Kuwait Energy has flowed a modest crude oil rate and a trickle of gas after drill stem tests were performed on a new field wildcat well in Egypt’s Abu Sennan Concession in the Western Desert Basin.
The company flowed a cumulative maximum rate of 2,834Barrels of Oil Per Day (BOPD and 4.211Million standard cubic feet of gas per day (MMscf/d) on a 64/64″ choke in two reservoirs in the ASD-1Xwell.
For these two reservoirs, the Lower Bahariya and Abu Roash C, the cumulative minimum flow rate was 1,511BOPD and 1.232MMscf/d on a more constrained 32/64″ choke
Modest as these results are, they exceed Kuwait Energy’s pre-drill expectations.
The oil rates are actually higher than the Egyptian average, but the natural gas flow is incredibly small.
Still, the operator has gone ahead to submit an application for a development lease to develop the “field”, within the Abu Senanconcession.
ASD-1X, located 12km to the north-east of the producing Al JahraaField, reached Total Depth (TD) of 3,750m MD on March30, several days ahead of schedule and under-budget.
Apart from the t reservoirs tested, preliminary results suggest the well encountered a combined net pay total of at least 22m across a number of reservoir intervals, including the primary reservoir targets of the AR-C and AR-E, as well as the Lower Bahariya and KharitaFormations.
The well was drilled by the EDC-50 rig, which has now been moved to the Al Jahraa Field, also within the Abu Sennan concession, where the drilling of the AJ-8 development well commenced on May 2, 2021. This well will target the Abu Roash and Bahariyareservoirs in an undrained portion of the Al Jahraa field.
Below are details of the test results:
· The ASD-1X well tested both the Lower Bahariya and Abu Roash C reservoirs
· Preliminary short-term test results from the Lower Bahariyareservoir indicate:
o A maximum flow rate of (c. 2,187bOEPD gross; 481BOEPD net) on a 64/64″ choke
o A rate of 852BOPD and 1.600MMscf/d (c. 1,172BOEPD gross; 258BOEPD net) on a more constrained 32/64″ choke
· Preliminary short-term test results from the Abu Roash C (“ARC”) reservoir indicate:
o A maximum flow rate of 1,215BOPD and 1.371MMscf/d (c. 1,489BOEPD gross; 328BOEPD net) on a 64/64″ choke
o A rate of 661BOPd and 0.632MMscf/d (c. 787BOEPD gross; 173BOEPD net) on a more constrained 24/64″ choke
Hope Okwa, Founder/Chief Executive Officer Hd Drilling Services, sees the high cost of well construction as major impediment to Nigeria’s meeting its goal of achieving 4Million Barrels of Oil Per Day of crude oil in the short term.
“If we reduce well cost from $25Million to just $5Million hypothetically speaking, requiring only 20% of the previous investment demands”, he tells Africa Oil+Gas Report’sAhmed Gafar, “even local banks may be able to fund field development campaigns”.
He also fields questions on a range of issues, from opportunities that newly awarded marginal fields throw up to demand for Nigerian hydrocarbon.
A bachelors and masters degree holder in engineering from the University of Benin (Nigeria) and Heriot Watt University in the UK respectively, Okwa has 29 years of post graduation industry experience, the first 14 of which he spent in AngloDutch Shell, mostly on well engineering and drilling supervision. He had a stint at BG (the defunct British Gas) as a senior well engineer in the company’s Nigerian deep-water operations. He had a five year stretch as senior drilling and workover well engineer on critical gas operations at Saudi Aramco, after which he had another 18-month stint at BP Angola as senior drilling engineer.
Excerpts from the conversation.
Hd Okwa Drilling advertises itself as a company with a laser focus on oilfield drilling services. How did you come to this realisation?
The Nigerian Government targets Four Million barrels of oil per day (4MMBOPD), but the country is barely achieving 1.5MMBOPD due to high well cost. A 10,000 ft well producing only 3,000 BOPD costs up to $25Million to construct. To move from current 1.5MM to 4MM BOPD requires massive well construction activities, in the order of over 800 wells per year. The associated investment is $21Billion per annum. Where will this investment come from, especially in an era where top global financiers are moving their investment to renewables? The only way is to rethink well construction efficiency, with a view to drastically reducing well costs from current levels.
The sources of inefficiencies in well construction, is very much within our expertise, as a demonstrated through the several SPE papers we have authored.
It is very urgent to implement these solutions. In nine (9) years’ time, by 2030, the first world will pivot away from fossil fuel. What will then happen to Nigeria’s reserves of 37 Billion BOE?
We believe we have the solutions to reduce well costs in Nigeria by as much as 70%. I have a track record of this achievement from my employment with Shell, BG-Group, BP, Saudi Aramco, as well as many local operators. Hd Okwa Drilling is collaborating with operators and service companies to deliver wells that are only 30% of the standard cost. We hope to have an opportunity to talk about these alliances and collaborations in the course of this discussion.
When you say: A 10,000 feet well producing only 3000 BOPD costs up to $25Million to construct, are you referring to an onshore well or a shallow offshore well?
The statement is true for land, swamp and shallow offshore. These use surface blowout preventers.
Ad if a 10,000feet well is considered too expensive at $25Million in Nigeria, what is the reference round the world? What are you benchmarking against?
My reference is Canada/USA, where the rig rate for land is $32,000/day comparable with $25,000/day for Nigeria. A 10,000 ft land well takes 8 days to drill while it takes 83 days in Nigeria. The Canada/USA cost is less than $2 million, while Nigeria is $25 million. The Canadians and Americans achieve the success by efficient well design (without gold plating as we do in Nigeria, efficient supply chain management, avoiding NPT and applying the science of drilling optimisation. We are experts in these areas. I should add that we are currently preparing to execute a $5 million horizontal well for a Nigerian marginal operator, applying our technigues..
Your website indicates that there’s an entire business proposition around well services that require some single mindedness. and how is the journey so far?
The establishment of Hd Okwa Drilling Services is a milestone in its own right. We have had opportunities to offer advice on Well Design, NPT avoidance, cost improvement, personnel recruitment, etc for various operators. In the years ahead, we plan to expand these offerings to technical consulting, staff development on cost-reducing well delivery processes and dealing with the complexity of supply chains in Nigeria.
Rig activity has taken a dive in Nigeria in the past year. What has been Hd Okwa Drilling’s Business Strategy in this prolonged period of silence?
We may ascribe the direct cause of rig activity collapse to the COVID-19 outbreak. However, I suspect the underlying cause of this sharp decrease in drilling activity may not be far from the high cost of wells, as I highlighted earlier, and the challenge of obtaining investment cash in an environment where everyone is going to renewables.
We believe that if we reduce well costs drastically, through our activities, we will be able to stimulate activities. For example, if we reduce well cost from $25Million to just $5Million hypothetically speaking, requiring only 20% of the previous investment demands, even local banks may be able to fund field development campaigns.
Over 200 companies are expected to form 57 Special Purpose Vehicles (SPVs) to develop 57 Marginal Fields in the next 36 Months. How is Hd Okwa working on taking advantage?
Here is where we hope to make the most impact. In the past, many marginal field winners have struggled to bring oil to market due to several challenges, related to investment funds availability. Many of the marginal operators are going to need to drill 3-5 wells to realise their field potentials. Without support from our activities, each operator will try to raise $75 – $125Million for field development. With our expertise, this could just be only $15 – $25Million, which is within the capability of local banks. We have assembled a repertoire of options available to marginal operators e.g. from our bespoke consulting services, to full project management through our sister company H-PTP Energy services, or our supply chain improvement alliances The Well Engineering Platform, etc. Through these outlets Hd Okwa Drilling services hopes to transform the well delivery landscape in the country and catalyse a speedy development of the marginal resources.
What is your outlook on Nigeria’s Upstream sector for 2021?
The environment is very challenging. There is demand for Nigerian oil with the ongoing commissioning of Dangote’s 650,000 BOPD refinery, and several modular refineries. These refineries will help reduce dependence on imported fuel, and not only satisfy local consumption, but fulfil demand across Africa and many of the developing world, who would still be dependent of oil consumption for the foreseeable future. As our contribution to the preparation, we are developing local manpower by running courses like the
Well Design Masterclass,
Re-Entry and Workover Engineering Masterclass,
Abandonment and Decommissioning Planning Masterclass.
We also extending our collaborations to experts overseas, who we are bringing to run specialist training in Nigeria for Nigerians, at very low price. We are also developing ourselves in readiness for the future challenges. For example, I am completing my Master of Science in Innovation and Entrepreneurship at the No.1 Business School in Europe, HEC Paris. Thus, we are ready to make our contribution to energise the Nigerian oil sector.
Nigeria exports oilfield service expertise outside the country. Are you one of such providers? Does Hd Okwa Drilling have Pan African ambitions?
Not at the moment. The focus of Hd Okwa Drilling Services is Nigeria. In North America, drilling planning has really advanced, and the gap with Africa is very wide. So, we focus on Nigeria first, then we can expand to the other African countries later. Let charity begin at home.
Hd Okwa Drilling takes training a so seriously that it’s a full component of its spectrum of business. This is quite unusual in the Nigerian industry. Is training a highly monetised component of your business portfolio?
A direct answer is ‘NO’. However, we need a pipeline of skilled professionals to master the techniques and processes that we deploy. One way of doing this is through training and mentorship. We have established several specialists’ courses relating to efficient well delivery. These courses are available to both individuals and operators, at a fraction of the cost. Training cannot pay back if we are to consider the efforts we put in, as these courses are at the cutting edge of the future of well engineering. They cover Well Design Masterclass, Re-Entry and Workover Engineering Masterclass, Abandonment and Decommissioning Planning Masterclass, Efficient Cementing Technology, etc. We also organise team alignment workshops, well challenge sessions, drill-the-well-on-paper (DWOP) exercises, in addition to our normal specialist courses. Our resource persons are the leaders on the well engineering disciplines within Nigeria and the global industry.
The International Association of Drilling Contractors (IADC) Nigerian Chapter is always talking about training about quality and capacity of rig personnel, about safety on rigsite. Is your company looking at Collaboration with IADC?
We have it as part of our strategy to collaborate with the IADC Nigerian Chapter, on manpower development for the Nigerian industry. We are in the process of founding a Well Engineering professional organisation. When completed, the organisation will also be part of our springboard for driving down well costs in Nigeria by accelerating competence development of professionals through mentoring by Nigerian professionals with extensive international experience.
I am curious about a company calling itself strictly a Drilling Service company; why can’t you simply describe yourself as a full subsurface solutions provider?
Of course, we are a subsurface consultancy group. However, expertise in the other areas of petroleum engineering abound. As drilling requires long training and mentorship to attain professional maturity, it appears to be the area in serious need of attention. If well costs are allowed to continue to grow, the current lull in well construction activities will linger too long. There is need for urgency, as we cannot predict what would happen to Nigeria’s oil after 2030, which is only nine years time!
I see that you count Shell, Amni, and First E&P as part of your clientele. For indigenous companies who are mushrooming in Nigeria, the logistics of integrated project management can be so challenging they’d do better to outsource it. Is this the space you are after?
Shell, Amni, First E&P, Monipulo, Elcrest, Addax, etc, are some of the beneficiaries of our expertise and we have worked in one form or the other with these organisations. However, we are a technical consulting organisation. We use our expertise to help operators, reduce well costs. We do this by facilitating well design improvement, helping them eliminating non-productive times, and training and mentorship of personnel. Our project management activities are carried out through another organisation that we contribute expertise to.
Out of the several specialisations in Hd Okwa Drilling services: Well Cost Improvement Catalysis, Strategic Expertise & Technical Consulting, Well Operations Risk Elimination, which of them does Hd Okwa Drilling find most forward looking? And which are you best at?
Our expertise covers all areas, and we need all of them as arsenal to attack the monster of well costs escalation. We operate through several avenues:
In Non-Productive-Time elimination for example, our research showed that all NPT’s in the Nigerian drilling operations are caused by four main events namely Well control, wellbore instability, equipment failures and human errors. These events constitute 30% of the total time spent at the well site on a well. We have developed expertise that we use to support operators to eliminate these events.
Invisible lost time constitutes the least beneficial activity to the drilling operation, but are being carried because they can’t be detected. This time constitutes up to 50% of wellsite times. We collaborate with international experts to develop well operations analytics software. We currently support two – SMARD and CI Drill. Both software are creating disruption in the well analytics space. These two-software combined can eliminate up to 30% of all invisible lost times.
Drilling project management requires high level of expertise. The country has relied on Shell to develop drilling expertise for the industry in Nigeria. However, as the company has shrunk over the years, so have the number of professionals they develop. We contribute technically to H-PTP Energy Services which is full services well projects management organisation founded by like-mind professionals with strong international expertise.
We have developing collaborations and alliances with service suppliers to the drilling business to help them improve their services to international standards.
I act as Technical expert in well engineering such as expert witness, standards development, expert opinions, etc.
We have supported a financial service organisation to advise them on energy project funding.
We act as well examiner, in line with international standards, where we look at drilling project plans, and offer recommendations for improvement.
We conduct workshops to drive the ideas through the clients’ teams.
And, of course, training services. We are very good in this area.
The last annual report by Shell sounded so despondent about their experience out on the Nigerian oilfield environment. What is your message to international investors about the future of the Nigeria’s oil and gas market?
We need investors to help us develop the 4MMBOPD we need to develop the economy and enjoy the benefits of oil and gas. I think investors can help to improve the technical space in the local industry by patronising local expertise. For example, our organisation consists of high-level professionals with experience of global oil and gas industry, as well as internal consultancies such as McKinsey & co, as well as PWC, among others. These professionals understand international standards and procedures, and are able to offer advice to international level.
On the whole, the development of local refineries will help insulate the industry from the vagaries of international oil market cycles. With a population of 200Million citizens, Nigeria is the country to invest in. And the oil and gas leads the way.
The astronomically high drilling costs of wells in Nigeria are key to the challenges faced by operators in reining in operating and capital expenses, an industry service provider has suggested.
If Africa’s highest crude oil producer is to reach its target of delivering Four Million Barrels of Oil Per day (4MMBOPD) in the near term, those costs need to be brought down, argues Hope Okwa, Founder/ Managing Director of Hd Okwa Drilling Services.
“A 10,000 feet well producing only 3,000 BOPD costs up to $25Million to construct in Nigeria”, Okwa allows. “To move from the current 1.5MMBOPD to 4MMBOPD requires massive well construction activities, in the order of over 800 wells per year. The associated investment is $21Billion per annum. Where will this investment come from, especially in an era where top global financiers are moving their investment to renewables?”.
Okwa is persuasive that he is not just throwing numbers around: “$25Million per well cost is true for land, swamp and shallow offshore, as the rigs all use surface blowout preventers.
“The only way is to rethink well construction efficiency, with a view to drastically reducing well costs from current levels”, he contends. “The sources of inefficiencies in well construction, is very much within our expertise”, Okwa declares: “it is very urgent to implement these solutions”, as “in nine (9) years’ time in 2030, the advanced countries will pivot away from fossil fuel. What will then happen to Nigeria’s reserves of 37Billion BO?”
Okwa’s benchmark is North America. “In Canada/USA, the rig rate for land is $32,000/day compared with $25,000/day for Nigeria. A 10,000 feet land well takes eight (8) days to drill while it takes 83 days in Nigeria. The Canada/USA cost is less than $2Million, while Nigeria is $25Million. The Canadians and Americans achieve the success by efficient well design (without gold plating as we do in Nigeria, efficient supply chain management, avoiding NPT and applying the science of drilling optimisation. We are experts in these areas. I should add that we are currently preparing to execute a $5Million horizontal well for a Nigerian marginal operator, applying our techniques”..
Cost control in oilfield activities has been a front burner issue in Nigeria. Last February, the state hydrocarbon company NNPC had an elaborate event on cost optimization, at which Timipre Silva, Minister of State for petroleum, asked the country’s 34 oil and gas producing companies to join in working towards reducing operations cost to achieve the $10 or less per barrel production cost target.
Stakeholders have responded to Ministry of Petroleum’s call for cost control by naming causes including insecurity (You need gunboats full of naval officers on the way to rig-site) and taxation (government at all levels level multiple taxes: DPR hikes costs of obligatory services, State Governments demand various tariffs, Local Governments harass operators; communities hold up work; regulators sometimes delay).
Okwa counters that “those issues relate to production mainly, and companies are having to trade off drilling wells due to the issues mentioned and high well cost”.
Okwa has 29 years industry experience, the first 14 of which he spent in AngloDutch Shell, mostly on well engineering and drilling supervision. He had a stint at BG (the defunct British Gas) as a senior well engineer in the company’s Nigerian deepwater operations. He had a five year stretch as senior drilling and workover well engineer on critical gas operations at Saudi Aramco, after which he had another stint at BP Angola as senior drilling engineer.
“We believe that if we reduce well costs drastically.. we will be able to stimulate activities”, he says. “If we reduce well cost from $25Million to just $5Million hypothetically speaking, requiring only 20% of the previous investment demands, even local banks may be able to fund field development campaigns.
Kuwait Energy Company is moving the ED-50 rig to the north of the Licence, to drill another well, after the moderate success of the last one, which will soon be brought to production.
The next probe is the ASD-1X exploration well, located close to the producing Al Jahraa field. The well is targeting the Abu Roash reservoirs in the Prospect D structure and, if successful, can again be quickly be brought into production.
The last well, ASH-3, a step-out development well in the ASH Field, penetrated a gross hydrocarbon column of 59metres in the primary Alam El Bueib (AEB) reservoir target, 27.5metres of which is estimated to be net pay. The well recorded a maximum flow rate of 6,379 bopd and 6.7 mmscf/d (c. 7,720 boepd gross; 1,700 boepd net), during testing, on a 64/64″ choke, from the AEB reservoir. On a reduced, 30/64″ choke, expected to be more representative of the producing flow rates, the well flowed at 3,561 bopd and 2.9 mmscf/d (c. 4,140 boepd gross; 910 boepd net).
It was spud on the 4th January, and it reached a total depth (TD) of 4,087m MD (3,918m TVDSS) on 8th February.
“The partners, Kuwait Energy and United Oil and Gas when brought on production over the coming days, ASH-3 will provide a significant boost to the concession-wide production rates that averaged 10,500 boepd gross (2,310 boepd net) during January 2021.
“We look forward to the spudding of the forthcoming exploration well and the remainder of our 2021 work programme,” the partners say.
Malaysian driller Sapura Energy Berhad has declared that its joint venture with Seadrill, namely Sapura Navegacao Maritima SA (SNM), is not impacted by the recent Chapter 11 cases filed by several Seadrill subsidiaries operating in Asia.
In a clarification to Bursa Malaysia, the country’s Stock Exchange, Sapura states the Chapter 11 filing by Seadrill, which is an internationally renown Scandinavian drilling company, does not involve Sapura or entities related to the corporate structure of the joint venture, stressing that the filing has no financial impact on Sapura Energy’s business plans and financial strength.
Sapura Navegacao Maritima SA (SNM) is the only joint venture between Sapura Energy and Seadrill.
Headquartered in Rio de Janeiro, SNM is one of the leading subsea services operators in the Brazilian market, with a fleet of submarine service vessels providing support, installation and flexible pipe laying expertise to clients in the region.
The company has a workforce of more than a thousand professionals, from 21 different nationalities. SEB’s clarification was in response to a media report linking Seadrill’s Chapter 11 filing of its Asian units, to the Brazil-based SNM. In the clarification, SEB also explained that the filing has no effect on its contracts with Petrobras, which forms the main revenue for SNM; and does not trigger any cross default for the joint venture’s business financing.
New deal comes with a price of $7.5 per thousand cubic feet of gas
Savannah’s Accugas subsidiary has entered into a revised Gas Sales Agreement GSA with Lafarge Africa for the supply of gas to its Mfamosing cement plant in Cross River State, Nigeria.
The company says the new deal “establishes a more sustainable long-term contractual position for the benefit of both parties”.
The revised GSA sees the contract term with Lafarge extended for a further five years to January 2037, giving a remaining contract life of 17 years. The new agreement also allows for an increase in the gas sales price from 2027, with additional US-Consumer Price Index indexation from 1 January 2029.
The revised GSA has a reduction in the daily contracted quantity (DCQ) of gas from 38.7 MMscf/d to 24.2 MMscf/d. This reduction in the DCQ will allow Accugas to release approximately 12 MMscf/d of currently reserved gas processing capacity at its Central Processing Facility (CPF), enabling Accugas to enter into additional long-term GSAs for these volumes, which will increase the business’ future revenues and cashflow potential.
To compensate Accugas for this reduction in DCQ, the revised GSA includes an advance payment of $20Million and a prepayment structure over the period to 2027, which effectively results in a gas price of $7.50/Mscf on take-or-pay volumes during this period. “This revised structure also allows Lafarge to utilise its accumulated make-up gas balance of approximately $58Million, whilst we have preserved the capacity to supply higher volumes when these are required by Lafarge”, Savannah says in a statement. “Lafarge’s commitments under the revised GSA will continue to be guaranteed by an international investment grade bank guarantee.
“Overall, the revised terms are expected to have a cumulative positive impact on Accugas’ cash flows over the short and medium term. Following the agreement, Accugas’ aggregate maintenance-adjusted take or pay volume will reduce from 141.4 MMscf/d to 131.8 MMscf/d.
Local contractors and staff working for the NPDC/Neconde Joint Venture in Oil Mining Lease
(OML) 42 and NPDC/Shoreline’s OML 30, in Nigeria’s Delta State, have caused disruption in crude oil output on the assets, ensuring drastic drop by over 50% in each of the OMLs.
They were protesting unpaid salaries and emoluments.
In November 2020, the NPDC/Neconde Joint Venture averaged around 18,000BOPD, a drop of more than half of the JV’s optimal output of 38-42,000BOPD. The same month, the NPDC/Shoreline Joint Venture plunged in output from around 50,000BOPD, to 18,000BOPD, according to field data available to Africa Oil+Gas Report.
OML 30 recorded no production between November 8 and 15, 2020, as a result of the protest, according to the report.
In OML 42, output stoppage occurred from November 22 to 28, record shows.
Reports say that the protesters on OML 42 numbering over 200, escalated things to above-surface level on Tuesday December 8, converging at the main gate of Neconde Energy Limited, located at the Berger
Yard, Warri, in Delta State in the mid-west of the country, vowing not to leave the premises until they were paid. They accused Nestoil and Neconde oil firms of owing them salary arrears and emoluments spanning between 2007 and 2020.
The protesters asserted that “communities, contractors and community staff have been working for Naconde and NNPC, yet they have decided to ignore us”.
Some of the protesters displayed placards with inscriptions such as “We want our total payment today”; “Nestoil pay all our money, stop being wicked to us”; “Stop intimidating us with your security agencies,” among others.
Harougue Oil Operations, a joint operating company on behalf of National Oil Operation, Libya and Suncor Oil (North Africa) GmbH invites tenders for the supply of material for tie-in of production wells.
The project s to be executed on Amal field,
The material request to be utilized for tie-in of Three new oil production wells at Amal field. All materials to be supplied to the specifications addressed in the material’s requisition.
Announces an invitation to participate in tender No (03/2020) for Companies which have the required Legal and valid License documents.
Assala Energy increased production of the Shell assets it bought in Gabon from 40,000BOPD to 55,000BOPD in the space of two years.
The London headquartered company claims it installed new equipment and brought down the cost per barrel to $12.
It is hoping to ride the storm of steep drop in prices, exacerbated by COVID-19, even with all the volatility.
Assala pumped $60Million into the five acreages in 2018 and spent $240Million more in 2019, in the process, drilling 20 new wells and optimizing 60 existing wells.
It had a war chest of $300Million for 2020, of which it had spent $70Milion in the first quarter alone.
So what will happen now?
If it survives the next 12 months, its plan is to continue from where it stopped.
The company was raring to go before COVID-19 happened. In late 2019 it acquired three onshore exploration licences from the Gabonese authorities: Mutamba-Iroru II, Nziembou II and Ozigo II, in addition to the five licences it purchased from Shell: Rabi Kounga II Toucan II Bende M’Bassou Totou II, Koula/Damier and Gamba/Iyinga. It also holds interests in four non-operated licences (Atora, Avocette, Coucal and Tsengui.
TechnipFMC has now signed the much-anticipated major Engineering, Procurement, and Construction (EPC) contract with Egypt’s state owned Assiut National Oil Processing Company (ANOPC) for the construction of a new Hydrocracking Complex for the Assiut refinery.
The $2.5Billion hydrocracker will upgrade residual oil from the 90,000BOPD Assiut refinery, in the town of Assuit, in Upper (southern) Egypt.
The work also involves Egyptian state-owned contractor ENPPI.
“This EPC contract covers new process units such as a Vacuum Distillation Unit, a Diesel Hydrocracking Unit, a Delayed Coker Unit, a Distillate Hydrotreating Unit as well as a Hydrogen Production Facility Unit using TechnipFMC’s steam reforming proprietary technology. The project also includes other process units, interconnecting, offsites and utilities.
The complex will transform lower-value petroleum products from Assiut Oil Refining Company’s (ASORC) nearby refinery into approximately 2.8Million tons per year of cleaner products, such as Euro 5 diesel.