Strategic integration at a Nigerian field

Nigeria

Anthony Adegbulugbe, chairman of Green Energy International Limited, talks to The Energy Year about the value of the government’s upstream cost optimisation scheme and the latest on the Otakikpo field development. Green Energy is a Nigerian energy investment vehicle. The company's main focus is on exploration and production activities in the country's oil and gas industry.

This interview is featured The Oil & Gas Year Nigeria 2020

How has Green Energy International managed to navigate the crisis?
To say that the sector we are in has gone through a tremendous shock is an understatement. Last year, we produced almost the same number of barrels as we did in 2019. However, we were able to take in only a third of the revenue.
Behind the turbulence there have been lessons we have learnt but also strategies that have now become permanent features of our company. To keep our head above water, what we have done is a simple exercise of looking at our cost centres. We found that there were several areas where we could cut down, and thanks to that we managed to reduce our overhead by 20%. Although our offices are closed, the work on the field has been ongoing.
Secondly, we also looked at our operations on the field, aiming to cut cost without compromising safety and security. To this we have made sure to harness operational efficiency as the main lever boosting our performance. We have instituted those policies and procedures, making them our new normal.

How necessary is the implementation of the Nigerian Upstream Cost Optimisation Programme (NUCOP) at this point of time?
The government seems to have finally taken the bull by its horns, as seen in the implementation of NUCOP. The average cost of production in Nigeria stands at about USD 31 per barrel and that is too high. From our perspective, as a small E&P company, there are too many unnecessary add-ons. What the federal government is now trying to do, and what we as a small E&P company are doing on a smaller scale, is to call everyone to the table and benchmark the cost of services.
Secondly, it is important to make contracting cycles shorter. The contracting cycle in Nigeria is six to eight months and many other matters come into play that extend it. At the same time, they need to make sure that contractors get paid as and when they should. As a contractor, if you perceive you will not get your money on time, you try to secure the money as quickly as possible by charging more and asking for 50% upfront.
These are the issues influencing the cost per barrel of production here. To this, we must also add the need to improve the security environment. Securing or repairing damaged pipelines or facilities represents added costs that raise the price.
For now, the government has started the NUCOP scheme by asking all of us to submit the costs of all services so that they can mandate some limits. We expect the government will use that information to do some serious international benchmarking. The government is on the right path and it should be commended.

What is the current state of the Otakikpo field, and what development plans does the company have?
The Otakikpo marginal field is a hybrid project as a contiguous field – part of it is offshore in shallow waters and part of it onshore. We are the operators of the field, with 60% operatorship, while 40% is held by Lekoil. They helped raise the funds for the initial development. The field is divided into Otakikpo Main, with 56,000 barrels of reserves, and Otakikpo South, which holds 150,000 barrels.
So far, we have developed two onshore wells from which we are producing close to 6,000 bopd, an amount that has held fairly steady over the last few years. This reflects the superb management of these wells. In light of this, we’re now planning to expand by drilling at least five to seven more wells, so we are now looking for financing. Each well is expected to produce 2,000-2,500 bopd, which means we are aiming to produce around 15,000 bopd.
With the help of potential financers, we are looking into a USD 15-million investment per well, which could upgrade the performance and efficiency of our asset. As for financiers, we have gone to the international market. We have engaged with Standard Chartered Bank to guide us through this process. We also linked with Schlumberger to be our partner. Working with these renowned entities is crucial as it boosts the perception that lenders can trust us.

Tell us more about your strategic projections of building a brand-new terminal.
Apart from drilling more wells, we are also trying to construct a terminal in our field. The idea of the terminal is to facilitate the evacuation and avoid bottlenecks. For example, if we are producing 6,000 barrels, it is easy to go to an FSO but the owner of the FSO also has his own need for storage, becoming competition. In this case, FSO owners will always have the last word. So, we have looked at it critically, and we are planning to build the first indigenous onshore terminal, with a capacity of 750,000-1 million barrels and a 20-kilometre pipeline offshore.
This terminal is extremely strategic as it aims to cater for all the fields in that same area. At the moment we have done the planning and design, and we are looking for financing. If it works, we could become a go-to for all the small fields in the area – 16 of them that are stranded because they have no evacuation option. We have a lot of government permits and we’ve interviewed many good international contractors that can make it happen. We are just waiting for funding to come our way. If it works, it will be a hub for small field operators in the area.

What updates can you give us on the new flow station you’re building?
As of now, we have a 10,000-bopd flow station, which is running. Yet, we’re hoping to ramp it up to 50,000 bopd. The expansion programme we are carrying out includes several phases. Along with those 10,000 bopd, phase two aims to bring on line 20,000 and if this goes well, we will do another 20,000. If it works, the idea is that we can be a regional processing facility. For example, operators of fields next to us, instead of building their own processing facility, can get their oil in a pipeline to us, have us process for them and then they export. Thus, we aim to be a hub where clusters of fields in the area can bring their output to be processed.

What initiatives are you taking to capitalise on gas-to-power?
The whole idea of this field was based on the fact that we don’t want to do business as usual. We saw that the energy mix is shifting to [low-carbon] energy – from coal to oil to gas, and ultimately to renewables. Having said that, small-scale gas utilisation is already happening.
Firstly, in terms of gas-to-power, in 2018 NERC [Nigerian Electricity Regulatory Commission] approved a licence to build a 40-MW facility. We’ve nearly completed the installation of 6 MW – three 2-MW units of the gas generator plant. It will be completed by mid-2021. We are planning another 15 MW for this year.
Our vision is not to sell to the grid, as this is not good business. We want to generate power to use onsite, to run all our operations and facilities, as well as providing electricity to the community.
Parallel to this, we are also planning to do some LPG extraction. As we speak, there is a plant onsite that can process 12 mcf [339,840 cubic metres] per day of rich wet gas. We aim to generate about 60 tonnes of LPG per day. LNG for the local market is also on the table and other small-scale industries that need gas-to-power. Our scope on mini-LNG is totally focused on the domestic market, and there have already been companies interested in our potential LNG.
Lastly, we are also planning to set up a small gas-based industrial park where apart from power, we can also produce methanol. We had some investors from China coming to see the prospects of this project in 2019. Covid-19 has put this plan on the back burner, but we are hoping to revive it soon.

What inroads are you making in the area of LPG?
In 2018, we implemented a 10-mcf [283,200-cubic-metre] per day LPG extraction facility. We are now installing it. All the equipment is onsite and we are doing the civil works, aiming to finalise it by Q1 of this year. After that we will move onto the second phase, which includes the installation. Hopefully, by the third quarter of this year we will be producing 60 tonnes of LPG per day.
Also, we are already planning for the second train because, if we are successful getting initial financing for extra wells to produce more oil, we can produce more associated gas, and thus more LPG. At present we produce 12 mcf of gas daily, from which around 15% is LPG. The market for LPG in Nigeria is huge, and we have already been in contact with possible offtakers.

How important could the construction of a modular refinery be for Green Energy International?
The option of building a modular refinery is still on the table. We have the licence and we will build a 5,000-bpd refinery at some point in the near future. What we want to do for now is concentrate on producing more oil and getting the industrial park in place. Only then will we start thinking about it.
This step would represent the realisation of a vision, and would trigger a multiplier effect among the community – it will create jobs and in-country value. At the same time, it would reduce costs. For example, the general cost of a refined shipment is USD 2-4 per barrel below the Brent. If we have a modular refinery, that loss will be cut. Based on a 5,000-bpd modular refinery, we would be saving up to USD 20,000 per day.

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