All posts tagged featured

Egina FPSO Finally Sails Away ..First Oil Now November 2018

By Fred Akanni

The Egina FPSO left the quay side in Geoje Korea at 7.18am Korean time on the 31st of October.

The vessel started its long anticipated journey to Nigeria, several months after the original schedule.

It will take 90 days to arrive at the yard of the Lagos Deep Offshore Logistics (LADOL) in Lagos, meaning either late January or early February 2017.

There, the six modules constructed by TechnipFMC, which are presently at the LADOL yard will, together with some other modules coming from Korea be integrated to the FPSO at LADOL yard, a process that will take about six months to complete. That is the key local content part of the FPSO integration.

The FPSO will then leave LADOL yard in Lagos to Egina location off the southeastern Nigeria, where the risers, offloading Buoy and other subsea cables will then be hooked up to the FPSO before Egina first oil in November 2018.

Kosmos Drills A Duster? That’s Huge

By Sully Manope, General correspondent

This prospect failed due to a lack of charge access

Kosmos Energy, widely regarded as a leading hydrocarbon finder in Africa’s frontier, has come up with a duster off Mauritania, the first in its recent history.

The Hippocampe-1 exploration well is supposed to be one of those probes outboard of the gas discoveries that Kosmos had been making off Mauritania. The search was for oil in as the company’s geoscientists described it: Large, out – board basin floor fan reservoirs trapped primarily stratigraphically, potentially charged vertically with oil / liquids.

Instead, the well “encountered well-developed reservoirs in both exploration targets but these proved to be water bearing”. Hippocampe-1 was drilled in approximately 2,600 meters of water in Block C-8.

Hippocampe-1 was designed to test Lower Cenomanian and Albian reservoirs charged from the deeper Valanginian-Neocomian source, the well was drilled to a total depth of 5,500 meters. The well will now be plugged and abandoned. Kosmos’ geoscientists believe that this prospect failed due to a lack of charge access in this part of the play fairway.

Andrew G. Inglis, Kosmos Energy’s chairman and chief executive officer, said: “Following on from our Yaakar discovery earlier this year, Hippocampe-1 is the second of four tests of independent prospects located in the outboard basin floor fan fairways in our Mauritania and Senegal acreage. Although the well did not encounter oil or gas, it has, together with Yaakar, confirmed the presence of quality cretaceous reservoir in the outboard basin floor fans, which contain multiple leads and prospects, more than 200 kilometers from the north to south through our blocks.

We are still in the early stages of opening this newly emerging basin and our forward drilling program remains unchanged given the independent nature of the prospect tests, in particular with regard to charge.”

The Ensco DS 12 drillship will now proceed as planned to Block C-12 offshore Mauritania to test the independent Lamantin oil prospect. The Lamantin prospect is located approximately 80 kilometers offshore and 180 kilometres northeast of Hippocampe in 2,185 meters of water. The prospect comprises Campanian age reservoirs charged from the shallow, immediately underlying, oil prone, oil mature Albian and Cenomanian-Turonian source rocks.

Kosmos holds rights in the C-6, C-8, C-12, C-13, and C-18 contract areas under production sharing contracts with the Government of Mauritania’s Société Mauritanienne Des Hydrocarbures et de Patrimoine Minier (SMHPM). The blocks range in water depth between 100 and 3,000 meters, and have combined acreage of over 40,000 square kilometres gross. Kosmos is the exploration operator of Block C-8 with 28percent equity and is joined by its partners BP 62% and SMPHM (10%).

‘WAIPEC 2018 Promises Even More’

The host and organisers of the West African International Petroleum Exhibition and Conference (WAIPEC) say that the second edition of the event will multiply the value proposition of the debut conference, held in February 2017.

PETAN (Petroleum Technology Association of Nigeria), an umbrella group of engineering service companies is the host. Global Event Partners (GEP), are the organisers.

“WAIPEC will return to the Eko Convention Centre 7-8th February 2018 as the only oil and gas event held in partnership with Nigeria’s petroleum industry”, say both PETAN and GEP. Working together, the two “will draw on their global resources to ensure that the event delivers to the needs of all stakeholders in Nigeria and through the region”.

‎Ranti Omole, who is head of Conferences at PETAN as well as Chairman/CEO at Radial Circle Group, says that there has been adequate time for preparation of the 2018 edition, compared with the inaugural 2017 outing. “Last year, we managed to deliver a great conference at such terribly short period of time”, he told Africa Oil+Gas Report.

That statement feeds into the promo that says “WAIPEC 2017 was the largest petroleum event of its kind in West Africa, as the city of Lagos welcomed in thousands of key regional stakeholders – plus leading international E&P firms and partners – to develop and drive new business across the sector.
It featured in excess of 25 technical and strategic conference sessions, driven by an esteemed steering committee.

Omole recalls: “The latter part of 2017 was hostile period in the subcontinent. “When we started last year, there was a whole lot of instability in West African oil industry, the head of GNPC was being removed, the same thing was happening in Cote d’ Ivoire, and the same thing happened in about 3-4 countries like that and that also made things to be too tight. Also. We started trying to talk to people during the holidays; December to early January. The success proved to us that we had good contacts”.

“The starting point is to get the cream of the society, the next thing is to ensure that we have regional representation: heads of NNPC, GNPC, PetroCI, GEPETRO. We have a strong advisory board”.

Taking place in the epicentre of Africa’s petroleum economy, WAIPEC stands as the largest event of its kind – having welcomed over 6,000 participants, over 450 senior VIP delegates and over 250 investing companies, including regional NOCs and global IOCs in 2017 and it is set to double again in size for 2018. Click here for details of the conference.

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.

Shell Divestment Transformed NPDC into A “Major”

By Toyin Akinosho

The divestment from four western Niger Delta acreages by the AngloDutch major Shell and its European partners transformed the Nigerian Petroleum Development Company NPDC, into “a major company”, in the opinion of NPDC managers.

“Huge hydrocarbon resources became available to us”, Kareem Folorunso, the NPDC Manager in charge of the Oil Mining Lease (OML) 26, told a technical session of the Nigerian Association of Petroleum Explorationists (NAPE) in Lagos recently.

Shell, with 30% operatorship of OMLs 26, 30, 34, and 42, led its two partners, TOTAL (10%) and ENI (5%), out of the acreages by selling the combined 45% equity to Nigerian companies between 2011 and 2012. NPDC’s involvement in those assets was triggered by NNPC assignment of her 55% equity to her wholly owned subsidiary.

The NAPE lunch hour presentation was part of a series of attempts by the company to counter charges that its takeover of operatorship of acreages divested by Shell & Co was not a value-destroying enterprise. There are widespread misgivings that the acreages would have delivered much more in terms of output and value to the Nigerian treasury if they had been operated by the private companies who purchased the Majors’ 45% share.
Mr. Folorunso’s paper presented NPDC as a technically honed, well-resourced entity, which just happens to be hampered by bureaucratic challenges normally faced by state owned enterprises.

NPDC’s crude oil in place increased tenfold from 313Million stock tank barrels before the divestment to 3.17Billion stock tank barrels (STB) post-divestment; the company’s stock tank barrels of condensate in place increased more than fivefold from 60MMSTB to 330MMSTB, while the gas resources in place jumped nine times from two trillion cubic feet (2Tscf) to 18Tscf, Folorunso said.

“NPDC is the third largest oil company in Nigeria in terms of oil reserves and has the 4th largest gas reserves in Nigeria”, Folorunso told the meeting, a monthly lunch hour talk designed for knowledge sharing among petroleum geoscientists. “Countless opportunities for partnership and collaboration with other business entities also became available as a result of the divestment”, he testified.

The word ‘Major’ was rather loosely used by Mr. Folorunso. In the oil industry lexicon, only six oil and gas companies –Shell, ExxonMobil, Chevron, BP, TOTAL and ENI are described as Majors. None of them produces less than 1.75Million Barrels of Oil Equivalent per day (1.7MMBOEPD) on a net basis.
The highest producer, ExxonMobil, produced 4.053MMBOEPD in 2016, of which liquid hydrocarbons, mostly crude oil, was 2.365MMBOPD, much higher than Nigeria’s gross total production. Even ENI, the smallest of the group, is only described as a Major because of its unique place in the European industry. In the strictest sense of the term, ENI is really considered “a large independent”, in the same class as ConocoPhillips, Apache, Anadarko and Woodside Petroleum.

What’s more, the smallest of these majors has 7.7BillionBOE, as proven reserves and not Stock Tank Barrel (STB) in Place.
So it is a clear misnomer for Mr. Folorunsho to say that NPDC had transformed into major company. But the Nigerian state hydrocarbon company can be forgiven for being excited by its good fortune.

Nigerian Bid Round Unlikely Until 2018

By McJohn Opotobo, in Warri
The much anticipated 2nd licencing round for oil fields deemed marginal in Nigeria is unlikely to be inaugurated until 1st Quarter 2018.
There is a heightened sense of anxiety for the round, the first in 10 years, and dozens of companies are waiting for the announcement, but impeccable sources at the Ministry of Petroleum in the country’s capital Abuja dismiss the possibility of the anticipated inaugural statement being made any time in the next three months.
The Department of Petroleum Resources, the country’s regulatory agency, responded angrily to a newspaper report which cited some guidelines to the round last week including allusions that the authorities plan to set aside some of the oil acreages for discretionary awards to “individuals from the Niger Delta region”. The report, published Monday September 18, had indicated that such discretionary awards are “to ensure that people from the region own the oil assets, even if it means holding a separate bid round for Niger Delta-owned companies”.
Petroleum ministry sources who spoke with Africa Oil+Gas Report were not discomfited by the parts of the said newspaper report which indicated that interested investors will be required to pay $50,000 each for a Competent Persons Report (CPR), which, the newspaper wrote “will require bidders to provide details of their shareholding structure, names of their directors, track record in the oil and gas sector, audited financial statements, partnership and/or collaboration with indigenous firms, and financial resources to bid and pay for the oil acreages”. The ministry sources also did not contest the part that said that “after the CPR stage, investors will also pay $15,000 each as data mining fees to enable them gain access to the relevant data on the acreages that will be placed on offer”. They are, however vigorously upset about the claims that the guidelines include a plan to set aside some of the oil acreages for discretionary awards to “individuals from the Niger Delta region.” Fuller story here

SDX Expects To Finalise KSR-14 in Mid-October

SDX Energy expects to announce the drilling results of KSR-14 in mid-October. The probe is the first of a nine well drilling programme on the Company’s Sebou, Gharb Centre and Lalla Mimouna permits in Morocco.
KSR-14 is a development well and it is located on the Sebou permit.
“On success, the well will be completed, flow tested and connected to the existing infrastructure. These activities are anticipated to be carried out within 30 days of the drilling rig departing the location”, SDX officials say.
The nine well drilling campaign on three permits follows extensive technical work from which the optimal drilling locations were identified, SDX claims. The London headquartered, Toronto and AIM listed explorer is targeting an increase in its local gas sales volumes in Morocco by up to 50% and an increase in its reserves by more than 100% through this drilling campaign.

Uganda’s Poor Outcome Highlights Africa’s Growing Bid Round Losses

By Toyin Akinosho

Whenever the Ugandan government awards a petroleum exploration licence and signs an oil production sharing agreement with Oranto Petroleum on the Ngassa area, as it expects to do in the coming week,it would be concluding its debut,31 month long, open acreage sale.

In the event, only two of the four companies that were granted the opportunity to take positions accepted to do so.

While Oranto of Nigeria and Armour Energy of Australia agreed to sign, Waltersmith and Niger Delta Exploration, both Nigerian companies, chose to walk out.

Incidentally, these two unsatisfied companies have far more hands-on experience in oilfield activity than the two who signed up (ref-Africa Oil+Gas Report, Vol 17, No 4, 2016).

And yet, Uganda’s is only the latest on the list of cases of poor outcomes of lease sales on the continent.
Angola, Nigeria, even Equatorial Guinea have suffered losses, both in relative and absolute terms, after drawn out bid round proceedings. Read the full article in the Vol 18, No 7 (September) 2017 issue of the Africa Oil+Gas Report.

Ghana Wins

Cote d’Ivoire’s Claim on Oil Discoveries in the Cape Three Points Has No Merit

By Sully Manope

Ghana’s 4-1 beating of Nigeria in the West Africa Football Union (WAFU) Final last Monday (September 25, 2017) was an icing on a cake baked with a huge victory on the economic front.

The country had won a decisive win over Côte d’Ivoire at the Special Chamber of the International Tribunal of the Law of the Sea(ITLOS) two days before the WAFU Cup final match in Cape Coast, capital of Ghana’s Central Region.

It’s worth noting that Côte d’Ivoire and Nigeria are Ghana’s two most important economic and political rivals on the mid-African edge of the Atlantic Ocean.

Ghana had taken Côte d’Ivoire to ITLOS in September 2014, after negotiations with the latter broke down over who had rights to explore and exploit the resources in the Cape Three Points acreages as well as the surrounding fields.

In April 2015, ITLOS forced Ghana to suspend the drilling of new oil and gas wells in the disputed territory by ordering a number of provisional measures, pending the outcome of the litigation. That decision caused Ghana’s Twenaboa, Enyenra and Ntomme (TEN) cluster of fields to begin production with 11 of the planned 24 wells, as no new wells could be drilled until the dispute was settled.

Three years after ITLOS was approached by Ghana to arbitrate, the Tribunal ruled as follows in favour of the country: 1) That there had not been any violation on the part of Ghana on Côte d’Ivoire’s maritime boundary; 2) Determined a new boundary for the two countries (3) Dismissed Côte d’Ivoire’s legal argument that Ghana’s coastal lines were unstable and 4) Declared that Ghana’s oil and gas exploration activities in the disputed basin did not violate any other country’s sovereign rights.

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..