SANS 342:2016 (South African National Standard) is the standard that governs the quality of diesel in South Africa. The SANS document, published by the South African Bureau of Standards (SABS) details the properties of diesel that are of importance, the tests that need to be carried out to determine quality, recommended test methods and the limits for the diesel to pass or fail the standard. Most of the test methods use the same specifications as ASTM (American Society of Testing and Materials), IP (Institute of Petroleum), ISO (International Standards Organisation) or SANS.

When determining diesel quality, it is important to use a laboratory that employs the correct test methods as dictated by the standard. It is also important to use a laboratory that is accredited by SANAS 17025 (South African National Accreditation System) and SABS ISO 9001. This ensures that the tests are carried out correctly, quality standards are met, and the results are reliable.

The quality of the diesel in South Africa is often a topic of hot debate. One of the first things to identify, is what we mean by “quality diesel” – let us not confuse poor quality with dirty, wet or adulterated fuel. It is extremely unlikely that a single drop of diesel leaving South Africa’s refineries does not conform to the SANS standard for the quality of diesel. It is from this point that the problems start, with poor transport methods, poor handling, sloppy storage and corruption. A wide variety of engine problems can be traced back to contaminated diesel.

This Technical Bulletin will look at the tests to determine diesel quality that are carried out in WearCheck’s Specialty Laboratory, the instrumentation used and what the consequences of failing to meet the standard might be, along with the actual limits that are applied.

Flashpoint

The flashpoint temperature of diesel is the minimum temperature at which the fuel will ignite on the application of an ignition source (naked flame). Flashpoint varies inversely with the fuel’s volatility. The SANS requirement is a minimum flashpoint of 55ºC.

The flashpoint of the fuel does not directly affect the combustion characteristics of the engine, but is important in terms of safe storage and handling – the lower the flashpoint, the more flammable the fuel is. A low flashpoint can help identify petrol adulteration, because for every ½ percent addition of petrol, we would see an approximate 8ºC drop in the flashpoint. Other contaminants – such as paraffin, other fuels and solvents – will also lower the flashpoint. Contamination with heavier fuels and lubricants will raise the flashpoint.

Viscosity

Viscosity is a measure of a fluid’s resistance to flow. It therefore affects injector lubrication and fuel atomisation. Fuels with low viscosity may not provide sufficient lubrication for the precision fit of fuel injection pumps or injector plungers, resulting in increased wear or leakage. High viscosity fuels, on the other hand, will increase gear train, cam and follower wear on the fuel pump assembly due to the higher injection pressures.

Diesel fuels with high viscosity also tend to form larger droplets on injection, causing poor combustion and increased smoke and emissions. Fuels that do not meet viscosity requirements lead to loss of performance. Again, this test would help identify both thin (petrol)and thick (oil) adulterants. The SANS requirement is 2.0 – 5.3 centistokes.

Viscosity is measured by the length of time it takes for the diesel to flow through a calibrated tube under the force of gravity at 40ºC.

Density

This is a measure of the specific gravity of the fuel, in other words, how much does a litre of fuel weigh? Both volume and mass are measured to determine density. Density essentially determines the energy content of the fuel. The denser the fuel, the more power the engine can generate, and vice versa. Diesel is specified at a minimum of 0.800kg/l at 20ºC (the density at 15ºC is also determined). This helps to identify adulterants such as IP, which has a density of 0.790kg/l. or oil, which has an approximate density of 0.885 kg/l. Low density fuel leads to a loss of power per litre of fuel and an increase in fuel consumption. Density and viscosity are actually measured on the same instrument.

Sulphur

This measurement helps identify what a diesel sample is not rather than what it is. Low sulphur diesel is specified at 0.005% (50ppm) or less, while normal diesel is 0.05% (500ppm). This specification only determines the maximum allowable level of sulphur in diesel – it does not mean that 50 ppm diesel has exactly 50 ppm sulphur and the same would apply to 500 ppm diesel. Contamination of 500 ppm diesel with 50 ppm diesel results in the actual sulphur content varying between 50 and 500 ppm in practice. Concentrations of less than 50 ppm are also frequently noted. In the SANS 342 document, these two fuel grades fall under what is called CF1 (clean fuels). If you read the document, you will note that there is also a CF2 requirement, which covers ultra-low sulphur fuel at 10 ppm. Although this forms part of the specification, CF2 is yet to be legislated. Legislation had been planned for September 2023, but has now been postponed to July 2026. The main reason for this is that the modification to refineries to produce 10 ppm fuel is prohibitively expensive.

Sulphur is a naturally occurring constituent of crude oil, but its presence in diesel is an area of concern. The sulphur content of diesel can either be reduced by using low sulphur crudes or during the refining process, which is expensive. There is a range of valid reasons for the removal of sulphur from our diesel supplies. The first and most pressing reason is that high-sulphur diesels are known to influence the emission of fine particulate matter through the formation of sulphates. These particulates are considered a health hazard, and their reduction is desirable. However, the presence of sulphur must not be confused with dirty diesel; it is a vital component of diesel in that it imparts a natural lubricity, protecting fuel pumps and injectors. When this is removed during refining, it has to be replaced with additives to perform the same function.

High-sulphur fuel also produces sulphur oxides on combustion which, when dissolved in other by-products of combustion such as water, form strong acids. When these acids condense, they attack the metal surfaces of valve guides, cylinder liners and bearings. The acids produced are neutralised by the engine lubricant and, in doing so, reduce the working life of the lubricant, necessitating shorter drain intervals.

There are, however, steps that can be taken to reduce the damage that can be caused by burning high- sulphur fuel:

• Know the sulphur content of your fuel. It is recommended that every bulk delivery is checked, especially if fuel quality is questionable.
• Keep the normal operating temperature of the cooling system above 80ºC; this will limit condensation of sulphuric acids on cylinder liner walls.
• Select oils with a sufficient starting TBN (Total Base Number).
• Follow standard oil-change regimes unless oil sampling indicates differently.
• Maintain the crankcase breather system to prevent condensation in the crankcase oil, which will cause rapid TBN depletion.

Finally, high-sulphur fuels act as poisons to catalytic converters and other systems which are used in diesel engines to reduce exhaust emissions and reduce pollution.

Sulphur is measured by X-ray fluorescence spectroscopy. It is important to use such an instrument, as other instruments and spectroscopic techniques such as ICP are not valid test methods for the measurement of sulphur in diesel.

Sulphur can be measured in either ppm or percentage; 1% is equivalent to 10 000 ppm (think of percentage as a part per hundred).

Distillation

This test measures the temperature range over which a fuel turns to vapour. Volatility is one of the primary methods which distinguishes various fuels from one another. It is also an indication of the fuel’s ability to start the engine, its power, fuel economy, emissions and deposit formation. In the laboratory, the point at which the diesel starts to boil is measured (IBP), the temperature at which the first 10% by volume has distilled over (T10), 20% has distilled over (T20) and so on up to 100% (T100) or the final boiling point FBP. Distillation is specified at a maximum of 362ºC for T90 or 90% recovery, in other words, 90% of the fuel has boiled off. If the percentage distilled is plotted against the temperature, a characteristic distillation curve is produced. Any deviations suggest contamination.

Distillation Data

Distillation Curves

Water

Water causes corrosion and reduces the ability of the diesel to act as a lubricant. Very small amounts of water can actually dissolve in diesel, and the maximum allowable amount of water is 350 ppm. It is important to note that water can exist in fuel in two forms – dissolved and free. The dissolved water is measured with a Karl Fischer titrator, which is an automated, electrochemical method for determining the amount of water very accurately.

Free water is assessed by examining a beaker of the fuel on a special light tray that shows up free water droplets very easily. The presence of free water is also grounds for the diesel to fail SANS 342. Note that it is quite possible for the fuel under test to pass one test whilst failing the other. The presence of free water, whilst passing the dissolved water specification, is usually an indication of contamination whilst taking the sample.

Total Contamination

This test is used to determine the amount of ‘dirt’ or particulate matter in the diesel. The maximum amount of particulate matter allowed in diesel is 24 mg of dirt per kg of fuel. Testing involves filtering one litre of sample through a pre-weighed 0.7 micron filter. The filter is then dried in an oven to constant weight. The difference in weight before and after is a measurement of the amount of solid particulate contamination in the sample. This test is known as IP440. The IP does not stand for ‘illuminating paraffin’ as many people think; in this case, IP stands for Institute of Petroleum, test method 440.

The presence of particulate matter in diesel is a source of abrasive material that can cause wear and damage to the components in the fuel system, such as pumps and injectors. This is the only approved method for Total Contamination.

Cetane Number (Index)

The cetane number is a measure of the ignition quality of the diesel. It represents the time delay between injection and ignition. If the cetane number is too high, the fuel will ignite too close to the injector. This forms a fuel-rich region whilst the rest of the chamber has a weak fuel-to-air ratio. Incomplete combustion and soot formation will be the result. Low-cetane fuels cause knock, difficult starting, rougher running and increased exhaust emissions. For typical on- and off-highway engines, a cetane number of 45-50 is considered ideal and is specified at a minimum of 45 in SANS 342 (but is generally found to be around 48). Illuminating paraffin has a cetane index of around 40, and will therefore affect the cetane number and performance of the diesel. The cetane number can be determined by expensive testing in an engine laboratory. However, WearCheck has a more cost-efficient test method – we determine the cetane index of the fuel using an ASTM method utilising the distillation values T10, T50, T90 and the density of the fuel at 15ºC and 20ºC.

Visual Assessment of the fuel

This involves placing a beaker of fuel on a light tray and making a visual observation. The fuel is checked for free water (as discussed under water analysis), free particulate matter (visible to the naked eye) and the clarity of the diesel. Any free water, particulate matter or haziness would be grounds for the fuel to fail SANS 342. Note that, as with the water test, it is possible for a sample to pass either the total contamination or the visual assessment but fail the other. The colour of the diesel is also noted.

Fungal and Bacterial testing

As the name suggests, a sample of diesel is tested for the presence of a range of bacteria and fungi. This is a time- consuming process and involves adding a portion of the diesel to a special testing strip containing a medium that is ideal for the growth of ‘bugs’. This is then incubated for 72 hours in an oven. The growth of bugs over this period of time is rated against a chart and given a very slight, slight, moderate or heavy concentration of bacteria and/or fungi classification. Essentially, this may allow us to identify problem areas; it would then be up to the operator to take corrective action such as dosing the bulk tanks with a biocide.

The amount of contamination is rated in cfu/ml, colony- forming units per millilitre.

Bacteria and fungi can grow in diesel, particularly if there is water contamination. The microbes live at the fuel/ water interface and can form foul-smelling mats that can clog filters and produce acids that would be damaging to fuel-system components. Note that SANS 342 does not provide a limit on this sort of contamination, as it is not part of the specification.

Biodiesel

Biodiesel is diesel manufactured from renewable organic sources, traditionally vegetable oils (biomass) and is considered to be an alternative, environmentally friendly source of power. Biodiesel can be used as a pure source for internal combustion engines. It can also be blended with ordinary fossil fuels (diesel). SANS 342 allows a maximum biodiesel content of 5% (B5). Biodiesel content is measured using Fourier Transform Infra-red spectroscopy (FTIR).

Total Acid Number (TAN)

The TAN of diesel can be measured using an electrochemical titration and gives an indication of the overall acidity of the fuel, however, it does not form part of the SANS 342 specification

Particle Counting (ISO 4406)

Particle counting by ISO 4406 can be carried out and used as another indication of fuel cleanliness. A sample of fuel is passed through a test cell and is illuminated by a laser, the various particles cast shadows on a detector and the number of particles per ml in various size ranges can be measured. The three size ranges are greater than 4, 6 and 14 microns. The total number of particles in each size range can be converted into a guide number for each size range and expressed as an ISO 4406 cleanliness rating (such as 18/16/13): the lower this is, the cleaner the fuel is.

ISO 4406 and particle counting do not form part of the SANS 342 specification, so no limit is given. However, there is an international body called the Worldwide Fuel Charter. The Worldwide Fuel Charter was first established in 1998 to promote greater understanding of the fuel-quality needs of motor-vehicle technologies and to harmonise fuel quality world-wide in accordance with vehicle needs.

The Charter gives an upper-limit recommendation for ISO 4406 of 18/16/13. Although there is no legal requirement for South African diesel to meet this recommendation, many OEMs are very interested in these numbers, which is why WearCheck carries out the test.

Particle counting on diesel is very difficult to carry out because the viscosity of diesel is so low. This means that particulate matter settles very quickly in the sample. The standard method of particle counting used on lubricating oils cannot be used on diesel. A special test method (ASTM D7619) exists specifically for the purpose of measuring the cleanliness of fuels and this is what must be used.

Other tests

There are quite a few other tests that form part of the SANS 342 specification, these are not carried out by WearCheck, but can easily be outsourced. These include copper corrosion, calorific values, cold filter plugging point (CFPP), cloud point, lubricity, carbon residue, ash and oxidation stability.

The range of tests that WearCheck offers on its standard SANS 342:2016 report covers a wide range of analyses that encompass the most common and day-to-day requirements of diesel testing. The cost of doing everything that is listed in the specification would make the cost of a fuel sample prohibitively expensive, however, the other tests can be provided on request

Illuminating Paraffin

No article on diesel testing would be complete without some discussion on the problem of diesel being contaminated with illuminating paraffin.

In response to an article that appeared in Fin 24 on June 15th 2022, Gwede Mantashe, the South African Minister of Mineral resources and Energy, warned of the use of illuminating paraffin to doctor diesel in an attempt to defraud the revenue services and increase profits. The following discussion gives a bit of background to this practice, the deleterious effects it can have, and the various methods for testing diesel for the presence of illuminating paraffin (IP).

Diesel can be subjected to a variety of chemical and physical tests in the fuels laboratory. One of the most common and important things to look for is contaminants, the most common of which are dirt and water.

Diesel can also be contaminated with other fuels and solvents, in particular illuminating paraffin, or IP, as it is known. IP is a readily available power source for domestic lighting, heating and cooking. Chemically, it is very similar to diesel, but because it is used as a domestic power source, it is not subjected to the taxes and levies that diesel is, in other words, it is cheaper than diesel.

The less-than-honest members of our society have taken to doping diesel with IP and, because it is so similar to (but not exactly the same as) diesel, a diesel engine will run quite happily on a diesel/IP mixture at less than the cost of diesel. Although the engine will run without a problem in the short term, in the long term, the IP will be quite damaging to the engine. IP has a lower viscosity and less lubricity than diesel, and will cause damage in terms of increased wear to the components of the fuel system.

Although the price difference may not be huge, if you think of the thousands of litres of diesel used every day, doping diesel with ten or twenty percent paraffin represents a large cost saving and loss of revenue for the country’s revenue services (SARS).

The effects of IP contamination on diesel are that the viscosity, density and flashpoint will decrease, and the sulphur concentration will increase. Low density means you get less bang for your buck (more litres of fuel required for the same number of kilometres travelled). Low flashpoint could become a safety issue, and elevated sulphur could impact the emission controls of modern engines and increase combustion by-products being introduced into the lubricating oil. This will reduce its ability to lubricate the engine adequately, resulting in shortened drain intervals.

Interestingly enough, small amounts of IP may not affect the properties of diesel enough for it to fail the Bureau of Standards specification SANS 342, so, IP can be present, yet the fuel will still pass the specifications of SANS 342. In fact, IP is often legally added to diesel in small amounts by the refineries, as it helps prevent the diesel from waxing (freezing) during the cold winter months inland. Doping diesel with IP, in the long term, is not a good idea and it is also illegal.

Because this type of doping represents a loss of income for SARS, they have introduced a chemical marker into illuminating paraffin sold in South Africa. The marker comes from an American company called Authentix, which specialises in brand protection and anti- counterfeiting. This marker is added to IP at a precise concentration once the product leaves the refinery.

It is possible to test for this marker. The test kit is a lateral-flow test kit, similar to those used for testing for Covid or pregnancy. The answer is just a simple yes or no, the marker either was or was not detected. The test kit is very easy to use and takes hardly any time at all. What it cannot tell you is how much IP is present. What is important to mention is that, if the IP came from a source that was not marked, for example from across our borders where markers are not used, then no marker will be detected, yet the sample could still be contaminated, but not by enough to fail the other physical tests that are carried out, for example, viscosity, density and flashpoint.

Further testing is possible, however. The diesel sample can be sent to a SARS-approved laboratory, where they use an instrument called a GC-MS (gas chromatography – mass spectroscopy) that can measure the actual amount of the marker that is in the fuel and, from that, it is possible to calculate the actual amount of IP in the fuel, as the exact concentration of marker that is added is known.

The reason for having two levels of testing is because (at the time of publishing), the lateral-flow test kit costs about R500, whilst the actual percentage test costs around R5,500 (more than ten times the lateral-flow test), and has to be outsourced.

Although it is possible to use gas chromatography to look for IP in diesel directly, because of the very similar physical and chemical characteristics of the two liquids and the large number of compounds in each, the process is slow, expensive, not particularly accurate and difficult to carry out.

At the end of the day, as with lubricating oil, keeping diesel cool, dry and clean is a policy that reaps great benefits, and rewards the user with lower operating costs.

Canadian company Reconnaissance Energy Africa and its joint venture partner, the National Petroleum Corporation of Namibia, have been granted approval to resume exploration in the northeast of the country.

This approval for the Second Renewal Exploration Period was granted by the mines and energy ministry (MME), and it is valid from 30 January 2024, to 29 January 2026.

The approval relates to ReconAfrica’s approximately 6.3 million acres (some 2.5 million hectares) petroleum exploration licence (PEL) 73.

ReconAfrica is an oil and gas exploration in the Kavango Sedimentary Basin in the Kalahari Desert of north-eastern Namibia and north-western Botswana, where the company holds petroleum licenses, comprising approximately ~8.0 million contiguous acres (3.2 million hectares).

“We appreciate the MME recognising the significant capital deployed and the work programme ReconAfrica has executed during the First Renewal Exploration Period on PEL 73 over the past three years. During the first exploration period, the company has exceeded our work commitments through the drilling of three stratigraphic test wells, the acquisition of over 2 750km of 2D seismic and a ~5 000km2 eFTG survey. I would also like to take the opportunity to recognise the efforts of the ReconAfrica and Reconnaissance Energy Namibia teams in executing those programmes safely – and for the benefit of the people of Namibia. We look forward to executing an efficient exploration programme as we commence our drilling programme to test the high potential Damara Fold Belt and oil-prone rift plays,” said Brian Reinsborough, president and CEO of ReconAfrica.

Under the terms of the Second Renewal Exploration period, ReconAfrica will acquire additional subsurface data.

This will include either 500 km of 2D seismic data, 1 200km2 of Enhanced Full Tensor Gradiometry data or a combination of these.

In addition, ReconAfrica will be required to design and drill one exploration or stratigraphic test well.

The approval of the Second Renewal Exploration Period is a key outcome as the company looks to continue exploring the potential of the Kavango Basin within PEL 73.

It is also an important outcome as ReconAfrica continues to progress its farm-out joint venture process.

In a statement, ReconAfrica noted that MME is Namibia’s lead agency in attracting private investment in resource exploration and development through the provision of geo-scientific information on minerals and energy resources, and management of equitable and secure titles systems for the mining, petroleum and geothermal industries.

“It also carries prime responsibility for regulating these extractive industries and ensuring that safety, health and environmental standards are consistent with the relevant State and Commonwealth legislation, regulations and policies,” ReconAfrica stated.

Today, flare-to-power solutions are garnering more and more attention as an innovative new method for tackling the environmental and economic hurdles tied to flaring within the oil and gas sector. These solutions have the potential to transform wasted gas into a valuable source of energy while mitigating the harmful effects of flaring.

But like any emerging technology that’s often misunderstood, there are myths and misconceptions surrounding flare-to-power solutions that need to be debunked.

In this blog post, we’ll take a look at some of the most common myths about flare-to-power, and shed light on the reality of these promising energy solutions.

Myth #1: Flare-to-power solutions aren’t environmentally friendly

One of the most common myths about flare-to-power solutions is that they contribute to environmental harm. However, this misconception overlooks the key benefit of flare-to-power solutions: they significantly reduce greenhouse gas emissions.

In reality, when natural gas is flared, it releases carbon dioxide (CO2), methane, and black soot into the atmosphere. This flaring exacerbates climate change, harms air quality, and damages human health. And with around 140 bcm of natural gas flared globally every year, this equated to 500 Mt CO2 equivalent annual GHG emissions in 2022.

Flare-to-power solutions capture this wasted gas and convert it into energy, preventing harmful emissions and utilising a valuable energy resource that would otherwise be lost.

By harnessing the energy content of flared gas, flare-to-power solutions align with environmental sustainability goals, making them a crucial tool in the fight against climate change.

Myth #2: Flare-to-power solutions are inefficient

Another common myth is that flare-to-power solutions are inherently inefficient. Some critics argue that the process of capturing and converting flared gas into energy is too complex and energy-intensive, ultimately wasting more energy than it produces.

In reality, flare-to-power solutions have come a long way in terms of efficiency. Modern technologies and engineering advancements have made these solutions highly efficient and capable of recovering a significant portion of the energy contained in flared gas.

At Aggreko, we prioritise efficiency in our flare-to-power solutions. Using modular units that can adapt to fluctuations in gas availability, we can ensure a consistent and reliable power supply.

Ultimately, this adaptability minimises energy wastage and maximizes the utilisation of flared gas.

Myth #3: Flare-to-power solutions are unreliable

Some believe that flare-to-power solutions are unreliable due to the intermittent nature of flaring in oil and gas operations. The fear is that these solutions may not provide a stable power source for critical operations.

In reality, reputable flare-to-power solution providers use advanced technology and engineering practices to ensure the maximum availability and reliability of their systems.

To address worries about declining gas volumes, Aggreko works closely with clients to develop solutions that align with environmental goals.

For example, by installing on-site gas chromatographs to provide real-time gas analysis, we can easily monitor and guarantee the consistent and verified quality of the gas supplied to the power plant. This level of monitoring and control enhances reliability.

In addition, Aggreko’s modular approach allows for seamless scalability, making it possible to adapt to fluctuations in gas availability.

This means that even during periods of intermittent flaring, flare-to-power solutions can continue to provide a stable power source.

Myth #4: Flare-to-power solutions are too costly

Another myth surrounding flare-to-power solutions is that they are prohibitively expensive. Some critics argue that the initial investment and operational costs outweigh the benefits, making these solutions economically unviable.

In reality, the cost-effectiveness of flare-to-power solutions depends on various factors, whether it’s the scale of the project, the efficiency of the technology, or the regulatory environment. While there may be upfront costs associated with implementing these solutions, they often yield significant long-term savings.

For example, Aggreko’s flare-to-power solutions have demonstrated substantial cost savings for oil and gas companies. By harnessing flared gas for energy generation, these companies reduce the need to purchase electricity from external sources, resulting in substantial operational cost reductions. Additionally, the environmental benefits of reducing flaring can lead to regulatory incentives and goodwill in the market.

Overall, as technology continues to advance, the costs associated with flare-to-power solutions are likely to decrease, making them even more economically attractive.

Myth #5: Flare-to-power solutions are only for large-scale operations

A common misconception is that flare-to-power solutions are suitable only for large-scale oil and gas operations, and are not practical for smaller facilities or remote locations.

In reality, flare-to-power solutions can be tailored to suit operations of various sizes. Modular units, such as those offered by Aggreko, provide unprecedented flexibility and scalability. These units can be deployed in both large industrial complexes and smaller, remote facilities.

For remote locations that lack access to grid electricity, flare-to-power solutions can be particularly valuable. They offer a reliable source of electricity, reducing the need for more expensive and environmentally harmful diesel generators.

The adaptability of flare-to-power solutions makes them a viable option for a wide range of oil and gas operations, regardless of their size or location.

Myth #6: Flare-to-power solutions are not technologically mature

Some critics argue that flare-to-power solutions are still in their infancy, and are not technologically mature enough to be considered a reliable alternative to traditional power sources.

In reality, flare-to-power technologies have advanced significantly in recent years, with cutting-edge technology and engineering processes helping to develop highly efficient and reliable solutions. These solutions have been successfully deployed across diverse projects and geographical contexts.

The use of modular units, real-time monitoring, and gas analysis technologies demonstrates the maturity of flare-to-power solutions. These technologies have been refined over time to ensure consistent performance and environmental benefits.

Additionally, the growing adoption of flare-to-power solutions by major oil and gas companies indicates industry confidence in the technological maturity of these solutions. They are no longer experimental concepts but practical, proven alternatives.

Myth #7: Flare-to-power solutions are only about mitigating flaring

Another common misconception is that flare-to-power solutions are solely focused on mitigating flaring, and do not offer any wider benefits.

In reality, flare-to-power solutions provide a host of advantages beyond reducing flaring. While they play a crucial role in mitigating environmental harm, they also contribute to energy security, environmental sustainability, and energy equity – the three components of the energy trilemma.

1. Energy Security: Flare-to-power solutions optimise the use of valuable energy resources, enhancing energy security by reducing dependence on external power sources.
2. Environmental Sustainability: By curbing flaring, these solutions significantly diminish emissions, contributing to environmental sustainability efforts and mitigating climate change.
3. Energy Equity: Flare-to-power solutions redirect valuable energy resources towards productive and accessible ends, promoting energy equity and the more equitable distribution of energy benefits.

These solutions align with the economic interests of oil and gas companies by offering the opportunity to optimise the total cost of energy, addressing both environmental concerns and economic efficiencies.

Embracing the reality of flare-to-power solutions

Flare-to-power solutions hold the promise of transforming the oil and gas industry into a more sustainable and environmentally responsible sector. By debunking common myths, we can better appreciate the potential of these solutions to address the challenges of flaring while delivering a range of benefits, from cost savings to environmental protection.

As the energy industry strives for a greener future and works towards the ambitious goal of zero routine flaring by 2030, embracing flare-to-power solutions becomes not just a choice but a necessity. With the proven success of companies like Aggreko and the growing recognition of the value of flare-to-power solutions, it’s clear that these innovative technologies are an essential part of our shared journey toward a more sustainable and equitable energy landscape.

The African upstream oil and gas sector is in the middle of an US$800 billion capital expenditure (capex) programme that will see liquified natural gas (LNG) emerge as a major investment theme alongside traditional deepwater oil according to Ian Thom, Upstream Research Director at Wood Mackenzie.

Speaking at the African Energy Week event in Cape Town, Thom told delegates that the 20-year investment cycle that started in 2010 would culminate at the end of the decade with world-scale LNG projects in Mozambique and floating LNG (FLNG) across five countries. Africa is already a leader in floating LNG with over 50% of global capacity, and scope for more projects to emerge.

“With abundant gas resources, Africa is looking at all opportunities to develop gas for domestic and export markets,” Thom said. “The niche role that FLNG plays has gained traction in Africa due to its flexibility, quick time to market and suitability for smaller volumes. We see more examples where FLNG could be applied to African resources, and we expect there is more to come on this growth story.”

Global FLNG capacity and Africa’s market share

West Africa offers huge LNG potential

Thom added that current LNG exports coming from Africa are just over 40 million tonnes per annum (mmtpa) and there are a number of LNG projects in Sub-Saharan Africa (SSA) that are in various stages of development. These include bp’s Tortue FLNG, located offshore from Senegal and Mauritania, which comes onstream next year.

“Tortue Phase 1 is expected onstream next year, so we will see 2.4 mmtpa of supply growth in the short term,” Thom said. “With easy access to European markets deepwater gas in Senegal-Mauritania offers significant potential in what are relatively stable and supportive countries.”

Mozambique LNG plays vital role

Thom also cited several LNG and FLNG projects in Mozambique as key to the future success of the continent’s LNG export aspirations. These include Coral Sul FLNG which shipped its first cargo in November 2022 as well as Rovuma LNG and Mozambique LNG both having stalled.

“Mozambique needs improved security to resume construction of onshore LNG facilities,” Thom said. “Rovuma and Mozambique LNG central to a potential doubling of African LNG supply by 2035, there is a risk that exports could flatline longer term if these projects fail to materialise.”

African Upstream capex by country

Oil trending down but deepwater projects offer hope

With gas projects in the ascendency, Thom told delegate that oil production in traditional hubs across Africa will struggle to offset production declines at mature assets. Big oil players such as Nigeria, Angola, and Egypt as a group will see oil production flatline as we move towards the end of the decade.

“With the global upstream trend firmly focused on advantaged resources, it is inevitable oil production will be affected in higher cost and higher emitting assets in Africa,” Thom said. “However, there could still be some upside from reserve growth or yet-to-find resources. TotalEnergies recent discovery at Ntokon in Nigeria is a great example where new oil discoveries drive incremental growth. And the exploration success in Namibia underlines how deepwater exploration can generate strong investment opportunities.”

The African Oil and Gas sector is in an exciting phase of its development, with global energy policy shifting, new discoveries being announced on the continent, and the sector itself being reimagined to expand its renewables and community-development components.

These and other trends are driving an ongoing restructuring of the sector, with some established oil-and-gas multinationals exiting the continent, while smaller and more agile operators continue doing business here.

In Ghana, the country’s upstream oil and gas industry essentially came into being in 2006, when the first offshore discoveries were made.

The first licence – the Jubilee field, at a depth of 1 100m – is still on stream today, and has helped to grow confidence in the Ghanaian oil and gas sector, and the future potential of the African industry at large. It has also provided learnings for governments and operators looking to develop opportunities in the African upstream in the future.

Pragmatic partners

From the time of the initial offshore discoveries, the Ghanaian government has set out to position itself as a pragmatic and reasonable partner, willing to do what is necessary to bring new fields on stream. Following the initial discoveries in 2007, the operators of the concessions were appointed within a year.

Since Jubilee would host Ghana’s first oil-production facility, a good deal of policy and infrastructure development was happening for the first time. However, the Ghana regulators understood that a steep learning curve need not be any limitation.

Work efficiently

Particularly in new exploration territories, the eyes of the world are fixed on the pace of pioneering developments. For businesses that may be comparing options in various parts of the world, a government that shows itself to be fast and efficient in developing policy, passing regulations and assessing project plans will always have the edge over its competitors.

So, it has proved with Ghana.

Ghana’s energy department approved the Jubilee field Phase 1 Development Plan and Unitisation Agreement in July 2009, and first oil was achieved in November 2010 – a mere 40 months after the initial discovery well. The speed of the development was at that time the fastest ever comprehensive full-scale deepwater development.

The development involved building a Floating Production Offtake Vessel (FPSO), which made it a relatively complex project. However, solid fundamentals were put in place early on, and today the field remains highly lucrative. Recoverable reserves are estimated to be more than 370 million barrels, and an upside potential of 1.8 billion barrels.

Develop relationships

It is sometimes useful to see initial projects as the foundation of a far larger vision. While a launch development may be lucrative, the potential of a longer-term relationship is significantly larger – for all parties.

The Government of Ghana has shown an ongoing commitment to the evolution of its upstream resource infrastructure. This dovetails with the long-term vision of a growing cohort of agile oil-and-gas independents. Subsequently Ghanaian discoveries have also been rapidly brought into production, based on the healthy relationships forged at initial development.

At the TEN field, discovered in 2013, first oil was achieved on time and on budget, within three years of the Plan of Development being approved.

Invest for the long term

Efficient, pragmatic development of its oil and gas resources, with an open, partnership approach, has seen Ghana establish an energy industry that now contributes 3.7 percent to the Gross Domestic Product (GDP) of the country, according to the 2022 EITI Mining & Oil/Gas Reports, through total crude oil production of 6.9 MMbbls and 88 000 MMscf of natural gas, adding $666.4 million to the fiscus in terms of total petroleum receipts.

The country is now set to launch as many as 17 oil and gas projects over the next four years, including new offshore fields, refineries and petrochemical processing facilities.

These figures demonstrate how African oil discoveries in frontier territories can become the drivers of entire new economic sectors, sectors that can play a meaningful role in the upliftment of the host country, and the African region at large.

Africa is yet to see anything close to a full return on its massive oil and gas resources. With one-third of the continent – almost 500 million people – still having no access to electricity, ending energy poverty across Africa is among the planet’s most urgent challenges.

To address this, action it is imperative to accelerate upstream investment across Africa and ensure a far wider share of its economic benefits. Giant discoveries in Namibia, FIDs (Final Investment Decision) in Angola and a bumper 2022 for new field start-ups all bode well, but can numerous other major projects across Africa secure the financing needed to move forwards?

Developing Africa’s huge natural gas reserves is essential not only for growing export revenues but also to support domestic economic growth and help the continent unlock its low-carbon energy potential. Can Africa find an economic solution for its gas riches?

As the Majors downsize across Africa, domestic independent operators are stepping up to champion the region’s oil and gas developments. But with mounting challenges around financing, carbon emissions and dominant NOCs (National Oil Companies), can these companies prosper?

Ahead of African Oil Week, which is due to take place between 09 – 13 October 2023, in Cape Town, at the International Convention Centre, Wood Mackenzie considers how to get oil and gas working for Africa.

Financing Africa’s oil and gas development

While African upstream investment is recovering, securing capital to develop the continent’s oil and gas resources remains a monumental challenge. Putting this into perspective, despite the region having the third-largest remaining resource base by region, over the next ten years we expect Africa to account for only 6% of global upstream investment. As a result, Africa’s production will decline from 12.4 million boepd in 2024 to 10.1 million boepd in 2033.

Second, the role of government. With high prices, governments’ default position will be to increase tax rates. This is likely to exacerbate the problem. A more enlightened approach would be to ease the tax take on new investment, as Nigeria and Angola have both done. Tax allowances for renewables to power upstream developments would be even bolder, showing a commitment to decarbonise Africa’s upstream industry and diversify into low-carbon technologies.

Third, investments in Africa must respond to the increasing regulations around sustainability. African upstream carbon intensity is amongst the highest globally, deterring buyers looking for low-carbon supply. African countries must tackle the major sources of upstream emissions – flaring, production and processing, and methane leakage – or risk an increasing number of IOCs (International Oil Companies) and lenders walking away.

Finding new avenues to gas resource development

With domestic gas markets non-existent in many countries, Africa’s major gas resource holders have historically looked to onshore LNG export projects for commercialisation. Most have been defined by high costs, low returns and long payback periods.

Alternative development solutions for their gas resource are therefore crucial for gas-rich nations throughout Africa and floating LNG (FLNG) is offering a differentiated pathway to gas monetisation.

The reasons are clear. After a stuttering start, FLNG’s lower capital costs combined with increased demand for quick-to-market LNG has again made FLNG an attractive proposition for developers, investors and off-takers.

Africa is at the centre of the current boom. Cameroon GoFLNG and Mozambique’s Coral Sul FLNG project blazed the trail, with projects in Mauritania/Senegal, Congo and Gabon following. FLNG is also under consideration in Nigeria and Namibia, and offers an alternative option for Mozambique’s troubled onshore Rovuma project.

Despite this bullish outlook, FLNG is not without risks. Concerns over cost blowouts, scheduling delays and security will need to be managed by developers of more than 20 mmtpa of African FLNG either under construction or considering FLNG as a development option.

A bigger challenge for Africa is developing gas for the domestic market. Despite the immense potential for gas to boost power generation and support economic growth, familiar issues around affordability and limited infrastructure continue to hold back capital investment.

The rise of the Africa’s independent operators

It is a sign of the increasing maturity of African independent operators that local players have the confidence to take on the development of their own natural resources. African independents are increasingly active, picking up assets from IOCs divesting non-core African portfolios.

We identify three drivers. First, the maturity of the Majors’ legacy African portfolios. With these companies under increasing pressure to focus on low-carbon, low-cost opportunities, divesting from late-life, carbon-intensive assets in locations including Nigeria, Gabon and Congo fits with their strategies.

Second, African governments are increasingly supportive of local independents accessing the region’s substantial resources. Favourable tax terms for new entrants and marginal assets have helped boost the emergence of African independents. Conducive regulatory environments in turn lead to greater economic diversification, job creation and growth in domestic industries. The Dangote refinery development in Nigeria, which is set to transform the regional oil products sector, is just one example.

Third, while financing remains a significant hurdle, African independents are increasingly demonstrating their ability to navigate above-ground challenges which have deterred IOCs from maximising the potential of their assets. A local “licence to operate” and partnerships with international investors are helping African companies access capital and the technical expertise required to acquire and develop assets.