American Oil and Gas Reporter - June 2017 - 59

SpecialReport: Offshore & Subsea
FIGURE 2
Evolution of ESP-Based Subsea Processing Technology
1995

2001

2002

2006

2009

2010

2010

2012

2015

2017?

Liuhua 11-1
South China
Sea
(CNOOC)

Marimba
Brazil

Jubarte
ESS-110 EWT
Brazil
(Petrobras)

Golfinho
Brazil
(Petrobras)

Parque das
Conchas
Brazil
(Shell)

Jubarte
Phase 2
Brazil
(Petrobras)

Perdido
GoM
(Shell)

Cascade and
Chinook
GoM
(Petrobras)

Parque das
Baleias
Brazil
(Petrobras)

Jubarte
Phase 3
Brazil
(Petrobras)

Wellbore ESP

VASPS ESP with

Boosting

Separation

Multiphase

Gas/Liquid

ESP above

Christmas Tree
Booster

Caisson ESP
Booster

Caisson ESP with
Gas/Liquid

Separation

separating gas on the seabed so that a
traditional "dry gas" compressor can be
used, or designing a liquid-tolerant (multiphase) compressor to handle wet gas.
Statoil demonstrated both in 2015, when
its subsea gas compression facility in the
Asgard Field became the first to commence
operations, followed a few weeks later
by the startup of the world's first subsea
wet gas compressor at the Gullfaks Field.
The closer the compression is to the
well, the higher the efficiency and production rates become, Statoil says. Carrying out compression on the seabed also
provides benefits in the form of improved
energy efficiency. Statoil describes the
technology as a "quantum leap" in its
subsea factory concept, which envisions
a subsea-to-shore paradigm with all processing done on the seafloor.
By eliminating the need for topsides
compression, subsea compression reduces
both capital and operating costs while
improving recovery/production rates and
extending a field's productive life. Furthermore, it provides advantages in flow
assurance risk management such as slugging, to ensure that production can be
maintained to deliver the reservoir's reserves potential.
The process flow diagram for the Asgard gas compression train (Figure 4) includes:
* Cooling the incoming multiphase
well stream;
* Using a scrubber to separate gas
and liquid;
* Pressurizing the gas stream in a
centrifugal compressor;
* Cooling the gas stream in a discharge cooler;
* Pressurizing the liquid stream in a
centrifugal pump; and
* Recombining the gas and liquid
streams and flowing the multiphase stream
to topside.
Another application is Statoil's Ormen

Caisson ESP
Booster

Caisson ESP with
Gas/Liquid

Separation

Horizontal ESP

Skids at Seabed
Booster

ESP Skid
Booster

Horizontal ESP

Skid at Seabed
Booster

Lange subsea compression pilot using a
fully marinized, vertically orientated 12.5megawatt centrifugal compressor. The
system has been installed and passed system tests, but has not yet been used in
full-field production. The Ormen Lange
Field is an all-subsea development that
has no surface platform. Instead, 24
subsea wellheads in four seabed templates
connect directly to two pipelines that run
to an onshore processing terminal.
Another advanced subsea concept is
"cold flow" multiphase pumping
(liquid/solid slurry), a hydrate mitigation
process designed to improve both capital
and operating costs compared with traditional production methods. In a cold flow
operation, hydrates are actively encouraged
to crystallize in a chemically conditioned
fluid to form a stable slurry mixture. The
slurry suspends inert hydrate crystals
throughout the liquid phase so that hydrates
can flow in suspension through the
pipeline. In other words, hydrates are allowed to form, but in a way that they become inert and cannot agglomerate in

flowing systems.
Although anti-agglomeration chemistry
is often required, cold flow technology
can eliminate the need for hydrate inhibition chemicals during normal steadystate operations in both oil and gas production streams. SINTEF's Saturn project
demonstrates the ability to develop subsea
fields using ultra-long multiphase cold
flow, well stream transport in uninsulated
pipelines with no heating or chemical
additives, and very simplified subsea
equipment and control procedures. The
process was achieved through a novel
recirculation scheme for seed particles
of gas hydrates and wax, resulting in an
easy flowing slurry with inert particles
suspended in the liquid phase.

Selecting A Subsea System
As new fields are discovered in deeper
and more remote waters farther from existing infrastructure, it can become impossible for the production stream to
flow naturally from the reservoir to the
end destination without adding energy
either in the wellbore or on the seafloor.
Subsea processing includes using pumps
to enhance the fluid-driving energy (boosting), separating and disposing the produced
water at subsea (two-phase separation),
or separating oil/gas/water at subsea
(three-phase separation).
Numerous factors and considerations
impact the selection of a subsea processing
solution-from the well completion design
to surface facility power systems and
step-out distance to the platform-but the
most critical and fundamental factors are
the characteristics of the reservoir and

FIGURE 3
Example Compact SSAO Seabed Layout

FPU
Gas

Production
Wells

Production
Manifold

Oil

Injection Wells

Compact SSAO

JUNE 2017 59
American Oil and Gas Reporter - June 2017

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