Introduction AGBAMI – in Nigeria. It was acknowledged that


            AKPO is an oilfield granted to
Total, which was firstly discovered at the beginning of the 21st century (OilMapNG, 2018). This field belongs to the block Oil Mining
Licence 130 (OML 130) and is located about 200 kilometers offshore Nigeria
(Figure 1), lying in water depths of approximately 1400 meters (Abarrelfull,
2018). Exploited by Total Upstream Nigeria Ltd (TUPNI) since the early 2000,
production started in 2009 (Abarrelfull, 2018). It encountered multiple
challenges such as world-scale industrial execution in an unstable Niger delta
or high commercial pressures (Rafin and al., 2010). Facing those challenges
made it one of the first deep-offshore developments including oil with high gas
content and Total’s first giant deep-water development in the country (Nelson,

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General information

Fig. 1 – Location map showing AKPO in OML 130 (total, 2018)

commercial reserves of hydrocarbons had been discovered in the area, a common
belief was that Nigeria’s future production would mostly come from large scale
offshore projects especially like this one (Offshore-mag, 2018). Without
a doubt, National Oil companies (NOCs) and supermajors, such as Total or the China’s National Offshore Oil Company (CNOOC), were attracted by this kind of resources (Rafin and al.,

Fig. 2 – Timeline of the AKPO project


though, the AKPO’s field was granted to Total, AKPO is split between multiple
partners (total, 2018). The French oil company holds a 24% interest, CNOOC
acquired 45% back in 2006, while Petrobras has a 16% interest, the Nigerian National
Petroleum Corporation (NNPC) possesses a share of 10% and South Atlantic
Petroleum (SAPETRO) only 5% (Sapetro, 2018).

Partneship in large scale offshore implies aggreeing
with one another. The 9th of November 2017, Petrobas, heavily indebeted,
claimed to be putting Petrobras Oil & Gas B.V. for sale. This subsidiary
owning interest in two deep-water offshore blocks – AKPO and AGBAMI – in
Nigeria. It was acknowledged that the oilfield (AKPO) alongside the condensate
field (AGBAMI) accounted for over 18% of Nigeria’s liquid production. According
to Petrobras, they were also the two largest producing offshore fields in
Nigeria out of four (Braga, September 2017). Since
the AKPO field is operated by Total and AGBAMI by Chevron, both companies are
allowed to put a veto on the sale if necessary (Figure 6) (Offshore Energy Today, 2018). Partnership
seems like a key point in situation like this.

Fig. 3 & 4 – Petrobras put Nigerian
deep-water assets for sale, 9th of November 2017

(Fig. 3) (BELLO, 2018)


(Fig. 4) (Offshore Energy Today, 2018)


            In 2009,
TUPNI gained major recognition by bringing on stream the largest deep-offshore
project (total, 2018). Furthermore, Total’s AKPO, alongside Chevron’s Corp AGBAMI oil field, were
the only major oil fields expected to come on-line in 2009 in Nigeria, adding
500,000 barrels per day (b/d) to the country’s output (total, 2018).


Field’s structure

            Higher temperatures, higher
pressures and deep waters require high-performance materials. Thus, five
reservoirs, installed in channels situated at depth from 2900 mSS to 3700 mSS,
were affected to AKPO’s development (Fournie?, 2010). Within those five
reservoirs, the field’s Miocene reservoir contains fluid in ‘critical
condition’ i.g. liquid and gas in single phase, at high temperature and high
pressure (Fournié, 2010).  While making
AKPO technically and economically viable, the reservoir fluid had to
acknowledge some constraints since it’s a critical fluid. Depending on temperature, pressure and depth, a light
oil/condensate liquid is produced from 42 °
to 53 ° Application Program Interface (API), with a high liquid-gas ratio (GLR)
from approximately 1600 to 7300 standard cubic feet per barrels (scf/bbl) (Rafin and al., 2010).

Fig. 5 –
AKPO design rates (Fournié, 2010)


the same temperature and pressure constraints, the subsea infrastructure is
designed as a complex array of subsea flowlines, more than a hundred kilometres
long joined by steel catenary risers to the Floating
Production, Storage and Offloading (FPSO)
(Rafin and al., 2010).           

oilfield consist 44 wells, including 22 production wells, 20 water injectors, 2
gas injectors with a network of Umbilical, Flowlines and Risers connecting the
Subsea Production Systems to the FPSO, as well as 9 offline production
manifolds and 1 offline gas injection manifold (total, 2018).


Suppliers and contracts

            Being one of
the first deep-offshore developments including oil with high gas content and Total’s
first giant deep-water development in the country, AKPO’s project required
ressources from various suppliers. A project of this scale involved multiple
awarded contracts such as:

A $340 million
contract awarded to Cameron, a Schlumberger Company for the subsea system (44
wells, manifolds and Christmas trees1.  ) (Cameron, 2018);

A $1.08 billion contract to Technip/Hyundai Heavy Industries for the
engineering and whole process of installation of the FPSO (Ship
Technology, 2018);

An $850 million contract
to Saipem for engineering, procurement, construction
and installation of the umbilicals, risers and flowlines, as well as the
oil-loading terminal, which is the FPSO mooring system and the gas export
pipeline. This extends from the AKPO FPSO to the AMENAM platform (Subseaiq, 2018).

            The FPSO
is a floating vessel, at 1314 meters water depth, which is able to produce
crude oil and gas. It is made up of two parts: the topside and the hull
(dimensions: 310m x 61m x 31m) (Subseaiq, 2018). This vessel has a storage capacity of 2 million barrels. This
latter allows it to produce approximately 185, 000 b/d. FPSO includes two
processing trains to separate water and gas and seventeen topside modules. It
also owns living quarters sleeping for a crew of 200 people (Ship Technology, 2018).



            Over 175,
000 b/d of condensates and 550 million standard cubic feet per day (mmscfd) of
produced gas are not only produced but also exported by AKPO (Rafin and al., 2010). While 320 mmscdf
are exported onshore to the BONNY LNG Terminal, which
is a liquefaction plant that allows gas storage, via the AMENAM field
facilities, the rest of the gas is re-injected. The BONNY LNG Terminal’s owner is the Nigeria LNG
Limited (NLNG). This liquefaction plant is divided between four
shareholders :

The NNPC with 49% ;

Shell Gas BV with 25.6% ;

Total Fina Elf with 15% ;

And Agip with 10.4%.

Gas is only injected in reservoirs, which can benefit from
this type of pressure support (User, 2018).


Fig. 6 –
AKPO condensates production (Fournie, 2018)


            Three oil
discoveries: PREOWEI, EGINA, and EGINA-SOUTH (located on OML 130) form,
alongside the FPSO (located in the EGINA zone), a basis for an oil development.
EGINA and AKPO give an ideal model of hubs developing future hydrocarbon discoveries
in the block since they have the ability to handle a variety of fluid (Anon, 2018).


Economic aspects

the 21st century, the cost of production, labour and security for oil companies
to operate in Nigeria had dramatically risen. Since the location of AKPO is
directly linked to the production factor (Ogj, 2018). As
a deep-water offshore project, AKPO required a sustainable crude price in
excess of $40 per barrel to support continued production (Subseaiq, 2018).

            The development
cost of the FPSO only was approximately about $1,080,000,000, which included
all the costs incurred from initiation to implementation of the project (Subseaiq, 2018). In 2000, most of Nigeria’s production growth was expected to come from
offshore projects but the technological challenges in developing the reserves
meant that only wealthy companies could participate (Bybee, 2010). This implies that only NOCs or
supermajors were able to extract the ressources of the AKPO field.


Theoretical vs Practical

stated before, a common belief was that Nigeria’s future
production would mostly come from large scale offshore projects and that it
would attract major oil companies. AKPO was no exception, especially with its
enormous resources. In 2009, AKPO had the capacity to produce 175,000 b/d and
reached the peak oil production (225,000 b/d). It was also assumed that 80% of
the production would be exported via a buoy, 2 kilometers away from FPSO, and
would be condensate by the end of 2010 (Subseaiq, 2018). As mentioned before, AKPO’s first production was achieved in
March 2009, but fortunately its peak production reached 5,000 b/d higher than
expected, being at 180,000 b/d with over 350 million barrels of condensate
produced to date (Ogj, 2018).

Fig. 7 –
Field layout and well delivered as of 1st January 2010 (Ludot and Delattre, 2018)

However, not all goals
were achieved on time. As shown in figure 5, 24 wells out of 44 were put in
place by the end of 2010. Nonetheless, most of the assumptions made before the
beginning of the project are up to date. 41 wells out of 44 planned, were
completed, 21 out of 22 producers achieved, including
2 gas injectors but excluding 7 water injectors.


Challenges encountered

            In large-scale oilfield, commercial
pressure comes at a risky point. It is commonly said that “All deep-water
offshore projects are challenging”, and AKPO was no exception (Nelson, 2010).
Oilfield within deep-water implies challenges such as the one mentioned before,
or even ensuring the “safe” travelling of condensates and gas in multiphase
flows to the production facilities (Nelson, 2010). Undertaking project in
deep-water raises various constraints, and even though the use of past
experience in deep-water e.g. Gulf of Mexico, can offer alternatives, AKPO
raised its very own issues (Rafin and al., 2010).

            In addition to those challenges,
some constraints due to its location were also taken into account. Large-scale
project like AKPO implies commercial pressure from the different operators
involved to the three major suppliers (Nelson, 2010). Moreover, the location,
the Niger delta, is obviously a challenge, which cannot be easily overlooked.
Ressources’ issues such as personnel or manufacturing, alongside a blooming and
promising market make this a one kind of a project (Ihs Markit, 2018).





though AKPO was the largest subsea infrastructure in Nigeria’s deep water
brought on stream in 2009, it is still an ideal model of hub. Despite the
complications of operating in Nigeria the commitment shown by Total there was
clear evidence that the reserves offered were worth pursuing. AKPO implied
various constraints to satisfy, along with massive capital investment, the need
of new technology supplies to make it profitable and viable meanwhile (Rafin
and al., 2010). The project and the oilfield provided a convincing benchmark
for other subsea developments not only in Nigeria but also on a global scale
(Nelson, 2010). Highlighting the fact that Nigeria’s production growth comes
from offshore projects, it seems obvious that only large NOCs, like Total, are
able to supply new technologies to maintain the extraction of resources from
complex location.












1: The set of
valves, spools and fittings connected to the top of a well to direct and
control and control the flow or formation fluids from the well (Glossary.oilfield, 2018)


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Available at:
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Available at:
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Available at: Accessed 17
Jan. 2018.


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nie, Francois. “AKPO Project Start-Up and Operation.” AKPO Project Start-Up and
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Accessed 17 Jan. 2018. (2018). Total updates assay for
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Brunno Braga Hart. “Petrobras Works To Sell Some Oil Assets Onshore,
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Akpo Field.onlineAvailableat:
Accessed 17 Jan. 2018.



Fig. 1 (2018). Nigeria: Early
start-up of production of the Akpo deep offshore field. online Available at:
Accessed 17 Jan. 2018.


Fig. 2

timeline via Vizzlo site

Fig. 3

BELLO (2018). Chevron, Total
are top contenders for Petrobras stake in Agbami, Akpo and Egina – BusinessDay
: News you can trust. online BusinessDay : News you
can trust. Available at:
Accessed 17 Jan. 2018.


Fig. 4

Offshore Energy Today.
(2018). Petrobras puts Nigerian deepwater assets up for
sale. online Available at:

Petrobras puts Nigerian deepwater assets up for sale

Accessed 17 Jan. 2018.


Fig. 5

Rafin, F., Laîné, A. and Ludot,
B. (2018). AKPO: A Giant Deep Offshore Development.


Fig. 6

Fournie, F. (2018). AKPO Project
Start-Up and Operation.


Fig. 7

Ludot, B. and Delattre, E.
(2018). Drilling Akpo: 22 Wells Required, 22 Wells
Delivered For Production Start Up and Plateau.