be considerably larger. The anchor would be installed such that

it would be deeply embedded in the seafloor following installation. Piled anchors typically comprise a small number of long, slender pipes (piles), grouped together for each mooring line. Each pile would be inserted into a drilled hole and cemented in place. The tops of the piles for each group would be connected to a small frame structure to which the mooring line is attached. Such structures would be expected to protrude 2 to 3m above the seabed.

Alternative anchor type options that may be considered include:• Gravity: A single gravity anchor installed for each anchor line (i.e.

it does not move because of its large weight). Such an anchor would be a steel-framed structure (such as a large box) that is filled with heavy material (usually iron ore), and may protrude approximately 6m above the seabed following installation.

• Suction anchors: A suction anchor is a single ‘short and squat’ round steel pile with a closed top. After embedding the bottom of the pile in the seafloor, the water that is trapped in the pile is pumped out. This forces the pile further into the seafloor. The pile would be expected to protrude some 1 to 2m above the seabed following installation.

4.4.5 Manifold installation

Manifolds are located on the seabed and connect wells to the FPSO via flowlines. They allow fluids from individual wells to be combined and flowed in common lines, and provide protection for other equipment that must be located on the seafloor. In the event that booster pumps and associated equipment are required, these will also be installed on the seabed in a manifold type structure.

Manifolds will be constructed and tested off-site. Each of the subsea manifolds will be installed on the seafloor at a location positioned near to the reservoir. In this base-case scenario, the manifolds will be installed on the seafloor by a dynamically positioned construction vessel, but support vessel outfitted with an A frame or a MODU could also complete installation of small- to moderate-sized manifolds.

Manifold configurations can vary widely, but are anticipated to be a fabricated steel framework with integral piping, valving, and controls with dimensions of approximately 6 to 9m square by 6m or more in height and weighing 2,000 to 3,000kg.

It is likely that the manifolds will have short steel extensions below the seafloor, which will penetrate the sediments and provide horizontal resistance to movement, and mats along the seafloor surface to support the weight of the manifold and provide for levelling.

Installation will be a matter of attaching lifting slings, lifting the manifold from the deck of the cargo barge and lowering it to set on the seafloor, using the acoustic positioning system to control location and orientation. Once on the seafloor, each manifold will disturb the surface sediments over an area roughly coincident with its plan dimensions (i.e. 36 to 81m2). The seafloor extensions will penetrate 2 to 3m or so below the seafloor at each ‘corner’, depending on the strength of the sediments.


4.4.6 Flowline and gas and water re-injection lines and installation

Production will flow from each subsea well through a short flowline (sometimes referred to as a ‘jumper’) to a nearby manifold. From the manifold the production will pass through flowline end modules (FEMs).

From the FEMs, flowlines (i.e. one pair for each manifold) run along the seafloor and are connected individually to flexible (lazy ‘S’ or lazy wave) production risers, which are suspended from the FPSO turret, passing through riser guide tubes within the turret cylinder, and connected at the riser termination deck on the turret.

Installation of the flowlines will be performed by a dynamically positioned lay vessel and will likely begin by lowering the FEM, with the flowline connected, setting the FEM on the seafloor within 15 to 30m of the subsea manifold and laying in the direction of the FPSO location. The end of the flowline will be terminated, lowered, and temporarily abandoned on the seafloor in the vicinity of the planned location of the lower end of the production riser, which will be connected to the flowline and installed after the FPSO mooring is in place.

The lay vessel will likely be resupplied (with material, fuel etc.) either by supply vessel or cargo barges towed by tugs.

At this stage it is not known whether stabilisation (i.e. covering to prevent movement) of the flowlines will be required. If it is required, stabilisation at the depths that occur over the proposed Pyrenees Development Area is usually achieved by placing concrete mats over the flowlines.

Following installation of a flowline, international codes and authorities require that a hydrostatic pressure test is performed in order to prove the strength and leak-tightness of the system. This test is normally a part of the pre-commissioning activities.

The hydrostatic test (hydrotesting) is performed by pressurising the flowline with water to the required pressure level, usually in the order of 25% above maximum operating pressure. At its completion, the hydrotest water will be discharged to sea from the flowline end-manifold on the seafloor, or recovered through the production process and discharged to sea at the surface. In addition to seawater or freshwater, the hydrotest water may contain a dye to aid in the detection of any leaks, a biocide, and an oxygen scavenger to prevent corrosion of the flowline.

Disturbance of seafloor sediments by both FEMs and flowlines will be limited to narrow areal corridors and shallow sediment depths. The routes selected avoid any sensitive features and problematic seafloor topography.

The gas re-injection line in this base-case scenario is assumed to run from a FEM at the bottom end of the export riser from the FPSO south to a location for re-injection within the Notional Development Area. The water re-injection line runs to the north and then east to injection points at all three fields.

As in the case of the subsea flowlines, disturbance of sediments by the deepwater portion of the gas and water re-injection lines will be limited to narrow corridors. The routes selected avoid any sensitive features and problematic seafloor topography.

4.4.7 Umbilical installation

Installation of the control umbilicals, one to each subsea manifold, will proceed in a manner similar to installation of flowlines and may be performed by a special dynamically positioned cable/umbilical vessel or by the same lay vessel which installs flowlines. Installation will likely begin by lowering a termination sled, analogous to a FEM for flowlines, with the umbilical connected, setting the termination sled on the seafloor within 15 to 30m of the subsea manifold and laying in the direction of the FPSO location. If timing is such that the FPSO is in place at the start of umbilical installation, the preferred approach could proceed by laying the umbilical in one piece, installing buoyancy to achieve the desired lazy wave riser configuration and passing the end termination directly to the FPSO, where it is lowered underwater and brought up through guide tubes in the turret, terminating on the turret deck. If this is not possible, the umbilical will be terminated in another sled and lowered to the seafloor, to be connected later to a riser termination sled by jumpers.

As in the case of the subsea flowlines and the gas and water re-injection lines, disturbance of seafloor sediments by the deepwater portion of the control umbilicals and termination sleds will be limited to narrow corridors.

4.4.8 Flowlines

Flowlines will carry crude oil, reservoir water and natural gas from the wells to the FPSO via risers, which are flexible pipes, or a combination of rigid and flexible pipes, from the seabed to the FPSO. They also transfer water and gas from the FPSO to selected wells for injection. Flowlines may be either flexible pipe or rigid steel pipe and will link each well manifold to the FPSO.

Flowlines are expected to be laid directly onto the seabed by either:• Tow spread: where a length of flowline is completely built onshore,

towed to location and lowered into position

• Specialised pipe-laying vessel: a ship that is equipped to allow pipelines to be built offshore (or onshore in the case of a reel laying vessel) and laid in place.

4.5 Hook-up and commissioning

Once wells have been completed, subsea wellheads are in place and the mooring and riser turret are installed, the hook-up of flowlines, risers and other subsea connections can take place. After installation of the riser turret, the FPSO can be connected.

PROJECT DETAILS


The majority of systems on the FPSO will arrive on-site already commissioned or at least pre-commissioned. For example, the power systems will be commissioned on diesel in the integration yard prior to sailing to the field. However, there are some systems that cannot be fully commissioned until reservoir fluids first flow onto the FPSO. These may include:• Production separation systems

• Gas compression systems

• Gas re-injection systems

• Fuel gas systems

• Flare systems

• Water injection systems

• Crude storage and offloading systems.

Commissioning involves the progression of equipment and systems from mechanically complete (pre-commissioned) to a state of demonstrated readiness to operate safely. This is achieved on a system-by-system basis by:• Pre-operation integrity and functional checks (readiness to

operate)

• Controlled first introduction of process medium, flow and energy

• Subsequent checks to demonstrate correct operation, start-ups and shut-down.

This will allow gas, water and crude oil systems to become functional as an integrated process for the first time. The commissioning period is where these systems are being tested and adjusted to bring them to normal operating performance. While commissioning is taking place, discharges and emissions may be higher before steady-state

operating conditions are established. Commissioning is expected to occur over a period of approximately three months.

The FPSO will be supported in the field by at least one and possibly two supply vessels during the commissioning period. At the peak of these activities, there may be in the order of 70 personnel on the FPSO.

4.6 Production

4.6.1 Summary

The FPSO will receive oil, water and gas from the oil fields. Crude oil will be processed, stored on the FPSO and then transferred to trading tankers for export. The production process is expected to have a design capacity to treat up to 15,100m3 of crude oil per day with an expected peak crude oil production of 15,300m3/day. Figure 4.6 shows a typical FPSO (in this case the BHP Billiton operated Griffin Venture) and the arrangement of main elements thereon.

Under normal operating conditions produced water will be re-injected into a proven reservoir. Surplus gas will not be routinely flared and re-injection of surplus gas for disposal will be into a suitable geological formation.

The FPSO will be able to disconnect and sail away from the area. This will happen, for example, prior to a cyclone arriving. In this event, before disconnecting, the process equipment, wells, subsea equipment, risers and turret will be shut down and safety valves activated.

Figure 4.6: Arrangement of Main Components of Typical FPSO

Accommodation

Production Process Train

Riser Assembly

Safety Flare

Helideck

Control Room &

Double Hull


4.6.2 Oil production

Oil reservoirs are subject to a natural decline in potential production rate as oil is withdrawn. The potential production rate of Pyrenees oil field is forecast to decline from start of production, particularly as water, which is more mobile than oil in the reservoir, breaks through into the production wells. Once this happens, the production of oil to surface declines and the proportion of water increases. In the latter stages of the production profile of the reservoir, the production is predominantly water and the rate of oil recovery declines to levels that are eventually unprofitable (refer to Figure 4.7).

As production declines, spare production capacity may become available on the FPSO and if the opportunity exists, other fields may be tied-back to the FPSO while still producing the first field. The tied-back field may be able to maintain production rates at a high level for several years, and will then decline in a similar manner to the first. This process of tying-back other fields may continue until the area has been fully developed and it reaches its final economic cut-off, at which point the facilities are decommissioned. Possible phasing for the proposed development is discussed in Section 4.2.2.

4.6.3 Production process

The FPSO will receive well fluids (crude oil, reservoir or produced water, and associated natural gas) from the production wells, process it to separate the crude oil, store it on the FPSO and then transfer it to trading tankers for export (Figure 4.8).

The production process is expected to have a design capacity to treat up to 15,100m3 of crude oil per day with an expected peak crude oil production of 15,100m3/day. It is possible, however, that the FPSO may be capable of processing slightly more than this. This extra capacity is a result of two main factors, firstly using margins built into the design

of equipment, and secondly as a result of minor modifications made after start-up. The total capacity of the oil storage tanks depends on the FPSO selected, with potential storage volumes for the FPSO varying between 110,000 and 175,000m3.

At peak design production levels, the FPSO will receive between 13,000 and 15,100m3 of oil and 1.7 million m3 of gas per day from the 13 producing wells. The system will also be capable of handling a maximum of 17,500m3 of produced water per day. Production will flow through the swivel and into a process train with two-stage separation.

Each processing stage separates oil, gas, and water at successively lower pressures. The oil may pass through temporary separation tankage before being delivered to onboard storage tanks in the hull of the FPSO. Gas will be further processed to reduce its moisture content before being either used in the onboard power generation or recompressed to be used for artificial lift (gas lift) and the surplus gas re-injected via the gas re-injection line. Diversion of any of the gas production stream to the flare system will only occur in the event of equipment failure, or the need to relieve system pressure (refer to Section 4.6.6).

Produced water extracted from the production flow will be re-injected under normal operating conditions (refer to Section 4.6.4).

Monitoring and control of subsea wells will be performed from the FPSO, except when control is turned over to a MODU during workovers and recompletion activities. Continuous FPSO activities involving the subsea wells may include hydrate suppression, corrosion inhibition and flow improving (demulsifier) chemicals. These chemicals are pumped through the umbilical to the manifold and are injected into the production stream at or near the wellhead.

The characteristics of reservoir production streams vary widely, but formation sediments, and other substances will be produced with the well fluids to the surface production facilities.

The material which is removed from surface production facilities will be processed on board in order to separate the various components. Hydrocarbons will be incorporated into the production or gas re-injection streams, water will be cleaned up and re-injected, and other materials will be shipped back to shore for disposal.

Drilling and downhole workover operations that may be required after installation will be performed by a MODU. The MODU will be moored or dynamically positioned over the subsea “trees,” as is typical of other subsea development schemes, and, other than initiating shutting and restart of the wells, will not involve any activities on the FPSO itself.

4.6.4 Produced water

Produced water is the water brought to the surface from the reservoir that is separated out from the oil and gas in the processing stage. Oil-water separation systems are expected to comprise hydrocyclone and degassing units.

Figure 4.7: Predicted Crude Oil and Water Production Profiles For Pyrenees Development (Without Tie-backs)

PROJECT DETAILS


Under normal operating conditions, produced water will be re-injected into the Pyrenees oil field. It is estimated that this can be achieved more than 90% of the time. If the re-injection system is unavailable, such as during commissioning, re-injection equipment downtime and process upsets, produced water will be discharged to the ocean at oil-in-water concentrations below the limits required by law (P(SL)A and Petroleum (SL)(MoE) Regulations: 24-hour average less than 30mg/L, maximum less than 50mg/L. When produced water is discharged overboard, oil-in-water concentrations will be measured continuously using an electronic meter, to ensure compliance with regulations.

If produced water from the oil and water separators exceeds the specification for maximum allowable oil-in-water concentration for re-injection, or if the re-injection system is unavailable, produced water may initially be routed to slops tanks located within the FPSO hull where it would be subject to further separation. The recovered oil from the slops tanks would be transferred via skimming pumps to oil storage and the cleaned water transferred to the water re-injection system or discharged to sea. In the case of this water being discharged overboard, it will be monitored for oil-in-water content.

4.6.4.1 Corrosion inhibitors

Corrosion is the deterioration of a metal substance as a result of reacting with its environment. Corrosion can be controlled through the use of corrosion resistant alloys, metal coatings, or by chemical inhibition.

Corrosion inhibitors may be used on a continuous basis or selectively (e.g. during pigging operations) to establish and maintain an inhibiting film. Typical treatment dosages range between 5 and 100ppm. Corrosion inhibitors are predominantly water-soluble and under normal circumstances would be re-injected with the produced water stream.

4.6.4.2 Hydrate inhibitors

Hydrates are solid crystalline structures that form when smaller, light hydrocarbon molecules contact water molecules at elevated pressures and reduced temperatures. Hydrates can be controlled by methanol injection treatments at the tree and downhole. The methanol treatments are based upon water and total fluid production and increase as the water production and percent water increases. Note that it is anticipated that methanol injection will only be required during well start-up or to remove a hydrate due to ingress of water into the flowline system.

In lieu of methanol, hydrates can be controlled through chemical injection of monoethylene glycol (MEG) at the production tree or downhole. Glycol remains in the production stream (i.e. are not recovered during processing) and is ultimately exported with the crude oil product.

Figure 4.8: Production Operation Schematic


4.6.4.3 Scale inhibitors

Scale is the deposition of the dissolved content in a produced fluid, as a result of evaporation, variation of pH levels, or changes in pressure, temperature, or flow conditions. Scale deposition can aid in the formation of hydrates or waxes because of the localised increased roughness on the deposition surface.

Scale is commonly controlled through chemical injection of scale inhibitors. The recommended water-soluble inhibitor is formulated to prevent scale deposits such as calcium carbonate, calcium sulfate, and barium sulphate.

Scale inhibitors are typically used on a continuous basis to prevent scale deposition downhole or in production equipment. Treatment dosages, which are based on the characteristics of the crude oil and the type of scale being produced, typically range from 5 to 15ppm. Scale inhibitors and mostly water soluble and under normal circumstances would therefore be re-injected with the produced water stream. Scale inhibitors may also be used in sea water cooling systems and would therefore be discharged to the sea.

4.6.4.4 Demulsifiers and defoamers

Water is produced with the crude oil and a stable emulsion is often formed with oil as the continuous phase. Breaking this emulsion normally requires neutralising or destroying the natural emulsifying agent, allowing water droplets to coalesce (unite) into larger drops. Eventually the water settles by gravitational force; the term for this separation is demulsification.

Demulsification can be accomplished by mechanical or chemical means, or heat or by a combination of these treatments. Demulsifiers are designed to favourably alter the forces that maintain stable water-in-oil emulsions; demulsifiers are typically comprised of complex resin adducts, sulfonates, esters, ethers, and complex organic polymers.

Demulsifiers are typically used on a continuous or intermittent basis to demulsify crude oil in a production stream with dosage determined based on the characteristics of the production system being used and crude oil characteristics. Demulsifiers may be injected into the producing well fluids downhole, at the wellhead and/or throughout the surface processing facilities and remain in the production stream (i.e. are not recovered during processing).

Defoamers, or antifoam products, are used to provide foam control in the production stream. Defoamers are high molecular weight, surface-acting agents. They are typically used on a continuous basis, normally through use of a chemical proportioning pump. Typical dosages for defoamers in a continuous injection system are in the 10ppm range, however, initial ‘charging’ of the production system may occur at a higher dosage level. Defoamers remain in the production stream (i.e. are not recovered during processing).

4.6.4.5 Asphelate dispersants

Asphaltenes are heavy hydrocarbon molecules that occur naturally in crude oils. They precipitate out of the produced oil due to a change in pressure, temperature, or composition. These compounds may vary

in chemical makeup from one crude composition to the next and are commonly associated with the formation of emulsions. Asphaltenes can be controlled mechanically through pigging or through chemical injection of asphaltene dispersants (also termed inhibitors). A typical liquid dispersant consists of a polymer in a hydrocarbon solvent.

Pyrenees crude oil has low asphaltene content and it is unlikely that asphaltene dispersants will be required. However, should they be needed asphaltene dispersants are typically used on a continuous basis to prevent build up in flowlines and to prevent asphaltene pad formation in production equipment; they may also act to protect producing formations from damage due to asphaltene plugging. Treatment dosages typically range from 20 to 500ppm and are determined based on the characteristics of the crude oil, the type of system being used and the application method. Applications entail injection of dispersants down the wellbore. Dispersants remain in the production stream (i.e. are not recovered during processing).

4.6.4.6 Biocides

Biocides are used to prevent or control the growth of sulphur-reducing bacteria (the by-products of sulphur-reducing bacteria are hydrogen sulphide, which is both corrosive and toxic in high concentrations, and iron sulphide, which can interfere with oil separation) consequently they are highly toxic. To improve performance and avoid the potential for development of biocide-resistant bacteria, biocides are generally applied in short batches of a relatively high concentration rather than as a continuous dosage. The biocides that are used on the North West Shelf typically have either aldehydes or amine salts as the active ingredients. Both of these types of biocide are soluble in water and under normal circumstances would therefore be re-injected with the produced water stream.

4.6.5 Seawater treatments

Seawater is required for various purposes, including cooling of process equipment, fire protection systems, and freshwater production. Seawater treatment systems may include coarse filters to strain debris from the seawater and injection of hypochlorite (or similar biocide) to prevent the build-up of marine fouling growth on the internal surfaces of the system. Hypochlorite is the most widely used material and is normally produced onboard by electrolysis of seawater.

4.6.6 Associated gas

Gas from the reservoir will be separated from the well fluids by processing equipment on the FPSO Gas from the separators will be recompressed and dehydrated, allowing use as gas for fuel and artificial lift purposes, with surplus being available for re-injection.

Surplus gas will not be routinely flared, although flaring may be necessary during commissioning, initial production, production restarts, process upsets, maintenance and equipment down-time. Surplus gas will be re-injected into a suitable geological formation for disposal, which could be the oil bearing reservoir or another suitable reservoir within the Notional Development Area.

PROJECT DETAILS


It is possible that a very small stream of low grade LP gas might be flared continuously for the first 18 months. Consideration was given to capturing and compressing this gas for re-injection, however the energy expended in compression would exceed, and negate, any greenhouse gas benefits associated with re-injection.

Gas re-injection systems are expected to comprise coolers and vessels for recovering liquid hydrocarbons from the gas, dehydration systems and high-pressure compressors for delivery of the gas.

The FPSO will have an emergency flare system in line with normal design of offshore oil and gas facilities.

It is possible that technical advances may create other gas disposal options in the future life of the proposed development. The potential export of natural gas for sale into the domestic gas market is being considered in the longer term. Should this occur, the gas export pipeline would be subject to a separate environmental impact assessment process.

4.6.7 Ancillary systems

4.6.7.1 Power

The base case proposed development is estimated to require up to 20MW of power, although it is expected that future optimisation in facility design may reduce this. The produced water, gas re-injection systems and gas lift systems represent significant sources of demand for generated power.

Associated gas will be the main source of fuel for power generation. A fuel treatment system usually consists of pressure reduction, filtering, dewpointing and metering equipment prior to use by turbines and other fuel gas users. During the project life, fuel gas will be imported from the gas re-injection well for start-up and once associated gas diminishes below fuel gas requirements.

Electric power may be supplied by gas-turbine–driven generators. Power generation systems would also be able to use diesel and/or crude oil to generate power, if gas is not available. Various machinery, such as cranes and fire pumps, will require diesel fuel.

4.6.7.2 Cooling and heating systems

A number of process systems will require heating or cooling. The heating and cooling circuits may be based on direct or indirect systems. The current feasibility base case assumes direct seawater cooling of process streams. The temperature of returned seawater is expected to be between 40 to 60oC and the discharge rate is expected to vary between 50,000 to 100,000m3 per day.

4.6.7.3 Flare

An emergency depressuring (flare) system, also referred to as a ‘safety flare system’, will be provided in line with normal design of offshore oil and gas facilities. The safety flare is designed to provide a safe means of rapidly disposing pressurised gas from process equipment in the event of emergency or process upset. The flare system is also

required during commissioning, initial production, process restarts, maintenance, and equipment downtime. During normal operations there will be some flaring of LP natural gas during the first year of operations and a small pilot flare will be run continuously throughout life of operations as a means of ignition for the emergency flare. Surplus gas will not be flared under normal operating conditions.

4.6.7.4 Gas lift

A gas lift system will be provided to assist the flow of well fluids to the processing facilities. Gas lift assists the flow of well fluids by reducing the density of the fluids in the well tubing and flowlines and therefore decreases the gravitational or hydrostatic head pressure exerted on the reservoir. The gas lift system for the development will be comprised of piping, valving and instrumentation to control the flow of pressurised gas to each of the production wells. Gas will be continuously injected into the tubing of each well below the sea floor through a gas lift valve. This valve prevents the flow of reservoir fluids in the reverse direction into the gas lift system. The gas used in this system will be formation gas that has been separated from the well liquids (oil and formation water), dehydrated and compressed. The flowlines used to distribute the gas will be of similar type to the production flowlines. This type of artificial lift system is used extensively throughout the region.

4.6.7.5 Safety systems

BHP Billiton places a strong focus on safety management. All process systems will be designed to meet standard international, national and local industry practice. Safeguards and safety systems are designed to avoid environmental as well as safety related incidents (e.g. uncontrolled release of hydrocarbons to the environment, or escalation of an event).

Safety systems will include escape equipment, fire/gas/smoke detection and protection systems, and back-up power systems. The fire protection system will consist of passive systems (such as equipment coatings) and active systems including deluge, water, foam, CO2

Figure 4.9: Accommodation on the Griffin Venture FPSO


and extinguishers. The most appropriate system for each area will be selected based on detailed risk assessments. Ozone-depleting substances will not be used for these systems.

Safety equipment including fire pumps, emergency lighting and communications equipment, are generally designed to be completely independent and with appropriate levels of redundancy. Independent fuel or energy sources, such as diesel fuel may be used.

4.6.7.6 Navigation and communication settings

Standard marine navigation and communications systems, navigation beacons, ship-to-ship radio and anti-collision radar systems will be in place. Additional safeguards will also be implemented such as the gazetting of the FPSO onto navigational charts and creation of a safety exclusion zone.

4.6.7.7 Accommodation

Accommodation facilities will be provided for personnel required for commissioning (estimated 60 to 80 people in addition to the operational crew) and production and maintenance during normal operations (estimated 30 to 40 people), with capacity available for additional personnel during campaign maintenance (estimated 10 to 20 people). Typical living room, quarters and galley facilities are shown on Figure 4.9.

4.6.7.8 Sewage and putrescible wastes

Sewage and greywater will be disposed of in accordance with Annex IV of the International Convention for the Prevention of Pollution from Ships, 1973, as modified by the Protocol of 1978 (referred to as MARPOL 73/78) and Clauses 222 and 616 of the P(SL)A Schedule Specific Requirements as to Offshore Petroleum Exploration and Production 1999 (referred to as the P(SL)A Schedule).

Putrescible wastes will be macerated to a size less than 25mm. Sewage will be disinfected prior to disposal. Sewage or putrescible wastes will not be discharged within 12nm of land.

A sewage treatment plant meeting the certification requirements of MARPOL 73/78 will be in place on the FPSO.

4.6.7.9 Diesel and material storage

Diesel is required to fuel various safety-related and other equipment including power generation equipment, fire pumps, emergency generator, inert gas system when gas is unavailable, such as during a cyclone disconnection. The diesel storage system will be similar to that used on other FPSOs and may include a main storage tank, clean-up equipment (including filters and water removal facilities), distribution pumps, small storage tanks on critical equipment (such as fire pumps and cranes), and distribution piping.

Storage facilities will be provided on the FPSO to allow various critical and routine spares to be kept onboard. Segregated chemical storage facilities will also be provided. The types and quantities of process, utility and production-related chemicals are not yet known.

A wide variety of other chemicals may be stored and used on the FPSO, including:• Acids and solvents

• Glycol and other similar chemicals

• Surface active agents and detergents

• Demulsifiers and emulsifiers

• Defoamers

• Lubricating fluids and greases

• Hydraulic oils/fluids

• Paints

• Inhibitor chemicals (e.g. corrosion and scale inhibitors)

• Specialised cleaning fluids

• Cooling system treatment chemicals.

Periodically, the FPSO will require stocks of materials to be replenished. One mechanism that is used for the transfer of bulk materials (such as diesel fuel and process chemicals) is to transfer them via hose from a supply boat. This transfer operation is commonly known as ‘bunkering’. Equipment and procedures for bunkering are yet to be specified, and will be selected to avoid or reduce the potential for a spill. For example, unique couplings are likely to be used on the various bunkering lines to avoid cross contamination. Dry-break couplings are likely to be used to reduce the potential for liquid loss when hoses

Figure 4.10: FPSO Offloading Operation

PROJECT DETAILS


are decoupled, and procedures will be implemented that define sea-state conditions under which bunkering is permitted. An alternative method for transfer of smaller volumes (up to about 5m3) is in tote containers or drums. Tote containers have dry-break couplings on the valve assembly, which is recessed to prevent accidental impacts that may cause a release of contents.

4.6.7.10 Drains

The drainage and disposal systems include closed drains, open drains, bilge and oil recovery systems and slops tanks.

Deck drainage consists mainly of washdown water and occasional rainwater. While no wastes will be routinely discharged via deck washdown, the washdown or rainwater run-off will generally be directed overboard, and may contain small quantities of oil, grease and detergents.

Areas on the FPSO which are more likely to have small oil leaks will be directed to a sump (or similar collection system) which is in turn directly connected to an oily water separation system, such as the slops tanks. Overflow systems are also provided which may discharge directly to sea in the event of high rainfall intensities. Oil is removed from the upper part of the slops tanks by skimming pumps and the water is directed to the water injection facilities or discharged into the ocean. This discharge water stream will be monitored for oil-in-water content.

The closed drains system collects and disposes of volatile hydrocarbon liquid drained directly from process equipment for maintenance or operational reasons. Collected hydrocarbon liquids are normally pumped back to the process, but depending on contaminants, may have to be collected and sent back to shore for recycling, treatment, or disposal.

The bilge and oil recovery system generally collects waste liquids from the engine room and other machinery spaces. Liquids are processed prior to discharge or stored until disposed to a suitable reception facility.

4.6.8 Offloading operations

Given the design capacity of the processing equipment and storage potential of the FPSO, offloading operations may take place about once every 5 to 10 days in the initial high production period, and become less frequent as production rate declines. The offloading of crude oil to trading tankers is expected to use a tandem mooring system (Figure 4.10).

Arrival of a trading tanker will be scheduled well in advance to meet FPSO production and offloading requirements (see also Tanker Vetting System, Section 4.6.8.2). A qualified tanker pilot will board the trading tanker prior to its arrival at the FPSO to supervise the tanker’s approach and the offloading operation. It is currently proposed that the pilot board in the Dampier area for the passage to the proposed development location. Alternatives which may be considered include maintaining a pilot on board the FPSO, or using alternative boarding locations, such as ports on the Western Australian coast other than

Dampier. To ensure that safe operations are maintained while the trading tanker is loading, the pilot stays on board the vessel as Loading Master and shore representative. When secure, prior to loading, a full safety inspection is conducted. Once loading, repeat inspections are undertaken on a regular basis. If any safety violations occur, the pilot is fully empowered to suspend loading operations and remove the vessel from the FPSO.

When ready for offloading, the trading tanker will be met two to four km away from the FPSO by an offloading support vessel (OSV). The purpose of the OSV will be to assist the trading tanker as it approaches the FPSO, and connect mooring lines, hawser and offloading hose.

The hawser is passed between the FPSO and trading tanker and secured, and the offloading hose connected. During cargo transfer operations, a towline from the stern of the OSV to the stern of the trading tanker will connect the vessels. The purpose of this configuration is to ensure the trading tanker and FPSO remain the required distance apart and in the required alignment.

Trading tankers typically have an oil storage capacity in the order of 100,000m3. A full offloading operation is expected to last 36 to 48 hours, while the actual transfer of oil may take 24 to 36 hours. When the cargo has been transferred, the trading tanker is disconnected and sails away.

A range of procedures are implemented with respect to pilotage and offloading operations. A Terminal Handbook will be developed for the FPSO and this will list all the offloading operations requirements which will need to be met.

4.6.8.1 Offloading hose

The offloading hose is a purpose-built flexible hose, approximately 250 to 300m long, with a 400 to 600mm internal diameter. It is manufactured from heavily reinforced material and is made up of sections, each section approximately 10m in length, with flanged and bolted connections between sections. This construction allows each section to be independently tested and replaced if necessary. The material used in the construction of the hose makes it buoyant, so it is commonly referred to as a ‘floating hose’.

A ‘Quick Connect Quick Disconnect’ (QCDC) valve assembly will be on the FPSO. This assembly allows for quick disconnect of the offloading hose without any spillage of product should circumstances require it.

At the end of each offloading, the oil in the hose will be flushed onto the trading tanker with treated (biocided) seawater or produced water. This is so the hose contains water only when not in use and prevents an oil spill in case of damage to the offloading hose.

As the FPSO will be disconnectable, any move of the FPSO from the location (such as for a cyclone), will require management of the offloading hose. The offloading hose may be towed by the FPSO, towed to a safe location by the support vessel, spooled onto a large reel on the FPSO, or lifted back onto the FPSO.


4.6.8.2 Tanker vetting system

Trading tankers are obliged to meet Classification Society Rules, and are subject to regular inspections that cover various aspects of the vessel’s condition. These inspections are required on a specified and regular basis (as prescribed by Class Rules), and include structural aspects of the hull. For trading tankers, these inspection programs include a requirement for regularly dry-docking the vessel to allow the external hull to be inspected.

Before any trading tanker will be loaded at the proposed development, permission must be sought from BHP Billiton to use a particular ship. This normally takes place about 2 to 3 weeks in advance of the proposed offloading.

The trading tanker must submit a wide range of data and evidence for assessment including facility compatibility, inspection status, and safety and environmental aspects, including:• Compatibility: engineering aspects of the vessel that allow it to

be loaded at the FPSO including draught, manifold configurations, manoeuvring and mooring aspects, and ability to safely navigate

• Inspection status: a satisfactory physical inspection of the vessel must have taken place within the last 12 months by a certified Oil Companies International Marine Forum (OCIMF), Ship Inspection Report Programme (SIRE) inspector

• Certification: all certification has to be in place and all relevant international conventions must be complied with including current International Safety Management certificate, MARPOL and classification society registration (such as American Bureau of Shipping, Lloyds, or similar)

• Insurance: satisfactory oil pollution cover must be held.

BHP Billiton uses a comprehensive shipping database to assess ships. The principal database contains records of over 6,000 vessels and utilises a large range of tools to assess ships including:• Casualty record

• Class history

• Flag history

• Operational performance

• Owner audits

• Port state inspections

• Ship operator assessment

• SIRE inspections

• Structural analysis

• Terminal feedback.

The OCIMF also maintains a database to which major oil companies contribute inspection reports. The use of both these databases ensures that the most current inspection information is available to assist in the assessment process.

4.6.9 Support services

4.6.9.1 Vessels

An OSV similar to that shown in Figure 4.11 will provide support for the pilotage operation, static tow support and oil spill response. Offloading support vessels are normally crewed by between 5 and 10 personnel. The vessel will most likely work out of King Bay Supply Base in Dampier, but may occasionally visit other ports in the area. The vessel will attend all offloading operations, and due to the initial offloading frequency will probably remain in the area when production rates and offload frequency are highest. When offload frequency decreases, the opportunity to utilise the vessel in other operational areas will be explored. The vessel may also be available to carry out ad hoc supply runs, although the main supply role will be conducted by existing supply vessels currently in use for the Griffin Venture. These arrangements are similar to those used at FPSO terminals worldwide.

4.6.9.2 Helicopters

A helideck and associated equipment will be provided to meet standard offshore facility requirements for the transfer of personnel and supplies. Helicopter fuel storage on the FPSO is not envisaged.

4.6.10 Workovers and additional wells

It is anticipated that the production wells will periodically require work that necessitates a drilling rig re-entering the field and working over existing wells. Additional wells may also be required over the life of the project to develop other fields within the proposed development area and/or to further exploit fields that are already linked to the FPSO.

Figure 4.11: Offloading Support Vessel

PROJECT DETAILS


Both work-over wells and drilling of additional wells would use similar processes and facilities as described for development drilling.

4.6.11 Cyclone and extreme weather response

BHP Billiton has been conducting exploration and production operations in cyclone-prone areas for more than 30 years. During this time, detailed cyclone contingency plans have been developed for the safety of personnel and the protection of facility integrity and the environment. These plans are periodically updated as new meteorological and oceanographic data are obtained.

A cyclone contingency plan will be developed for the proposed development. Cyclone contingency plans provide detailed guidance to protect personnel, environment and assets in case of a cyclone approaching a facility and contain the following information:• Cyclone warning status: blue, yellow and red alert are based on

associated weather conditions, distance from the facility and estimated time for the cyclone to affect the facility

• Cyclone category: Category one to five are based on weather conditions (e.g. wind speed) associated with the cyclone.

Preparation activities including:• Tasks required to keep the facility in a state of readiness in case

a cyclone develops, e.g. ensuring adequate fuel is onboard

• Tasks required based on distance of a cyclone from the facility (e.g. storage or tie down of certain items)

• Critical tasks including down-manning if necessary, checking of propulsion and steering equipment, shutdown of production and disconnection

• Cyclone monitoring.

Communications including:• OSVs

• The trading tanker(s) which are in the field or may be approaching

• MODUs which might be in the field

• Helicopter operator

• Fixed wing aircraft operator

• Reconnection activities.

The capability of the facilities to withstand extreme weather events is assessed by BHP Billiton engineering studies to meet regulatory requirements including P(SL)A requirements, and verified separately by an independent agency, such as Lloyds of London or the American Bureau of Shipping.

The likely wave height and period of a tsunami in the Pyrenees Development Area falls within the range of extreme weather conditions that are included in the design criteria for the development (Section 5.2.1.4). The proposed development will be designed to meet 100-year non-cyclonic storm surface currents of greater than 1m/sec; consequently, tsunamis are not an engineering risk in deep water.

The most direct threat of a tsunami that may affect the Pyrenees Development Area is the Sunda Trench plate subduction zone bordering southern Indonesia. Travel time for a tsunami from the Sunda Trench to the proposed development area is of the order of two hours. As such, an effective early warning system is not feasible. However, given the negligible impact of a tsunami on the proposed development, an early warning system is considered unnecessary.

4.6.12 Safety exclusion zones

Underwater obstruction from the array of mooring lines will range from 30 to 60m below the water surface in the vicinity of the FPSO to the seafloor at a radial distance of about 1,000m or more.

Production risers, umbilicals, and the produced water and gas re-injection lines hang almost vertically under the FPSO to a depth of 100m or more, flaring horizontally into a lazy wave and intercepting the seafloor several hundred metres from the FPSO location.

The produced water and gas re-injection lines, flowlines, and umbilicals will be at the seafloor for most of their length. Jumpers to the manifolds may extend as much as 3m above the seafloor.

The four subsea manifolds and 17 subsea wellheads may extend 6 to 9m above the seafloor.

A gazetted safety exclusion zone restricting the access of vessels will be sought under the P(SL)A to provide protection for the facilities and equipment in place for the proposed development. The safety exclusion zone will extend for 500m from the outer edge of the FPSO, flowlines, wellheads and other subsea equipment. All vessels will be prohibited from entering the safety exclusion zone under P(SL)A (s.119), unless they have the consent of the Designated Authority.

4.7 Decommissioning

Decommissioning will be carried out at the end of the project, in accordance with prevailing legislation and industry best practicable technology and practices at that time. The aim is to decommission production facilities and abandon operating areas to leave them as near as practicable to their original condition. The proposed use of an FPSO that can be easily removed helps meet this aim.

The sequence of decommissioning includes:• Shutting down of production processes

• Flushing of risers, flowlines and subsea facilities

• Plugging and abandonment of wells

• Disconnection of the FPSO and movement from the location.

It is expected that decommissioning will include removal of most structures above the surface of the seabed, including flowlines, manifolds and moorings for the FPSO. The time of decommissioning is unknown. A detailed decommissioning plan will be prepared and submitted to the relevant authorities prior to commencement of decommissioning activities.


4.7.1 Wells

Decommissioning of wells will be planned to achieve the following objectives:• To isolate formation fluids from each other

• To isolate formation fluids from the surface

• To leave the seabed clear of obstructions.

Wells will be decommissioned in accordance with all regulatory requirements in place at the time of decommissioning and with consideration of the best environmental outcomes.

It is intended to leave any remaining drilled cuttings in place.

Decommissioning and suspension of wells is currently regulated via Section 107 of the P(SL)A, and P(SL)A Schedule. The DITR, as well as APPEA1, have developed guidelines for the decommissioning of offshore petroleum facilities.

4.7.2 Seabed structures

It is expected that decommissioning will include removal of structures on the surface of the seabed, including flowlines, manifolds, and moorings for the FPSO. Where pile-driven foundations are used, all mooring systems above the seabed will be completely removed with only the anchor piles remaining. Gravity box moorings will be left in place. Due to the depth of the project area (180 to 220m) it is not expected that these moorings will cause any obstruction to navigation or future uses of the area.

It is possible that flowlines will be flushed and left on the seabed. Where possible, recovered equipment will be re-used or recycled.

4.7.3 Floating production storage and offloading facility

Decommissioning of the FPSO will be a relatively simple matter of disconnecting the FPSO from the turret and sailing it away.

4.8 Wastes

A variety of wastes will be generated in association with drilling, installation, commissioning, production and decommissioning activities. Key waste categories have been identified and include:• Non-hazardous solid wastes

• Hazardous solid wastes

• Produced water discharge

• Greenhouse gas emissions.

These categories and the waste management principles to be applied for the proposed development are discussed below. A summary of expected waste types and quantities is provided at the end of this chapter (Section 4.8.6).

4.8.1 Waste management principles

Design processes aim to develop production processes and equipment in a manner that is efficient and minimises resource use and waste generation.

The waste management process to be adopted by the proposed development will give priority to the prevention and minimisation of hazardous waste materials and will focus on reducing the quantities of waste requiring disposal, such as through pre-qualification, tendering and contracting processes. The objectives of the waste management process are to:• Identify opportunities to prevent and/or reduce waste generation

from the proposed development through design and operation standards

• Identify opportunities to re-use, recycle or reprocess wastes generated during all phases of the proposed development

• To reduce the amount and toxicity of wastes requiring disposal

• Identify and eliminate hazards to human health and the environment (to as low as reasonably practicable)

• Utilise certified waste transporters and disposal facilities for ultimate waste disposal if other options are not practicable

• Document waste management information, including inventory, disposal, waste characteristics and procedures.

A comprehensive Waste Management Plan will be developed and integrated into the design phase of facilities and processes.

The proposed development will comply with the requirements of the NEPM National Pollutant Inventory (NPI) and any relevant requirements of the National Environmental Protection (Movements of Controlled Waste) Measure.

4.8.2 Non-hazardous solid wastes

Non-hazardous wastes will generally be separated into recyclable and other components as much as possible offshore, which enables the appropriate onshore destination to be determined. The quantity of non-hazardous waste will be tracked using a database to permit the identification of improvement opportunities.

An estimate of non-hazardous waste quantities over the life of the proposed development is provided in Section 4.8.6.

4.8.3 Hazardous solid wastes

Hazardous wastes will be separated offshore and tracked through to ultimate disposal, which may include recycling, incineration or landfill. A database will be used to compile an inventory of hazardous wastes (i.e. date, types, quantities, ultimate destination) to track the fate of wastes and to permit the identification of improvement opportunities.

Substances identified under the National Pollution Inventory (NPI), National Environment Protection Act 1994 (NEP Act) will be reported in accordance with these requirements (refer to Chapter 7). NPI substances that may be NPI reportable for the proposed development include:• Nitrogen oxides (NOx)

• Carbon monoxide (CO)

• Sulphur dioxide (SO2)

• Particulates

• Benzene, toluene, ethylbenzene, and total xylenes (BTEX).1 http://www.appea.com.au/Publications/docs/WellDecommGuide.pdf

PROJECT DETAILS


Estimates of quantities of hazardous wastes generated over the life of the proposed development are provided in Section 4.8.6.

It is also possible that scales potentially containing naturally occurring radioactive materials (NORMs) may accumulate and will require periodic disposal.

4.8.4 Produced water discharge

Under normal operating conditions produced water will be re-injected into a proven reservoir. It is estimated that this can be achieved more than 90% of the time. If the re-injection system is unavailable, produced water will be discharged to the ocean. Water treatment systems (Section 4.6.4) will reduce oil-in-water concentrations to below limits required by law (24-hour average less than 30mg/L, maximum less than 50mg/L). When produced water is discharged overboard, an electronic meter will measure the oil-in-water concentration continuously to ensure compliance with the regulation.

In the event that produced water is discharged to the ocean (predicted to be less than 10 % of the time), the peak flow rates are estimated to be in the order of 17,600m3 per day.

4.8.5 Greenhouse gas emissions

The global warming potential of different gases varies depending on their particular physico-chemical structure and the time span over which the effect is being considered. In order to be able to compare the effect of different gases, the global warming potential (GWP) of a gas is expressed relative to carbon dioxide (CO2) over a time horizon (100-year is the most usual) and is referred to as CO2eq. The global warming potential of the six main greenhouse gases are given in Table 4.2 (Houghton et al., 1995).

4.8.5.1 Greenhouse gas emmissions from the proposed development

The development will be designed to minimise emission of greenhouse gases throughout all project phases to as low as practicable.

The tiered approach for quantifying atmospheric emissions (E&P Forum, 1994) has been used to compile an inventory of greenhouse gas emissions. This is the standard methodology applied for calculation of emissions in the oil and gas exploration and production industry.

The Kyoto Protocol listed greenhouse gases that apply to the proposed development include carbon dioxide (CO2), methane (CH4) and nitrous oxide (N2O). There will be no emissions of perfluorocarbons, hydrofluorocarbons or sulphurhexafluoride from the proposed development.

The potential environmental effects of other atmospheric emissions, such as nitrogen oxides (NOx), sulphur oxides (SOx), volatile organic compounds (VOCs), cargo tank vents and fugitive emissions, have also been assessed.

No hydrogen sulphide (H2S) has been detected in the Pyrenees reservoir fluids, thus no H2S emissions are predicted to result from the use of stationary combustion sources. Reservoir performance will be continuously monitored through the production systems and well testing to identify issues such as increase in concentration of H2S.

Fuel gas will be available and is the preferred fuel for normal operation, with backup provided by diesel.

Production and processing air emissions

The greenhouse gas emissions for normal operation have been estimated for the first year of production at up to 162,000t/year CO2eq. This is based on the annual average production rate of 12,720m3/day.

Operation CO2 CO NOx CH4 CO2eq %

Power Generation 92,077 90.2 7.4 14.1 95,018 64.9

Process Heating 24,865 7.2 2.0 0.6 25,539 17.4

Flare Emissions 16,414 54.7 0.5 220 22,107 15.1

Tank Venting <0.1 <0.1 <0.1 154.1 3,774 2.6

Fugitive Emissions <0.1 <0.1 <0.1 1.3 31.2 <0.1

TOTAL (Tonnes) 150,422 147 12 270 161,169 100

*GWP applied: CO2: 1, CO: 0, NOx: 0, N2O: 296, SOx: 0, CH4: 23, VOC: 0

Table 4.3: Predicted Greenhouse Gas (Tonnes per year) Emissions for Year 1

Gas Global Warming Potential

Carbon dioxide (CO2) 1

Methane (CH4) 21

Nitrous oxide (N2O) 310

Perfluorocarbons 6,500 – 8,700

Hydrofluorocarbons 560 – 11,700

Sulphurhexafluoride 23,900

Table 4.2: Global Warming Potential of DifferentGases Relative to CO2

Source: IPCC, 1995


The following sources of greenhouse gas emissions from the Pyrenees Development have been identified during operations:• Power generation of electricity from dual fuel turbines (or their

equivalent direct drive machines if selected)

• Flaring of hydrocarbon gas required to maintain safe operating conditions for the operational and emergency flares

• Emissions associated with inert gas generation (i.e. tank venting during crude loading)

• Fugitive emissions resulting from minor leaks in pipe connections and equipment.

Atmospheric emissions are quantified based on the Tier 3 Approach, developed according to the E&P Forum (1994) methods for estimating the principle inventory sources of atmospheric emissions including combustion equipment, tank/storage vents, flare and fugitive emissions (Figure 4.12). The results of this analysis are expressed in terms of CO2eq to compare the emissions from various greenhouse gas emissions based on their GWP. A prediction of the annualised account of main energy types, their consumptions and associated greenhouse gas emissions are shown in Table 4.3.

Assuming total recoverable reserves of 19,875,00t (125 million barrels) of crude oil and an operational lifespan of 20 to 25 years the average annual greenhouse gas efficiency is calculated to be 0.16 to 0.20t CO2eq per tonne of product.

Power Generation

The majority of greenhouse gas emissions are from combustion of gas for the powering of equipment. Table 4.4 presents a breakdown of the predicted emissions from equipment sources. Power requirements have been minimised where possible in the Pyrenees Development by utilising the following design features:• Direct crude inter-stage heating requirements have been minimised by

using heat recovery from product oil and produced water streams

• The use of cross exchangers to recover process heat significantly reduces the process heating duty and therefore the pumping and duty/electrical load for the heating medium circulation system

• Where possible the layout will facilitate free flow of liquids from the LP Separator and electrostatic coalescer via the process cross exchanger to the produced water treatment system. This will avoid the electrical power requirements that would otherwise be associated with pumping water and crude from the electrostatic coalescer to the produced water treatment system and crude export system respectively

• Water carryover with the oil from the HP separator will be minimised and separation of water at HP will be maximised. Removal of water in the HP separator will enable the water to free flow to the water treatment system and will reduce interstage heating requirements

• The electrical energy for the entire facility shall be supplied from central dual fuelled (fuel gas/MDO) turbine driven power generators. In the event of central generation total failure, power for essential services shall be supplied from an emergency diesel generator(s) and critical services from UPS systems.

Figure 4.12: Predicted annual greenhouse gas emissions

PROJECT DETAILS


The main consumers of power on the process topsides are the HP gas compressors and the water injection pumps (included in major topsides pumps). For the hull systems the major users of power are the thrusters and cargo off-loading pumps.

Exhaust gases from the power generation turbines contain predominantly carbon dioxide with small amounts of nitrogen oxides, carbon monoxide and unburned hydrocarbon. The use of low NOx burners may not be feasible for dual fuel requirements. This issue will be resolved during further design activities.

Process Heating

Heat is principally required on the topsides for process heating to aid oil/water separation and to achieve crude specifications. It is also used on an intermittent basis for heating the cargo tanks wash water, heating the slops tank. A closed loop, pressurised water heating medium system will be used. Alternatively LP stream from the FPSO marine systems may be used depending on final configuration.

Flare Emissions

A flare system will be provided to ensure safe disposal and discharge of gases and liquids resulting from relief, blowdown and vent streams from the topsides and turret area. During normal operation, some non-continuous and non-routine activities will lead to flaring and venting of gas. The flare system is designed to handle peak emergency rates as well as flaring continuously at facility peak design gas rates.

Flaring of associated gas from the FPSO will be minimised, although a small continuous source is required to maintain an ignited flare pilot.

During normal operations, the proposed development will not flare surplus gas (other than LP flare in first year and continuous flare purge over the life of the project). Where possible, all produced gas not consumed for power generation or for maintaining the flare pilot will be compressed and re-injected (or exported).

The operational flare requires a continuous flow of LP, small flow streams, such as gas dehydration TEG regeneration off-gas, and is disposed as part of the continuous flare pilot. HP compressor maintenance and the compressor gas seal leaks are also included in the emissions estimate for continuous flaring.

Emergency flaring disposes 1t of natural gas per day, assuming two trips/failures each year. Flare emissions associated with normal operations and emergency flaring are estimated to contribute approximately 15% of the total CO2eq emissions.

The emission generated during flaring will contain water vapour, carbon dioxide, carbon monoxide, nitrogen oxides, nitrous oxides and unburned hydrocarbons.

Fugitive Emissions

Fugitive emissions are estimated to contribute 31 tonnes CO2eq/year during annual production.

Inert Gas and Tank Ventilation System

When the FPSO is loading oil into the cargo system, there will be loading emissions from its own tanks as they are filled. This is estimated to contribute 154 tonnes/year of methane or 3,774 tonnes CO2eq/year (based on first year production rates) for both FPSO and offtake tanker loading operations. During offloading, inert gas (IG) is pumped into the void space to prevent an explosive atmosphere developing.

Volatile Organic Compounds (VOC) emitted during loading of tanks result from the displacement of vapour present in the empty tank before loading commences and from evaporation from the cargo being loaded. The very small portion of low molecular weight hydrocarbons in the stabilised Pyrenees crude oils means that the amount of VOC emitted is low.

The anticipated offloading rate is 71,500m3 (450,000 bbl) parcel size within 24 hrs. The storage capacity will include 3 days of margin above this parcel size at field peak oil production rate (i.e. 110,000m3 storage capacity).

Two inert gas (IG) generators will be provided for tank blanketing, sized to be capable of supplying IG to cargo, process and slop tanks at a rate of 125% of the maximum cargo offloading rate. Cargo tank stripping system will be capable of discharging tank washing fluid back to the slop tanks. Both slops tanks can receive crude oil washing water or gravity separated water decanted from any of the cargo tanks via the product header line.

Equipment CO2 CO NOx CH4 CO2eq %

HP Compressor – Train 1 21,514 21.1 1.7 3.3 22,121 23.5

HP Compressor – Train 2 21,514 21.1 1.7 3.3 22,121 23.5

Major Topsides Pumps 18,687 18.3 1.5 2.9 19,214 20.4

Other Topsides Systems 9,769 9.6 0.8 1.5 10,044 10.7

Hullside Equipment1 20,023 19.7 1.6 3.1 20,588 21.9

Subsea Equipment Minimal (not included)

TOTAL (Tonnes) 91,507 89.8 7.4 14.1 94,5089 100(1) This is hullside power usage during on station production only.

Table 4.4: Equipment Greenhouse Gas Emissions


The IG system will be in compliance with Classification Society requirements to provide safe atmospheric discharge of the tank gases to compensate for the loading/unloading of crude oil, normal tank breathing due to temperature fluctuations and the emergency relief of over/under pressure.

4.8.5.2 Greenhouse gas emissions benchmarking

Targets for greenhouse gas emissions have been based on benchmarking of other offshore production facilities. No two facilities are identical, and so comparison with the closest equivalent is required. For benchmarking against Australian oil and gas industry performance, data was obtained from the ‘APPEA 2003 Greenhouse Gas Inventory of Oil and Gas Exploration and Production Activities’ (APPEA, 2003). The APPEA greenhouse gas totals take into account production and emissions associated with onshore and offshore oil and gas production facilities around Australia.

The data included venting of CO2 from onshore gas treatment plants, which is not relevant to FPSO operations. To provide a more realistic benchmark, this contribution should be removed from the APPEA totals. When this is done, the APPEA performance indicator for 2003 is approximately 0.2 t CO2eq per tonne product (i.e. tonnes of hydrocarbon product). Note that this represents greenhouse gas emissions from the facilities calculated on an annual basis.

Values for annual performance of greenhouse gas emissions per tonne of product for the proposed development would vary significantly over the field-life as oil production declines particularly considering the significant additional emissions associated with water and gas injection systems that will either remain constant or increase over time. Lifecycle totals have been used to moderate this effect for comparison purposes, and are more representative of lifecycle impacts.

The predicted lifecycle greenhouse gas emissions from the proposed Pyrenees Development is 0.16 to 0.20 t CO2eq per tonne of product. The predicted greenhouse gas efficiency compares favourably with the APPEA value of 0.2 t CO2eq per tonne of product, particularly considering the significant additional emissions associated with water and gas injection systems that will be in place.

4.8.6 Summary of expected waste types

The expected waste types and estimated quantities for the main lifecycle phases of the proposed development are shown in Table 4.5.

PROJECT DETAILS


Waste Type(unit)

Installation and Commissioning Drilling Production Decommissioning

Pyrenees fields only

Tie-back fields

Pyrenees fields -only

Tie-back fields


Tie-back fields


Tie-back fields

Recyclable inert (t) 60 100 10 per well 10 per well 30 per year 50 per year 500 1,500

Non-recyclable Inert (t) 100 150 40 per well 40 per well 60 per year 80 per year 30 50

Recyclable hazardous (t) 20 30 10 per well 10 per well 10 per year 15 per year 30 50

Non-recyclable hazardous (t) 100 120 5 per well 5 per well 50 per year 60 per year 30 50

Sewage (m3/day) 5 5 5 5 5 5 5 5

Food scraps (m3/day) 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3

Greywater (m3/day) 10 10 10 10 10 10 10 10

Cooling water (m3/day)420–500 420–500 420–500 420–500 50,000–

100,00050,000–100,000

420–500 420–500

Drilling muds (m3/well) Nil Nil 275-450 275-450 275-450 275-450 Nil Nil

Drill cuttings (m3/well) Nil Nil 300-400 300-400 300-400 300-400 Nil Nil

Hydrotest water (m3) 1,700 5,000 Nil Nil Nil Nil Nil Nil

Produced water (m3 /year)* Nil Nil Nil Nil 1,760 1,760 Nil Nil

Desalination brine (m3/day) 150 150 150 150 60 60 150 150

Subsea control fluids (m3)15 50 Nil Nil 30 per year 100 per

year15 50

NOx (t) 4,000 12,000 400 1,200 8,000 24,000 200 600

SOx (t) 600 1,800 50 150 600 1,600 30 100

VOC (t) 20 50 1 3 60,000 180,000 10 20

Greenhouse gases (t CO2eq)20,000 70,000 210,000 620,000 162,000

per year162,000 per year

20,000 70,000

*Based on peak water production rates and discharge to sea for 10% of time

Table 4.5: Summary of Expected Waste Types and Quantities

04 Project Details

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