Introduction projects as vast commercial reserves of hydrocarbons


AKPO field was discovered in the beginning of 2000 by Total Upstream Nigeria
Ltd (TUPNI) and less than a decade later production started. The AKPO field in
block Oil Mining Licence 130 (OML 130), granted to Total, is located about 150
kilometres off the Niger Delta (Figure 1) or approximately 200 kilometres
offshore Nigeria in 1400 meters water depth. This project was not only the
first deep-offshore development including oil with high
gas content but also Total’s
first deep-water development in Nigeria. It did not only face the challenges of
combining gigantic scale but also world-scale industrial execution in an
unstable Niger delta. (Abarrelfull, 2018) (Nelson, 2010) (OilMapNG, 2018) (Bybee, 2018)
(, 2018)

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

in 2009, it was believed that much of Nigeria’s future production would come
from large scale offshore projects as vast commercial reserves of hydrocarbons
had been discovered in the deep waters and more would be found. It was also
assumed that such a field would attract many National Oil Companies (NOCs) and
supermajors. (Bybee, 2018)

Fig. 2 – Timeline of the
AKPO project


In 2009 AKPO was the
largest deep-offshore projects ever undertaken at the time and was the largest
brought on stream through that same year. 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,

Total holds a 24% interest and is operating OML 13, alongside, China’s National
Offshore Oil Company (CNOOC) which purchased a 45% stake in OML 130 in 2006,
Petrobras NOC with 16%, the Nigerian National Petroleum Corporation (NNPC) with
10% and South Atlantic Petroleum (SAPETRO) with 5%. (Sapetro, 2018)


development involves 5 reservoirs, deposited in a complex channels, situated at
depth ranging from 2900 mSS to 3700 mSS. In the field’s Miocene reservoirs, the
fluid is assumed to be in ‘critical condition’ i.g. liquid and gas hydrocarbons
are in a single phase, at high temperature and pressure. It is important to highlight the fact that higher
temperatures/pressures and deeper waters required high-performance materials. (OnePetro, 2010)

Here, the reservoir
fluid is a critical fluid, which implies that the fluid type is dependent on
temperature and pressure, as mentioned before, as well as on depth. The liquid
produced is light oil/condensate, 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). Moreover, maintenance in the reservoirs is necessary, with
gas injection in one of them and water injection in the 4 other reservoirs. (OnePetro, 2010)

Fig. 3 – AKPO design rates (Rafin, Laîné and Ludot, 2018)


oilfield is composed of 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 Floating Production, Storage
and Offloading (FPSO),
as well as 9 offline production manifolds and 1 offline gas injection manifold.
(total, 2018)
(Nelson, 2018) (Bybee, 2018)

The subsea infrastructure consists of a complex array of high
temperature and high pressure subsea flowlines that is more than a hundred
kilometres long connected by steel catenary risers to the FPSO. (Nelson, 2018)


involved in the project

scale of projects such as AKPO requires resources from many suppliers. In May
2005, Cameron, a Schlumberger Company, was awarded a $340 million contract for
the subsea systems on the fields, including 44 wells, manifolds and Christmas
trees1. (Abarrelfull, 2018) (Cameron, 2018)

            Technip/Hyundai Heavy Industries, was
also awarded a $1.08 billion contract by TUPNI for the engineering,
procurement, construction and installation of the AKPO FPSO. The FPSO is a floating vessel, moored in 1314
meters water, which is able to produce crude oil and gas. It is made up of two
parts: the topside and the hull. The hull’s dimensions are 310m x 61m x 31m, which means it has a storage
capacity of 2 million barrels; thus allowing it to produce approximately 185,
000 b/d. This vessel includes two processing trains to separate water and gas,
17 topside modules and living quarters sleeping for a crew of over 200 people. (Ship Technology, 2018) (Subseaiq,

In addition, in May 2009, Saipem was awarded an $850 million contract
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)



plateau production is 175, 000 b/d of condensates and 550 million standard
cubic feet per day (mmscfd) of produced gas. 220 mmscfd of the gas is
re-injected, while 320 mmscdf are exported onshore to the BONNY LNG Terminal,
which is a liquefaction plant that allows storing gas, via the AMENAM field
facilities. (User, 2018)


Fig. 4 – AKPO condensates production (Fournie, 2018)


is a 15% shareholder of the liquefaction plant alongside NNPC with 49%, Shell with
25.6% and Agip with 10.4%. The remainder is used as fuel gas. The hybrid
injection/export gas scheme optimises hydrocarbon recovery. Gas is only
injected in reservoirs which can benefit from this type of pressure support. (User, 2018)

the same OML 130 block as AKPO, three oil discoveries (PREOWEI, EGINA, and
EGINA-SOUTH) now form the basis for an oil development with a FPSO located in
the EGINA zone. Both EGINA and AKPO, with their ability to handle a variety of
fluid, were and are still today ideal hubs for developing future hydrocarbon
discoveries in this area. (Anon, 2018)



As a deep-water offshore project, AKPO required a sustainable
crude price in excess of $40 per barrel to support continued production. As
stated before, the location an oil field exists based on economic aspects. The
costs of production, labour and security had risen in the beginning of the 21st
century for oil companies operating in Nigeria, leading to even more expenses
as expected. (Ogj, 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 the large NOCs and supermajors would be able to extract the resources of
such field. Indeed, 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) (Bybee, 2018)


Theoretical vs

assumptions were based on its gigantic resources which would surely make enormous
profits; such as the reaching of 175,000 b/d by the end of 2009 or even the
reaching of the peak oil production of 225,000 b/d. In addition, 80% of this
production was exported via a buoy located 2 kilometres from the vessel and was
supposed to be condensate by the end of 2010. The gas
is piped 150 kilometres to the AMENAM Kpono Oil Field platform;
from where it is sent to the Nigeria LNG Terminal. (Abarrelfull, 2018) (Subseaiq,

Fig. 5 – Field layout and well delivered as of 1st January
2010 (Ludot and Delattre, 2018)


As shown in figure 5,
not all wells were achieved by 2009; with only 24 out of 44 wells by 2010. However,
full field development is
still ongoing with 41 out of 44 planned wells completed, 21 out of 22 producers
achieved, excluding 7 water injectors but including 2 gas injectors. 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)



It is
commonly said that “All deep-water offshore projects are challenging”, and AKPO
was no exception. Projects which are undertaken in deep-water imply high
commercial pressures and thus each new project, such as this one, entails new
problems and use of past experience of deep-water e.g. Gulf of Mexico and West
Africa. The most evident challenge was to ensure that condensates and gas in
multiphase flows would reach the production facilities without being stopped by
hydrates, wax and scale deposition. (OnePetro, 2018)

the increase in oil prices and commercial pressure on the suppliers from
multiple operators and fields had to be taken into account. In addition to
economic and technical issues, the location is obviously a challenge which
cannot be easily overlooked. Indeed AKPO had issues of resources of personnel
and manufacturing capacity in a dynamic market as well as the new challenge of
manufacturing in Nigeria.

            Despite the complications of operating in Nigeria the
commitment shown by Total, there was clear evidence that the reserves offered
were worth pursuing.


Petrobras stake

the 9th of November 2017, Brazilian oil company Petrobras said it was selling
Petrobras Oil & Gas B.V., a subsidiary owning interest in two deep-water
offshore blocks in Nigeria: AKPO and AGBAMI. According
to Petrobras, the condensate field AGBAMI and the oilfield AKPO together
account for 18% of Nigeria’s liquid production, and are two of the four largest
producing offshore fields in the country.  (BELLO, 2018) (Offshore Energy Today, 2018) (Brunno Braga Hart, 2017)

Fig. 6 & 7 –
Petrobras put Nigerian deep-water assets for sale, 9th of November

6) (BELLO, 2018)


7) (Offshore Energy
Today, 2018)



Heavily indebted Petrobras announced plans to sell its 50%
stake, and began sending information on the company to potential investors.
According to Petrobras’ website, the Brazilian oil company would be looking to
unlock $19.5 billion through partnerships and asset sales between 2017 and
2018. However, since the giant EGINA and AKPO fields are operated by Total and
AGBAMI by Chevron, they are allowed to put a veto on the sale if necessary (Figure
6). (Offshore Energy
Today, 2018)



By being one
of the largest subsea production systems in Nigeria deep-water brought on
stream, the AKPO project is providing a huge and significant benchmark for
other subsea developments not only in Nigeria but also on a global scale. Altogether,
AKPO required large capital investments, leading edge technology and expertise
to make it viable. Today, a big part of Nigeria’s
production growth comes from offshore projects such as AKPO but the
technological challenges in developing the reserves means that only large NOCs,
like Total, are able to extract the resources of such field.


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