Egypt has attracted large and small producers, thanks to higher well-head prices and favourable geology. Its ultimate goal is not only self-sufficiency but a surplus for exports.
Egypt’s gas demand is 52bn m³/yr and is expected to continue rising and may reach 65-70bn m³/yr over the next ten years. A combination of a switch to renewables, lower subsidies, higher gas prices and an awareness campaign by the Egyptian government about more efficient energy use may help stem the rampant increase in demand. But even with these, without new gas coming online the gas deficit of 7bn m³/yr in 2015 will carry on growing.
The challenge is that gas production declined this year to less than 40bn m³/yr, owing to the policies of past governments, requiring expensive LNG imports as from last year. And if this decline continues unchecked, gas production may go down to 15bn m³/yr in 10 years, as most of Egypt’s existing oil and gas wells are either at maturity or beginning to decline. The oil minister said recently that Egypt is expected spend an estimated $8bn on energy imports this fiscal year – a drain on the country. It is currently importing about 1.1bn ft³/day (11.4bn m³/yr). Without new oil and gas production this will worsen.
However, Zohr and a number of new gas-field developments, spurred on by the new gas prices negotiated recently by the Egyptian government and the gas companies, are coming to the rescue, with BP and Eni leading the way.
Egypt’s hydrocarbons are produced in: the Western Desert, Eastern Desert, the Mediterranean Sea, Upper Egypt, Nile Delta, Gulf of Suez, and the Sinai Peninsula. Gas reserves are expected to grow mostly due to new discoveries in the Mediterranean and the Western Desert. While a lot of attention has gone to Zohr, most of Egypt’s oil and gas is produced from relatively small fields that are tied into regional gathering systems.
Egypt has revamped its energy sector strategy and is on a drive to increase oil and gas production. It is dealing with the crippling problem of energy subsidies and increased energy prices in August. Also in August, Tareq El Hadidi, the chairman of EGPC, told Reuters that state spending on petroleum subsidies dropped 23% year-on-year in the financial year 2015-2016 and further reductions are expected during 2016-2017. Egypt is also signing new exploration contracts, and has renegotiated new and higher gas prices, between $4/mn Btu and $5.88/mn Btu, that have prompted gas companies to speed up project development.
BP, Eni and other producers operating in Egypt stand to gain from this new pricing regime, which has become a massive incentive to develop new projects. And with a gas-hungry domestic market, they do not have to look far or hard to find end-consumers. Through its unused LNG plants, Egypt also has the capability to export excess production. Provided also the security and fiscal situation improves, so that Egypt can catch up and keep up payments to the upstream companies, there is a huge growth potential ahead for upstream companies operating in Egypt. However, there is still some way to go. By the end of June Egypt’s debt to international oil companies reached $3.4bn, up from $3.2bn last year.
New gas projects
Last year, Eni announced the discovery of the giant 100 km² gas field Zohr, in the Shorouk block about 190 km offshore and close to Egypt’s exclusive economic zone’s border with Cyprus. Zohr was drilled to a total depth of 4,130 m, in 1450 m of water. It is estimated to hold about 850bn m³ gas. This was confirmed by the first five appraisal wells just completed, which showed there is an upside in comparison to original estimates, increasing these to 907bn m³. Zohr was discovered in a Miocene carbonate formation with excellent reservoir characteristics with a 630 m hydrocarbon column and 400 m net play.
Eni plans to drill six appraisal wells by the end of the year, including a dedicated well to test out a deeper Cretaceous prospect this year. Based on evaluation of seismic data, Eni indicated that this may hold another 280bn m³ gas.
On September 1 it said its fifth well, drilled to a final depth of 4,350 metres, 12 km southwest of the discovery well Zohr 1x and in water depth of 1,538 m, confirmed the potential at 30 trillion ft³ (850bn m³). It proved the presence of a carbonatic reservoir and gas accumulation also in the south-west of the mega-structure, with a 180-m continuous hydrocarbon column.
The well was also successfully tested opening 90 m of the reservoir section to production and confirms the great deliverability of the Zohr reservoir, in line with the Zohr-2 well test, producing more than 50mn ft³/d, limited only by the constraints of the drilling ship production facilities.
In the production configuration, Zohr 5x is estimated by Eni as capable of delivering up to 250mn ft³/d.
Spurred on by an attractive gas price of up to $5.88/mn Btu, Eni and the Egyptian government agreed a fast-track development plan that will bring Zohr online by the end of 2017 with an agreed initial production of 10bn m³/yr, to reach a plateau of about 27bn m³/yr when full production is achieved by 2019, with a total investment of about $12bn. Eni’s CEO Claudio Descalzi confirmed that development has already started. In fact Eni is already investing $3.5-4bn in building a natural gas processing plant in Port Said with a capacity of 2.7bn ft³/day (28bn m³/yr) to process gas from the Zohr field and has awarded contracts for the construction of the first phase. Descalzi said Zohr gas will be “mainly sold on the Egyptian market.” But he noted that Egypt’s two LNG export terminals have enough spare capacity to enable some Zohr gas to be liquefied for export, especially if Eni discovers more gas beneath Zohr.
Descalzi told the Financial Times July 8 that the company hopes to sell a part-stake in the 30 tn ft³ (850bn m³ ) field in the Mediterranean by the end of 2017 and it has received several expressions of interest from majors and national oil companies. According to Reuters these include Lukoil, ExxonMobil, Total and BP. Descalzi did not say how large a stake it will sell, but said it would contribute to Eni’s target for disposals, and spread the risk of its Egyptian investment. An analyst told the FT that a 20% stake might fetch $1.6bn.
Eni, as the operator, and BP are also expanding development of Abu Madi West block in the Nile Delta through Nidoco North 1X in the Nooros prospect, having been successful with Nidoco NW3 late 2015. Last June BP and Eni announced their latest gas discovery in the area through the drilling of Baltim South West Well. Eni has also identified significant additional potential in this area, which will be tested through the drilling of two exploration wells. They have already increased output in the Nooros area this year, achieving 65,000 boe/day, about 3.7bn m³/yr, in May and plan to increase it to 140,000 boe/day, close to 8bn m³/yr, by end of 2016 through the drilling of additional
development wells.
In August Eni announced that it aims to increase the Western Desert Noras field gas production to 1bn ft³/day (10.3bn m³ /day) at the beginning of 2017, up from 700 mn ft³/day in the current year and 300 mn ft³/day at the end of 2015.
The $12bn West Nile Delta (WND) Project involves the development of gas and condensate fields about 65 km-85 km off the coast of Alexandria. BP, as the operator, and DEA have started work on phase I, which involves the development of five fields – Taurus, Libra, Giza, Fayoum and Raven – to produce over 140bn m³ of gas and 55mn barrels of condensate. First production is expected to start in 2017, with peak production expected to reach 12.5bn m³/yr of gas.
WND also includes other discoveries – the Maadi, Viper, Ruby, Polaris and Hodoa fields – which will be further explored and developed in later phases. These are expected to produce another 140bn m³ to 200bn m³ gas, potentially adding another 12bn m³/yr to 16bn m³/yr to the Egyptian gas grid.
BP is also accelerating development of the 42bn m³ Atoll gasfield in the North Damietta Offshore Concession in the Nile Delta, with production expected to start in 2017. This is expected to add another 3bn m³/yr to Egypt’s gas grid.
With a market for its gas assured, and at attractive prices, BP plans to also step up investment in its existing operations through its joint ventures with GUPCO in the Gulf of Suez and the Pharaonic Petroleum Co (PhPC) in East Nile Delta with an estimated potential exceeding 140bn m³, as well as continuing to progress its exploration program in the Nile Delta. BP with its partners currently produces 30% of Egypt’s gas and expects to more than double this amount over the next four years.
BP’s North Africa regional president Hesham Mekawi said in an interview with Reuters that future discoveries will revive the Damietta LNG plant, and allow restart of Egyptian LNG exports. He added “There is still a lot of gas to be found in Egypt in the Mediterranean.”
Another successful operator in Egypt is Apache with major presence in the upstream rich area of the Western Desert. It operates there through its JV with EGAS, Khalda Petroleum, and increased gas production in 2015 close to 9bn m³/yr. Apache has allocated close to $1bn investments during the fiscal year 2015-2016 budget for the drilling of 94 development and exploratory wells. Apache is currently producing 9bn m³/yr gas and announced in August that it is planning new investments, including expansion of its activities in Egypt.
Apache, through Khalda Petroleum, has also embarked on an unconventional/shale gas exploration programme in the Western Desert through a JV with Shell as the operator with 52%, having agreed a price of $5.45/mn Btu. Three wells were to be drilled at the field by June, when Shell and Apache would be discussing the full-scale development of the project with the Egyptian government, but there are no news yet. Initial indications are good. The EIA estimates Egypt’s recoverable shale gas reserves at 2.83 tn m³, most of which are in the Western Desert.
Dana Gas Egypt and its partner BP successfully drilled Balsam-2 and Balsam-3 wells onshore Nile Delta in 2015, discovering new gas reservoirs, which could add close to 1bn m³/yr to the grid. In addition to Blocks 1 and 3, Dana Gas also has another three concessions onshore Nile Delta, the El Manzala, West El Manzala and West El Qantara. The concessions now consist of 14 development leases with gas and condensate production from 12 fields, and with a further two fields in development. Today, gas production is about 2bn m³/yr and 4800 b/day condensate. Dana plans to increase it to 2.5bn m³/yr and condensate production to 7000 b/day during 2016. As a result, Dana plans to spend $400mn in Egypt over the next three years on an ambitious E&P programme that includes drilling at least 20 development wells and up to 6 exploration wells. In August it announced that its gas production in Egypt increased by 11% year-on-year.
In the meanwhile it was reported in the Egyptian press that BG Egypt, now fully owned by Shell, and EGPC have patched up their differences on the gas price associated with the development of the West Delta Deep Marine Phase 9B project. The compromise appears to be that BG will receive an initial payment of £400mn towards its debt and will be allowed to export gas through Idku, but it has not been confirmed. Development of the project should then resume with the drilling of 15 wells, with production scheduled in 2017 and estimated to be over 4bn m³/yr. But so far the government has failed to fulfill this promise due to foreign exchange shortages. The total debt to BG has now increased to $1.1bn.
In the meanwhile, Shell announced in June its new plans in Egypt for the coming fiscal year 2016/2017. It plans to invest $342m in drilling 33 wells in its concession areas. This is down £100m on 2015/2016, reflecting the state of the industry but perhaps also Shell’s debt uncertainties in Egypt. It should also be remembered that Shell announced early this year that that it plans to end its oil and gas operations in 10 countries in order to reduce the company’s costs and streamline operations, but there are no details yet, except perhaps for Gabon.
Finally, EGPC has just signed a cooperation agreement with Edison International to develop the second phase of the offshore Abu Qir gas field. This is expected to add another 1.5bn m³/yr to the Egyptian gas grid, possibly in 2017, in addition to the 2.8bn m³/yr it produces now.
Potential for new discoveries
Zohr is encouraging oil and gas companies to look more carefully at carbonate formations in the eastern Mediterranean. The region has produced some significant discoveries in recent years and it is believed that the Med still has massive hydrocarbon deposits to be discovered.
Among the blocks close to Zohr, and east of Shorouk, are North Thekah and North Port Fouad operated by Italy’s Edison. 3D seismic surveys have been completed and Edison is in the process of planning its drilling campaign in North Thekah. It has been reported that initial indications are good. The plan is to tender for a similar survey for North Port Fouad by the end of the year and decide if and where to drill by 2018 or 2019. Eni has two other exploration blocks, North Leil and Karawan, west of Shorouk.
BG, now owned by Shell, has three offshore concessions, El Manzala, North Gamasa and El Burg, where two discoveries were made Harmattan Deep-1 and Notus with an estimated 170bn m³ gas. It remains to be seen how Shell progresses these.
Onshore prospects are also good, particularly in the Western Desert where Shell and Apache are drilling for shale gas.
Having awarded four offshore licenses last year, and 56 concessions in total between 2014-2015, Egypt plans to announce a new international tender in 2016 for 9 new exploration blocks in the Mediterranean sea. In August the government approved five oil and gas drilling and exploration agreements with foreign companies, that include BP, Eni, Total and Edison.
Based on the new discoveries and gasfield development described in this article, Egypt expects to more than double its current gas production by 2020, by bringing onstream another 50-60bn m³/yr gas. This was confirmed at the Offshore Technology Conference in Houston. In fact, two of the presenters said that gas production in Egypt is expected to increase by more than 90bn m³/yr by 2022, with increasing future prospects. Not only this is enough to achieve self-sufficiency, and do away with the need for LNG imports, but there should also be excess gas available for exports. The process has already started with two LNG cargos exported from Idku so far this year. It is expected that significant reductions in LNG imports should materialize from 2018 onwards.
From Egypt’s perspective, the good news is that it is not just Zohr coming to the rescue, but also development of many other smaller gas fields, spurred on by new government policies, higher gas prices and a guaranteed domestic market.
With BP planning to develop the other WND discoveries soon after phase I, Eni progressing with new finds, Shell and Apache progressing with unconventional/shale gas, and exploration and development of new offshore blocks, Egypt is experiencing a remarkable transformation and is well placed to continue expansion of is gas production well into the next decade.
The outcome of all these developments is a dramatic reversal of fortunes for Egypt from gas shortages to self-sufficiency and exports. The Egyptian gas sector is turning the corner as a result of better management and regulation, but also through the new and potential gas discoveries. Reversal of the decline in gas production started during Q1 2016 and by August production reached 4.2bn ft³/day (43.4bn m³/day). The Petroleum Minister stated in August that currently there are 13 projects being executed to develop Egypt’s natural gas fields with investments estimated at $33bn. These are expected to increase gas production to about 5.5-6bn ft³/day (57-62bn m³/yr).
These developments impact the hopes of its neighbours Israel and Cyprus to export their gas to Egypt. Not only this is commercially challenging, but the markets for it may no longer be available
