Selecting the Right Field Development Plan for Global - KBR

Deep Offshore Technology, 27-29 November 2012, Perth, Australia
Paper # 2317
Selecting the Right Field Development Plan
for Global Deepwater Developments
Richard D’Souza, Shiladitya Basu, Ray Fales
Granherne
A KBR Company
Abstract:
Production from deepwater fields began in earnest just fifteen years ago. Currently deepwater
developments provide about 10% of global oil supply. In the future, an increasing percentage of
the world’s oil and gas supply will come from deepwater. An assessment of existing projects
revealed that a significant percentage underperformed technically and commercially. Inadequate
attention to and poorly executed field development planning (FDP) was identified as a leading
causal factor. With large capital outlays and increasingly complex developments, industry has
acknowledged the need for a rigorous, structured development planning process to fully realize
the commercial value of deepwater projects.
A major objective of the FDP process is the selection of a development plan that satisfies an
Operator’s commercial, strategic and risk objectives, subject to regional and site constraints. The
process requires continuous and effective collaboration and alignment amongst the major
stakeholders, which include the reservoir, well construction, surface facilities and commercial
teams.
This paper will:
Present an overview of the FDP process
Establish the links between reservoir characteristics, well construction and surface
facilities
Examine major regional and site considerations that influence selection of a development
plan
Describe a structured FDP selection methodology
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Deep Offshore Technology, 27-29 November 2012, Perth, Australia
Paper # 2317
The material will provide development planners with a systematic roadmap to select the right
development plan for a specific deepwater field that will meet the project’s commercial, risk and
strategic objectives with a high degree of certainty.
Introduction
Global demand for oil and gas has been steadily increasing and is projected to continue on this
growth trajectory for the foreseeable future. The price of oil and gas, which are publicly traded
commodities, is determined by the spread between demand and supply. The current high oil price
is a response to forecasts that supply will have difficulty keeping up with demand. To minimize
further escalation oil and gas supply must keep pace with rising demand.
Currently a large percentage of total daily oil and gas supply are from offshore developments.
Supply from shallow water fields is in terminal decline. Production from deepwater (1000m –
2000m) and ultra deepwater (>2000m) is projected to provide most of future growth
requirements. The contribution of non-OPEC oil supply from deepwater is projected to grow to
35% in 2030, from about 12% today. The industry currently has the proven capability to drill and
produce deep reservoirs in up to 3000m water.
Field Deepwater Planning (FDP) Overview
The FDP process involves a continuous interaction between three key elements: subsurface, well
construction, and surface facilities (Figure 1). Regional considerations and site conditions play
key roles in the decision making process. The goal is to select a facilities development plan that
is compatible with the reservoir depletion plan while satisfying an Operator’s technical, risk and
commercial requirements.
In the early years of deepwater development there was little communication between these three
elements. Deepwater technology was evolving and choices for facility building blocks were
limited. Further, some Operators were pushing for faster, cheaper developments. The upshot was
that a significant percentage of deepwater developments underperformed. Fortunately rising oil
and gas prices and high productivity wells allowed Operators to make satisfactory commercial
returns in many cases.
Over the years, technology advanced and surface facility choices grew. However high capital
costs and substantial risks and uncertainties inherent in developing deepwater fields remained.
The industry recognized the need for a structured and phased development planning process.
This evolved into the phased FDP cycle shown in Figure 2. At the end of each phase is a stage
gate where a decision to proceed, discontinue or recycle must be made. Final investment decision
or sanction occurs after the Define phase. The greatest value to a project is created in the
Appraise and Select phases which involve:
- Developing a robust reservoir model and depletion plan
- Optimizing drilling program (greatest recovery with fewest wells)
- Minimizing well performance uncertainty
- Selecting the right surface facility plan
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Deep Offshore Technology, 27-29 November 2012, Perth, Australia
Paper # 2317
The spend in these phases is generally a small percentage of total development spend but
provides substantial added value to the project.
Reservoir Characterization and Depletion Plan
The FDP process begins in earnest following a successful exploration and appraisal program.
The first step is for the subsurface team (geologists, geophysicists, and reservoir engineers) to
generate a robust model of the reservoir from seismic, well log and drill stem test data. The last
decade has seen step changes in the ability to rapidly develop sophisticated models. The key is in
data interpretation and assignation of rock properties (permeability and porosity) that drive well
performance to the model. This is followed by multiple simulations by varying well count,
profile and completion types and assessing well performance and recovery. A typical well
production profile is shown in Figure 3. Because of the extremely high cost of drilling and
completing wells it is critical to establish a depletion plan that maximizes recovery factor with
fewest wells. With complex reservoirs (stacked, faulted) or those with poorly understood
geology, a decision on measures to reduce uncertainty must be made.
Strategies to manage reservoir uncertainty are summarized in Table 1 (Ref. 1). They are, in
order of increasing capital cost and uncertainty reduction; drill stem test, more appraisal wells,
long term test, phased and staged development. The FDP team must trade-off the cost associated
with each strategy against the value of information obtained in mitigating reservoir and well
performance uncertainty.
The success of the FDP lies in the skill of the subsurface team in achieving the highest recovery
factor with fewest wells while factoring in uncertainty in key variables as well as the cost and
complexity of well construction and completion. Additionally the top hole locations and
dispersion of wells at the seabed drive the selection of the facilities development plan. The
greater the interaction between the subsurface, well construction and facilities teams in the
appraise and select phases of the FDP, the greater the probability of achieving this goal.
Well Construction and Intervention
The cost of drilling and completing deepwater wells can often consume half the development
budget because of the high spread rates of new generation, high capacity drilling rigs (Figure 4)
and drilling durations. Drilling ultra deepwater wells must overcome significant challenges such
as high currents in the water column, thick unstable salt formations, shallow geohazards and
water flows and very high pressure and temperature reservoirs.
Wells have to be periodically re-entered for reservoir management, remediation and
recompletions. Wells directly accessed from a production or wellhead platform enable easier and
more frequent intervention than subsea wells resulting in lower operating cost and increased
recovery. They also facilitate easier running and retrieval of downhole boosting pumps which
can substantially enhance production profiles and ultimate recovery. Choosing between direct
access and subsea wells is an important decision in the FDP process.
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Deep Offshore Technology, 27-29 November 2012, Perth, Australia
Paper # 2317
In the aftermath of Macondo, industry has tightened regulations, increased oversight,
implemented additional safety measures in well construction and developed sophisticated oil
spill response measures to rapidly cap, contain and clean up spills resulting from loss of well
control in a deepwater well.
Regional Considerations
Regional considerations have a significant impact on the FDP process. The host country dictates
the terms and conditions of the exploitation of its hydrocarbon resources. These vary
significantly from country to country. A few of the more impactful regional considerations are
briefly discussed.
The Production Sharing Agreement defines commercial and contractual terms between the host
nation and the block operator. These include capital cost recovery, production sharing terms,
taxes and royalties that strongly influence project economics and development strategies.
Local content requirements are country specific, are becoming more prescriptive, and must be
factored into the development planning decision process.
Regions that have well developed infrastructure (existing host facilities, pipeline grid, shore
bases, etc.) provide an operator with considerable FDP flexibility as will those that have ready
markets and distribution networks for produced oil and gas. Those that do not will have higher
capital, operating and midstream costs. Monetizing produced gas in regions that cannot consume
it is a particularly challenging issue.
The host nation will have a regulatory regime that oversees safety and environmental impact of
drilling and production operations. Developed nations have more stringent regulations that will
result in higher development costs.
Site Characteristics
Field architecture and floating platform selection are strongly influenced by site-specific water
depth, metocean conditions, seabed bathymetry and geotechnical conditions. For example loop
and eddy currents prevalent in the Gulf of Mexico (GoM) substantially impact drilling and
seabed installation operations and drive fatigue lives of mooring and riser systems. The capex,
drillex and opex of platforms located in sites subject to hurricanes or cyclones will be
significantly higher than those in mild or moderate metocean conditions.
Seabed bathymetry and geotechnical conditions influence well and platform placement and
technical feasibility of station-keeping systems. Rough seabed terrain, escarpment and canyons
will drive field architecture, flowline routing and installation cost of infield flowlines.
It is imperative that quality site-specific metocean, bathymetry and geotechnical data be acquired
prior to undertaking facility development planning.
Overview of Select Phase Screening Methodology
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Deep Offshore Technology, 27-29 November 2012, Perth, Australia
Paper # 2317
A typical screening methodology is summarized in Figure 5. The subsurface team creates a
reservoir model from available seismic and well log data. Working in concert with the well
construction team they generate reservoir depletion scenarios (production, injection well count
and seabed locations, production profiles with associated uncertainties). The number of scenarios
will depend on the size, geometry and complexity of the reservoir and its rock and fluid
properties.
The surface facility team then generates development scenarios to match these reservoir
depletion scenarios, factoring in regional considerations and site conditions. It is possible to
create a large number of facility development scenarios from the catalogue of available and
proven facility components. A procedure to ensure that all probable development scenarios
consistent with reservoir and site constraints are visualized and assessed is described. It consists
of deconstructing the facility development into discrete building blocks (subsea, floating
systems, export systems) which are combined appropriately into a number of discrete facility
development scenarios.
If the number of scenarios is large (10 or more) a two stage screening process is recommended.
The first is qualitative based on scoring and ranking non-commercial factors. This requires an
experienced multi-disciplinary facilities team to achieve the desired result of selecting a smaller
group of technically feasible development scenarios for the second stage screening.
The second stage screening is a quantitative comparison of economics of each scenario. This
requires concept definition of the scenario building blocks followed by capex, opex, and
schedule estimates to a defined accuracy level. The commercial team will create economic
models from this information. The models will assess life cycle economics of each scenario
(including drillex, revenue streams, decommissioning) with production sharing terms factored in,
against specific commercial hurdles required to sanction a project. If more than one development
scenario clears the commercial hurdles then the final selection will be based on strategic drivers,
contracting strategies and relative risk assessment.
Surface Facility Building Blocks
A deepwater facility development scenario can be constructed from the following building
blocks: Subsea System, Drilling Platforms, Production Platform, Export System and Onshore
Facilities (Table 2).
Subsea System Building Blocks: A subsea system consists of an assemblage of trees, manifolds,
umbilicals and flowlines to a riser pipeline end termination (PLET). The basic building blocks
are the single well tieback and a multi-well manifolded tieback. A variety of subsea architectures
can be generated from these basic building blocks regardless of well count and seabed dispersion
of subsea trees. It is advisable to have seabed bathymetry data and to layout the subsea
architectures including routing of flowlines to potential host platform locations. Preliminary
hydraulic analysis runs are conducted to size flowlines and derive arrival production rates,
temperatures and pressures at the platform.
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Deep Offshore Technology, 27-29 November 2012, Perth, Australia
Paper # 2317
Enhanced Recovery Building Blocks: Enhanced recovery is often necessary to boost well flow
rates as reservoir pressures decline to overcome the large hydrostatic heads in ultra deepwater
and ensure ultimate recovery for a commercially viable development. Traditional enhanced
recovery building blocks are water and gas injection via subsea wells and gas lift at riser base or
downhole. Feasibility and reliability of subsea mechanical boosting technologies in increasingly
deeper waters have greatly improved and are included as building blocks.
Drilling Platform Building Block: Subsea wells remote from the host platform will generally be
drilled and completed by a Mobile Offshore Drilling Unit. These will be spread moored or
dynamically positioned semisubmersible or dynamically positioned drillships. In some cases
where a large reservoir can be depleted from a single drill center, a tender assisted or full drilling
wellhead spar or TLP can be used as a building block in conjunction with an FPSO stationed in
close proximity.
Host Platform Building Blocks: The host platform building block consists of topsides, hull,
station-keeping and riser systems. Besides the fundamental mission of processing well fluids, a
host platform could have drilling or workover functions. There is a growing catalogue of mature
production platforms (TLP, spar, semisubmersible, ship-shape FPSO) and proven platforms
(cylindrical FPSO, FDPSO), to select from (Figure 6). An addition to the host platform
catalogue is the FLNG platform for large remote gas fields, following recent the sanction of two
FLNG projects. A potential building block is an existing floating production platform or a
shallow water fixed platform located within subsea tieback distance.
Export System Building Blocks: The host platform processes hydrocarbons to pipeline or sales
quality oil and gas. Each will have an oil and gas export system. Oil export system building
blocks will include pipeline to market on onshore tank farm or via direct shuttle tanker loading
from an FPSO host. For host platforms without buffer storage capability (Semi, TLP, Spar) an
option is to direct the flow to an FSO/shuttle tanker combination. Gas export building blocks
will include pipeline to shore for onshore processing or conversion to LNG or power. A FLNG
host will export its product by direct offloading to a LNG tanker.
Onshore Facility Building Blocks: These could include a tank farm and loading terminal for oil
stream and a gas processing plant for LNG plant with storage and loading terminal for the gas
stream. Other potential options are converting gas to wire or liquids at an onshore plant.
Combining Building Blocks into Development Scenarios
The most effective way to generate multiple facilities development scenarios is via a facilitated
framing workshop with representatives from all stakeholders present. The workshop should be
held early in the select phase with the following objectives:
Establish design basis
Generate development scenarios
Develop decision drivers and scoring methodology
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Deep Offshore Technology, 27-29 November 2012, Perth, Australia
Paper # 2317
Establishing Design Basis: The design basis provides the framework and constraints within
which the development team must operate. The design basis as a minimum must include
relevant data related to:
Reservoir Characterization & Depletion Plan: well count and seabed locations, fluid
properties, production profiles, enhanced recovery, reservoir management
Drilling & Completions: on well locations, drilling or workover rig specifications,
drilling and completion durations, intervention type and frequency
Site and Regional Conditions: water depth, metocean conditions, seabed bathymetry and
geohazards, infrastructure and logistics, local content requirements
Generate Development Scenarios: This is a two step process illustrated in Figure 7. The first is
to choose applicable components from each surface facility building block (Table 2) consistent
with Design Basis requirements and constraints. There are a large number of floating platform
building blocks that include platform types (Figure 6), as well as variations in hull configurations
and topsides functional capabilities. Reference 3 provides a decision tree approach to selecting
the most appropriate building blocks for GoM deepwater development based on a hierarchy of
recoverable reserves, well count, production rates, well seabed locations and water depth.
The next is to assemble surface facility development scenarios by combining components from
each building block. As many practical combinations should be included at the stage to insure
that all probable development scenarios are canvassed. Figure 7 shows how four scenarios are
generated from generic building blocks for illustrative purposes. The qualitative screening
process described below can assess and grade (or rank) preferred scenarios from a large
population very efficiently.
Decision Drivers & Scoring Methodology: A qualitative ranking method to grade and screen
development scenarios is described. A set of decision drivers is established and agreed upon.
These must capture major non-commercial factors that drive an Operator’s selection decision.
The drivers should be mutually exclusive and limited to about five or six. Typical drivers are:
Minimize technical risk
Maximize hydrocarbon recovery
Schedule to first oil or gas
Flexibility for future expansion
Flexibility to adapt to reservoir uncertainty
Operability, Reliability, Availability
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Deep Offshore Technology, 27-29 November 2012, Perth, Australia
Paper # 2317
The selected drivers should be weighted to reflect their relative importance in achieving
development objectives. Each driver is scored on a scale of 1 to 5 with the high score indicating
greater desirability. A rationale for assigning relative scores should also be established to ensure
that sufficient, consistent and explainable differentiation is achieved.
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Qualitative Screening Matrix
Deep Offshore Technology, 27-29 November 2012, Perth, Australia
Paper # 2317
A typical qualitative screening matrix is shown in Table 3 using the four scenarios generated
above (Figure 7). Each development scenario is listed in a row of the matrix. For clarity the
building blocks used to create the scenario are identified. The scenario is then scored on the 1-5
scale for each decision driver and weighted average score is calculated. Once all scenarios are
scored, those with the highest weighted average scores are short listed for the second stage
(quantitative) screening. A “threshold” score can be established with scenarios exceeding the
score retained and the rest triaged. Since commercial considerations are not addressed in this
screening, it is important to retain scenarios that bracket a range of options from those with low
capex and schedules to those with greater capex but higher throughputs and ultimate recovery. It
is typical to retain from 5 to 10 development options for second stage screening.
Second Stage Screening
Each surviving FDP scenario is subjected to a quantitative screening process executed in three
phases.
Concept Definition: The objective is to define all surface facility components to a level
sufficient to generate Class 4 capex, opex and schedule (sanction to first oil/gas) estimates as
input to the economic model.
It begins by developing overall field architecture that locates all building blocks and establishes
their interconnection (flowline and pipeline routing) subject to reservoir geometry, well
locations, site specific bathymetry and regional constraints. Flow assurance simulations will size
flowline, risers and pipelines, define measures to prevent plugging of in-field flowlines in
operating and shut-in conditions (chemicals, insulation etc.) and determine arrival pressures,
temperatures, and flow rates of production fluids at the platform. Topside equipment needed to
process and export oil and gas and to support other functional requirements (drilling rig,
enhanced recovery, riser tensioning) is defined and a deck layout prepared to suit the specific
hull configuration topside weight and CG are estimated.
The hull configuration is sized to support the topsides, riser, hull and mooring weight. Global
performance and stability are validated to ensure operability and survivability in extreme seas.
Technical verification of mooring and riser systems follow to a level sufficient to verify technical
feasibility. An execution plan for the design, fabrication, integration, transportation and
installation of subsea, floating platform and export systems is developed which will be the basis
for capex and schedule estimates. A high degree of confidence and consistency in developing
these estimates is essential to ensure an equitable comparison of scenarios. Validation by
benchmarking against analogous projects is recommended.
Economic Analysis: Commercial and economic teams conduct an economic analysis of each
FDP scenario to derive commercial metrics such as NPV and IRR. Principal drivers that
influence these metrics are capital and operating costs, production profiles, ultimate recovery and
realized sale price of produced oil and gas. Each driver has associated uncertainties which are
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Deep Offshore Technology, 27-29 November 2012, Perth, Australia
Paper # 2317
quantified by probabilistic analysis. The NPV reflects impacts of taxes, royalties and other
relevant terms in the Production Agreement with the host country.
Final Selection: The metrics of each scenario are compared against a commercial threshold.
Those that exceed the threshold are compared against each other. If one scenario is clearly
differentiated it will be recommend as the field development plan. If commercial metrics of
several scenarios are within the margin of error of estimates, then a relative risk assessment will
further differentiate and facilitate recommendation of a scenario. These include technical,
execution, operational, safety and commercial risks. Scenarios that provide greater contracting
flexibility and flexibility to adapt to reservoir uncertainty will be favored.
The FDP team will present a justification for the recommended field development plan to
management backed up with a decision support package to enable passage through the Select
stage gate and into the Define phase of the FDP process.
Conclusion
Deepwater projects are capital intensive and complex undertakings requiring a phased stagegated
process to select and execute the development. The greatest value to a project is realized
in the Appraise and Select phase of the process when the field development plan (subsurface,
drilling and completions, surface facilities) is picked for the Define phase. A methodology to
generate, screen and select a development plan that has a high probability of achieving defined
project objectives is presented. A necessary condition for selecting the right project for a
deepwater development is the skill and experience of the team and continuous and effective
collaboration between the multiple disciplines that comprise the team.
References:
1. D’Souza R., Basu S., “Field Development Planning and Floating Platform Concept Selection
for Global Deepwater Developments;” OTC 21583; 2011.
2. Xia J., D’Souza R., “Applicability of Various Floating Platform Designs for Deepwater
Hydrocarbon Production Off North West Australia,” DOT 2012, Perth.
3. D’Souza R., Basu S., “Selecting Floating Platforms for Developing Deepwater Gulf of
Mexico Fields”, DOT Houston, 2010.
4. D’Souza R., Basu S., “Importance of Topsides in Design and Selection of Deepwater
Floating Platforms”, OTC 22403, OTC Brazil 2011.
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Deep Offshore Technology, 27-29 November 2012, Perth, Australia
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Figure 1 Deepwater Field Development Planning Overview
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Deep Offshore Technology, 27-29 November 2012, Perth, Australia
Rate (stb/d) / Reservoir Pressure (psia)
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Figure 2 Field Development Planning Cycle
8,000
7,000
6,000
5,000
4,000
3,000
2,000
1,000
0
Reservoir
Pressure
Oil Well
Production Profile
Water Cut
Gas Rate
0 180 360 540 720 900 1,080
Day
1,260 1,440 1,620 1,800 1,980
0
2,160
Figure 3 Typical Production Profile
Oil Rate
Figure 4 A 6th Generation Drilling Semisubmersible
24
21
18
15
12
9
6
3
Watercut (%) / Gas Rate (MMscfd)
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Deep Offshore Technology, 27-29 November 2012, Perth, Australia
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Figure 5 Select Phase Screening Methodology
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Deep Offshore Technology, 27-29 November 2012, Perth, Australia
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Figure 6 Catalogue of Floating Platform Building Blocks
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Deep Offshore Technology, 27-29 November 2012, Perth, Australia
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Figure 7 Field Development Scenario Generation with Building Blocks
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Deep Offshore Technology, 27-29 November 2012, Perth, Australia
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Table 1 Strategies for Managing Well Performance and Reservoir Uncertainty
Strategy Description Duration
(months)
Drill Stem
Test
More
Appraisal
Wells and
Sidetracks
Single Well
producing to
MODU, gas
flared
Drill additional
appraisal wells to
define extent and
connectivity of
reservoir
Extended Well Single well
Test producing to
production
platform
Phased
Development
(Early
Production
System)
Staged
Development
Multiple wells
producing to
mobile production
platform; gas
exported or
injected
Bring wells online
to a production
platform in stages
1-2 per
well
6-12 per
well
Pros Cons Examples
Relatively low cost
($100M - $150M per
well);
MODU can be used
for testing.
Some wells designed
as keepers
More reservoir data
and improved
reservoir model
6-12 Improved confidence
in well performance
and recovery
Better definition of
reservoir connectivity
36-60+ Significant reduction
in well performance
and reservoir
connectivity risk;
Test enabling
technologies and
completions;
Optimize full field
development plan to
capture reservoir
Life of
field
upside.
Flexibility to capture
reservoir upside
Maximize reservoir
recovery
Some (but
insufficient) well
performance data
Limited well
connectivity data
Increased cycle
time to sanction
Limited well
performance data
Jack (Lower
Tertiary,
GOM)
18-24 months to Roncador
mobilize (Campos
production platform Basin,
Capex in $400M - Brazil)
$600M range
Significant Capex
($1B $3B) outlay
36+ months to
mobilize platform
Largest Capital
investment and
longest schedule to
peak production
among all options
Cascade &
Chinook
(Lower
Tertiary,
GOM)
Perdido
(Lower
Tertiary,
GOM)
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Subsea
Production
Single well
tieback
Cluster well
manifold
with dual
flowline
tieback
Deep Offshore Technology, 27-29 November 2012, Perth, Australia
Enhanced
Recovery
Mudline
Separation
and ESPs
Multiphase
Pumps
Subsea Gas
Compression
Gas Lift
Gas
Injection
Water
Injection
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Table 2 Surface Facility Building Blocks
Drilling
Platform
Mobile
Offshore
Drilling Unit
Tender
Assist
Wellhead
Spar
Full drilling
wellhead
Spar
Tender assist
wellhead
TLP
Full drilling
wellhead
TLP
Host
Production
Platform
Dry Tree
Spar with
Drilling
Dry Tree
Spar with
Workover
Wet Tree
Spar
Dry Tree
TLP with
Drilling
Dry Tree
TLP with
Workover
Wet Tree
TLP
Shipshape
FPSO
Cylindrical
FPSO
Production
Semisub
Production/
Drilling
Semisub
FLNG
Existing
Host
Fixed
Platform
Export
System
Oil Pipeline
Gas Pipeline
Oil shuttle
tanker
LNG shuttle
Tanker
FSO with
Oil Shuttle
Onshore
Facility
Oil Tank
Farm /
Terminal
Gas
Processing
Plant
Gas to
Liquids
Plant
Gas to
Power Plant
LNG Plant
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Option ID Subsea
Producti
on
Enhance
d
Recover
y
Deep Offshore Technology, 27-29 November 2012, Perth, Australia
Producti
on
Platform
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Table 3 Qualitative Screening Matrix
Gas
Export
Oil
Export
Onshore
Oil Plant
Onshore
Gas
Plant
Overall
Preference
(Weighted)
Scoring: 5 most preferred; 1 least preferred
Technical
Driver 1
Technical
Driver 2
Technical
Driver 3
Technical
Driver 4
1 1S 1E 1P 1GX 1OX 1OP 1OG 3.2 3 4 2 3 5
2 1S 1E 2P 1GX 1OX 2OP 2OG 3.4 4 5 1 1 4
3 1S 2E 3P 2GX 2OX 1OP 1OG 3.8 5 3 3 4 3
4 2S None 4P 2GX 2OX 2OP 2OG 2.2 1 1 5 5 1
Driver weighting
1.0
Sum of Weights
35% 30% 20% 10% 5%
Technical
Driver 5
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