TECHNOLOGY FOCUS
Field Development
Projects
World demand for oil has moved the industry to increase its exploration in deep
and ultradeep water, resulting in several oil discoveries. Brazil, West Africa, and
the Gulf of Mexico are places where significant reserves have been found in
recent years and where several deepwater fields are now producing oil.
The recent disaster in the Gulf of Mexico and its environmental effects call
everybody’s attention to the risks involved in offshore operation, particularly in
deep water. This accident will move the industry to find new solutions to minimize the risks to continue exploring for and producing oil from deepwater fields.
Changes in regulation, new equipment requirements, and safety procedures
will be implemented to make operations in deep water safer. We should also
expect increased costs, but this will allow the industry to develop and produce
in deep water with less environmental risk.
Several fields are producing oil from deep water. For this feature, I have
selected papers presenting interesting and successful field-development projects.
Akpo field producing light oil in Nigeria, Parque das Conchas producing heavy
oil in Brazil, and Azurite in the Republic of Congo are good references. Azurite is
also the first development project to use a floating drilling, production, storage,
JPT
and offloading vessel.
Mauricio P. Rebelo, SPE, is a Technical
Services Manager for Petrobras America
Inc. for the Gulf of Mexico. His 23-year
career at Petrobras spans engineering
and management positions in drilling and
completion activities and includes participation in projects in South America,
Africa, the Middle East, and the Gulf of
Mexico. Rebelo holds an electrical engineering degree from Universidade Gama
Filho, Rio de Janeiro. He serves on the
JPT Editorial Committee.
Field Development Projects additional reading
available at OnePetro: www.onepetro.org
OTC 20395 • “Thunder Horse and Atlantis: The Development and Operation
of Twin Giants in the Deepwater Gulf of Mexico,” by Simon Todd, BP plc, et al.
SPE 126598 • “IA for the Goliat Offshore Oilfield Development: World’s
Northernmost Offshore Oil Development?” by Erik Bjørnbom, Eni Norge A/S,
et al.
SPE 127819 • “High-Rate Gas-Well Completions in Egypt’s Mediterranean
Sea: Tao Field Development Strategy and Case Histories,” by Ashraf Mekawy,
Nospco, et al.
38
JPT • OCTOBER 2010
FIELD DEVELOPMENT PROJECTS
Akpo: A Giant Nigerian Deep Offshore Development
Akpo field was discovered in January
2000 and production started ahead
of schedule in March 2009 in Block
OML 130, 200 km offshore Nigeria in
1400-m water depth. The Akpo project faced the challenges of combining
gigantic scale, new technological frontiers, world-scale industrial execution,
scarcity of resources in booming years
for the offshore industry, and setting
new records of local content in an
unstable Niger delta
Introduction
A unique hybrid gas-injection/gasexport development scheme was chosen to maximize hydrocarbon recovery
with massive pressure maintenance
and the extensive use of intelligent
and selective completions and subsea
multiphase-flow measurements.
The wellhead shut-in pressure of
430 bar and temperature of 116°C
represented new frontiers for the deepwater industry.
To deliver a 72-slot, 44-well, 10-manifold, 14-steel-catenary-riser (SCR)
subsea development in West Africa,
the project strategy was to use generic
and qualified systems and equipment.
The Akpo field characteristics required
several technological innovations and
the development of existing technology
such as:
This article, written by Assistant Technology Editor Karen Bybee, contains
highlights of paper OTC 20989,
“AKPO: Early Completion of a Giant
Nigerian Deep Offshore Development,”
by Francois Rafin, SPE, and Allain
Laîné, Total S.A., originally prepared
for the 2010 Offshore Technology
Conference, Houston, 3–6 May. The
paper has not been peer reviewed.
Copyright 2010 Offshore Technology
Conference. Reproduced by permission.
• All-electric floating production,
storage, and offloading (FPSO) vessel
with a centralized control room on
each topside module
• Inconel-clad SCRs with high-pressure/high-temperature flex joints
• One fully integrated control and
safety system from wellbore to FPSO
topside provided by a single contractor
• An internally flow coated 155-kmlong gas-export line that increases
the flow capacity by 20%, enabling
(because of a reduced diameter) the use
of seamless pipe
• Crushable foam and bursting disk
to control the well annulus-pressure
buildup, because no casing steel is available to withstand the stress at Akpo
pressure and temperature conditions
• First 103/4-in. frac-pack runs in a
single trip
• First use of 7-in. expandable
screens for a subsea application
• Intelligent completions with downhole monitoring and control from the
FPSO control room
• Automatic ultrasonic testing system for Akpo subsea pipelines, capable
of detecting defects smaller than minimum acceptable
Development of
Metallurgical Solutions
Deeper waters and higher pressures
and temperatures require higher-performance materials. To design, qualify,
and produce new grades of materials is
a long and uncertain process and one of
the most challenging to manage within
a giant-field development that is everything but a laboratory.
The specified stainless-steel 625
plates used for the touch-down sections of the SCRs failed to achieve the
required quality. During the fabrication
of the clad plates to make up the clad
pipes, very-low Charpy values at low
temperature were identified. After sev-
eral failed attempts, the decision was
made to change the stainless-steel grade
from 625 to 825 to enable the procurement of an ingot. This manufacturing
method was better at segregating impurities that generate tiny heterogeneities
in the base material. The change from
625 to 825 was a difficult decision to
make but was made sufficiently early
to enable a clean fabrication of the clad
pipe without impact on the plan.
Forged sockets, which are critical
components of the FPSO and offloading
terminal anchor lines, failed to attain
the mechanical properties required by
Akpo-site conditions. A complete reengineering of the fabrication process
had dramatic consequence on the delivery and preinstallation of the anchor
lines. A rather trivial event, generating
several months of uncertainties, led
to rearranging the offshore installation
schedule to allow accommodation of a
late anchor-lines installation, although
it turned out to be just in time for the
arrival of the FPSO on the field.
The material selection during basic
engineering called for titanium-made
heat exchangers. During detailed engineering and sourcing, titanium was in
short supply worldwide and a lead time
of 45 months was quoted to deliver the
45 tons needed. This schedule incompatibility forced the project to adjust and
move to bulkier Hastelloy heat exchangers. The schedule was maintained, but
at the expense of an undesired change.
Risk Management
Risk management was coordinated by
a risk manager and was based on a risk
register with some 250 risks identified.
The risks were reviewed routinely with
as many as 25 managers, each having
specific responsibilities for the implementation of the risk-mitigation plan.
The global project scheduling was
consolidated among all activities,
The full-length paper is available for purchase at OnePetro: www.onepetro.org.
JPT • OCTOBER 2010
39
Fig. 1—Akpo FPSO during startup with Jack Ryan drilling rig in background.
including reservoir management, drilling construction, and commissioning.
Risk management also included a risk
analysis carried out twice a year by
independent third parties using Monte
Carlo simulations.
The capability to quantify and share
the perception of the risks and the
probabilities of success of any remedial plan was a key element in the
overall decision making. In large deepwater projects, the higher number of
interfaces between the various activities and contracts make them more
interdependent. The cost of changes
also is very much higher than it is in
more-conventional types of projects.
Therefore, the schedule risk management requires a thorough analysis and
an integrated decision-making process.
Risk-management tools proved helpful,
as attested to by first production occurring a month ahead of budget at a date
that had been deemed hardly achievable 2 years before, with a probability
of occurrence of less than 20% .
Technological Risks
One fundamental character of the engineering, procurement, and construction (EPC) lump-sum contracts is the
40
endorsement of the basic engineering
by the contractor, and this was done at
the end of the bidding phase. Another
important feature of the EPC lump-sum
contract is the responsibility of the contractor for the performance of the scope
of work. This is achieved better where
the contractor owns and controls the
engineering and the construction, and
the Akpo project favored the choice of
industrial solutions that were under the
direct control of the main contractors.
The size and the complexity of
the EPC contracts called for innovations and subcontracting, which bring
unavoidable contractual and legal issues
such as patents, property rights, guarantees, design disclosure, and access to the
premises of the vendor for quality control. Usually, the ownership of the technology remains with the vendors and
subcontractor and the ultimate ownership of the risk will remain with the
operator. A well-balanced risk sharing
is required in the framework of a large
field development. This often proves
difficult to achieve. On Akpo, the risk
sharing took different forms. One of
the most successful was the application
of commercial incentives whereby the
contractor remuneration was increased
when the technology helps to beat
preset field-performance objectives. In
return, the operator benefits from confidential disclosures and quality checks
that ensure that it remains in control
of the overall risk. This was applied
successfully on Akpo to the development of new directional-drilling and
well-logging tools along with advanced
ultrasonic testing of the SCR welds.
However, in some technology domains,
an insufficient risk sharing left the
vendors, the EPC contractors, and the
operators unprotected against failures.
Attracting and Keeping
Human Resources
The Akpo project used some 10,000
highly qualified staff worldwide
including more than 4,000 in Nigeria.
Attracting and maintaining the appropriate resources in Nigeria was not an
easy task.
Organizing a high-level security
regime was a primary task for Total
and for the main contractors involved
in Nigeria. Effective communication
with staff, contractors, subcontractors,
and vendors also was a key element to
attract personnel. Strict attention was
given to the safe accommodation and
JPT • OCTOBER 2010
transportation of the staff and to crew
changes, which were perceived as a
prime concern by the staff.
Furthermore, a system of retainer
fees was implemented to keep the project personnel all along the project,
not only in Nigeria but also worldwide. Except in the drilling sector, the
turnover of personnel was lower than
in benchmarked projects. This greatly
contributed to the startup being ahead
of schedule.
Simultaneous Operations
As the trend of individual project activities was tending toward delay, the
global project schedule was salvaged
thanks to a series of measures and
anticipations.
From inception to the production
phase, the project management directly
controlled all the activities, including
geophysics and geology, engineering,
drilling, construction, commissioning,
and production. All trades and disciplines used the same scheduling tools
which facilitated the integration of the
schedule. The common services included health, safety, and the environment
(HSE); logistics; human resources; contract; cost control; and finance.
A large offshore logistics fleet included a 450-bed dynamically positioned
flotel that stayed attached by a telescopic gangway to the FPSO (Fig. 1)
and two purpose-built long-range helicopters that could fly the 550 km from
Lagos to the field nonstop.
Vetting all marine vessels with North
Sea type mobile-offshore-drilling-unit
(MODU) inspection, ensured that all
construction and support vessels could
be engaged safely in simultaneous
operations with cranes, thrusters, and
dynamic-positioning systems in a full
state of maintenance and redundancy.
Simultaneous-operations procedures derived from gained experience allowed flowlines to be layed in
very-close proximity to wells being
drilled, allowed installation of SCRs
and umbilicals on the producing FPSO,
and allowed construction and commissioning of the high-pressure FPSO
topside to continue while producing
gas and condensates.
An early and planned progressive
handover or takeover from contractors
of the subsea and surface facilities by
the operator ensured the required standard of HSE management with clearly
defined responsibilities among all the
JPT • OCTOBER 2010
parties throughout the offshore campaign. Finally, the experience of the
supervision and the coordination procedures permitted three MODUs, three
construction vessels, the FPSO, the flotel, and some 20 support vessels to work
safely on the field and in close proximities with only 3 days of vessel standby.
The main benefit was an earlier production. This was possible thanks to
parallel scheduling of activities (rather
than sequential) and a continuation of
construction and commissioning after
production started. This strategy paid
off even further by allowing production to be ramped up with all facilities progressively put into service as
soon as practical, enabling full gas/
water injection and gas-export capabilities less than 4 months after startup,
maximizing production while reducing
gas flaring.
JPT
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41
FIELD DEVELOPMENT PROJECTS
An Ultradeepwater Heavy-Oil Development Offshore Brazil
Parque das Conchas is an ultradeepwater heavy-oil development in the
northern Campos basin offshore Brazil.
The project is a joint venture between
Shell, Petrobras, and Oil and Natural
Gas Corporation of India. The first
phase of the project is the development
of three independent subsea fields tied
back to the centrally located turretmoored floating production, storage,
and offloading (FPSO) host facility, the
FPSO Espirito Santo.
Introduction
The Parque das Conchas development
grew out of a substantial exploration and
appraisal program beginning in 2000 in
which 13 wells were drilled and six
discoveries were made. The Declaration
of Commerciality was signed with the
Brazilian National Petroleum Agency
in December 2005, and the project was
sanctioned in November 2006. The
four main reservoirs—Ostra, Abalone,
Argonauta B west, and Argonauta O
north—were named after shellfish indigenous to the area. Together, they form
“Parque das Conchas,” or “Shell Park,”
in Portuguese. This is the first project in
Brazil taken by Shell from exploration
discovery to production. First oil from
Phase 1 was achieved on 12 July 2009,
just 9 years after discovery.
This article, written by Assistant Technology Editor Karen Bybee, contains
highlights of paper OTC 20537,
“Parque das Conchas BC-10—An UltraDeepwater Heavy Oil Development
Offshore Brazil,” by K.H. Stingl, Shell
International E&P, and A. Paardekam,
SPE Shell Brazil E&P, originally prepared
for the 2010 Offshore Technology
Conference, Houston, 3–6 May. The
paper has not been peer reviewed.
Copyright 2010 Offshore Technology
Conference. Reproduced by permission.
Development
Abalone, Ostra, and Argonauta B
west are small-to-medium in size and
stratigraphically complex, with highly
faulted, compartmentalized, unconsolidated sand packages. The reservoir
pressures are low, and the oils range
from heavy to light, ranging in gravity
from 17 to 42°API. A fourth heavy-oil
field, Argonauta O north, will be tied
back as part of Phase 2 and is planned
to be ready for production in 2013.
The Argonauta O north field contains
16°API oil and will require waterflood
for reservoir-pressure support.
The Phase 1 subsea infrastructure
consists of 10 producing wells and one
gas-injection well connected by 100 km
of insulated and uninsulated flowlines
ranging in size from 6 to 12 in., 15 flowline sleds, two production manifolds,
two artificial-lift manifolds housing a
total of six vertical subsea-separation
caissons with 1,500-hp electrical submersible pumps (ESPs), and 25 rigid
jumpers, all of which are serviced by
approximately 30 km of multicircuit
high-voltage electrohydraulic (HVEH)
umbilicals connected to the FPSO.
The gas is processed on the FPSO,
and to avoid flaring and to reduce CO2
emissions, it currently is being injected
into a gas-injection well. A dedicated
40-km-long 6-in. uninsulated Parque das
Conchas trunkline has been installed
from the FPSO and will be tied into the
Petrobras Caipixaba gas-export pipeline
at the Petrobras BC-60 location scheduled to be operational in 2010. The oil
is stored on the FPSO and offloaded to
shuttle tankers as required.
The development challenge was to
find an economically attractive and
sustainable solution to unlock all of
these light-, medium-, and heavy-oil
volumes. This was accomplished by:
• Designing a drilling and completion
program to connect the sand packages,
optimize the inflow performance, and
minimize the number of drill centers
• Designing subsea systems to commingle the production, separate the
produced fluids at the seabed, and
boost the production back to the FPSO
• Designing the host facilities to receive, process, and offload the heavy oils
• Developing a comprehensive flowassurance strategy and metering and
allocation system to optimize production and allow for subsea commingling
• Developing a fully integrated subsea- and surface-systems operating philosophy and implementation plan for
flawless project delivery
• Developing a robust project-execution plan with integrated managementcontrol process to ensure success
• Executing a truly global equipmentdesign, -testing and -fabrication program
• Coordinating the complex offshore
installation, hookup, commissioning,
and integrated-system-startup activities
• Implementing a “goal zero” health,
safety, and security environment mindset and culture
Breakthroughs in Technology
These major development challenges
required the designing, testing, and
maturing of significant new breakthroughs in deepwater technology. These
new technologies include the following.
• First full development using subsea
separation and boosting
• First use of lazy-wave steel catenery
risers (SCRs) hung off on a turretmoored FPSO
• First use of multicircuit HVEH
control umbilicals in a single cross
section.
• First use of surface blowout preventers (SBOPs) to perform well completions
These technologies are described in
general in the full-length paper and in
much greater detail in the papers listed
The full-length paper is available for purchase at OnePetro: www.onepetro.org.
42
JPT • OCTOBER 2010
• Unique heavy-oil processing facilities
• Incorporating multiple separation
trains
• Incorporating cargo-tank heating
for offloading heavy crude oil
• Using crude oil as ballast to prolong the hull service life
• Designing novel turret interfaces
to accommodate SCRs for subsea fluid
transfer
• Designing large high-voltage swivels
to meet the high subsea power demands
Fig. 1—FPSO Espirito Santo.
in the References section at the end of
the paper.
Wells
The main challenges of the well-delivery team were to (1) design a drilling
and completion campaign to deliver
technically complex ultradeepwater
low-margin, long horizontal wells with
sand control and (2) deliver the wells
at low cost in a high-cost environment.
The well-design effort, which began
as long ago as 2003, tackled the key
subsurface challenges such as the shallow reservoir setting (approximately
900 m true vertical depth below the
mudline), the low pore-pressure/fracture-gradient margin, and the need for
reliable sand-control systems through a
continuous performance-improvement
process designed to maximize the speed
by which learnings are captured and
incorporated into the design of the
next well. The well-design and -execution campaign yielded many significant
results to date, including one of the longest horizontal openhole wells in Brazil
(1120 m from 95/8-in. shoe to total
depth) successfully completed with a
full-length alpha-wave gravel pack.
The drilling and completion campaign was executed with a moored
Generation-3-type rig that was upgraded before the campaign to use SBOP
technology. This upgrade essentially
doubled the water-depth drilling capabilities of the Transocean Arctic 1 rig
and resulted in significant cost savings
relative to a Generation-4/5 dynamically positioned drilling unit. Additionally,
the anchor-handling vessels (AHVs)
were used to preinstall all of the well
conductors and to install the artificiallift manifold template and, eventually,
JPT • OCTOBER 2010
all of the tubinghead spools and subsea
trees offline of the rig to minimize
installation costs. Optimization of the
AHV use was a key cost-saving enabler.
Host Facility
The FPSO Espirito Santo is a converted 1975 very-large crude carrier
(VLCC) moored in 1780 m of water
and equipped to process 100,000
BOPD and 50 MMscf/D of gas, with
1.4 million bbl of oil-storage capacity. After shuttling crude oil around
the world for the first 18 years of its
life, the vessel was first converted to a
floating storage and offloading (FSO)
vessel in 1993 and spent the next 11
years moored offshore Nigeria as the
XV Domy. The conversion from an
FSO to an FPSO was completed in
24 months at the Keppel shipyard in
Singapore, after which it sailed under
its own power the 9,000 nautical miles
to Brazil. The FPSO Espirito Santo is
331 m long, with a displacement of
327,000 tons (Fig. 1). The topside
contains 25 separate modules weighing
more than 8,000 tons plus a 21-slot
turret weighing more than 4,500 tons.
The Parque das Conchas development presented many challenges that
needed to be overcome whose solutions
were incorporated into the design of the
hull and topside, including the ability
to receive, process, and offload heavy
crude. The water depth, vessel motions,
and demands of the complex subsea
artificial-lift system that relies on continuous surface-supplied power required
careful consideration during the design
and execution phases. The selection of
SCRs dictated a new design for the riser
interface in the turret. These challenges
were addressed notably through:
Subsea Separation and Boosting
The key enabling new technology and
the heart of the subsea-system infrastructure is the complex caisson-fluidseparation and ESP artificial-lift system.
This system consists of a 100-m-long
caisson which acts as a cylindrical
cyclonic gas/liquid separator and a
1,500-hp ESP housed inside the caisson. The multiphase production from
the single 42°API Abalone well and
the seven 24°API Ostra wells enters
the caisson through a top-end assembly and flows into the caisson separator through a purposefully angled
tangential inlet spool. The liquid and
gas separate as the flow stream travels
downward 100 m in a spiral pattern.
Further separation occurs as liquid is
thrown by centrifugal force to the wall
of the separator. The liquid then flows
down to the caisson sump where it is
pumped back upward by the 1,500-hp
ESP into the oil flowline and the lazywave SCR back to the FPSO. Separation
of the gas and liquid by the separator
also reduces the risk of hydrate formation and slugging typically associated
with ultradeepwater production. The
gas collects in the caisson annulus and
flows naturally to the FPSO through a
dedicated gas riser. Extensive full-scale
onshore testing was conducted spanning several years, the results of which
were used to finalize and optimize the
system design.
The multiphase production from the
two Argonauta B west wells is commingled subsea at the artificial-lift Manifold
No. 2. Because this crude has a much
lower gas/oil ratio, separation is not
required and the multiphase liquids are
boosted straight through 1,500-hp ESPs
and pumped to the FPSO. The caissons are housed in modular artificiallift manifolds. The Ostra/Abalone field
manifold contains four caisson slots,
and the Argonauta B west field manifold
JPT
contains two caisson slots.
43
FIELD DEVELOPMENT PROJECTS
FDPSOs: The New Reality and a Game-Changing
Approach to Field Development
The Azurite field development, installed
in the Republic of Congo in 2009,
employed the industry’s first floating drilling, production, storage, and
offloading (FDPSO) vessel to develop
the field. While the FDPSO concept
has been a subject of interest within
the industry for some time, the Azurite
project team took the FDPSO from concept to reality. The concept has tremendous potential as a “game changer” for
field developments.
Introduction
The Azurite field lies within the Mer
Profonde Sud (MPS) Block offshore the
Republic of Congo, just north of the
border with Cabinda Block 14. Water
depths across MPS range from 1100 to
2000 m. Azurite field was discovered
in January 2005 with the AZRM-1 well.
The field was appraised in late 2005
and early 2006 with the drilling of the
AZRM-2 and AZRM-3 wells. Each of
the latter two wells was sidetracked
(ST). AZRM-2ST also was cored and
tested. Aquifer support was found to
be essentially nonexistent along the
producing trend, necessitating water
injection to support reservoir pressure.
This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 20482, “FDPSOs:
The New Reality, and a Game-Changing
Approach to Field Development and Early
Production Systems,” by W.D. Harris,
SPE, H.J. Howard, SPE, and K.C.
Hampshire, SPE, Murphy West Africa;
J.A. Moore and K.J. Bayne, SPE, Doris
Inc.; and Jean Pepin-Lehalleur, Doris
Engineering, originally prepared for the
2010 Offshore Technology Conference,
Houston, 3–6 May. The paper has not
been peer reviewed.
Copyright 2010 Offshore Technology
Conference. Reproduced by permission.
Fig. 1—Azurite field development.
Concepts Considered
The Azurite integrated project team
began the task of identifying and evaluating field-development alternatives.
Multiple development schemes were
identified and evaluated. The four main
alternatives evaluated were:
• Subsea tiebacks to third-party facilities
• Subsea tieback to infield floating
production, storage, and offloading
(FPSO) vessel
• Dry-tree unit (DTU) producing to
FPSO
• Infield FDPSO
A subsea tieback to third-party
facilities in the Republic of Congo or
Angola was considered and deemed
technically feasible, with the aid of
subsea boosting. However, tiebacks to
third-party facilities in the Republic
of Congo or tiebacks to third-party
facilities in Angola, with the associated
cross-border issues, would have introduced too much schedule and political
risk. Hence, tieback schemes involving
third-party facilities were not selected.
A subsea tieback to an infield FPSO
was considered. However, strong market demand for deepwater floating
rigs exposed the project to significant
schedule delays. Likewise, their associated day rates adversely affected project economics.
DTU options were considered as a
way to overcome the roadblock posed
by the tight market for deepwater rigs.
A DTU option was a possibility because
the Azurite reservoir depth and areal
extent permitted directional drilling
from a single surface location. One
alternative considered was a minimal
wellhead facility with a tender-assist
drilling rig. This concept was used successfully to develop the Kikeh field in
Malaysia. Another alternative considered was a DTU with a self-contained
compact drilling rig. In both DTU cases,
processing would occur on an FPSO
in the field. The option of a minimal
The full-length paper is available for purchase at OnePetro: www.onepetro.org.
44
JPT • OCTOBER 2010
wellhead facility with tender-assist rig
was ultimately rejected because of a
lack of available tender rigs. Faced with
deepwater-rig shortages and the desire
to make a step-change improvement
in project economics, the project team
developed the FDPSO alternative. Fig. 1
shows the overall view of the Azurite
field development.
FDPSO Feasibility
The FDPSO concept has tremendous
potential as a game changer for the oil
and gas industry for deepwater-field
developments, whether it is used to
unlock the value of marginal fields in
deep water (even in a low-oil-price
environment) or as an early-production system. Because the concept uses
a compact drilling rig onboard the
vessel, traditional challenges regarding
deepwater-drilling-rig availability and
expensive day rates are eliminated.
Field-development economics heavily favors an FDPSO concept when
reserves can be produced from a single
location. However, the concept still has
application for fields with multiple drill
centers. The FDPSO can be positioned
over the drill center containing the
majority of field reserves, and other drill
centers can be tied back to the FDPSO.
FDPSOs have been discussed and
the concept has been developed in the
marketplace since the 1990s, but, until
Azurite, they never became a reality. While it sounds relatively novel,
the technology involved is not new.
Combined drilling and production platforms are commonplace, as are deepwater drillships. Thus, extending these
time-tested concepts to drilling from an
FPSO did not represent a quantum leap.
Both wet- and dry-tree FDPSO solutions have been studied in the industry;
however, the Azurite team opted to focus
its efforts on a wet-tree solution because
it represented less of a technological
stepout. With the wet-tree FDPSO, the
moonpool is located in the center of the
vessel to minimize rig motions. A base
suitable for mounting a modular drilling
rig is installed. Wells are drilled from the
vessel and completed subsea.
Drilling from an FDPSO requires
either a spread-moored solution or drilling in a continuous dynamic-positioning
mode. Benign environments and unidirectional seas permitted the use of a
spread-moored FDPSO. Motions studies
for Azurite confirmed that the relatively
benign West Africa seastates, dominated
JPT • OCTOBER 2010
by a long-period swell from the southwest, permitted drilling operations to
continue even during a 10-year event.
An FDPSO-concept hazard-identification review was held before final consideration of the FDPSO as an acceptable option. The hazard-identification
team included facilities engineers from
the Azurite team, drilling-engineering
and field-supervisor representatives
from Kikeh team, and drilling-contractor and engineering representatives. No
high risks were identified that could
not be mitigated through layout restrictions or the implementation of specific
operating procedures.
Market supply-and-demand forces
and the strategic aims of the operator
in the Republic of Congo led the team
to the logical conclusion of using an
FDPSO. However, the concept is certainly not limited to Azurite. The concept can be extrapolated easily to other
uses such as in fields with marginal
reserves, as an early production system,
as part of a phased development, and in
fields where other storage and offloading infrastructures are already present.
Phased Development
Operators of blocks that contain multiple prospects or discoveries, many
of which might be considered subeconomic on a standalone basis, also will
find that the FDPSO with subsea trees
offers tremendous advantages over
conventional development schemes.
If there is a portfolio of prospects
with sufficient chance of geologic success (e.g., operating in a known geologic basin), then a more aggressive
approach may be warranted. Operators
that discover a marginal field in an
area with multiple prospects normally
will require that multiple prospects be
drilled and appraised before an investment decision can be made. Thus,
cycle time, from initial discovery to
first oil, is affected significantly as each
field is studied, reservoir models are
built and analyzed, and multiple discovery and appraisal wells are drilled.
An FDPSO, used in tandem with a
semisubmersible drilling rig, is a good
fit to exploit the resources of blocks
containing numerous marginal prospects and/or discoveries.
Early Production System
The cost of today’s conventional offshore-field development is staggering, with capital costs alone routinely exceeding USD 1 billion, even for
fields in relatively shallow water and/
or producing less than 100,000 BOPD.
Reserves size, well productivity, and
well count have a significant influence
on project economics. Consequently,
reducing subsurface risk in offshorefield developments is of paramount
importance. For operators with portfolios that are sufficiently robust to
support the associated capital cost and
operating expense, the use of an FDPSO
is an attractive solution because of:
• Early revenue generation from
early production system or extended
well tests.
• Less-expensive exploration and
appraisal campaigns (day rate of the
FDPSO vs. day rate of a deepwater
semisubmersible drilling rig).
• Information gained on subsurface
performance to optimize future fullfield development.
• The capability of being redeployed
elsewhere if results do not match predictions (as opposed to preinvesting
in a full-field development solution).
Thus, the concept acts as an effective
hedging mechanism.
Conclusion
Regardless of application, Azurite has
shown the way forward. The possibilities and permutations are many. The
step change in economics afforded
by the incorporation of a drilling rig
onboard a conventional FPSO brings
new hope to fields of similar geometry and in similar environments that
heretofore were considered marginally economic or uneconomic. The
FDPSO concept also has application
as an early-production system, in
advance of full-field developments.
Drilling and production can begin,
generating revenue as well as valuable
data regarding reservoir performance.
The FDPSO also can be an integral component of phased-development schemes.
The FDPSO has proved to be a
robust concept that can add significant
value, in terms of both reduced cost
and information gained on reservoir
performance that permits further fielddevelopment optimization. Against the
backdrop of the lean economic reality
of today, and as the number of large
discoveries in deep water shrinks and
the industry seeks new ways to monetize stranded pockets of oil and gas,
the concept will no doubt receive much
more scrutiny.
JPT
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