Steps to the Subsea Factory

1) Steps to the Subsea Factory
Abstract
During the last 25 years Statoil, in cooperation with key vendors, have developed
technical solutions for subsea field development resulting in more than 500 subsea wells.
As part of the corporate Technology strategy Statoil has launched a technology plan for
the Statoil Subsea Factory™ concept. The plan describes how to combine subsea production and
processing technology elements together with key business prioritised elements such as long
distance multiphase transport, floating production facilities and pipeline networks to enable costeffective field development. In addition, subsea production and processing can enable
accelerated production and increased recovery in an energy-efficient manner, and with low
environmental footprint
This paper provides an overview of the technologies enabling the Subsea Factory concept
and the operating experience gained in assets having implemented subsea processing
technologies.
The paper describes the technology staircase starting with subsea boosting in the LuFeng
field and the separation, produced water reinjection and fluid boosting applications at Troll Pilot
and the Tordis fields. The paper describes Tyrihans raw seawater injection and summarises the
gas compression technology projects underway for the Gullfaks and Åsgard fields.
The plan takes account of two specific value-creation goals Statoil is targeting - namely
to realise subsea compression by 2015 and a complete subsea factory by 2020.
Focus on establishing a Subsea Factory concept can be explained by the desire to
improve the economic value of field developments. Utilizing a system approach from reservoir
to export system, combine and reuse in new ways the subsea production and processing
technologies already installed or being constructed in Statoil.
The processing element will enable the fluids to be treated to a level where they can be
safely transported in flowlines to a downstream host, whether onshore or offshore, fixed or
floating. Future generations of subsea factory may include more sophisticated processing
elements.
Statoil's vision is to develop and deploy all the necessary technology elements required
for a "subsea factory??, i.e. for the equivalent of a topsides processing facility to be operated on
the seabed, enabling remote subsea to beach hydrocarbon transport solutions in any offshore
location. Statoil will be "Taking subsea longer, deeper and colder?? to accelerate and increase

production?? by implementing the Statoil Subsea Factory™. The term "Older?? is also discussed
in light of the potential to reuseexisting technology elements to increase recovery and maintain
production at existing/brownfield facilities at the Norwegian Continental shelf.
2) Subsea facilities
Abstract
This paper presents the system design and concept solutions selected for the Ormen Lange
subsea
facilities.
The field is located in a remote area off the coast of Norway and system availability has been a
key driver in the subsea system selection and design. This paper focuses on the following
elements:

Ormen Lange key technical challenges and concept development.

Subsea system architecture.

Design premises and essential functional requirements that have driven the subsea
design.

Selected subsea system hardware solutions with emphasis on availability of the
key functions.

Technology qualification programs that will be executed in order to provide
confidence in the selected solutions.
3) The future of electric controls: Trees and subsea processing


Since 2008 the world’s first all electric production controls system is operating in the
Dutch sector of the North Sea. Valuable feedback is constantly being received and lessons learnt
are

being
implemented
for
future
generations
of
all
electric technology. A new generation has been developed for the operation of Subsea Production
Systems, ie. X-Mas Trees and Manifolds in particular. But with Subsea Processing systems
becoming
more
and
more
accepted
by
the
industry,
all
electric technology could be a key enabler for further enhancement of Subsea Processing
applications. For instance with the subsea factory emerging on the horizon, a key requirement for
complex
systems
is
that
control
valves
be
operated in a continuous operation mode, either manually or in a closed loop (PID). For surface
applications this generally poses no problem as various technical means are at the industry’s
disposal

ranging
from
pneumatic,
hydraulic or electric actuation control. For subsea this is different, with longer step-outs and deep
water depths having a hydrostatic pressure constraint reaction times). These severe conditions
require
special
equipment
capable
of
handling the increased process control challenges. Controlling valves faster becomes
increasingly important, and in general demands electric control characteristics. The majority of
applications
so
far
have
used
hydraulic
actuators, although there are systems currently in build which will use electric actuation control.
This paper will focus on explaining electrical technology, its history, and identify its advantages
especially
when
used
for
long
offsets,
zero discharge requirements and complicated process controls. The paper will also provide a
vision of the control technology for the future, drawing from proven Electro-Hydraulic and
electric
control systems of today and considering current technology developments.

4) AKPO: The Subsea Production System
Abstract
It has been said "All deep water offshore projects are challenging??. Nowhere in the
world do projects have such high commercial pressures as those which take on the challenge of
Deep Water. Rarely if ever can it be said that any one field is a repeat of another. Each therefore
raises its own issues which each development must solve anew. Some lessons are the same, and
we forget them at our peril. Some are new challenges, and we then call on our experience of the
past to rise to meet them, and hence all our experience is necessary. In the case of Akpo, many of
the issues were totally new and we called on all of our experience of Deep Water fields in the
Gulf of Mexico and West Africa.
The Akpo field in block OML 130, 200 km offshore Nigeria is in 1400 m water depth. It
is a gas/condensate field with high pressures and high temperatures. One of the greatest
challenges is to ensure that condensate and gas in multiphase flow reach the production facilities
without being stopped by hydrates and wax and scale deposition. The technical challenges alone
are significant, but when set against the background of increasing oil prices and high commercial
pressure on the suppliers from more than one operator and more than one field, the challenges
take on a new dimension. Added to that for Akpo were the issues of resources of personnel and
manufacturing capacity in a very buoyant market as well as the new challenge of manufacturing
in Nigeria.
This paper also addresses the challenges of the Subsea Production System of the AKPO
development. It shows how the conceptual design principles are encapsulated in the simple
acronym - RAM and how these lead to some key issues.
The second most important issue facing all Subsea decisions is the fact that the cost of
installation - whether by Drilling Rig or by Installation Vessel - FAR exceeds (in most cases) the
cost of the equipment itself. Added to that is the cost of the lost production. This cost is
effectively tripled if equipment has to be retrieved and then re-installed. No Subsea Engineer
ever wants to see their equipment return to the surface. Nevertheless - things do go wrong even


on a single well - and in a system as large as Akpo, the opportunities for something to go wrong

increase. Such is the inevitable nature of large Systems. The ability to recover and install was
seen as vital. Design for installation was a vital strategy in the design process. This lead to design
in order to minimize installation - and retrieval - costs.
5) Subsea Processing Systems: Future Vision
Abstract
To surpass the main challenges established by deep water, high gas-oil flowratios, flow assurance
and constant increases in produced water, Petrobras is developing, within PROCAP Technology
Program - Future Vision, several projects in the subsea processing area, such as: Compact OilWater and Gas-Liquid Separation Systems, Multiphase Pump with High Differential Pressure
and Gas Compression System.
The main applications of these projects are in fields with high fraction of gas and water,
in fields/discoveries located far away from Production Units and to increase the reservoir
recovery factor. Furthermore, the application of these technologies may have great benefits, such
as: production anticipation, reduction of process system footprint on the Production Unit,
decrease in CAPEX/OPEX and especially an increase of the topside oil processing capacity.
This paper aims to present an overview of those technologies being developed in
PROCAP - Future Vision. Also, this article shows the main motivations of these developments,
the main benefits of using each technology, the technological challenges and gaps, typical
application scenarios and results of the evaluations performed so far.
Major petroleum companies are searching for new technical solutions that fulfill their
needs of reducing both CAPEX and OPEX while increasing oil and gas production. The
development of new subsea processing technologies, as stated above, will enable, and in some
cases reinforce, the use of these technologies for deepwater and/or subsea to shore scenarios.
6) SS: Subsea Well Intervention: Development of a Deepwater Subsea Well
Intervention Package Control System
Abstract
The paper describes the ongoing work, overall approach and process used to develop a
deepwater subsea well intervention control system using structured risk and reliability principles
and hardware based upon remotely operated vehicle (ROV) control technology. It discusses the
selection of IEC61508 and IEC61511 as the governing standards for development of the controls
architecture and certification of this deepwater well control system. It also presents the

challenges that have to be addressed when using ROV hardware for well control and describes
the methods implemented to overcome system deficiencies. The methods used are currently
being vigorously applied throughout the control system's development stage to insure the entire
control system and not just its components, will be highly reliable, manufactured, tested and
certified in accordance with the principles of IEC60508/61511 to a Safety Integrity Level of 2
(SIL 2).
7) SS on Implications of Subsea Processing power Distribution - Subsea Power
Systems - a Key Enabler for Subsea Processing
Abstract
The paper provides an overview of and operating experiences with the subsea power supply
systems for the Statoil fields utilizing high voltage power; Lufeng (seabed booster pumps), Troll
(oil/water separation, water re-injection) and Tordis (separation, boosting, water re-injection).
The paper gives a status on performance of the power system for these projects, and an overview
of the most important "lessons learned??. The Tyrihans pump power supply system, which
represents the world's longest step-out with topside VSDs and highest subsea motor power, is
also
briefly
presented.
Future fields utilizing subsea processing at deeper waters and with longer tie-backs will require


further development of power system technology and Statoil is undertaking several qualification
programs for such applications. Status of Statoil's main ongoing qualification programs within
HV power is given, including R&D and study activities. The overview includes status on all
main power supply components such as motors, connectors, VSD, switchgear, transformers and
cables/umbilicals
within
these
projects.
The information provided gives a good overview of "state of the art?? of subsea HV power

systems and components within Statoil, and can be useful to both manufacturers and end users of
subsea power components.
8) SS IMPLICATIONS OF SUBSEA PROCESSING POWER DISTRIBUTION <
SUBSEA SWITCHGEAR MODULE - A KEY ENABLING COMPONENT IN SUBSEA
INSTALLATIONS>
Abstract
Subsea high and low voltage switchgear is a key enabling component for subsea process units.
Locating the switchgear module at the heart of the subsea load center avoids having to provide
any top-side facilities, greatly reduces the operation expenditures and reduces the cost of the
power lines. The subsea environment has a very strong influence on the design, fabrication,
assembly and testing of the module, both the enclosure itself and the switchgear equipment
inside
of
the
enclosure.
After the introduction and some general information regarding the subsea switchgear module, the
feasibility study and various conceptual design calculations performed during the development
of the switchgear portion will be described. Since this is the first time that such a large electrical
distribution system has been installed in a subsea environment, the main purpose of these studies
was to ensure a very high availability of the switchgear to provide power to the process loads.
Reliability studies combined with mechanical and thermal analyses were performed to ensure
correct installation and operation in a subsea environment at about 1000m below sea level.
Electromagnetic compatibility studies were also performed to avoid any nuisance operations of
the switchgear and controlgear which could result in loss of production.
After the information about the switchgear portion, the design, fabrication and testing of the
enclosure itself will be described. There are two main criteria for the enclosure. The first is the
high pressure due to installation on the seabed. The second is the requirement for the installation
of the switchgear within the enclosure prior to its submersion, and also access to the switchgear
during maintenance operations at the surface. This criterion requires removable enclosure parts
that must have adequate sealing to prevent any leakage when submerged. Also very important

are the constraints due to the handling of the complete module when installing it and also when it
requires
servicing.
Finally the integration of the switchgear portion within the enclosure will be described.
9) Husky Liwan Deepwater Subsea Control System
Abstract:
The Liwan subsea control system located offshore China in deepwater of 1,500 meters is
one of the most technologically advanced systems to be installed. The control system for Liwan
is of necessity large and complex and has incorporated many current industry innovations in
control and communications across the system.
This paper will present a review of the control system and the key components provided
for the deepwater Liwan field such as,
• Subsea Control Modules (SCM) for Subsea Production Trees and Structures
• Subsea Router Modules (SRM) for Manifold, Pipeline End Manifold (PLEM) and Umbilical
Termination
Units


•
Subsea
Monitoring
Module
for
Corrosion
Monitoring
System
• Subsea Power and Communications Unit located on the Central Production Platform (CEP)
• Chemical Injection Metering Valves for the methanol (MeOH), monoethylene glycol (MEG)
and
Corrosion

Inhibitor
(CI)
distribution
at
the
subsea
structures.
•
Umbilical
Termination
Units
for
Subsea
Distribution
•
Umbilical
Termination
Heads
for
the
Infield
Umbilical
Distribution
•
Fiber
Optic
Communications
from
Topside
to

the
SRM's
• High Voltage Direct Current (DC) system to all SRM's and SCM's located on all structures
The development and engineering of the Liwan control system will be described within the paper
from conceptual design, explaining the control system architecture due to the Liwan field layout
complexity of area's Liwan 3-1 and Liuhua 34-2 and their distant geographical locations subsea.
This paper will also cover the subsea control system fabrication, integration testing and finally
installation and commissioning offshore in China.
10) Operation Of Subsea Electrical Power Systems
Reliable, dependable and cost effective subsea electrical power supply systems have been
one of the most important factors in the successful development of the subsea boosting and
processing applications and technologies over the last 15 years. This paper will provide an
overview of how the system and component parameters and ratings have developed over this
period. In the early days of subsea, there was a lot of skepticism using high voltage equipment
under water - today we see that when the design and qualification is done thoroughly, high
availability is achieved on subsea electrical power systems. Further, a focus on what have been
the decisive factors for system design, correlation to the end-load and consequently component
selection will be offered. An overview of key component qualification methodologies and
programs will be described, and finally an overview of operational experience of the existing
subsea power systems will be given. The end loads have increased in power rating from some
hundred kilowatts to multi-megawatts. This have obviously had a significant impact on the
design and utilization of the power components, such as subsea wet mateable connectors, subsea
transformers, variable speed drive units, electrical motors, etc. In parallel to the increase in
power rating, and consequently voltage and current, the water depths and environments for
installation have changed in this time period and have led to increased requirements to pressure
withstanding capabilities, cooling and physical robustness.
11) Barracuda Subsea Helico-Axial Multiphase Pump Project
Abstract
PETROBRAS, other operators and suppliers have carried out many efforts to make available the
subsea multiphase pump technologies. Many of these pumps were installed and are now in

operation, including helico-axial pumps. However, until now, these pumping systems were
limited to differential pressures lower than 45 bar, which is not attractive to PETROBRAS
scenarios, since the gas-lift has similar performance. Thus, PETROBRAS launched a program to
qualify, through flow loop tests and field operation, a helico-axial multiphase pump to
differential pressures up to 60 bar. The Barracuda field was selected to host the prototype. This
paper describes the Barracuda helico-axial multiphase pump, including the design phase,
qualification process and operational experience so far, involving: installation, commissioning
and operation.
The Barracuda multiphase pump is designed to operate at maximum differential pressure
of 70 bar. The other main flow characteristics are: liquid flow rates between 2000 and 3000
m3/day; GVF between 35 and 60%; and viscosity between 15 cP and 20 cP. The pump is
installed at a water depth of 1040 meters and distant 10,5 Km from the P-48 production platform.
The boosting system is composed by many components, including a flow base, control system,
topside equipments, integrated umbilical and subsea motor-pump unit inside the pump module.
This boosting system was comissioned in July of 2012 and since then its operational
performance
has
been
evaluated.


A description of the main subsystems of the Barracuda Multiphase pump is presented, including
their qualification process and FAT tests. In order to evaluate the hydraulic performance of the
motor-pump unit, a special flow loop test program was established. The results of this
qualification process and the operational experience indicated that this technology is adequate to
be applied in other similar applications.
Boosting untreated oil is a field proven solution and is coming to the age. Efforts to
develop high differential pressures multiphase pumps will increase its operational envelop, that
will enable its use in important scenarios, accelerating the number of applications and increasing
the benefits of this important subsea boosting method. The benefits to brown and green fields

will be significant, mainly to Campos Basin scenarios.
12) Albacora Subsea Raw Water Injection Systems
This paper presents the Albacora field Subsea Raw Water Injection (SRWI) systems.
Application of SRWI involves some challenges, which demand a detailed and systematic
analysis in order to evaluate the technical feasibility and establish the requirements to implement
this solution. This paper describes the evaluation process carried out and details the adopted
solutions. Furthermore, the system installation and operation are presented.
The Albacora field is a mature field located at Campos Basin in water depths between 250 and
1100 meters. In order to increase the oil recovery, its reservoirs are requiring a significant
amount of water injection, what was not considered in the initial phases of the Albacora field
development project. Technical and economical constraints do not allow the use of conventional
seawater injection plants, since current production units have no available area to implement a
conventional water injection system. The selected alternative to overcome these constraints was
the SRWI technology, by which seawater is injected in the reservoir with a minimum treatment,
using
mainly
pieces
of
equipment
installed
at
seabed.
The feasibility analysis involved studies of the seawater compatibility with the reservoir rock and
fluids, microbiological control, corrosion, etc. The solution was specified based on these studies
and included subsea pumps, back-flushing filters, well components and topside facilities. In
order to achieve required seawater flow rates, the adopted solution considered the use of three
subsea injection systems, injecting around 16,500 m3/day in seven wells.
Waterflooding is still the most common method used worldwide for improving oil recovery. The
SRWI technology can be an important alternative to inject seawater where it is not possible to
use conventional systems, mainly in mature fields. The SRWI is expected to generate large

economical and technical benefits to the Albacora project.
13) Power Distribution for Arctic Subsea Tiebacks
Abstract
Subsea tiebacks are becomingincreasingly prevalent in oil and gas field developments.
As the accessibilityof the production from wellheads becomes more difficult, the need for
subseacompression and pumping increases. Compression and pumping require significantpower
which can be distributed and controlled from a HVSS (High-Voltage SubseaSubstation). The
viability of an Arctic field development will be determined bythe reliability of all elements in the
tieback and in particular, thecentralized subsea power distribution system.
14) Subsea Water Treatment and Injection for IOR and EOR
The patented SWIT technology enables production and injection of clean sea water
directly from the seabed, a flexible and cost effective solution. The technology, proven and ready
to use, enables a step change in reservoir and asset management, accelerating production and
increasing recovery. A new test proved that a combination of SWIT and membranes can produce
low salinity and sulphate free water for a long time without any degradation in performance.
The SWIT technology offers a different approach to how reservoir and assets are managed and
produced. Cleaning the surrounding sea water at the seabed and feeding directly into subsea


injection wells is a completely different concept than the traditional topside approach. The
benefits are significant from many aspects; reduced weight and area required topside; no long
reach platform water injectors (WI) required; acceleration of production; increased recovery
through
flexible
and
phased
deployment
of
the
WI capacity

required.
In 2009 - 2010, a 15 months full scale pilot test was carried out at the seabed in the Oslo fjord.
The SWIT cleaned water was pumped to shore to NIVA Marine Research Centre for monitoring
and testing. The results exceeded expectations and documented superior water quality for WI
compared to traditional topside facilities. The Joint Industry Project (JIP) companies verified the
results and technology is ready to be used in field applications. SWIT has been approved via
technology
qualification
program
with
major
oil
companies.
The superior quality water from SWIT, including the ability to control the chlorine level very
accurately, paves the way for producing low sulphate and low salinity water at seabed. A second
test proved that SWIT feeding membranes make membranes last very long without any
degradation in performance or maintenance requirement. SWIT combined with membranes
therefore enables low sulphate and low salinity water injection from seabed. Currently planning
is ongoing to design and build a full integrated sulphate free and low salinity water facility at the
seabed.
15) Subsea Control And Automation: Evolving For the Future
ABSTRACT
Increasingly complex machinery is being installed on the seafloor for applications such as subsea
separation, gas compression and boost pumping. The oil and gas industry faces a significant
challenge to ensure that this higher complexity equipment achieves the required operational
efficiency and availability. Control systems are a key element in addressing this challenge. The
next generation of control systems must provide superior availability, lower lifecycle costs and
superior
performance.
Other industries faced with similar increases in complexity and the demand for very high

reliability have evolved solutions to manage the challenge. Several evolutionary themes recur
across these industries, and they include:

Significantly more sensing and control technology embedded in these control
systems

Software enabling many operation and maintenance functions to be automated
rather than manual

Information from operation and maintenance processes being transported to
decision-makers independent of their location.
Some solutions created in other industries to achieve these objectives can also be applied
to the subsea environment; these solutions can be adopted rather than reinvented. (Examples
include smaller, lower cost electronics, networkbased architecture and configurable hardware.)
Challenges unique to subsea control systems include packaging technologies and subsea
connection techniques, and these elements require invention rather than adoption.
Successful designs will yield lightweight modules that are suitable for subsea exchange by
remotely operated vehicles (ROVs) and autonomous underwater vehicles (AUVs). Such modules
will be less expensive to manufacture than conventional subsea control components. The
combination of adopted and invented technologies will make the next generation of subsea
control systems connected, configurable, modular and serviceable.
16) API 17G Specification for Subsea Well Intervention Equipment
This paper describes the long awaited third revision of API 17G as it migrates from a
Recommended Practice to a design and equipment Specification. The revision provides a
systematic approach for the design and operation of through BOP/drilling riser and open water
completion/workover riser systems, and also provides the "boilerplate" from which ancillary
recommended practices for emerging well intervention equipment and methods can reference


common and standard requirements. The specification updates design guidelines addressing:

safety analyses, intervention planning and identification and testing of well barriers, including
performance requirements for specific hardware and provides updates to global and local stress
analyses. The author’s focus is to provide the reader with guidance to navigate the document.
The updated specification is intended to illustrate current technology and design practice along
with structuring its format to accommodate future intervention technologies and hardware. It is
also intended to provide the necessary safety review and campaign planning tools being asked of
the offshore community in the realm of well intervention and workovers, similar those now
being incorporated into offshore floating drilling practices. The paper overviews the new
Specification assisting the reader in navigating the lengthy document. The results of the paper
will be a simplification of the Specification and an in-depth understanding of the safety
philosophy and strategy which is the core upon which the analysis and material specifications are
based, extending the systems capability to deeper depths and harsher operating conditions. The
document stops short of addressing HP until the task group has time to review and incorporate
API 17TR8. Establishing this set of standards will be crucial for industry safety and meeting
regulatory scrutiny.
17) Emergency Supply of Subsea High Pressure Control Fluid Six Shooter
Abstract
An overview of the design and functionality of the Oceaneering subseaaccumulator or Six
Shooter is provided. The Six Shooter was developed as asolution to the historical challenges of
BOP emergency intervention. ROVtooling for subsea Blowout Preventer (BOP) intervention has
been limited tosmall hydraulic pumps which require substantial amounts of time to operate
BOPrams. With faster closing times recommended for emergency intervention,supplementary
accumulated volume is required subsea. The Six Shooter can belaunched from a support vessel,
IMR vessel or Rig, eliminating the need forcostly Rig or BOP modifications. The unit can be
deployed
onto
a
customdesigned
mudmat
or

an
existing
structure.
When deployed, the Six Shooter would allow a ROV (Remotely Operated Vehicle) ofopportunity
to function and provide high flow (100 gpm) and pressure (5000 psi)to the BOP via a flying lead.
At these flow rates, the industry standardspecifications of 45 second ram closures can be
obtained.
Equipped with dual regulators, the output pressure of the Six Shooter can beselected with the
turn of a ROV valve. Depending on the number of BOP functionsthat need to be closed during
an emergency situation, additional units can beeasily added with standard high flow flying leads
to increase the usablevolume. The subsea accumulators are constructed with materials that
allowdependable and repeatable functioning over long exposures to a subseaenvironment.
18) Development and Qualification of a High Differential Pressure Subsea Pump
Abstract
Growing global demand for hydrocarbons has forced key operators to expand field
developments towards deeper waters and remoter areas with increasing step out distances. At the
same time, brownfields already in production are facing high water cut and low reservoir
pressure; these scenarios have created a demand for more powerful subsea pump systems.
FMC Technologies and Sulzer Pumps have jointly collaborated to develop a new
multiphase pump system. This new solution is a helico-axial pump that is driven by an
innovative 3.2 MW permanent magnet motor (PMM). This subsea pump is distinguished by its
high power and efficiency, with a design optimized for the seabed environment. PMM
technology has been applied and proven for topside and onshore applications but now is also
qualified for subsea use. The key advantage of using PMM is the high power density, the ability
to operate at higher speeds and improved efficiency in a more compact design compared to
traditional induction motors, these key differentiators are of significant benefit to subsea
processing production schemes.


The pump unit proven during the qualification program was designed for water depths of

up to 2000 m [6562 ft], internal pressure rating of 345bar [5000 psi], and a design temperature of
80°C [176°F] and furnished with helico-axial multiphase hydraulics and a highly tolerant waterbased barrier fluid (coolant/lubricant/motor pressurization fluid). Radial hydraulics are also
available, as well as a combination of helico-axial and radial (hybrid hydraulic) depending on
gas volume fraction (GVF).
A full size subsea pump system, complete with motor, pump cartridge, fluid conditioning
system, process control and additional systems was engineered and constructed and installed at a
purpose-built pump test facility able to simulate multiphase field operational conditions. The
initial qualification test program of the 3.2 MW, 5000 psi multiphase pump module is now
complete and complementary system endurance testing is reaching conclusion.
This paper presents an overview of the key features of the pump and motor system, and
the qualification program to which this boosting system was subjected. The paper also will
describe case studies and the pump selection criteria for these scenarios.
19) Qualification, Verification and Validation of Novel Subsea Tooling
Abstract
This paper describes the design, development and testing of a set of diver operated subsea
tooling used to resolve a unique issue that occurred during the construction of two subsea wells
installed by Esso Australia in 95 metres of water, off the coast of south-eastern Australia.
By following a structured and rigorous process of qualification, verification and
validation it was possible to successfully develop the required tooling on a fast track basis in
order to meet the schedule constraints of the on-going diving support vessel campaign.
A Western Australia based company with design and manufacturing capability and
demonstrating expertise in the development of comparable customised subsea equipment was
selected to supply the required tooling. A considerable number of technical solutions were
evaluated during the concept development phase prior to selecting a single optimised concept
and finalising the design of the tooling.
Comprehensive onshore testing of the tooling and involvement of the diving personnel
were essential steps in maximising the probability that the offshore operations could be executed
in a safe and efficient manner. As a result of these efforts the tooling operated flawlessly in the
field and a multi-million dollar re-drill campaign was avoided.
This paper focuses on the steps undertaken in each part of the qualification, verification

and validation process, in order to use this work as an example of the activities that are typically
involved in each of these steps, and thus provide a roadmap for the application of this process in
other time critical, high consequence situations.
20) A Classification Society´s Experience with Subsea Mining
Abstract
Growing interest in deep water minerals resources is providing opportunities for both the
mining and oil industries. Exploration and production of ocean minerals require synergies
between different technologies. In this context appropriate standards are needed to cover both
new equipment and existing equipment that may be subject to changed service conditions. This
paper covers ABS’ experience with related equipment such as deep sea oil and gas, certification
of equipment as per existing API requirements, manufacturer’s Specifications and Coastal
Administration’s requirements.
21) Application of a Grouted Sleeve to Remediate Damaged Subsea Pipeline
Abstract
This paper describes the method and equipment developed to allow ROVinstallation of a groutfilled reinforcement sleeve on a damaged 18" subsea gaspipeline at a water depth of 2,300 ft.
The Williams Canyon Chief pipeline wasdamaged by an anchor drag that pulled pipeline
approximately 1,500 feet out ofits original right-of-way, bent the pipeline to an unknown radius,


and left asignificant dent in the side of the pipe as well. The damage did not result ina leak and
the pipeline was allowed to continue to operate at not only areduced pressure, but also a
minimum
pressure,
while
repair
plans
weredeveloped.
Extensive research and testing determined that the pipeline could be returnedto normal operating
pressure and ultimately maximum design pressure if the dentcould be restrained from flexing due
to changes in pipeline pressure.Laboratory testing confirmed that cement grout inside a steel

sleeve installedaround the dent would provide the necessary reinforcement.
A specially designed, ROV friendly repair sleeve was developed to match thepipeline curvature
that was estimated by side scan sonar imaging andphotogrammetry. The sleeve was fabricated as
a straight cylinder but the endswere angled and positioned off-center to account for the pipeline
curvature.The sleeve was split horizontally so that all clamping screws were vertical.
Anarticulated spreader bar, ROV operated pull-down winches, and a large syntacticbuoyancy
module allowed the ROV to control the entire installation after theequipment spread was landed
on
the
seafloor.
A project specific metrology tool that measured the curvature of the pipelineat 24 points was
built and landed on the pipeline to confirm earlier calculatedestimations. An ROV video record
of the gauge readings was then used in theshop along with the metrology tool to fabricate a
dimensionally correct mock-upof the pipeline. This mock-up was then placed into the repair
sleeve to confirmthat it would fit on the pipeline.
22) Completion Design for Sandface Monitoring in Subsea Wells
Summary
The expense of subsea well intervention often leads to insufficient reservoir information
for accurately understanding reservoir connectivity, drainage, and flow assurance. For those
wells requiring sand control, an additional constraint is that sandface sensors must be deployed
on a separate completion run. The objective of a recent engineering development program was to
create a new deployment system that addressed these constraints directly. Instead of individual
gauges on mandrels, digital sensors were miniaturized and distributed along a single spoolable
bridle. In addition, a novel inductive coupling mechanism was developed to pass power and data
from the upper to the lower completion. In a recent subsea deployment in southeast Asia, such a
coupler was attached to the top of a sensor bridle and both were deployed as part of an openhole
gravel-pack completion. Standard packers and gravel-pack service tools were used. The system
became activated when a mating inductive coupler was landed as part of the upper completion.
Surface indication of landing was provided by incorporating mechanical feedback into the lower
assembly. With the coupler components in position, the tubing hanger was landed into the

horizontal tree. Upon activation of the electrical penetrator, high-resolution temperature data
were then immediately available across the length of the sandface, which was an industry first
for a subsea producing well. No additional penetrations were required in the tree.
Development of this system required coordination from the operator because of the
multiple vendors involved in the project. They supervised multiple qualification and systemintegration tests performed over the 2-year development period to ensure ultimate success in the
subsea deployment.
Field results showed that the mating inductive couplers provided high-efficiency of
power transmission so that industry-standard power settings were sufficient to power a bridle
with one sensor per joint of screen. The sandface data were available onshore during the cleanup
phase, allowing the operator to monitor the cleanup in real time. Once the wells are brought on
line, the sandface data will further enhance the interpretation of flow allocation and reservoir
drainage.
23) Subsea Processing: A Holistic Approach to Marginal Field Developments
Abstract
Description


The application of Full Subsea Processing (FSP) to develop remotely locatedmarginal fields in
Offshore West Africa is an attractive option for breakingthe techno-economic barriers which
have long hindered the development of thesefields. Some of the fields have remained marginal
and unproduced over theyears, arguably, due to incorrect estimates in recoveries and
economicsoccasioned by erroneous estimates in basic input parameters. Therefore, theright
method of application for developing marginal fields must be sought toensure that both National
and International Operating Companies partake in thedevelopment of these fields.
The present paper explores the use of full subsea processing technology todevelop marginal
fields economically.
24) Subsea Processing and Boosting in Brazil: Status and Future Vision
Abstract
Subsea processing and boosting can be key enablers or optimization alternatives for
challenging field developments and their benefits increase with water depth, flowrates and stepout. Petrobras has invested a lot on the development of such technologies, supported, among

other pillars, on an aggressive R&D policy through its technological programs like PROCAP,
and several subsea processing and boosting systems have successfully operated in Petrobras
fields. Considering that, these technologies are being considered for application in potential
Petrobras' scenarios including mature and green fields.
This paper aims to give an overview of the systems developed and applied in Petrobras
prospects during the last twenty years, such as the Vertical Annular Separation and Pumping
System (VASPS), Boosting Systems with Electrical Submersible Pumps (Mudline ESP and
MOBO), Subsea Multiphase Pumps, Subsea Raw Water Injection and Subsea Oil-Water
Separation (SSAO). It also reports the new R&D initiatives related to subsea processing and
boosting that are being developed within PROCAP - Future Vision technology program, showing
the main motivations of these developments, the main benefits of using each technology, the
technological challenges and typical application scenarios. Also, this paper illustrates the
analysis and evaluations performed so far, for all of the new developments presented.
25) Improvements to Deepwater Subsea Measurements RPSEA Program: ROVAssisted Measurement
Abstract
This report documents a project to improve subsea flow measurements to allowthe flow rates of
individual wells to be known more accurately, thus reducingrisk to both producers and the US
government while also improving reservoirrecovery. In this project, a non-invasive metering
approach was adopted using aclamp-on meter that may be conveyed to the sea floor using a
ROV. The goal ofthis project was to develop and prove methods for conveying a clamp-on meter
tothe sea floor by ROV, and document the results as a draft standard for thefuture.
Meters/sensors were marinized for prototype demonstration in surfacemultiphase flow loops and
in underwater test tanks.
26) Experience to date and future opportunities for subsea processing in
StatoilHydro
Abstract
Subsea processing involves one or more combinations of fluid conditioning and pressure
boosting of wellstream fluids and water at the seabed. The main benefits of applying subsea
processing include increased hydrocarbon recovery and accelerated production, together with
reduced

CAPEX
and
OPEX,
and
HSE
benefits.
This paper provides an overview of field operating experience for subsea boosting in the LuFeng
field and the separation, produced water reinjection and fluid boosting applications at Troll Pilot
and the Tordis fields, including the Tordis restart plans. The paper also describes design and
installation of the Tyrihans raw seawater injection and summarises the gas compression


technology qualification activities underway for the Gullfaks 2030, Åsgard Minimum Flow and
Ormen
Lange
Pilot
projects.
An overview of Statoil's future subsea processing opportunities is then presented and discussed,
including new opportunities being assessed at the Norne and Astero and fields.
All aspects of subsea processing are reviewed, including boosting, raw seawater injection,
separation, sand handling and produced water reinjection, and subsea gas compression
technology. The important role of large scale testing and technology qualification, and close
collaboration with key technology suppliers is described, together with a step-wise approach to
deploying increasingly complex subsea processing systems in ever more challenging
environments. Step out distance, water depth and harshness of the local environment for new
fields are all increasing and new, more cost-effective technologies will be need to profitably
develop
future
fields.
It is concluded that subsea processing has already provided positive business upsides, despite

certain technical challenges, and Statoil expects to continue a stepwise development and
deployment of subsea processing technology in the near and longer term future.
27) Development of a High-Boost, High-Power, Ultradeep Subsea Twin Screw
Multiphase Pump System
Abstract
Between 2005 and 2010 Shell has been working with Flowserve and other specialty contractors
to develop a next generation pumping system requiring a complete review and redesign of all
major components. The work has been performed at multiple locations in Europe and the
Americas by an integrated team. It has now reached the level of maturity that it can be shared
within the industry. In 2004, Shell performed a comprehensive assessment of industry capability
for subsea pumping. This study concluded that boost pressures available at the time were
insufficient to meet future project needs, particularly for ultra-deep, heavy oil applications with
large gas volumes. As a result the high boost, high power, ultra-deep twin screw multiphase
pump
development
was
initiated.
The development included building and testing the subsea twin screw pump, a submersible
motor, subsea electrical high power connectors, a pressure compensation system and high
bandwidth fiber optic health monitoring system in addition to a purpose-built high capacity test
loop. The project is now reaching its conclusion with integration of the core components due to
take place by the end of 2010. Individual components such as the pump have already been tested
up to 4 MW shaft power, 2400 psi differential pressure, flow rates up to 90,000 barrels per day,
with viscosities ranging from 2 - 2,000 centipoise, an order of magnitude greater than any similar
existing
machine.
This paper describes the work performed, the major challenges addressed and the methodology
used to overcome them. One particular challenge was the implementation of rigorous HSE
requirements for such high energy, heavy equipment.
28) The Development of an Instrument Measuring Pressure behind the Casing in

Subsea Production or Injection Wells
Abstract
This paper presents the results from a long term development project to produce an instrument
that measures pressure behind the casing in subsea production wells: online and in real-time.
Such an instrument will be an important application in protecting well integrity, where effective
cement seals behind the wellbore casing provide a barrier against the high pressures encountered
deeper in the well. Poor or deteriorating cement sealing and/or loss of casing integrity can allow
oil or gas to migrate vertically towards the surface along the outside of the casing which can lead
to a number of unwanted and potentially hazardous conditions. To this end, an instrument that
detects any variations in pressure behind the casing will provide early warning of these


conditions and allow intervention or other remedial actions to be planned and implemented in a
timely manner. The instrument also has a health & safety application in verifying the integrity of
the
B
annulus.
Two challenges to be overcome were the need to avoid any penetrations in the casing string, thus
maintaining its full pressure integrity, and the requirement to provide power to instrumentation
behind this casing without using batteries. The paper will describe the development process,
technology choices and laboratory testing of the instrument. It will also describe the applications
and limitations of the new system, which has been developed as part of a joint industry project
with Statoil (who co-author the paper) in competition with other instrument vendors.
The paper will be highly significant for oil and gas operators planning subsea production or
injection wells and for government regulating agencies in i) improving well integrity; ii) meeting
safety and environmental protection; and iii) in the development of a new technology instrument
not previously available on the market.
29) SS: Marlim 3 Phase Subsea Separation System: Controls Design Incorporating
Dynamic Simulation Work
Abstract

This paper describes the control system design for the Marlim three phasesubsea separation
system (SSAO) and how the standard subsea control system hasbeen adapted for the new
requirements for automated control. This is the mostadvanced subsea process system to date with
several "first ever" applicationsof separation equipment subsea: harp, pipeseparator, desanders
andhydrocyclones. The SSAO has a total of 7 control loops and a number of complexautomatic
sequences.
Further, the paper addresses how dynamic simulation analysis has been used tovalidate the
process control strategy and improve the operational proceduresdesigned during the basic
engineering
phase.
Control and operation of the SSAO has proved to be very challenging for severalreasons:
•
There
are
strong
interactions
between
different
process
components
• The system dynamics are stiff due to small liquid hold-ups and low GOR in thesystem
• The pressure drops of inline cyclonic equipment need to be balanced to ensureoptimal
performance
• Constraints in valve opening/closing speed and the importance of limiting thenumber of valve
movements
put
restrictions
on
controller
performance

•
Instrumentation
is
limited
compared
to
topside
facilities
The content described above contain several new aspects compared to atraditional subsea control
system and this paper will describe systemconsiderations with regards to implemented process
control and also theimportance of using dynamic simulations as a design tool.
30) Challenge and Solution of PanYu35-2 Subsea Manifold Design Fabrication and
Testing
Abstract
As one of the main equipments of South China Sea Deep Water Gas Development
project, PanYu35-2(PY35-2) subsea manifold provides a support for the connection of 6” and
10” pipeline in the pipeline route, and also provides a support for the field pigging and pressure
test. The manifold is connected with two production wells, and considering the commercial
benefit of client, one spare hub and four spare valves are provided in the manifold system for the
future wells. During the design fabrication and testing, there are lots of challenges. In the paper
the design fabrication and testing of PY35-2 subsea manifold were presented, and the challenge
and solution during the manifold development were presented as well. These can provide a good
reference to the subsequent project in South China Sea.


31) Use of a Parallel System For Improving Subsea Intelligent Well Control, Monitoring
And Reliability
ABSTRACT
The issue of improving monitoring and control of subsea completions while maintaining high
reliability is critical due to accessibility and intervention costs. Hydraulic control of the

downhole choke valves in multiple zones can be complex, and the situation is further
complicated by the fact that traditionally different companies supply the downhole completion
equipment and the tree control system at the wellhead. This can lead to less production data
being available, reduced control functionality and valve control logic issues. Additional
interfacing requirements also lead to an increase in costs for a project.
This paper details the design approach, application and advantages of a dedicated intelligent well
completion (IWC) control system for subsea fields. It also reviews the methodology and issues
related to the integration of the control system within an existing field development in the North
Sea.
The proposed system has an electrohydraulic control module, provided by Schlumberger,
mounted on a subsea production tree, which provides complete control and monitoring of the
intelligent well independent from the tree control system. This approach allows the intelligent
well subsea control system to be tailored specifically for the completion equipment and well
type. It also provides additional protection to the tree control system from control line thermal
expansion
and
the
potential
of
leaks.
The subsea solution selected by the client aims to reduce the loading and project-specific
customisation of the production critical tree control system. This will allow it to be standardised
while still providing maximum performance and flexibility for monitoring and control of the
well. This approach permits a single supplier, in this case Schlumberger, to manufacture and test
the complete intelligent well control and surveillance system from surface to the subsea well
prior to delivery and the site integration test (SIT). This reduces the overall project risk and
avoids interface issues being detected late in the project phase.
32) Integrated Control System & Human Machine Interface - Challenges for
Uninterrupted Onshore & Subsea Operations
Abstract

The health and effectiveness of any Integrated Control System depends on many factors. Among
these factors is the proper design, selection of Control System, seamless integration, System
Architecture, System Configuration, System Integration Testing, Control System Installation,
Commissioning, Site Acceptance Test, Preventive Maintenance, Predictive Maintenance,
Functional
Testing
etc.
The integrated solution for the Onshore, Offshore & Subsea Control System includes a dedicated
Subsea Control System, DCS System, ESD System, Process Simulator System, F& G System,
Large Screen Abnormal Situation Management Video Wall, Measurement Systems etc.
The power to the Offshore and communication to Offshore & Subsea is through Umbilical's. The
backup communication from Onshore to Offshore is through dedicated Microwave Network. The
communication from Onshore Terminal (OT) Control Room to Subsea wells is about 50 Km to
60 Km. The remote Subsea wells are Controlled and can be Shut down from OT.


The best-in-class technologies in Control & Safety was effectively implemented by deploying
various protocols like Foundation Fieldbus, HART, Control Net, OPC, MODBUS TCP I/P, Serial
Interface etc. The digital Control System reliably monitors and controls the over 1, 10,000 tags.
All the DCS hardware is integrated with the non DCS hardware while having a common control
system information. The System has the facility to provide information across the organization
giving the best possible foundation for collaboration between people, processes and systems.
In such a large network of integration of technologies & integrated operations of Subsea &
Onshore, identifying and minimizing control system errors are a big challenge. It is a big
challenge to ensure continued operations of these facilities without any Trips.
This article focuses on Control & Instrumentation Systems contributing factors for uninterrupted
Operations of Onshore/Offshore/Subsea facilities during the first 1033 days of operations & the
challenges to ensure continued operations without any facility Trips.
33) Controls Reliability And Early Life of Field Failure of Subsea Control Modules
Abstract Subsea control systems are becoming more complex. As they are moving into

even deeper water, using more complex equipment and collecting more data, the demands on
their performance are increasing. This has resulted in the need for faster data retrieval, more
complex programmable processors, bigger power-hungry devices and continual technological
progression.
Thus whilst there is a desire in each project to keep innovation to a minimum and use only what
is tried and tested, in reality the industry is seeing a steady product development and evolution.
Nowhere is this more apparent than in the heart of the control system''s subsea control module
(SCM). It is no secret in industry that the SCM is one of the systems with the biggest reliability
challenges. Chevron collects all the subsea reliability data in a database called Subsea Master.
On reviewing the data of the SCM reliability statistics, not surprisingly, Chevron has found them
to
be
one
of
its
principal
bad
performers.
Further analysis revealed that SCM reliability was not as high as desired or expected, and
attempts to correlate against the various fields and environmental conditions revealed little. It
appeared that there was no correlation between environmental factors and failure rate, or even
the age of the systems and failure rate. However one thing clearly stood out, early life failure was
a major problem.
34) ESP Technology Maturation: Subsea Boosting System With High GOR and Viscous
Fluid
Abstract
This paper provides insight into the Caisson ESP Technology Maturation for subsea boosting
systems with high GOR and viscous fluids. It will focus on the developmental research on the
effects of viscosity and two phase (liquid & gas) fluids on electric submersible pumps (ESPs),
which are multistage centrifugal pumps for deep boreholes.

The Electrical Submersible Pump (ESP) system is an important artificial lift method commonly
used for subsea boosting systems. Multiphase flow and viscous fluids cause problems in pump
applications. Free gas inside an ESP causes many operational problems such as loss of pump
performance or gas lock conditions (Barrios 2010 [6]). The objective of this study is to predict
the operational conditions that cause degradation and gas lock. This paper provides a summary
on the Technology maturation for a high scale ESP Multi-Vane Pump (MVP) for high GOR
fields to in support of Shell's BC-10 developments. These novel projects continue the long


tradition of Shell's leadership in the challenging deepwater environment. This paper will describe
the capability and effects of viscosity and two phase (liquid & gas) fluids using a MVP 875
series G470 as a charged pump in a standard ESP system 1025 series tandem WJE 1000 mixedtype pump.
Extensive testing and qualification of the subsea boosting system was undertaken prior to field
considerations. Testing was conducted at the world's only 1500-hp ESP test facility capable of
controlling multi-phase fluid viscosities and temperatures. A comprehensive suite of tests was
performed in conjunction with Baker Hughes Centrilift replicating the expected conditions and
performance requirements for Shell's deepwater assets. This paper describes the subsea boosting
system maturity process, and reports the effects of viscosity and two phase liquid - gas fluids on
ESPs. The test facility work was performed using pumps with ten or more stages moving fluids
with viscosity from 2 to 400 cP at various speed, intake pressure, and gas void fractions (GVF,
aka gas volume fractions). The testing at Shell's Gasmer facility revealed that the MVP-ESP
system is robust and performance tracked theoretical predictions over a wide range of two-phase
flow rates and light-viscosity oils
35) API 17TR12 - Consideration of External Pressure in the Design of Deepwater Subsea
Equipment
This paper will present an overview of the issues which must be addressed by designers
of subsea equipment for deep water applications. It will describe API guidelines which are being
proposed to establish “Depth Adjusted Working Pressure” ratings for equipment, indexed to the
water depth where the equipment will be installed. A new recommended practice will be
presented providing guidelines for how such equipment design should be conducted; using triaxial VME FEA methods, applying applicable load cases, and additional design verifications for

protection against other identified failure modes. The equipment is to be qualified using testing
methods which simulate the effects of external ambient seawater pressure at depth. The new
“Depth Adjusted Working Pressure” (DAWP) ratings will have a significant beneficial effect,
specifically on HPHT projects, where the external ambient seawater pressure at water depth can
be used to improve or enhance the equipment maximum allowable internal pressure, allowing
the equipment’s DAWP rating to be considerably higher than the traditional API “Rated Working
Pressure” (RWP). The authors will propose recommended practices for how to equipment may
(and should be) designed and qualified to take into account the effects of external ambient
seawater pressure. Using the proposed design, analysis and testing methods will result in an
optimized equipment design which is lighter, less expensive, and more efficient equipment for
high pressure projects in deep water applications. Using the recommended methods for including
external pressure in the design of deepwater subsea equipment can result in significant wall
thickness optimization for pressure-containing components and connectors. Maintaining an
optimized wall thickness will result in valuable savings in size and weight, improves the
reliability of heat treating and welding operations, and reduces the suspended weight for
equipment installation operations (which can be a significant issue for projects in deep water). In
many cases, by using the new Depth Adjusted Working Pressure ratings, one can avoid the need
to jump to the next higher API RWP category for deepwater HPHT projects where internal
pressures may only be moderately above the current API RWP category.
36) Integrated Operations and Integrity Management: Subsea System Vendors as Value
Added Providers
Abstract
The recent resurgence of interest in Integrated Operations (IO) and Integrity Management (IM)
for the oil and gas industry has triggered necessary discussions of why revisiting these ideas and
initiatives is important to the future of the industry. By implementing IO and IM programs and


initiatives, operators gain an advantage in achieving increased recovery, reduction of operating
expenses (OPEX), efficiency in execution, and optimization of asset availability. More than ever,
the operator is held accountable by company stakeholders to determine rationalization when

implementing any new program. This paper is to provide supportive rationale that the operator
needs in choosing the subsea system provider as the best equipped to develop the intelligence
engine
driving
its
IO
and
IM
programs.
The key to a successful IO and IM program design and implementation lies in the provider's
proven history of experience and competence in the areas of well completion, production flow
management, power distribution (hydraulic and electrical), controls (subsea and topside),
installation, intervention, and life of field services and support. On both the technical and
logistical sides of IO, expertise in these areas lends to the provider a better comprehension and
applicable tools essential to the successful and effective implementation of a real-time
diagnostics system and the associated support services program, including:
37) Merging ASME and API Design Methods for Subsea Equipment Up To 25,000 PSI
Working Pressure
Abstract
A current challenge in the oil industry is the design of subsea equipment forpressures more than
15000 psi. Current standard, American Petroleum Institute,Specification, 17D (API 17D) for
designing subsea equipment is limited to 15000psi working pressure. One of the key
recommendations of API TR PER15K (draft)is the utilization of the American Society of
Mechanical Engineers (ASME)Boiler and Pressure Vessel Codes (BPVC) for designing pressure
vessels forpressures above 15000 psi. This paper proposes a design methodology combiningthe
relevant API and ASME design codes for the design of subsea equipment forpressures more than
15000
psi.
Specific guidance is provided in this paper to safely utilize the ASME designmethods with API
materials. These approaches allow for the increase of ASMEdesign test pressures to match API

while satisfying ASME and API designallowable limits. Methods and guidance are provided for
the use of stressclassification, stress linearization, protection against general plasticcollapse,
local collapse, buckling and cyclic loading. Recommendations are madefor Load Resistance
Design Factors to accommodate the difference in hydrostatictest pressure between ASME and
API. Additionally, approaches using bothtraditional stress-based fatigue analyses methods and
fracture mechanics theoryare compared. The design of closure bolting conforming to API
requirements isintegrated with the ASME methods, along with the recommendation ofnondestructive examination (NDE) requirements to align with the recommendedstress and fatigue
design
factors.
An example design evaluation of a pressure containing API 6A, 4 in. 20 ksi type6BX flange is
presented for a design pressure of 20000 psi with bolt preload asrecommended in API 17D. The
results show the existing API methods are adequateup to 25000 psi and the design verification
methods meet the recommendations ofAPI TR PER15K.
38) Transforming Raw Subsea Sensor Data for Advanced Dynamic Positioning and
Autonomous Functions in Real-Time for Asset Management and Remotely Operated
Vehicle Operations
Oil and gas exploration is moving towards deeper waters, challenging geographical areas
and dynamic working environments. This paper outlines the technology developments in an
advanced control system embedding intelligent algorithms with sensor data in a closed loop, to
perform various IRM tasks autonomously on a workclass remotely operated vehicle (WROV).


Original
analysis
and
field
trial
results
are
presented.

The data from the navigation sensors can be used to position and geo-reference the payload data,
however, survey has relied upon expert piloting skills to maintain the WROV on a set course at a
predetermined speed, heading and height from the seabed. In response to emergency situations,
the equipment is hard to mobilise and the investment can be compromised if the WROV cannot
be made to steer the course. This paper presents novel work in developing an autonomous
control function suite integrated on a WROV to maintain a pre-laid course and offer a stable
platform to gather data, and perform a task. Combined navigation functionality fuses data from
GPS string, imaging sonars and a state-of-the-art phased array Doppler Velocity Log (DVL) with
a Dynamic Positioning computer. Operators are equipped with the tools to survey and inspect
their
environment
in
a
compact,
easily
deployable
form
factor.
This development highlights vehicle and umbilical positioning, movement logging, advanced
vehicle controls (sophisticated cruise, mission planning and object/target recognition modules)
and increased reliability. The Dynamic Positioning computer translates high-level mission
requirements from a surveyor into automatic thruster commands providing automatic inspection
and survey. Results from a selection of trials conducted with a major subsea operator using the
system will be shown. The results demonstrate improvements in WROV control during transit,
station keeping and conducting simulated riser inspection - via easy-to-use human-machine
interface. The advance controls offer significant reduction in time and costs, and increased
reliability,
compared
to
pilots

performing
operations
manually.
The technical industrial contributions of this technology are reduced training costs, mitigating
lump sum risks by saving time in construction support operations, maintaining the quality and
reliability of drill support operations, improving the quality of data for survey and IRM activities
and providing better umbilical management.
39) Successful Placement of an Advancing Sand and Fines Control Chemical as a Remedial
Sand Control, using Subsea Flow Lines from an FPSO
The ENI Nigerian subsidiary operates a subsea field located in the north western sector of the
Nigerian offshore deep-water, is an oil and gas producing field. The production is from subsea
wells which are directed to a Floating Production, Storage and Offloading vessel (FPSO). All the
wells in this field require sand control measures in the reservoir section from the onset to prevent
sand production. Sand control in the field is challenging and various methods (gravel pack, frac
pack and expandable sand screens) have been used. Conventional sand control integrity has
failed in one of the wells, compromising production rate and exposing subsea asset to risks
related to sand production. Compared to heavy workover required for primary sand control
application, an advancing chemical treatment bullheaded through the subsea flowline and the
production tubing provided a unique, highly economical, and effective solution to this
challenging problem. The product effect creates an ionic attraction between the sand grains and
fines, using non-damaging water-based fluid. The chemistry mitigates sand production, reduces
or stops fines migration and increases the Maximum Sand Free Rate (MSFR). After pumping
chemical treatment through a 4.2 km flow line in the failed frac packed completion, well
returned to production with minimal sand presence, less than 24 hours NPT and eliminating the
need for re-completion. This was the first time the chemical had been pumped from an FPSO and
through subsea flow line. This paper discusses the planning, execution, post job analysis and
lessons learned.


40) Control System Upgrades for Tordis and Vigdis Field - A Project Case Study of

Revitalising Brownfield Developments with Next Generation Subsea Controls
Abstract
Since the 1980s, multiplexed electro-hydraulic control systems have been successfully employed
in subsea oil and gas production. With field lives extending, and the original equipment
becoming more difficult to maintain, particularly because of electronic component obsolescence,
it is possible by applying new generations of control system equipment to bring enhanced
controls capabilities into brownfield developments.
From the inception of the Tordis/Vigdis Controls upgrade & Modification programme (TVCM),
it was seen that a number of the design limitations of the legacy system could be overcome when
upgrading to a modern and flexible communications system with standard comms interfaces.
There were some specific limitations of the installed system, and in addition, for the legacy
system, electronic component obsolescence was becoming an increasing burden in support of
continuing production.
Following the completion of the upgrade under the TVCM programme, the new system will
deliver significant step-changes in the performance envelope of the overall Control and
Instrumentation System, including improved reliability, a new configuration employing ‘Open'
communications protocols between topsides and subsea with the communications bandwidth
available to the Tordis producer wells upgraded to 1Mbit/s.
A novel feature, and a key success factor for the project, is the use of Subsea Control Module
interface adapters.
41) A Innovative Liquid Detection Sensors for Wet Gas Subsea Business to Improve GasCondensate Flow Rate Measurement and Flow Assurance Issue
In subsea business, the use of wetgas flowmeter is becoming a standard for deep and ultradeep
field development. The business growth is outstanding over the last few years and it is expected
to continue at the same path. Furthermore, the tieback of these fields to hosting platform or
onshore facility has increased drastically. The critical measurement is not only on high accuracy
flow rates but also on water detection with 99.x% of the production being gas. The liquid is
initially predominantly condensate phase continuous before becoming more watery with the well
ageing. Water is the main concern either in presence of H2S or because hydrate could be formed
and will plug the production line . To counterbalance these catastrophic scenarii the chemical use
is necessary, but the cost leads to loss of benefit, therefore an optimization is necessary. The need

for a reliable water detection became a compulsory practice with constraint to be working
initially in oil and water continuous phase. The innovative solution describes in this paper look at
how an accurate measurement could be offered at any GVF and WLR based on the use of two
different types of measurement having a different response to the water-hydrocarbon contrast
and water conductivity sensitivity.This approach led to a development of an innovative add-on
on the wet gas meter which provides a high accurate local water fraction measurement that can
be comparing with a global measurement. This paper is focusing on the explanation of this
innovative analysis after 10 years of work in this direction, and the value brought to oil/gas
operator in detection of water and then optimizes the use of expensive chemical. It is also
possible to identify clearly, if the water is coming from the formation or not in any WLR mix. It
addresses also the use of MPFM beyond the classical metering flow rate performance and focus
on the benefits of brought for a subsea flow assurance and reservoir management.


42) The Ormen Lange Langeled Development
Abstract
This paper provides a summary of the challenges of executing the Ormen Lange Langeled
Project. Hydro is the operator responsible for the planning and development phase. After Ormen
Lange comes on stream in October 2007, Shell will take over the operatorship and be responsible
for the operational phase.
This paper introduces three main features of the execution phase of the project: The Ormen
Lange offshore development, the Ormen Lange onshore development and the Langeled gas
export system including gas receiving facility in the UK. This paper also addresses managerial
perspectives concerning HSE, quality and risk management, and procurement management.
43) Ormen Lange Pipelines - Geotechnical Challenges
ABSTRACT
The selected development scenario for the Ormen Lange gas field is a subsea tie-back to an
onshore terminal located at Nyhamna in Mid-Norway. There are large variations in soil
conditions along the 120 km long pipeline routes from shore to the template area. In narrow
valleys in the near shore area one of the main challenges was to find enough space for installing

all pipelines within the same corridor. The severe seabed requires rock supports for free span
mitigation of the gas pipelines both near shore and in the deep water area. For the service lines,
protection against trawling and dropped objects was required along the entire length and this
turned out to be particularly challenging at the steep Storegga slide slope and in the rough terrain
at the deep water area with soil shear strength of 1 kPa. The quasistatic stability of rock supports
higher than 0.5 m was not satisfactory for the 10-2 earth quake load event due to the soft soil
conditions. A deformation criterion was therefore applied both for the 10-2 and 10-4 earth quake
load events.
44) Ormen Lange - Flow assurance challenges
Abstract
Ormen Lange is a gas field located 100 km off the Norwegian coast in water depths varying
between 850 and 1,100 meters. The selected development scenario for Ormen Lange is a subsea
tie-back to an onshore processing facility at Nyhamna.
The field is located in a prehistoric slide area with varying water depths, from 250 to 1,100
meters. The result of this subsea slide is an extremely uneven sea bottom with local summits 60
to 80 m high. The back wall of the slide is steep, up to 26 degrees. Environmental conditions are
also challenging.
This paper describes the flow assurance challenges and technical solutions selected due to the
harsh environmental conditions specific to the Ormen Lange development, including:


Rough seabed combined with long tie-back distance.



Sub-zero temperatures (-1° C).

All together, this makes the Ormen Lange project one of the most challenging field
developments worldwide with respect to flow assurance.

45) Slope Stability At Ormen Lange
Abstract
The Ormen Lange gas field is located in about 900 to 1100 m water depth in the slide scar of the
enormous Storegga Slide that occurred about 8000 years ago. The slide left steep and high
headwalls above and below the planned field development area. Today's stability of the
headwalls is a major concern for the field development work The area under consideration is
large and has been mapped extensively with 2D and 3D seismic profiling The number of
geotechnical borings is limited and integration of geological, geophysical and geotechnical
information was required to develop a geotechnical model of the area. Stability analyses have
been carried out for critical sections of the headwalls. These involved long-term drained analyses
under gravity loading and undrained analyses considering the effects of earthquake-loading and
possible Influence from field installations like rockfill supports for pipelines and anchors. Focus
has been set on explanation of slide mechanisms involved in the Storegga slide and comparison
of the stress-strain-strength conditions in the headwall at the tune of the slide and today. Work is
still ongoing and under review and the conclusions presented here are thus to be considered as
preliminary.
46) Ormen Lange Subsea Compression Pilot
Abstract
Ormen Lange is a long tieback gas field developed with gas processing facilities onshore 120 km
from the production wells. The development strategy is to deplete the reservoir. In order to
maintain the production plateau for as long as possible and recover the anticipated gas and
condensate resources, offshore compression is required at a later stage.
This paper describes subsea compression as a cost effective alternative to the platform
compression solution and the strategy for qualifying subsea compression system at the time of
offshore compression concept selection.
This paper further describes the subsea compression technical solution.
47) Ormen Lange Subsea Production System
Abstract
This paper presents the concept and the technical solutions developed and applied to the Ormen

Lange subsea production system. First, the key technical challenges related to the subsea system
are presented. Thereafter the paper describes the extensive design, fabrication and testing
processes undertaken in order to verify correct functionality and gain confidence in the applied
solutions. Finally the paper summarizes achievements and key success factors for the project.
48) Ormen Lange Onshore Processing Plant
Abstract
The Ormen Lange Plant at Nyhamna consists of well stream processing, gas export compression
and condensate offloading to tankers. The gas from the field is conditioned to dew point and
heating value according to European specifications, then routed into the export pipeline to
Easington, UK, via the leipner field.
Condensate recovered from the well stream is stabilized and stored in a custom-built rock cavern
before being shipped from the terminal. Gas and liquid products are metered to fiscal standards
before being exported. The process facilities at Nyhamna consist of two gas conditioning and
dehydration trains, three export compressor trains and one condensate stabilization train. The


plant processing capacity is 70 million standard cubic metres per day (MSm 3/d) of sales gas at
an initial arrival pressure of 90 bar. Maximum condensate production is estimated to be 7000
Sm 3/d.
Before construction could start, a massive civil works task was performed, blasting more than 2
million m3 of rock in order to prepare the plant site and build storage caverns. The construction
and installation of steel structures, buildings, pipes, cables and equipment continued throughout
2006, while in 2007 the main task will be to test out the plant before starting production.
49) Ormen Lange Subsea Production System
Abstract
To ensure adequate safety of marine structures in extreme weather, it is conceivable that
standards are needed that account for the characteristics of ultimate limit seastates based on wave
conditions with a return period higher than 100 years. Such standards must include an analysis of
the reserve strength available when a marine structure is subject to an extreme event of a freak
wave. For the generation of freak waves traditional potential flow methods are not well suited to

accurately predict wave loads, because phenomena such as wave run-up on the structure's legs
and impact-related loads on the hull are not accounted for. Therefore, wave effects were
predicted with advanced computational fluid dynamics techniques. The purpose here was to
determine the safety level under freak wave conditions. We selected a typical mobile selfelevating drilling unit stationed the North Sea and investigated its structural response under
survival conditions and, in addition, under two extreme wave conditions representing freak
waves. Based on a comparison of the resulting stresses with the structure's rule based design
capability, we assessed the reserve strength capacity still available under freak wave
50) Ormen Lange-Challenges in Offshore Project Execution
Abstract
Ormen Lange is the second-largest Norwegian gas field and was discovered by Hydro in 1997.
The Ormen Lange field comprises an offshore subsea solution approximately 125 km off the
west coast of Norway, an onshore gas processing and export facility at Nyhamna, a gas export
transportation system between Norway and the UK, and the Easington gas reception terminal in
the UK. The Ormen Lange development is divided into three main sub-projects: Onshore,
Offshore, and Langeled.
This paper gives a summary of the Ormen Lange Offshore development, including descriptions
of project execution and contract strategy, and how Hydro's competence and systematic work
processes have been utilized in order to secure efficient progress. The Offshore project will be
further described - including the technical challenges of the project -in three OTC 2007 papers:


OTC 18965 Ormen Lange subsea production system



OTC 18967 Ormen Lange pipelines installation and seabed preparation



OTC 18969 Ormen Lange subsea compression pilot as a supplement to the summary

provided here.