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ENI Pools $4.7Billion From Seven Lenders For Coral South FLNG

Italian giant ENI and its partners have pooled $4.675Billion worth of debt facility from seven lenders for the Coral South FLNG development, offshore Mozambique.

In the company’s announcement regarding the project’s financial close, Africa’s most aggressive hydrocarbon explorer lists five export/import credit agencies as participants in “covered loans”.

ENI and Co are also taking two direct loans, one each from an unnamed Commercial Bank and the Korea Export Import Agency (KEXIM).

ENI reports that the total amount of debt is split in the following facilities:

• France owned BPI Export Credit Agency -Covered Loan
• Korea Eximbank (KEXIM), the official export credit agency of South Korea-Covered Loan
Italian Export Credit Agency(SACE)-Covered Loan
• Korea Trade Insurance Corporation (K-sure)-Covered Loan
• China Export and Credit Insurance Corporation (Sinosure) -Covered Loan
• Commercial Bank Direct Loan (Unnamed Bank/s)
• KEXIM Direct Loan

Coral South FLNG, located in Area 4, in deepwater Rovuma Basin, is the first project sanctioned by the Block’s Partners for development.

It targets the production and monetization of the gas contained in the southern part of the Coral gas reservoir, by means of a floating LNG plant with a capacity of 3.4 MTPA. A Sale and Purchase Agreement was signed in 2016 for the sale of 100% of the LNG production to BP.

ENI is the Operator of Area 4, holding a 50% indirect interest through its participation in ENI East Africa (EEA). In March 2017, ENI and ExxonMobil signed a Sale and Purchase Agreement to enable ExxonMobil to acquire a 25% interest in Area 4, through EEA.

The remaining interests in Area 4 are held by CNODC (20%), Empresa Nacional de Hidrocarbonetos E.P. (ENH, 10%), Kogas (10%) and Galp Energia (10%).


FID Dates Slip Again For ANOH and Fortuna

By Fred Akanni, in Malabo

London listed juniors: Seplat Petroleum and Ophir Energy, have again slipped in their proposed dates for final investment decisions (FID) on their respective gas monetisation projects.

They had both declared the end of the first half of 2017 as target date, missed that timeline and now they are both saying that First Quarter 2018 is more likely.

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Don’t Rule Out FID For Kudu Gas To Power in 2017

BW Offshore, the main investor in the upstream part of Namibia’s Kudu Gas To Power project, has not ruled out financial sanction for the project before the end of 2017.

The company indicated in the events guidance in its 3rd Quarter 2017 report, that Final Investment Decision for the 800MW project remains one of the several milestones on the cards for second half of the year.

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NLNG Mulls A 2018 Date for Financial Close on Train 7 Plus

Nigeria LNG Limited has declared it is making steady progress towards achieving Final Investment Decision (FID) on its Train 7 Plus (7+) project during 2018.

“This phase of the company’s strategic growth programme will on completion upscale NLNG’s annual production capacity from the current capacity of 22MMTPA (Million Metric Tonnes Per Annum) to 30MMTPA”, the company’s spokesman, Kudo Eresia-Eke, said in a release.

He was quoting Tony Attah, NNLG’s Managing Director and Chief Executive Officer, who said at the World LNG Summit holding in Portugal, on Wednesday November 29, 2017, that West Africa’s largest gas export company was looking to the project’s financial close in 2018, “with the full support of the NLNG Board.”

This would mean that the prospects for constructing the 8MMTPA capacity train has brightened since it came on the drawing board at least 12 years ago, as Natural gas grows to account for a quarter of global energy demand, becoming the second-largest fuel in the global mix after oil by 2040, according to the International Energy Agency (IEA)’s New Policies Scenario.

The current period in which this Final Investment Decision is being taken certainly has its own challenges. There is ample supply and the prices are low, but the IEA says that so long as “gas remains affordable”, its growth in the near future is assured. To NLNG’s advantage, “LNG accounts for almost 90% of the projected growth in long-distance gas trade to 2040: with few exceptions, most notably the route that opens up between Russia and China, major new pipelines struggle in a world that prizes the optionality of LNG”, the IEA says in its latest report.

“With Nigeria’s proven reserves of about 192 trillion cubic feet of natural gas, and another 600 trillion cubic feet in potential, this milestone development is coming at a crucial time. I am excited about this development which would not be possible without the support of our Board and shareholders”, Attah said at the Summit, attended by the world’s leading LNG stakeholders.

“NLNGhas so far converted over five trillion cubic feet of associated gas, which otherwise would have been flared, to liquefied natural gas (LNG) and natural gas liquids (NGLs) for both export and domestic use. It is Nigeria’s most significant natural gas utilization intervention to date, which is helping to preserve the environment and support Nigeria’s economic growth”, Attah told the audience. “From an initial investment of about $6Billion, NLNG has grown into a $15.6Billion investment with an asset base of about $11billion”, he explained. “The company has generated $90Billion in revenues as well as paid $5.5 billion in taxes to the government. The company has also has helped monetise the country’s gas resources and significantly contributed to reducing gas flaring from 65% to less than 20%,” he remarked.

NLNG runs an integrated plant on Bonny Island where its current six liquefaction trains share common facilities including storage tanks, shipping capacity and loading jetties with a gas intake of 3.5Billion standard cubic feet of natural gas per day.

All these have been achieved with a management staff entirely made up of Nigerians and a workforce which is 95% indigenous.

NLNG is owned by four shareholders, namely, the Federal Government of Nigeria, represented by the Nigerian National Petroleum Corporation, NNPC (49%), Shell Gas B.V. (25.6%), Total Gaz Electricite Holdings France (15%), and Eni International N.A. N. V. S.àr. l (10.4%).


Dangote’s Gas Project Is the Riskiest of the Industrial Quartet

By Sully Manope

Dangote Industries’ proposed 1,100kmdeepsea pipeline from the Niger Delta to Lagos, Nigeria’s top commercial hub, is the most uncertain, from a business perspective, of the four projects under development at the company’s Lekki Port complex.

Whereas there’s clear demand for petroleum products and fertilisers from the refinery and fertiliser complexes under construction and the Petrochemical Plant will have customers, the domestic gas market, which the pipeline is expected to serve, is severely challenged.

The East-West Offshore Gas Gathering System (EWOGGS), as it is christened,consists of two 38 inch, 550km pipelines, each with a capacity of 1.5 Bcf/day. The two pipelines will be running side by side.

“To talk about a three billion standard cubic feet of gas supply into Nigeria today requires a lot more work than wishful thinking,” says Sam Ojehonmon, an African hydrocarbon market analyst based in Johannesburg.

To start with, some of the projects that are widely expected to be supplied by the EWOGGS are, in reality, going to be supplied by other parties.

Take the560MW Qua Iboe Independent Power Plant for example. It is going to be built by Black Rhino, with which Dangote is a partner. It is located in the vicinity of the EWOGGS’ take off platform and had been widely assumed to be the EWOGGS’ most likely first customer. But that’s a wrong assumption. The gas for QIIPP will be supplied by ExxonMobil, whose Joint Venture with state company NNPC will build a 400MMscf/d processing plant for gas from OML 70, primarily for that project and ultimately for the Nigerian domestic gas market.This fact alone places a direct competition in EWOGGS’ face.

Indeed, the Dangote Industries’ published list of acreages from which the EWOGGS is expected to extract natural gas, begins to look doubtful, with a little bit of scrutiny. The list includes ExxonMobil operated OMLs70 and 138, Amni operated OML 52, Shell operated OML 77, Sunlink held OML 144 and First E&P held OMLs 71 and 72, in which West African E&P, a Dangote subsidiary, has significant stake. Of this list, the gas fields that are ready to come on stream are those in ExxonMobil’s OMLs 70 and 138 and Shell’s OML 77. A Dangote document actually lists OML 138 as scheduled to provide 10% of the 3Bcf/d EWOGGS capacity, but ExxonMobil does not have any agreement yet with Dangote Industries Limited, nor does Shell.

Sunlink has been desperate to monetise its gas in OML 144, As such it is keen to get in board; First E&P will deliver on OMLs 71 and 72, but It’s not clear what arrangement Amni has with Dangote.

Dangote Industries’ expectation is that Africa’s most populous country should be able to utilize 10Billion cubic feet of gas per day, in its power plants and factories, by 2020.

In the last 12 years, the state has built over 10 thermal power plants with nameplate capacity in excess of 5,000MW, expected to be fueled by natural gas. But the volume available has been held down by “in-sufficient Investment focus to grow the required supply capacity”, according to a concept note by the Dangote group, which it shared with Nigeria’s Vice President Yemi Osibajo, in 2016.

Current gas consumption by factories, power plants and Gas based industries in Nigeria is slightly less than 2Billion cubic feet per day (Bcf/d). Growth in these sectors is reportedly constrained by inadequacy of supply of natural gas.

But the big challenge is the absorptive capacity of the market itself.

The bulk of the gas produced for the Nigerian market is for electricity, an industry considered rather unstable at the moment. “The power sector is beset by “illiquidity, price and securitization challenges”, says Dada Thomas, President of the Nigerian Gas Association. “Lurking behind these monsters are the secondary diseases of inadequate and dilapidated power transmission and gas distribution infrastructure, low economic returns for gas projects”. Other Gas and power analysts have lamented the obstructions imposed by offtake assurances vis-à-vis pipeline tariffs, funding mix and failure of payment guarantee structures.

And yet there are projects under construction and in feasibility studies. Shell and Seplat are collaborating on the Assa North Ohaji South (ANOH) project, which will deliver 600MMscf/d at peak, to the Nigerian market.

This story benefited from extensive excerpts in the piece Huge Ambition, Hefty Risk, at $3Billion, published in the February/March 2017 issue of Africa Oil+Gas Report.


ExxonMobil Is Now Betting on Nigeria’s Domestic Gas Market

By Toyin Akinosho

ExxonMobil will handle the upstream and midstream parts of the Qua Iboe Independent Power Project.
The company’s joint venture with NNPC will deliver the required 100MMscf/d to fire the plant, from the Oso field, in the country’s prolific south east offshore.

The NNPC/ExxonMobil JV will construct a 400MMscf/ gas processing plant and a pipeline from Oso to Qua Iboe Terminal.
These facts fly in the face of insinuations that, with a partnership between Black Rhino and Dangote Industries signing a 540 MW Power Purchase Agreement with the Nigerian Bulk Electricity Trading Plc (NBET), ExxonMobil had finally let go of the project, conceived close to two decades ago.

As things stand, in fact, the Qua Iboe IPP should, indeed, make ExxonMobil play a bigger role in domestic gas market than it currently does. The company has been the only multinational without a processing plant-meant for producing lean gas- to its name in Nigeria.

Instead it constructs projects around stripping Natural gas Liquids for sale and injecting what would otherwise have been flared, to increase crude output.

“With a 400MMscf/d gas plant and a pipeline from offshore gas field to shore, they will be playing a bigger role in the domestic gas space”, sources at the NNPC, the senior JV partner, say.

“Whoever wants to offtake gas from the remaining 300MMscf/d capacity not dedicated to the QIIPP has to construct its own evacuation infrastructure to the QIT”.


‘Europe Prefers Russian Gas To American Imports’

By Goma Jeyipo, Downstream Gas Correspondent

Europeans will rather buy gas from nearby …state than the increasing LNG imports from the United States.
Part of the reason is a business decision, unrelated to either the political challenges that mainland Europe faces with Russia or the American President Donald Trump’s increasing hostility to European leaders. Neither country, in any case, is pretending to be the best of friends with Europe at the moment.

“At the end it is the prices that count”, says Claudio Descalzi, Chief Executive Officer of ENI, the Italian giant. “The U.S. will encounter great difficulty in Europe for the gap, to their disadvantage, of prices. It would not be difficult for Gazprom, which supplies Europe with about 170-180 billion cubic meters, to cut them out, all they would need to do is lower the price by a few cents”.

Further north, in the German capital, Berlin, a clear majority of German citizens reject the USA’s planned expansion of its economic sanctions against Russia, according to research conducted by The Forsa Institute for Social Research and Statistical Analysis forsa for short, one of the leading market research and opinion polling companies in Germany. Whereas half the Germans surveyed support a further diversification of the natural gas provision, only 6% want more imports of American liquefied natural gas. Forsa interviewed more than 1000 German citizens on behalf of Wintershall, the German independent E&P company.

Wintershall says of the survey, published on its website: “The vast majority of Germans (83%) reject the planned increase in economic sanctions, which would also restrict the activities of German and European companies.

“For more than 80 percent of the German citizens, the top priorities for the natural gas provision are its affordability and security of supply. Diversified suppliers and transport routes (50%) are also considered relevant. However, only 6% want to import less natural gas from Russia and instead import more American liquefied gas. Just under a quarter (24%) would like countries that have previously benefited from gas transport revenues to also benefit in future from transit revenues”.

Mr. Descalzi says: “The U.S. are experiencing a phase of excess, the market has grown a lot thanks to shale gas. U.S. President Donald Trump offered to sell LNG in Poland but imposing a political accord is difficult”.
For more information, see www.eni.com and www.wintershall.com


DHarmatan Fishes In The LPG Waters

By Paul Kelechi

Dharmattan Nigeria has proven itself in the G&G (Geology and Geophysics) services sector of the upstream segment of the oil and gas value chain.

It has worked for Chevron, Yinka Folawiyo Petroleum, Addax Petroleum, Belema Oil and ENI.

Now the company is fishing downstream, reaching out for opportunities in the gas business.

Between January 2016 and September 2017, Dharmattan Nigeria sold 2,500 tonnes of Liquefied Petroleum Gas in the Nigerian market 2,500 tonnes are equivalent to about 4 million liters of the product. Per quarter for 2017, the company has delivered about 600,000 liters.

This is clearly less than 1% of the 250,000Tonnes per annum that Nigeria consumes, but DHarmattan has a huge, downstream ambition.

The 13 year old company carries out home delivery of LPG in cylinders. “There is home delivery through pipes but this is highly localized”, says Bashir Koledoye, D’Harmattan’s founder and Chief Executive who earned his stripes as geologist with Chevron Nigeria. “If you have a high rise, then we can have gas tanks and piping to the flats and homes” he explains.

DHarmattan has the capacity to pipe LPG to homes on a bigger scale than it does now. “If we have a cooperative government, be it local or state that is interested in doing this on a bigger scale”. To pipe the LPG in a housing estate, a company needs a centralized storage tank, ranging in size from as low as 2 tonnes to as high as 10 tonnes.

D’Harmattan has 10tonne storage tanks in estates in four states in Nigeria Lagos, Oyo, Delta, and Imo. The company also manages LPG sites for clients who run petroleum product Its facilities are deployed in about 30 such stations in five states of the country.

We asked Koledoye if he had ever thought of extensive LPG pipelines to thousands of homes in cities.

“Those facilities are very expensive to put together and the configuration of the domestic offtakers is such that it will be difficult to get enough volume through those pipelines to actually pay for the project. But if you have estates that are well structured, then it is easier. From Ibadan to Lagos, or even if you just go to Yaba, how many houses would you supply that way to pay for the project?”

Even so, he avers, “there are two key incentives for LPG; one is that the product is cheaper than kerosene and two, LPG is healthier than both kerosene and firewood. Those are the incentives but of course, there are barriers or problems with that one of which is access and that is why you have to carry the cylinders to the refill stations”.
When it comes to bulk LPG supply, DHarmattan’s major customers are schools, industries and hotels.

The company gets its supplies from NLNG which comes from Bonny Island “but we are working on a number of gas processing projects. I will also like to add that there are a lot of opportunities in the industry and we need the government to allow local companies that have the proven financial competence, technical and managerial capacity to take control of small assets because that will definitely help our economy. Because what happens is that for every local company, you have a large group of indigenous employees, contractors and other groups who work with them.

Unlike foreign companies, who rightly so, would like to repatriate as much of their profits to their countries as possible. There are a lot of projects that are not too tasking that the government can allow local companies to take control of.


Will the current over supplied LNG market leave room for future East African LNG?

By Henrik Poulsen and Bimbola Kolawole, Rystad Energy

A decade ago, several of the E&P majors turned their exploration eyes on East Africa.
The first half of this decade became an East African exploration success, and major gas discoveries with more than 120 TCF (Trillion Cubic Feet) combined were discovered (Mozambique & Tanzania). A new ‘world-class’ petroleum province was revealed and the optimism in the region soared to record levels, and it might be only the beginning. The undiscovered potential is still very promising and could very well triple already discovered volumes. Mozambique can become the largest petroleum producer in Africa by the mid of the century, if the success continues.

However, the majority of the gas will initially need to be exported as Liquefied Natural Gas (LNG), due to limited domestic markets and inadequate pipeline infrastructure. The liquefaction process and distant transport to the consumer markets add to the breakeven cost of East African gas. Simultaneously, the global LNG-markets (since 2014) have undergone a set back as the rest of the petroleum-markets. Finally yet importantly, comes the COP21 (21st. Conference of the Parties, Paris, December 2015) agreement, and the uncertainty political decisions may have on the future long-term role for gas as a primary energy resource in the global energy mix.

This article discusses in further detail the East African potential to become a significant international LNG supplier, the outlooks of the Asian LNG markets and finally share some aspects on the future fate of natural gas as a primary energy source.

Will it be possible for East Africa to become a significant global LNG supplier?
Several world-class gas discoveries were discovered offshore South East Africa in the years 2010 to 2014. A brand new global petroleum province was revealed. In most cases, major IOCs operate the discoveries with resource ensuring Asian companies as partners. Solid operators will ensure financial strength, technical knowhow and long term mind set. All important factors required when developing and exploiting a new petroleum province. As per today it has been discovered more than 120 TCF, and Rystad Energy estimates the total future resource potential to be around 370 TCF. In other words, the undiscovered potential is twice as big as what has already been discovered. The figure below shows the commercial natural gas resource potential in Mozambique and Tanzania, split by project Life Cycle. Undiscovered potential is marked in light blue pattern, and dominates the volumes.

The operator ENI recently reached a final decision on development (FID) of the Coral South gas field in Mozambique. The project will be developed by a floating LNG (FLNG) production unit. The production capacity is (by the operator) estimated to be 3.4 million tons per annum MTPA, equivalent to 4.7 bcm/yr. Rystad Energy believes that this project is only the first in a long row of many more to come in the following years. Anadarko recently reported that the development of the offshore area 1 in Northern Mozambique, comprising an on-shore LNG plant consisting of two initial LNG trains, soon is reaching an FID. The capacity is by the operator estimated to be 12 MTPA or 16 bcm/yr. Tanzania is for the moment lagging behind Mozambique, but should be encouraged by the results achieved by its neighbor to the south, to reach agreements with the operators Shell and Statoil.

Rystad Energy believes first LNG shipment from Mozambique to be in either in 2023 or 2024, and Tanzania to follow 4-5 years later. We estimate that the combined gas and LNG production in East Africa will exceed 120 bcm/yr by 2040, whereof LNG will be the dominant product. As East African pipeline infrastructure is developed (from the 30’ies and onwards) will the piped gas share for domestic use (in East Africa) become more and more dominant. Mozambique’s potential to pipe gas to South Africa could be an engine in this regional development. Below is a figure showing Rystad Energy’s prediction of East African natural gas production split by LNG and piped gas towards 2040.

How will the LNG markets develop – is the world about to become swamped in gas/LNG?
The Asian LNG markets will be paramount for East African LNG export. Similar to the oil market, did the North American shale industry turn the gas markets upside down in 2015. The rapid increased production sourced from shale gas reservoirs made US self-supplied and left the country with a significant export potential. The price of Henry Hub plummeted, and the same effect spilled over to the (Asian) LNG markets.

The new LNG price became suddenly dependent on the Henry Hub pricing, as US commenced to export most of its excess production as LNG to other continents. LNG is now priced as Henry Hub + liquefaction- and transport costs. The large numbers of sanctioned LNG projects in Australia and US before the price crash has left the world currently swamped in LNG. Rystad Energy has estimated that the LNG market will remain over supplied to 2023, with a peak in 2020, where the supply capacity excess the demand by almost 70 bcm/yr. However, we predict LNG demand to continue its strong growth as gas is becoming a more and more important primary energy resource in Asia and the Middle East. By the end of the 20’ies, it will be a deficit of more than 200 bcm/yr, if no new LNG-projects are sanctioned for development.

As seen from the figure above, it is likely that by 2023 will the world face a deficit on LNG, due to lack of LNG project sanctioning the last couple of years. Two thousand and twenty three coincides perfectly with prediction of the first LNG to be exported from East Africa. East Africa can/will be instrumental in filling the deficit supply gap in the second half of the next decade. If no projects are sanctioned for development the coming years, will the LNG deficit by 2030 surge to more than 200 bcm/yr. Hence, leaving plenty of room for East African LNG, as shown in the figure below.

East African LNG will of course face strong competition from other producers, especially Qatar, Australia and Papa New Guinea, in the race for the rising demand in South-East Asia and the Middle East. East Africa benefits from its reasonable vicinity to India and Pakistan compare to Australia. The majority of the growing gas production in the Middle East will be needed for domestic purposes to cover an increased gas consumption. Hence, the production increase in Qatar and Iran will not find its way to Asia. Below is a figure showing India’s predicted need for gas import versus the LNG export from Mozambique and Tanzania towards 2040. It will not be until 20 years from now before East Africa will export enough LNG to cover India’s import needs only. The latter as an indication of future Asian LNG needs.

Rystad Energy has assessed which LNG projects would most likely be sanctioned and developed by 2025. It is predicted that the production deficit gap in 2025 will be about 50 MTPA (70 bcm/yr), which soon need to be covered. By assessing breakeven prices for potential future LNG projects it is possible to predict, which projects will most likely be developed, and to which breakeven cost. An LNG price at 7-8 $/MMbtu is needed in order to develop another 50 MTPA by 2025. Below is a figure ranking potential future LNG-projects to come on stream by 2025 by breakeven price. Projects to the left have the lowest breakeven costs. The development of Area 1 offshore Mozambique (in red circle) has the 3rd. lowest breakeven price (6,2 $/MMbtu) among the most profitable projects believed to come on stream by the mid of next decade.

Which role will gas get in a carbon-restricted world?
The COP21 agreement negotiated and ratified in Paris in December 2015 will probably have a great impact on the future mix of primary energy sources. Fossil fuels, and especially coal, will be taxed in order to curb the markets. Coal, as gas, is predominantly used for power generation. Coal is cheap, scalable and reliable with low or no disruptions. The same characteristics apply for gas. However, coal emits about twice as much CO2 per energy unit as gas, which makes gas more attractive if the consumer has to pay for the emissions. Three countries, China, US and India, currently count for 50% of the global CO2 emissions. Thanks to lowered gas prices (shale revolution) in US, which made gas more competitive over coal, has the world’s second biggest emitter been able to reduce its annual CO2 emissions by more than 700 million tons (about 10%) since 2007. What happened in US is likely to happen in the two biggest coal consumers, China and India, as well. Replacing coal power plants with gas plants has shown to be the most effective step towards a less carbon-emitting world. This partly explains why gas consumption in IEA’s ‘2-degree scenario’ is expected to increase by 12-14% towards 2040. Gas will to a quite large extent need to replace coal. The highest gas consumption growth will come in Asia and the Middle East when coal and oil are abandoned and replaced with gas as power generator. Africa’s dire needs for energy and power in their race for raised prosperity, will also play a significant role in the future hunger for gas.

As shown in this article, East Africa has a considerable potential to become a significant LNG exporter. Less tight LNG markets from the mid 20’ies provides good timing for East African LNG. Price competitive development, vicinity to main markets and steady growing Asian LNG (gas) demand should ensure East African LNG export for several decades to come. However, Mozambique and Tanzania need to continue to court the industry to leverage their discoveries and ensure revitalized exploration. Building a sustainable E&P industry needs both the industry and the government to co-operate and to wear the ‘generation perspective glasses’, in order to become a success.

About Rystad Energy
Rystad Energy is an independent oil and gas consulting services and business intelligence data firm offering global databases, strategy consulting and research products.
Rystad Energy’s headquarters are located in Oslo, Norway. Further presence has been established in Norway (Stavanger), the UK (London), USA (New York & Houston), Russia (Moscow), Brazil (Rio de Janeiro), as well as Singapore and Dubai.

Author: Henrik Poulsen
Henrik holds an MSc. in Petroleum Geology from the Norwegian University of Science and Technology and is currently Senior Vice President – Government Relations at Rystad Energy. He has more than 25 years of experience in the E&P and oilfield service industry and has worked as a consultant for 15 years in the E&P industry, assessing geological and economic uncertainties. Since 2005, Henrik has held several senior management positions at different companies such as Roxar (Emerson), Schlumberger and Rystad Energy.

Author: Bimbola Kolawole
Bim (Bimbola) is Business Development Manager –Africa at Rystad Energy. She is also responsible for account management, training and support for clients in the Region. Her area of expertise includes business strategy, general management, business development, training and support as well as project coordination. Previously, Bim worked at IHS Energy where she was responsible for managing selected clients across the Oil & Gas space value chain in the EMEA region. She holds a BSc. in Economics from Ilorin University, MSc. in Energy Finance from Dundee University and an MBA from Leicester University.


Ogbele Reaches 50 Billion Cubic Feet Milestone

By Sully Manope, in Lagos

Niger Delta Petroleum (NDEP) will be delivering the 50 Billionth standard cubic feet of gas from the Ogbele field to the Nigeria Liquefied Natural Gas(NLNG) System on Friday, September 22, 2017.

This comes to 8.62Million barrels of oil equivalent (BoE).

The field, the first in the country to be officially classified as a marginal oil and gasfield, has produced 35Million standard cubic feet of gas every day(35MMscf/d), transporting the molecules through its 20km pipeline to the NLNG system, since November 2012. It is the only indigenous, Non NNPC JV supplier of gas to the NLNG Bonny Terminal, site of Africa’s largest gas monetisation project.
“It also holds the distinction of being the first independent, indigenous marginal oil field to attain gas flare-down from its operations in Nigeria”, company officials say.

The Ogbele field was awarded to NDEP in 2000 and it came on stream as an oil producer in August 2005. Five years later, NDEP decided to develop and monetise the field’s gas resources with the construction of a 100MMscf/d capacity gas processing plant, which it completed in 2012.

Three years after it commenced gas delivery, the company received an Excellence Award for implementation of a gas flaring reduction project from the World Bank led Global Gas Flaring Reduction (GGFR) Partnership at the GGFR Global Forum held in Khanty-Mansiysk in Russia in 2015.

50 Billion standard cubic feet translates to millions of Carbon Dioxidemolecules that would have been emitted into the atmosphere when the flared natural gas (mostly Methane), combusts with the oxygen in the air, NDEP officials argue, “but we shouldn’t even be lenient on the equivalence of CO2that the company has saved the world by exporting 50Bscf of Methane, because Methane is a far worse offender in global warming than CO2”, they contend.

There are other reasons why the 50 Billion standard cubic field milestone is significant. For one, a so-described marginal field has delivered so much oil (over 12 million barrels) and gas over a time frame often associated with midsized hydrocarbon fields. For another, Marginal field operators in Nigeria, as a rule, are some of the worst gas polluters in the country: NDEP and Platform Petroleum are exceptions to the rule, with their gas processing plants. Frontier Oil operates a gas plant on the Uquo Field, but it doesn’t have a choice because Uquo is a gas field with a small oil rim.

Pan Ocean also takes credit for installing a gas processing plant to mop up some of the associated gas produced in the course of crude oil production. Seplat and NDWestern are big suppliers of gas to the domestic gas market, in part because they acquired gas processing plants as part of the purchase of their core assets from multinationals. But constructing a gas processing plant by such companies from the scratch is rare. Thirdly, NDEP’s gas processing plant makes it, along with its crude oil-to-diesel topping plant, a vertically integrated oil and gas company.

© 2017 Festac News Press Ltd..