Deepwater gas exploration as next investment frontier in West Africa

Deepwater gas exploration presents the next investment frontier in West Africa despite the huge capital involved as gas begins to command attention due to falling oil prices and the huge CAPEX spend on developing new oil fields.

Tarek El Molla, Egypt’s oil minister’s presentation at Abu Dhabi International Petroleum Exhibition and Conference (ADIPEC) recently revealed the country’s plans to focus on the more costly deepwater gas exploration.

“Deepwater gas exploration is the future,” Tarek El Molla, Egypt’s oil minister told the audience during a presentation.

He said the country is turning its attention to this area, which costs over 15 times more than onshore drilling because of added complexities, as its huge gas find is slated to start production next year.

The Zohr gas discovery made last year is expected to begin production in 2017 with a capacity to produce 1 billion cubic feet (bcf) per day, ramping up annually until it reaches 2.7bcf a day at the start of 2019.

Eni of Italy announced last year that the Zohr discovery in the Mediterranean Sea could hold the potential of 30 trillion cubic feet, which unarguably is one of the largest finds in the region.

El Molla said the first phase of the project that will have gas hitting the market next year will cost a third of the total $12 billion for the first three years. Afterwards, more investment may be needed to maintain production.

Similar feet can be replicated in other parts of Africa especially in West Africa due to vast potentials offshore. “Three of Ghana’s four sedimentary are offshore”, said Theophilus Ahwireng, CEO of the country’s Petroleum Commission.

In 2016 exploratory drilling in Ghana has proven over 1 Bbbl of oil and 1.5 tcf of gas. The discovery of deepwater Jubilee field in 2007 opened the way for further finds, now the country has recorded 25 further finds.

“A lot of the present activity is offshore but there is also open acreage,” Ahwireng told Offshore Magazine. “The most recent discoveries were 150 km from the [maritime] border with Côte d’Ivoire.” In the main, drillers have targeted prospects at the same Campanian and Turonian level that delivered Jubilee, but the government is now looking to extend exploration stratigraphically down to Albian level, he added.

The ongoing Jubilee Phase 1a development is designed to recover 585 MMbbl of oil. In February, 26 wells were onstream, Ahwireng said, delivering 106,000 b/d of oil and 105 MMcf/d to the FPSO. PetroSA recently joined the Tullow Oil-led partnership. “Jubilee is stratigraphically a well-defined field, typically Turonian in nature…although it had to be developed in clusters due to concerns about flow assurance.”

Three more major developments should follow. The first in the sequence is in the Offshore Cape Three Points (OCTP) project in the 600-1,000 m of water in the Tano basin, operated by Eni.

This is a light oil and non-associated gas development focused on two accumulations at Cenomanian level (Sankofa and Gyaname) containing an estimated 500 MMbbl and 1.5 tcf of gas, which will be developed via subsea production systems connected to a leased FPSO.

In February, the vessel had transferred from Malaysia to a shipyard in Singapore. Eni plans to re-use some of the existing appraisal wells for production and also to drill 12 new ones, Ahwireng noted. Oil production should start in 2017, building to 40,000 b/d, followed by gas production at rates of up to 180 MMcf/d.

Deepwater developments in Nigeria have been few and far between for almost a decade largely due to the absence of favourable regulatory and fiscal environment to encourage investments.

Nigeria has proven gas reserves of 192 Trillion Cubic Feet (Tcf) with ambition for a projected gas production of 15billion standard cubic feet (bscf) by 2025. Currently, Nigeria’s domestic gas use hovers around 1bscf. Unproved gas reserves are estimated at 600tcf with the right investments to tap into them.

“Nigeria has the world’s 9th largest gas reserves but ranks 17th on production demonstrating the vast untapped potential that exists in the country,” said Clay Neff, chairman of Oil Producers Trade Section and managing Director Chevron Nigeria.

Gas consumption has rapidly grown in Nigeria through its use in power plants to provide electricity, for manufacturing purpose in factories, utilisation for feedstock and for Compressed Natural Gas (CNG) and Liquefied Petroleum Gas (LPG).

Harnessing the potentials

Nigeria’s government and the Nigerian Association of Petroleum Explorationists (NAPE) are in discussion to encourage investments into exploring for oil and gas in the frontier basins in Nigeria.

To a government that is allocating N34billion for oil exploration in the northern part of the country, Nosa Omorodion, president of the association urged the country to look for oil and gas in other sedimentary basins outside the Niger Delta region to grow the nation’s reserves, which is fast being depleting.

Maikanti Baru, NNPC group managing director, recently said the President had instructed the Corporation to go into the frontier basin of Chad by Kolmani River in Bauchi State, where oil is reported to have been discovered and begin exploration activities.

To harness opportunities in deepwater gas exploration in Egypt, the country offered new terms to incentivise companies.

“We’re meeting all producers and traders. It’s an ongoing process because we’re importing one-third of our consumption and we have to improve pricing and terms that we receive in general, because it helps reduce costs,” said Tarek El Molla.

Cairo embarked on deep reforms including floating its currency in a bid to increase investments including attracting a $12bn loan from the International Monetary Fund (IMF). This could drive more funds into the country, which will help Egypt pay its more than $3.5bn in outstanding arrears to oil and gas operators.

Ghana is already moving toward driving more investments into the country with improved fiscal terms in its recently passed Petroleum industry bill. Nigeria and other African countries need to open up the space for more investments.

Nigeria’s Petroleum Industry Bill is plagued by disagreement over a 10 percent host community provision and imposition of 50 percent and 25 percent hydrocarbon tax on upstream operators who already pay Companies Income tax at 30 percent and Education tax at 2 percent.

Under the existing fiscal regime, production sharing contracts for companies operating offshore water depth of 201m – 500m, with a sales volume of 1,000,000 barrels at official selling between $45/$75per barrel pay 12 per cent royalty after deducting cost of production at $30, give Federal government a 35 per cent share of profit while IOC’s keep 65per cent. The Federal government wants to tweak this arrangement but the IOCs have opposed it.

“The company assumes all pre-production risks in the contract area since it can only recover its costs if there is adequate commercial discovery and production of crude oil in a quantity sufficient enough to pay for such costs. If the production achieved is insufficient to cover the costs the company shall bear its losses,” said John Adidi, a chartered accountant, on the reason such a deal was agreed in the first place.

Non resolution of these issues poses stiff challenge in a sector upstream operators have been cutting capital and exploratory budgets year on year to meet tough operating environment.

The decision of Nigeria’s Federal government to settle its debt to International Oil Companies will go a long way to boost confidence in the sector. IOCs have long accused the NNPC of an imperial attitude towards them and a settlement may further deepen investments in deepwater basins.

ISAAC ANYAOGU