CHAPTER 1: What is Oil & Gas Exploration?

Introduction

The hydrocarbon oil is valuable to the humankind. Oil has been used for lighting purposes for many thousand years. Nowadays, it is the main fuel for power generation and transportation. The first successful oil well was drilled to a deep of 69 feet in 1859 for the sole purpose of finding oil. The well drilled by Colonel Edwin Drake was located in the middle of quiet farm country in north-western Pennsylvania, and began the international search for and industrial use of petroleum.

Today with the aided of science and researches, we have the strong evidence of geologic theories along with good technology support that help the people to explain how oil and gas were formed

One of the initial theories concepts in developing the current geologic organic theory of petroleum is that life on earth based on the research possibly began hundreds of millions of years ago in vast seas and inland lakes. In marine area, though of being reasonably shallow, the hydrogen and carbon material that made up from the decomposed plants and animals living on land and in the sea. Then, all these slowly composed together to become petroleum which took millions of years.

Terminology

1. Upstreama. Exploration

i. Geophysical SurveysShock waves that pass through the earth and send back waves to the receiver. The waves’ speed vary depend on the type/density of the rock through which they pass. The receiver will measure the speed of the reflection waves to differentiate the type of rock beneath the earth. Here, they can determine the existence of the hydrocarbon. Hydrophones use if waves passing through water.

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Offshore Seismic Survey

2D Surveying

Sound source and detectors moved along straight line; create vertical cross section summing compression wave reflections. This method can be on land or seabed. The generator will produce a huge amount of waves to the designated area. Then geophones will absorb the reflection waves to be processed by seismometer. This waves will vary between, oil, gas, water and shale.

3D Seismic Imaging

Sound detectors spread out over an area and processed to create a cube of a common depth with improved resolution over 2D. 3D image definitely will show better and clear image on particular area for further researches.

3D Seismic Image

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4D Seismic Imaging

The 3D setup done over two or more time intervals such as fluid movement.

Reservoir Imaging

Uses frequency waves to locate reservoirs, estimate volumetric capacity and monitor ongoing reservoir development. It has furthered the exploration of offshore and deep sea oil reservoirs.

Remote Sensing

The system use satellite mapping technology, capture aerial photographs taken to map surface features. It uses to locate hydrocarbon traps called; anticlines; synclines; faults.

ii. Wildcat ExplorationAfter doing all the seismology searches, then the exploration company will send a drilling vessel to do the wildcat exploration generally with little information. Wildcat exploration is basically an exploratory oil well drilling in land or sea bed in effort to locate undiscovered hydrocarbon. About 1 in 10 wildcat wells strike oil or gas, but reserves can be extremely profitable when these programs are successful. Many wildcat wells are drilled on a hunch, intuition, or a small amount of speculative geology. Many times they are based on surface trends, photography, and experience in a particular area.

iii. Appraisal drillingDrilling carried out following the discovery of a new field to determine the physical extent, amount of reserves and likely product rate of the field. From the appraisal analysis, the researches, developer and operator company can determine the feasibility of the project, either is it relevant to build a drilling and production platform for such amount of hydrocarbon.

iv. Exploitation drillingAfter all the exploration processes done and the particular well has been set, that area opens for any operator to run for exploitation. The operator company will make full profit and productive of the area.

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Designer will be assigned to design either FPSO or platform based on depth and product estimation.

b. Oil and Gas ProductionIt varies depend on the product, situations and requirements from the operator/client. I just refer to a simple oil and gas production overview taken from “Oil and Gas Production Handbook: An Introduction” by Håvard Devold, 2006, ABB ATPA Oil and Gas.

i. WellheadThe wellhead sits on top of the actual oil or gas well leading down to the reservoir. A wellhead may also be an injection well, used to inject water or gas back into the reservoir to maintain pressure and levels to maximize production. Once a natural gas or oil well is drilled, and it has been verified that commercially viable quantities of natural gas are present for extraction, the well must be 'completed' to allow for the flow of petroleum or natural gas out of the formation and up to the surface. This process includes strengthening the well hole with casing, evaluating the pressure and temperature of the formation, and then installing the proper equipment to ensure an efficient flow of natural gas out of the well. The well flow is controlled with a choke. We differentiate between dry completion with is either onshore or on the deck of an offshore structure, and Subsea completions below the surface. The wellhead structure, often called a Christmas tree, must allow for a number of operations relating to production and well work over. Well work over refers to various technologies for maintaining the well and improving its production capacity.

ii. Manifold and GatheringOnshore, the individual well streams are brought into the main production facilities over a network of gathering pipelines and manifold systems. The purpose of these is to allow set up of production “well sets” so that for a given production level, the best 13 reservoir utilization, well flow composition (gas, oil, waster) etc. can be selected from the available

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wells. For gas gathering systems, it is common to meter the individual gathering lines into the manifold as shown on the illustration. For multiphase (combination of gas, oil and water) flows, the high cost of multiphase flow meters often lead to the use of software flow rate estimators that use well test data to calculate the actual flow.

iii. SeparationSome wells have pure gas production which can be taken directly to gas treatment and/or compression. More often, the well gives a combination of gas, oil and water and various contaminants which must be separated and processed. The production separators come in many forms and designs, with the classical variant being the gravity separator. In gravity separation the well flow is fed into a horizontal vessel. The retention period is typically 5 minutes, allowing the gas to bubble out, water to settle at the bottom and oil to be taken out in the middle. The pressure is often reduced in several stages (high pressure separator, low pressure separator etc.) to allow controlled separation of volatile components. A sudden pressure reduction might allow flash vaporization leading to instabilities and safety hazards.

iv. Gas treatment and CompressionGas from a pure natural gas wellhead might have sufficient pressure to feed directly into a pipeline transport system. Gas from separators has generally lost so much pressure that it must be recompressed to be transported. Turbine compressors gain their energy by using up a small proportion of the natural gas that they compress. The turbine itself serves to operate a centrifugal compressor, which contains a type of fan that compresses and pumps the natural gas through the pipeline. Some

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compressor stations are operated by using an electric motor to turn the same type of centrifugal compressor. This type of compression does not require the use of any of the natural gas from the pipe; however it does require a reliable source of electricity nearby. The compression includes a large section of associated equipment such as scrubbers (removing liquid droplets) and heat exchangers, lube oil treatment etc. Whatever the source of the natural gas, once separated from crude oil (if present) it commonly exists in mixtures with other hydrocarbons; principally ethane, propane, butane, and pentanes. In addition, raw natural gas contains water vapor, hydrogen sulfide (H2S), carbon dioxide, helium, nitrogen, and other compounds.

Natural gas processing consists of separating all of the various hydrocarbons and fluids from the pure natural gas, to produce what is known as 'pipeline quality' dry natural gas. Major transportation pipelines usually impose restrictions on the make15 up of the natural gas that is allowed into the pipeline. That means that before the natural gas can be transported it must be purified.

v. Oil and gas storage, metering and export. Offshore production facilities without a direct pipeline connection generally rely on crude storage in the base or hull, to allow a shuttle tanker to offload about once a week. A larger production complex generally has an associated tank farm terminal allowing the storage of different grades of crude to take up changes in demand, delays in transport etc. Metering stations allow operators to monitor and manage the natural gas and oil exported from the production installation. These metering stations employ specialized meters to measure the natural gas or oil as it flows through the pipeline, without impeding its movement. This metered volume represents a transfer of ownership from a producer to a customer (or another division within the company) and is therefore called Custody Transfer Metering. It forms the basis for invoicing sold

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product and also for production taxes and revenue sharing between partners and accuracy requirements are often set by governmental authorities. Typically the metering installation consists of a number of meter runs so that one meter will not have to handle the full capacity range, and associated prover loops so that the meter accuracy can be tested and calibrated at regular intervals.

vi. Christmas treeIt is installed to provide surface pressure control, has isolation valves and choke equipment to control the well fluids.

a. pressure gauge Device that measures the oil pressure inside the producing well.

b. flow bean Calibrated opening of a flow line through which oil flows; it is used to limit the flow from a producing well.

c. pipeline Steel piping that carries oil from the well to the refining facilities.

d. tubing valve Device that regulates the flow of oil extracted from the well and carries it in flow lines, here toward an oil pipeline.

e. casing first string First column of large-diameter tubes are inserted into the producing well mainly to strengthen its walls.

f. tubing Last column of small steel tubes to be inserted in the well; they are used to bring oil to the surface.

g. tubing head Equipment to which oil production and extraction tubes and devices (Christmas tree, tubing) are attached.

h. master gate valve Main device that regulates the flow of oil; it can completely shut off the outflow.

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WET TREES DRY TREES

Well intervention costs high – need to mobilise MODU

Well intervention easier (eg wire line for well work-over)

No structure required Need supporting structure

More flexibility for locating well over reservoir – can decide/change well locations as development proceeds

Ability to access reservoir may be limited due to facility location (length of wells)

Limits maintenance opportunities Need drilling capability from facility – may drive facility size/weight/cost up

Sub-sea equipment higher CAPEX

Can defer CAPEX expenditure – NPV driver

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CHAPTER 2: Fixed Structures

Structures Development

Structure type selection influenced by:

Infrastructure Seabed characteristics Water depth Environmental conditions Platform function Number of well slots Type of production facilities

From above selection, aided by further information then we can identify constrains (typical criteria for development).

Topside capacity (estimate amount) Jack up ability Barge loading capacity/ installation

Shallow Sea Level

Once the reservoir has been identified, a structure need to be built for hydrocarbon extraction, separation and offloading. Referring ‘Offshore Engineering, Angus Mather’, shallow sea level defines below than 100m depth.

Fixed structures satisfy within this level; Jacket form. Jacket leg will hold the topside above the sea surface for product extraction, separation and transferring.

Based on production requirement, the sizing design:

Number of legs Base dimensions Framing levels Framing styles Manned or unmanned

All these basically analyzed by structural. Here, I only write brief information about jacket form in term of number of legs and factor influencing base dimensions.

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a. Fixed platform- number of legs. Braced monopods

Tripod

4-legged

Jacket through leg piles

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Jacket floatover through leg piles

Tower skirt piles

6-legged

8-legged

Bullwinkle – largest fixed piled platform

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b. Factors influencing base dimensions. Environmental loading during in-place conditions Pile requirement On-bottom stability (pre-piling) Fabrication Cranes Lift Vessel Natural Period Dynamic Forces

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CHAPTER 3: Floating Production System

Beyond Shallow Sea Level

Oil exploration and production (E&P) companies are drilling further out into the sea and deeper under the ocean floor, at depths greater than 1000 feet to tap into one of the last remaining pockets of oil and natural gas in the world. Though deepwater was once prohibitively expensive, high oil prices during 2007 and the first half of 2008 made the economics of deepwater drilling more feasible. In long term contracts, companies continue to drill despite falling profits. Even then, new deepwater projects continue to be opened, as prices are expected to rebound in the long term because of rising global demand for energy. That's good for E&P companies, as to keep generating profits. As traditional oil producing basins mature there are only a couple of places left to get oil. Proven reserves of oil at the end of 2006 were at 1.15 trillion barrels, of which about 10% is deepwater - a little more than 100 billion barrels.

Deepwater + 3000 ft or 900 m Ultra deepwater + 7000 ft or 2100 m Exploration today 10,200 ft or 3100 m Production today 8000 ft or 2400 m

Production at Gulf of Mexico

For deepwater, fixed structure become impossible since it needs very large and long jacket leg to suit with the deep water level. Jacket installation required extremely large heavy lift barge and fixed jacket at cost-effective limit.

Therefore, the companies go for floating alternatives which using hull, pontoons and tendons/tethers. Various deepwater structures developed: Subsea tiebacks, FPSO, TLP, Spars, Semi-subs, etc. Each has their own inherent characteristics, advantages and disadvantages.

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The functional requirements for floating structures can be generalized as:

• Drilling facilitieso Number, type and location of drilling rig

• Production facilitieso Weight, area and centre of gravity

• Drilling / production riserso Number and arrangement

• Well systemso Number of wells, completion and work over methods, minimum well spacing and

well bay location• Hull compartmentalization

o Damage stability considerations• Air gap requirements

o New metocean criteria.• Wet/ dry trees.

o The requirement for wet or dry trees is one of the most fundamental in deepwater concept selection.

Structure development options

Semi-submersible, spars & TLP

• Typically used for deepwater 300m+ (but see detail on each).

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• All floaters have hull, topsides, moorings/tethers, production risers & import/export risers.

• Topsides generally have limitations on payload, COG.• Payload = Topside + Moorings + Risers + Drilling + Liveload • Permanent moorings/tethers => cannot weathervane => directional metocean

conditions apply for moorings, response.• Excellent for benign/moderate metocean conditions, Ok for hurricanes/cyclones.• No oil storage => export required (i.e. pipeline / FPSO / FSO).

Semisub Spar TLP

Waterdepth 85m - 2,440m

Median = 560m

Mean = 820m

570m - 2,440m

Median = 1,290m

Mean = 1,310m

275 - 1,425m

Median =950m

Mean = 880m

Hull 12,000-25,000 Te 6,500 – 32,500 Te 2,800 – 30,000 Te

Topsides 3,000-25,000 Te 2,900 – 24,000 Te 1,700 – 21,350 Te

Moorings ~2,000-12,000 Te ~4,000-12,000 Te ~ 2,000 – 8,000 Te

Risers No Off 10-36-50

~400-1,400-2,000 Te

No Off 9-25

~ 400-1,000 Te

No Off 4 – 46

~200 – 2,000 Te

1. Semi-submersibles

Types:

• FPSS – Floating Production Semi-submersible• FPU– Floating Production Unit• FPDU– Floating Production Drilling Unit

FPSS is a permanently moored Semi-sub, typical detail:

• Hull 12,000 – 25,000 Te• Topside 3,000 – 25,000 Te• Moorings- 12,000 Te

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• Risers - 400 - 2,000 Te• Suitable for cyclonic conditions• Water depth- 85m to 2440m+.• Large number of risers/subsea tiebacks => 12-

36-50 large diameter risers (Troll C – top Fig).• Vessel may include drilling / work over

facilities especially if based on an existing semisubmersible rig (new build or conversion)

• Retaining the rig allows well workover – beneficial if require high intervention• Columns may be braced to provide additional hull rigidity and to support the

topsides.• Topside typically box or truss frame• Topside “modules” or PAU (Pre-Assembled Units) installed.• Marine systems still required, but usually need to be upgraded• Easy to abandon and possible reuse.

Installation

• Easy to install• Self propelled barge or wet-tow• Excellent for remote province• No high-cost mechanical active tension• Hull simple shipyard fabrication• Pre-commission in shipyard• Preinstall foundations => major crane barge not

required.

ADVANTAGES

• Large payload and storage capacity • Relatively insensitive to minor variations in topside weight & COG. • Excellent & proven motion characteristics.• Drilling, Completion & Workover possible.• Large working space for safe & efficient operations • Protected working and storage areas • Large POB capacity • Deepwater mooring capability

DISADVANTAGES

• Wet trees only (cannot support rigid risers or dry trees due to excessive motions (roll, pitch, heave, sway, surge, yaw)

• Newbuild = Large CAPEX & Long schedule

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• Conversion = Large upgrade, remedial work, drilling, schedule risk& good condition.• Cannot weathervane => directional fatigue issues• Very large/heavy moorings for cyclonic conditions.

2. Spars• A Spar is a vertical floating cylindrical buoy moored or anchored to the seabed.• Spars are also known as DDCV (Deep-Draft Caisson

Vessel). • All existing Spars installed in GOM (with 1 in Malaysia).• Stabilized by a midsection hull / truss.• Stability supplemented by solid ballast placed in the

keel.• Supported at top by buoyancy chambers ("hard tanks")• There are 3 different types of spars:

- Classic Spar – original 3 spars: 3 exist- Truss Spar – is the most common: 13 exist- Cell Spar – recent development: only 1 exists.

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Typical detail:

• Hull 6,500 – 32,500 Te• Topside 2,900 – 24,000 Te• Moorings ~12,000 Te• Risers ~ 2,000 Te• Designed for GOM hurricane conditions• Waterdepth 570m to 2,440m+.• Moderate number of risers =>9 – 25• A deep draft is required to maintain the centre of buoyancy above the centre of

gravity to provide stability.• Top of Spar is a ‘hard tank” which provides buoyancy, while

below there are “soft tanks” (flooded tanks) which provide variable ballast, trim & stability.

• Deck area is limited. To some extent spars are mildly sensitive to payload & COG changes.

• Spar is moored to the seabed with semi-taut catenaries anchor lines (similar to Semisubs). The 12-16 anchor lines providing station keeping have the fairlead chains located at or above mid-draft to minimise mooring line dynamics.

• Large footprint at seabed => tight clearances for pipelines, subsea tiebacks, Semi-sub drill rig anchor pattern and etc.

a. Hull types: Classic Spar• Original 3 spars only (installed 1996-1999) ‘Neptune’, ‘Genesis’, ‘Diana’.• Full-length hardtank.

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• Extensive keel ballast due to high submerged buoyancy.• Full length hardtank results in large wave/current loads => large moorings• High inertial loading, especially heave motions & amplitude, as well as pitch/surge

response.

b. Hull types: Truss Spar• Most common spar type (13 of 17).• Open truss with deep-draft heave plates in bottom segment limits heave response &

motions.• Open truss reduces wave/current loads on structure.• Truss Spar has an inherent high steel weight near the keel, driven largely by the

need for permanent ballast to provide hydrostatic stability and pitch stiffness.

c. Hull types: Cell spar• Cell Spar: small diameter tubular tanks welded together to act compositely as a

Classic spar.• Cell Spars also have extensive keel ballast• VIV strakes required on individual tubular tanks & around entire composite hull for

both global & local VIV mitigation.• Smaller diameter hull tubular => significantly increases fabrication yard capability.

FABRICATION

• Traditional shipbuilding panels• Spar hulls traditionally made in Finland

INSTALLATION

• Upending operation to be controlled. Ballast to be installed and moorings connected.

• Topsides to be lifted on. Spars are also sensitive to lateral COG thus weight COG offset limits exist.

• Topside modules stacked vertically not laterally.

ADVANTAGES

• Dry trees; frequent intervention possible. • Subsea tiebacks possible.• Suitable for GOM hurricanes.

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• Largest spars support extremely large topsides• Drilling / Completion / Workover possible

DISADVANTAGES

• Custom-designed for site-specific conditions (water depth, metocean, geotechnical).

• Dry trees involve complex risers.• Moonpool is space limited• Layout & COG results in minimal separation &

segregation• High CAPEX & relatively long schedule• Heavy Lift Vessel required to install deepwater

piles, topsides• Offshore HUC• NWS is more significantly more severe than GOM.

3. TLP• TLP (Tension Leg Platform) is a floating deepwater facility permanently moored on

site with vertical tethers (steel pipe tendons) piled to the seabed.

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• The TLP is deballasted so that the tendons are maintained in tension i.e. excess buoyancy over the weight of the structure.

• The world's 1st TLP installed June 1984 for Conoco Hutton field in U.K. North Sea in 148m of water (experience indicates too shallow)

• Original Hutton TLP large 4-column, based primarily on Semisub hull technology

• Current TLP versions also include mini-TLP, ETLP versions.

• Currently 20 TLP operating - GOM, West Africa & Indonesia.• TLP can be used as DPP or WHP• TLP can be provided with drilling and/or workover capability• Proved for GOM hurricane conditions• Easy to abandon and possible reuse.

Typical detail

• Hull ~ 2,800 – 30,000 Te• Topsides ~ 1,700 – 21,350 Te• Payload ~ 4,500 – 31,000 Te• Water depth 275m – 1,425 m typical ~950m• Number of dry trees ~ 4 – 46• Tendons are high-strength steel tubes, sized

neutrally buoyant to minimize applied payload. Remain in tension.

• Tendons neutrally buoyant => can pre-install • Tension depends on metocean • Tendons are fatigue sensitive

FABRICATION

• TLP hulls historically been built in USA, Italy, South Korea and Singapore.• TLP hulls typically fabricated using traditional stiffened plate / shipyard construction.

INSTALLATION

• Large TLP pre-commissioned at nearby yard & wet-tow to site• ETLP & Mini-TLP small / light for SSCV to install offshore single lift• ETLP & Mini-TLP next generation => dry-tow to site => removes requirement for

SSCV => excellent for remote province.

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ADVANTAGES

• Dry trees - Drilling/Completion/Workover • Minimal heave, roll, pitch, dry tree.• Minimal Footprint• Low CAPEX• Fast schedule

DISADVANTAGES

• Generally cannot use < 350m• Well drilling limitations after TLP installed.• TLP are weight sensitive• Limitations on variable payloads.• Mooring custom designed for site specific conditions (waterdepth, metocean,

geotechnical)• Fatigue from lateral motions.

TLP

4. FPSO – Floating Production, Storage and Offloading.

I would like to explain more on FPSO since the company involve a lot in FPSO development (topside specialist).

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Definition by word:

By floating- the body is in equilibrium when floating. This could include Semi-subs, monohulls, deep draft semi-subs and spars, but does not include TLPs. Note that the motion characteristics of the deep-draft semi-sub and the spar permit the use of deck mounted “dry trees” whereas the first two types, have normally to deploy subsea completed “wet trees”.

By production- the unit support processing equipment to fully treat live well fluids, with separation gas compression, water injection, cooling and heating systems, water treatment, fuel gas, chemical injection and etc..

By storage- the processed oil is held in tanks on the unit prior to export. Gas cannot be stored and must be exported by pipeline, used for power generation, reinjected, used for subsea gaslifting or flared.

By offloading- the oil product is transferred to a shuttle tanker or other export system like pipelines.

Compared to the other platform and structures, there are reasons of choosing FPSO and make the system becoming more popular.

1. The best thing about FPSO is it can be located in greater water depths (20m – 1500m)

2. Can be self-contained developments with onboard storage (2 million bbls plus) – no pipelines or adjacent infrastructure required

3. Can be easily re-deployed – good for marginal developments

4. Can be brought back to shipyard for modifications/repairs

5. Significant processing capacity – 250,000 bbl/day plus facilities

6. Hulls can have significant load bearing and space capacity – less weight vs cost effects

7. Less heavy lift equipment required for installation

8. Can cut and run from very extreme environments – e.g. cyclones, icebergs

9. Possibility to utilise existing hulls by converting existing tanker

10. Exists an active lease market – gives alternatives for project economics

However, there are major designs issues with FPSO compared to platform since the difference in structures, construction, and building block. For example all FPSO have the hull (oil storage)

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rather than platform and platform structure not as complicated as fixed platform. The major issues are:

1. Hulls hog and sag – i.e. bend as waves pass down the hull. This results in bending of the topsides - hence movement that must be accommodated by the structure, piping and etc

2. Vessel pitches and rolls – hence acceleration of topsides and equipment, sloshing in separators etc

3. Need to accommodate movement relative to seabed (including rotation) – hence flexible risers, swivels and mooring required

4. Need to integrate with hull systems – power, controls, utilities – creates more interfaces that must be managed

5. Hulls are designed by marine folk – different technology and practices to oil and gas industry

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FPSO development

In developing a new FPSO, the experts have to come out with some main issues in order to be solved. It supposedly synchronizes with the installation of process system. The solutions basically will lead as the constructions’ references.

The following are the main issues that need to be addressed for FPSOs development:

I. Storage volumeII. Spread vs Turret moored.

III. For turret moored – permanently moored vs disconnectable. Also internal vs external turret

IV. Hull tank configuration – single sided, double sided/single bottomed, double sided/double bottomed.

V. Hull accommodation configuration - fore or aftVI. Offloading options

VII. Conversion vs new-buildVIII. Degree of topsides/hull integration – e.g. power generation, power/propulsion

IX. Leased vs owned

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1. Storage volume – normally driven by the following:a. Production rate plus 3 days peak rate production buffer in case of late offloading.b. Parcel sizec. Available hulls for conversion.

2. Spread vs Turret moored – basically about holding the ships immovable on the sea surface. Decision to spread vs turret is ussualy driven by the metocean.a. Spread moored usually cheaper because no swivel or turret (advance structure).

However, forffloading efficiency, CALM (Catenary Anchor Leg Mooring) may be required.

b. Spread moored usually only in benign environmentsc. Turret moored reduced mooring loads and ships motions as vessel can face into seasd. Turret moored may also increase offloading weather window

3. If turret moored – permanently moored vs disconnectable and also internal vs external turret. Permanently moored vs disconnectable is usually a joint economic and technical decision:a. Disconnectable allows cut and run from worst sea

states (eg cyclones) – therefore reduced mooring design loads. However this results in production downtime

b. Disconnectable can return to port/shipyard for modification repairs etc

c. Disconnectable mooring may allow fewer/shorter mooring legs (eg 3 leg as opposed to 4 leg pattern) and allow FPSO to be closer to well centres – flowlines savings

d. Disconnectable mooring/turret system slightly more complex than permanently moored as has to have retrieval system

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e. Disconnectable vessel has to have propulsion and steerage equipment as opposed to “dumb barge”

f. Disconnectable vessel may have to have dedicated marine crew separate to production crew.

Internal vs external turret is again economic and technical decision:

a. Internal turret requires hull modifications and strengthening to accommodate turret.

b. External turret requires bow re-enforcement

c. Internal turret reduces available storage volume

d. Potential for gas accumulation in internal turret – explosion risk

e. Internal turrets are easier to weathervane or hold off-axis to create lee for loading from workboats etc

Internal turret external turret

4. Hull tank configuration – three main options exist for hull tank protection configuration. The selection is usually driven by environmental/regulatory requiments:a. Single sided/single bottomed – no additional protection from collision or grounding.

Large fleet of existing tankers exist that may be suitable for conversion.b. Double sided/single bottomed – offers protection from collision damage, but no

additional protection for grounding. May be suitable for permanently moored FPSOc. Double sided double bottomed – protection against collision and grounding. Both

tanker and FPSO industry moving towards this becoming the norm

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5. Hull accommodation configuration – there are two main choices for accommodation, either fore or aft.

6. Offloading options- a function of metocean conditions and the development option chosen. Main alternatives are:a. Tandem moored – most common method. Tanker

pulls up behind FPSO and connects via a hawser and offloading hose. Mooring must be able to restrain both vessels.

b. Bow and aft tandem mooring – used in benign environments with spread mooring so that there is a higher offloading availability

c. Side to side transfer – higher risk. d. CALM buoy - removes FPSO/Tanker interaction so is safer.

Additional expense as CALM buoy and mooring required, and transfer hose to CALM buoy.

e. Pipeline.

7. Conversion vs new-build – usually availability, economic and risk decision. Some of the factors to be considered are:a. Availability of suitable existing hullsb. Cost of new-build vs existing hull and modification/refurbishmentc. Schedule – refurbishment of existing hull may reduce schedule, especially when dry-

dock slots are tightd. Condition of existing hull to met design life requirements of development needs to

be considered (especially fatigue life)e. Refurbishment scope risks associated with re-use of existing hull and associated

equipment/utilities – some FPSOs have experienced large refurbishment budget blow-outs or poor availability in production.

8. Degree of topsides/hull integration is a function of new or existing hull and client preference:

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a. If existing hull then may be savings in re-using existing equipment. Duplication of equipment means additional expense

b. Higher degree of inter-dependency or complexity, then more modes of failure – downtime

c. Mostly applies to power generation, process heat and cooling: If ship is electric propulsion, then integrate power for topsides and propulsion –

as you never process and steam at same time Use of power or direct gas engine for large power uses (compressors, water

injection pumps) If ship is steam, then use steam for process heat. Also waste heat recovery

from generators etc or direct fired heatersd. Also applies to utilities e.g. seawater, cargo handlinge. One problem is that during concept selection the decision to refurbish or new-build

may not have been made, and the philosophy may be different depending upon which is chosen.

f. Additionally the existing equipment and configuration in existing hulls can vary – hence changing the scope – and will only be known once a hull has been selected.

9. Lease vs own- to lease or own is purely an economic/financing decision.

1World's FPSOs

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Advantages of FPSO

Location and sizeo Nowadays FPSOs are often first choice for new areas where there is little or no

existing infrastructure with the possibility of a tie-back to existing hosts or accessing export lines. The self contained nature of the FPSO including its shuttle export system make it ideal for such locations.

Water deptho Floating production systems were first used in shallow water depths, where they

competed with jacket platforms. As exploration and production have moved to ever increasing water depth, production from bottom founded structures is no longer viable and the range of floating systems must be deployed.

Mobilityo In a number of areas of the world it is not possible to design a production system

host that can survive the local weather conditions. Here FPSO are an ideal solution with a disconnection capability to shut down the wells, disconnect and move off station. At the end of the weather situation the FPSO may come back and reconnect to the well systems.

Decommissioning/ re-useFinally a major advantage that floating systems have of fixed platform is that at the end of the field life they may be easily decommissioned and disconnected and taken to dockside. Very often the floating facility can be refurbished or upgraded and re-deployed to another potential field.

5. Miscellaneous: Mooring

An act making fast a vessel, as by a cable or anchor to provide stability to it from wind and waves.

Moorings primarily relevant for FPSO Also applicable to Semisubs & Spars. Current world FPSO fleet moored in waterdepth from

20 m (Chang Qing Hao) to 1,853m (Seillean). Moorings typically easily adapted to deeper water by

upgrading mooring & riser systems

Typical Mooring Types

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a. Mooring: Permanent In cyclonic regions, the magnitude of extreme & ultimate

metocean conditions directly affects the cost and feasibility of a permanent mooring system.

Mooring system is driven by maximum design loads of the permanent configuration.

Additional hull strengthening will be greater for a permanent system.

Greater forecastle height is required to counter the effects of green water for a permanent system.

The greater structural weight in way of the mooring/hull strengthening is countered by the increased simplicity of the permanent system.

A greater number of contractors have demonstrated a proven capability in the design and construction of permanent systems.

Permanent FPSO can be classed as a Fixed FPS. Ship structural fatigue issues are generally not

affected by permanent mooring system. Permanently moored FPSO need not be fitted

with any propulsion/steering machinery.

b. Mooring: Disconnectable If cyclonic region, uncertainty exists as to the

magnitude of extreme & ultimate metocean conditions; impact on a disconnectable system is simply that disconnections occur more often.

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FPSOs

Weathervaning

Permanent

External

Internal

Disconnectable

External

Internal

Spread Moored

Other (Product Transfer) Shallow water: CALM;SALM;YOKES;etc

internal permanent turret

The lower structural weight (less hull strengthening, moonpool, etc.) is countered by the additional complexity of a disconnectable system.

A limited number of contractors have demonstrated a proven capability in the design and construction of disconnectable systems.

The process of reconnecting a disconnectable system requires rope-handling vessels and tugs. Availability requires consideration.

If disconnectable; marine crew required (union/labour issues).

c. Mooring: Spread Moored Anchored Fore & Aft

at both Bow & Stern vessel cannot weathervane(follow wind direction)

Suitable for benign environments only. Large beam/broadside loads. Not suitable for extreme metocean

Mooring Layout

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Several things have to pay high attention.

Large corridors required to route risers/flowlines to the facility. Interaction with drillship anchors Moorings and risers inter-related. Interaction critical => often 3 separate analyses (risers, moorings, floating facility). Mooring spread design to maintain a tight watch circle to maintain station & ensure

acceptable vessel/riser interaction. Station-keeping achieved primarily by spread or group moored anchor pattern. Pattern is typically grouped asymmetric layout depending on prevailing weather and

directionality of extreme & ultimate storm conditions. Grouped anchor lines for permanent & disconnectable mooring arrangement. Optimised layout for intact and damage condition. Grouped moorings permit greater vessel drift (from mean location), but provide

improved performance for possible damaged line condition as required by the certifying authorities.

N

123

45

6

7

8910

N

12

456

789

N

123

45

6

7

8910

NN

123

45

6

7

8910

N

12

456

789

N

12

456

789

Mooring Chain

Moorings typically chain-wire-chain. Fairlead Chain ~ 5” Wire ~ 4” (synthetic) Chain ~ 5” Ground Chain ~ 6” – 8” Anchor Chain ~ 5” Fairlead chain permit marine chain winches to be used to install & tension. Ground chain is thicker/robust due to soil abrasion. Anchors either flukes, suction buckets or piles depending on geotechnical Response primarily dependent on weight & stiffness of mooring lines. Shallow - minor changes to mooring weight & stiffness will not significantly alter facility

behaviour. Deepwater – moorings weight critical.

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Recent advances in synthetic polyester (more elastic but lighter) have replaced wire in deeper water.

CHAPTER 4: Engineering Design Process

Engineering Department in the company:

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1. Process2. Piping3. Mechanical4. Instrument5. Electrician6. Structural

Project engineering design:

1. Feasibility studies2. Conceptual design3. Front End Engineering Design (FEED)4. Detailed design5. Construction6. Pre-commissioning7. Commission8. Production

Explanations of engineering design process:

1. Feasibility studies is an analysis and evaluation of a proposed project to determine if it is technically feasible, is feasible within the estimated cost, and will be profitable.

2. Conceptual design is the first stage of the design process, in which drawings are the dominant tool in showing the proposed project. Usually drawings in this phase are composed of simple plans, instruments, site plans and production flow with related production option.

3. FEED is the stage of a project's lifecycle at a time when the ability to influence changes in design is relatively high and the cost to make those changes is relatively low. It typically applies to industries with highly capital intensive, long lifecycle projects. Though it often adds a small amount of time and cost to the early portion of a project, these costs are minor compared to the alternative of the costs and effort required to make changes at a later stage in the project. During this period, the process flow diagrams are produced by the engineers.

4. Detailed design is the final design stage of the design process, by which the detailed scale of drawings are refined sufficiently to be submitted for approval, including mechanical, electrical, structural, piping and instruments. All the specifications of the material, mechanical instruments (turbines, vessels & etc) and structural dimensions are specify for next construction process.

5. Construction begins based on the design plans and supervised by the engineers.6. Pre-commissioning is a procedure by which a completed process module is tested and

certified to be in operable condition (the condition is rendered by the plan and design function).

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7. Commissioning is a period by which any modification and change will be done during the commissioning period before it is passed to the client/operator.

8. Production starts after all the commissioning is completed by operator.

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CHAPTER 5: Process Module and Equipment

A complete production system consists of a number of process modules. Each module has their job description to produce pure cleaned oil as the final output before being transferred to the customer.

1. Launcher and receiverFor WHP, it is very small and no facilities for water injection, gaslift system and hydrocarbon pump. Therefore the platform needs external support from main platform which has those systems to provide water injection and so on. On the platform, there are only receiver and launcher to be connected from the main platform.- FWS pipe receiver- Gaslift/ injection launcher- Water injection launcher

2. Separation system- Separator

An item of production equipment used to separate liquid components of the well stream between gaseous elements, water and hydrocarbon. Separators are either vertical or horizontal and either cylindrical or spherical in shape. Separation is accomplished principally by gravity, the heavier liquids falls to the bottom and the gas rises to the top. A float valve or other liquid-level control regulates the level of oil at the bottom of the separator. Basically, separator operates in 2 stages. The first stage is high pressure (HP) separator about 3-5MPa and the inlet temperature 100-150oC. The second stage is low pressure (LP) separator about 1MPa and inlet temperature 100oC.

- Degasser.For small amount of entrained gas, the degasser can play a major role of removing small bubbles that a liquid film has enveloped and entrapped. It releases and breaks out the air and gas such as methane, H2S and CO2 from the mud to the surface for PW (produced water) treatment.Electrostatic coalescerA device, located in a separator vessel having an inlet and a number of outlets, through which a mixture of fluids flows, for promoting electrostatic coalescence of a first conductive fluid emulsified in a second fluid, said device comprises a number of tubular electrostatic coalescer elements extending in the flow direction which are arranged in a matrix substantially covering the entire cross sectional area of said

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vessel, and means to apply an electrical field to the fluids flowing through said coalescer elements.

3. Produced water treatment system.The crude oil consists of water, gas and oil. After the water has been extracted from the crude oil, it still needs to be treated to make sure the oil is totally extracted from the water until the water achieve below the standard value (nowadays: 40ppm) before it is released to the ocean or reuse for potable water.

- HydrocycloneA hydrocyclone has two exits on the axis: the smaller on the bottom (underflow or reject) and a larger at the top (overflow or accept). The underflow is generally the denser or thicker fraction, while the overflow is the lighter or more fluid fraction. Internally, centrifugal force is countered by the resistance of the liquid, with the effect that larger or denser particles are transported to the wall for eventual exit at the reject side with a limited amount of liquid, whilst the finer, or less dense particles, remain in the liquid and exit at the overflow side through a tube extending slightly into the body of the cyclone at the center. In production its main use to separate oil from water or vice versa.

4. Crude oil export system.Basically, during transportation in the pipeline, the flow pressure will reduce within the pipeline as result of pipe diameter, frictions and elbows. The pump uses to increase back the pressure within the pipeline thus the flow run smoothly. The flow is measured by meter prover for customer and operator references.- Crude oil booster pump- Oil metering skid and oil meter prover.

5. Production gas compressionsThe purpose is to increase the gas pressure either to flow through the pipeline to the shore or gas reinjection. The scrubber and discharge cooler are form part of the auxiliary - Suction scrubber

A compressor suction scrubber is a vessel whose purpose is to knock-out liquid from a gas stream. Condensate can damage the compressor. Change of volume will reduce the gas flow and droplets begin to form, this shall separate between gas and condensate.

- Gas compressor.

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This will be explained more on next Compression report.- Discharge cooler.- A compressor aftercooler is required to cool the gas stream for next stage of the

process.

6. Gas dehydrationThe purpose is to remove moisture from natural gas. Natural gas usually contains a large amount of water that can cause several problems for downstream processes and equipments. At low temperatures the water can either freeze in piping or, as is more commonly the case, form hydrates with CO2 and hydrocarbons. Depending on composition, these hydrates can form at relatively high temperatures plugging equipment and piping. Without dehydration, a free water phase (liquid water) could also drop out of the natural gas as it is either cooled or the pressure is lowered through equipment and piping. This free water phase if combined with H2S and CO2 can form acidic fluid thus cause corrosion. The skid consists of:- Glycol contactor.- Glycol re-gen package

7. Fuel gas systems The purpose of this system is to treat natural gas before entering the fuel gas super heater. The super heated gas will be used by gas turbine/engine.- Fuel gas suction scrubber- Gas compressor- Discharge cooler- Fuel gas super heater

8. Open and closed drains system.

The objective of drain systems is to safely collect and transport residual process fluids, hydrocarbon liquid and/or chemical spills, deluge water and rain water to an appropriate disposal location giving consideration to protection of personnel, plant, equipment and preventing environmental pollution. The fluids are contained, collected and sent to a recovery unit or disposed of in a safe manner.

a. Open drain - The Open Drain system will be installed to catch storm water, firewater, washdown and any spills of fluids into bunds around process equipment and process laydown areas. The open drain system will consist of strategically placed tundishes and deck drains that will feed open drain headers that spider throughout the upper and lower decks of the ship and flow to an

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Open Drain Header before routed to the slop tank which details is under marine scope of design. There will be separate “Safe Area” and “Hazardous Area” open drain systems.

b. Close drain - The Closed Drain system will be installed to catch fluids that are drained from pressure vessels (like the HP Separator) when they are emptied for maintenance. Fluids will dump into the closed drain collection network under the process skids above the ships deck and terminate at a Closed Drain Sump Vessel that will be mounted on deck.

- Sewage treatment operationGrey water: waste from sinks, bathroom and pipes. Usually the waste will be directly flowed out in to the sea without any treatment procedures.Black water: waste from toilet bin (hard waste).When the waste enter macerator, it is then blended before flowed out to the sea.The other way is gathering the waste and then biologically degraded. The second way is using chlorine which extracted from the sea water (electrolysis) to degrade the waste before flowed out to the sea

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9. Flare system

Flare system shall be designed to handle hydrocarbon relief from all process vessels. All the gases will be gone through knock-out vessel prior to flare as to remove all the unwanted condensate. The condensate is pumped to separation unit and the gas will be flared.

10. Instrument and utility air systemThe process facility shall have a dedicated instrument air system. Air from the compressors will be dried through air dryer skids. One air dryer will be in service while the other dryer is regenerating. Following drying of the air, it will be stored in the Instrument / Utility air receiver. From there it will be distributed to end users. Operating and design conditions shall be developed based on following conditions:

a. Instruments air operating& design conditions

b. Utility air operating& design conditions

11. Diesel fuel systemThe diesel oil system shall be designed to supply diesel oil to end users. The diesel supply should design to have enough fuel for certain duration specified by client. Diesel coalescer is required to provide clean / treated diesel fuel for turbine generators to meet the following specification.- Diesel fuel coalescer

The purpose is to separate water, particle, solid and gas from the diesel. Then it is transferred to storage tank.

12. Chemical injection system.Some chemical injected to the flowline as preventive to corrosion, wax formation and emulsions in the transferred fluid. The chemical store in the tote tank and is injected using plunger in the metering pump. Some of the chemicals use as below:- Corrosion inhibitor- Scale inhibitor- Demulsifier

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- Wax inhibitor

13. Nitrogen generation packageThe nitrogen gas is used to purge or to act as blanket in identified service (by client). Nitrogen generator consists of membrane where 99.5% oxygen is being removed from the compressed air.

14. Water injection systemThe system is basically to clean and provide enough pressure for well water injection. The water pumped up from the sea, cleaned and filtered using the coarse and fine filter. All the free oxygen gas is removed using deaerator. Typical equipment in the system are:- Deaerator- Coarse filter- Fine filter- Vacuum pump

15. Power generation systemThese generators shall provide the required and adequate power capacity to production complex. This system typically will be run by gas turbine generator. However, some clients prefer to choose other system such as steam turbine, gas engine and etc.

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