Introduction Atlantic Petroleum (SAPETRO) with 5%. (Sapetro, 2018)

Introduction            TheAKPO field was discovered in the beginning of 2000 by Total Upstream NigeriaLtd (TUPNI) and less than a decade later production started. The AKPO field inblock Oil Mining Licence 130 (OML 130), granted to Total, is located about 150kilometres off the Niger Delta (Figure 1) or approximately 200 kilometresoffshore Nigeria in 1400 meters water depth. This project was not only thefirst deep-offshore development including oil with highgas content but also Total’sfirst deep-water development in Nigeria.

It did not only face the challenges ofcombining gigantic scale but also world-scale industrial execution in anunstable Niger delta. (Abarrelfull, 2018) (Nelson, 2010) (OilMapNG, 2018) (Bybee, 2018)(, 2018)             I.        GeneralinformationFig. 1 – Location mapshowing AKPO in OML 130 (total, 2018)            Backin 2009, it was believed that much of Nigeria’s future production would comefrom large scale offshore projects as vast commercial reserves of hydrocarbonshad been discovered in the deep waters and more would be found. It was alsoassumed that such a field would attract many National Oil Companies (NOCs) andsupermajors. (Bybee, 2018)Fig. 2 – Timeline of theAKPO project In 2009 AKPO was thelargest deep-offshore projects ever undertaken at the time and was the largestbrought on stream through that same year.

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Furthermore, Total’s AKPO, alongside Chevron’s Corp AGBAMI oilfield, were the only major oil fields expected to come on-line in 2009 inNigeria, adding 500,000 barrels per day (b/d) to the country’s output. (total,2018)            NowadaysTotal holds a 24% interest and is operating OML 13, alongside, China’s NationalOffshore Oil Company (CNOOC) which purchased a 45% stake in OML 130 in 2006,Petrobras NOC with 16%, the Nigerian National Petroleum Corporation (NNPC) with10% and South Atlantic Petroleum (SAPETRO) with 5%. (Sapetro, 2018)          II.

        Fielddevelopment            AKPOdevelopment involves 5 reservoirs, deposited in a complex channels, situated atdepth ranging from 2900 mSS to 3700 mSS. In the field’s Miocene reservoirs, thefluid is assumed to be in ‘critical condition’ i.g. liquid and gas hydrocarbonsare in a single phase, at high temperature and pressure. It is important to highlight the fact that highertemperatures/pressures and deeper waters required high-performance materials. (OnePetro, 2010)Here, the reservoirfluid is a critical fluid, which implies that the fluid type is dependent ontemperature and pressure, as mentioned before, as well as on depth. The liquidproduced is light oil/condensate, 42 ° to 53 ° Application Program Interface (API), with a highliquid-gas ratio (GLR) from approximately 1600 to 7300 standard cubic feet perbarrels (scf/bbl). Moreover, maintenance in the reservoirs is necessary, withgas 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)             Thisoilfield is composed of 44 wells, including 22 production wells, 20 waterinjectors, 2 gas injectors with a network of Umbilical, Flowlines and Risersconnecting the Subsea Production Systems to the Floating Production, Storageand 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 hightemperature and high pressure subsea flowlines that is more than a hundredkilometres long connected by steel catenary risers to the FPSO. (Nelson, 2018)        III.        Suppliersinvolved in the project            Thescale of projects such as AKPO requires resources from many suppliers.

In May2005, Cameron, a Schlumberger Company, was awarded a $340 million contract forthe subsea systems on the fields, including 44 wells, manifolds and Christmastrees1. (Abarrelfull, 2018) (Cameron, 2018)            Technip/Hyundai Heavy Industries, wasalso 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 1314meters water, which is able to produce crude oil and gas. It is made up of twoparts: the topside and the hull. The hull’s dimensions are 310m x 61m x 31m, which means it has a storagecapacity 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,2018)In addition, in May 2009, Saipem was awarded an $850 million contractfor engineering, procurement, construction and installation of the umbilicals,risers and flowlines, as well as the oil loading terminal, which is the FPSOmooring system and the gas export pipeline. This extends from the AKPO FPSO tothe AMENAM platform. (Subseaiq, 2018)       IV.        Production            AKPOplateau production is 175, 000 b/d of condensates and 550 million standardcubic feet per day (mmscfd) of produced gas. 220 mmscfd of the gas isre-injected, while 320 mmscdf are exported onshore to the BONNY LNG Terminal,which is a liquefaction plant that allows storing gas, via the AMENAM fieldfacilities. (User, 2018) Fig. 4 – AKPO condensates production (Fournie, 2018)             Totalis a 15% shareholder of the liquefaction plant alongside NNPC with 49%, Shell with25.6% and Agip with 10.

4%. The remainder is used as fuel gas. The hybridinjection/export gas scheme optimises hydrocarbon recovery. Gas is onlyinjected in reservoirs which can benefit from this type of pressure support. (User, 2018)            Onthe same OML 130 block as AKPO, three oil discoveries (PREOWEI, EGINA, andEGINA-SOUTH) now form the basis for an oil development with a FPSO located inthe EGINA zone. Both EGINA and AKPO, with their ability to handle a variety offluid, were and are still today ideal hubs for developing future hydrocarbondiscoveries in this area.

(Anon, 2018)         V.        EconomicaspectsAs a deep-water offshore project, AKPO required a sustainablecrude price in excess of $40 per barrel to support continued production. Asstated before, the location an oil field exists based on economic aspects. Thecosts of production, labour and security had risen in the beginning of the 21stcentury for oil companies operating in Nigeria, leading to even more expensesas expected. (Ogj, 2018)            Backin 2000, most of Nigeria’s production growth was expected to come from offshoreprojects but the technological challenges in developing the reserves meant thatonly the large NOCs and supermajors would be able to extract the resources ofsuch field. Indeed, the development cost of theFPSO only was approximately about $1,080,000,000, which included all the costsincurred from initiation to implementation of the project.

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

5 – Field layout and well delivered as of 1st January2010 (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 isstill ongoing with 41 out of 44 planned wells completed, 21 out of 22 producersachieved, excluding 7 water injectors but including 2 gas injectors. Asmentioned before, AKPO’s first production was achieved in March 2009, butfortunately its peak production reached 5,000 b/d higher than expected, beingat 180,000 b/d with over 350 million barrels of condensate produced to date.(Ogj, 2018)    VII.        Challengesencountered It iscommonly said that “All deep-water offshore projects are challenging”, and AKPOwas no exception.

Projects which are undertaken in deep-water imply highcommercial pressures and thus each new project, such as this one, entails newproblems and use of past experience of deep-water e.g. Gulf of Mexico and WestAfrica. The most evident challenge was to ensure that condensates and gas inmultiphase flows would reach the production facilities without being stopped byhydrates, wax and scale deposition. (OnePetro, 2018)Furthermore,the increase in oil prices and commercial pressure on the suppliers frommultiple operators and fields had to be taken into account. In addition toeconomic and technical issues, the location is obviously a challenge whichcannot be easily overlooked.

Indeed AKPO had issues of resources of personneland manufacturing capacity in a dynamic market as well as the new challenge ofmanufacturing in Nigeria.             Despite the complications of operating in Nigeria thecommitment shown by Total, there was clear evidence that the reserves offeredwere worth pursuing.   VIII.

        Petrobras stakein AKPO            Onthe 9th of November 2017, Brazilian oil company Petrobras said it was sellingPetrobras Oil & Gas B.V., a subsidiary owning interest in two deep-wateroffshore blocks in Nigeria: AKPO and AGBAMI.

Accordingto Petrobras, the condensate field AGBAMI and the oilfield AKPO togetheraccount for 18% of Nigeria’s liquid production, and are two of the four largestproducing 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 November2017(Fig.6) (BELLO, 2018)&(Fig.7) (Offshore EnergyToday, 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 tounlock $19.5 billion through partnerships and asset sales between 2017 and2018. However, since the giant EGINA and AKPO fields are operated by Total andAGBAMI by Chevron, they are allowed to put a veto on the sale if necessary (Figure6).

(Offshore EnergyToday, 2018) ConclusionBy being oneof the largest subsea production systems in Nigeria deep-water brought onstream, the AKPO project is providing a huge and significant benchmark forother subsea developments not only in Nigeria but also on a global scale. Altogether,AKPO required large capital investments, leading edge technology and expertiseto make it viable. Today, a big part of Nigeria’sproduction growth comes from offshore projects such as AKPO but thetechnological 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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