selecting the right field development plan for global deepwater developments 2

Deep Offshore Technology, 27-29 November 2012, Perth, Australia

Paper # 2317

1

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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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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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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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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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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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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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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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

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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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 stage-

gated 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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Figure 1 Deepwater Field Development Planning Overview


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Figure 2 Field Development Planning Cycle

Figure 3 Typical Production Profile

Figure 4 A 6th Generation Drilling Semisubmersible

Oil Well

Production Profile

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

0 180 360 540 720 900 1,080 1,260 1,440 1,620 1,800 1,980 2,160

Day

Ra

te (

stb

/d)

/ R

es

erv

oir

Pre

ss

ure

(p

sia

)

0

3

6

9

12

15

18

21

24

Wa

terc

ut

(%)

/ G

as

Ra

te (

MM

sc

fd)

Oil Rate

Reservoir

PressureWater Cut

Gas Rate


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Figure 5 Select Phase Screening Methodology


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Figure 6 Catalogue of Floating Platform Building Blocks


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Figure 7 Field Development Scenario Generation with Building Blocks


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Table 1 Strategies for Managing Well Performance and Reservoir Uncertainty

Strategy Description Duration

(months) Pros Cons Examples

Drill Stem

Test

Single Well

producing to

MODU, gas

flared

1-2 per

well Relatively low cost

($100M - $150M per

well);

MODU can be used

for testing.

Some (but

insufficient) well

performance data

Limited well

connectivity data

Jack (Lower

Tertiary,

GOM)

More

Appraisal

Wells and

Sidetracks

Drill additional

appraisal wells to

define extent and

connectivity of

reservoir

6-12 per

well Some wells designed

as keepers

More reservoir data

and improved

reservoir model

Increased cycle

time to sanction

Limited well

performance data

Extended Well

Test

Single well

producing to

production

platform

6-12 Improved confidence

in well performance

and recovery

Better definition of

reservoir connectivity

18-24 months to

mobilize

production platform

Capex in $400M -

$600M range

Roncador

(Campos

Basin,

Brazil)

Phased

Development

(Early

Production

System)

Multiple wells

producing to

mobile production

platform; gas

exported or

injected

36-60+ Significant reduction

in well performance

and reservoir

connectivity risk;

Test enabling

technologies and

completions;

Optimize full field

development plan to

capture reservoir

upside.

Significant Capex

($1B $3B) outlay

36+ months to

mobilize platform

Cascade &

Chinook

(Lower

Tertiary,

GOM)

Staged

Development

Bring wells online

to a production

platform in stages

Life of

field Flexibility to capture

reservoir upside

Maximize reservoir

recovery

Largest Capital

investment and

longest schedule to

peak production

among all options

Perdido

(Lower

Tertiary,

GOM)


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Table 2 Surface Facility Building Blocks

Subsea

Production

Enhanced

Recovery

Drilling

Platform

Host

Production

Platform

Export

System

Onshore

Facility

Single well

tieback

Cluster well

manifold

with dual

flowline

tieback

Mudline

Separation

and ESPs

Multiphase

Pumps

Subsea Gas

Compression

Gas Lift

Gas

Injection

Water

Injection

Mobile

Offshore

Drilling Unit

Tender

Assist

Wellhead

Spar

Full drilling

wellhead

Spar

Tender assist

wellhead

TLP

Full drilling

wellhead

TLP

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

Oil Pipeline

Gas Pipeline

Oil shuttle

tanker

LNG shuttle

Tanker

FSO with

Oil Shuttle

Oil Tank

Farm /

Terminal

Gas

Processing

Plant

Gas to

Liquids

Plant

Gas to

Power Plant

LNG Plant


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Table 3 Qualitative Screening Matrix

Option IDSubsea

Producti

on

Enhance

d

Recover

y

Producti

on

Platform

Gas

Export

Oil

Export

Onshore

Oil Plant

Onshore

Gas

Plant

Overall

Preference

(Weighted)

Technical

Driver 1

Technical

Driver 2

Technical

Driver 3

Technical

Driver 4

Technical

Driver 5

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

1.0 35% 30% 20% 10% 5%

Sum of Weights

Scoring: 5 most preferred; 1 least preferred

Driver weighting

selecting the right field development plan for global deepwater developments 2

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