The industrial landscape for oil refineries has been challenging of late, with the Covid-19 pandemic triggering a massive slump in demand for oil which resulted in many refineries across the world having to temporarily shut down. The question for anyone working in the industry is whether the sector will spring back as lockdowns lift across the world, or whether the impact of the pandemic was merely an accelerating factor within a process which was already underway. If the answer to this question is yes, what’s more, then the sector will have to accept that refinery shutdowns are becoming a fact of life and, having accepted that, start planning for the future.

Refining Capacity Dip Caused by Pandemic Cuts Across Operators

The evidence for the impact of the pandemic on the sector is widespread and undeniable. According to a report from Reuters, published in June of this year, the refining capacity across the US fell by 4.5% during 2020, the largest drop since the recession of 2012. The drop in capacity was driven by a 13% drop in gasoline consumption, and prices for gasoline and diesel hit a four year low. The result was that five refineries across the US shut down permanently. Three of the refineries in question were run by the largest US refiner of crude oil, Marathon Petroleum, while one was run by Shell and the other by independent HollyFrontier, illustrating the fact that this is an issue which cuts across operators and impacts the industry as a whole. Not that the problem is confined to the US, with closures – some tagged as temporary at the time – also happening across Europe and in Australia.

Over 2021, several refinery complexes saw workforce lay-offs - some as high as 60%. Indeed, Galp halted operations at the Matosinhos oil refinery complex in Portugal from early 2021, citing a 16% drop in throughput in the fourth quarter of 2020. The same thing is happening across Europe, With Neste closing the Naantali refinery which has previously refined 55,000 barrels per day (bpd), and Gunvor closing the loss-making Antwerp refinery – previously dealing with 115,000 bpd – with no plans to reopen it if the market picks up.

In Australia, the collapse of the oil refining industry has resulted in their now being just two refineries in the country, after Exxon Mobil closed the 86,000 bpd Altona refinery in February, following on from BP closing the Kwinana refinery in November of last year, and converting it into a fuel import terminal. Of the two remaining Australian refineries, Geelong in Melbourne is the largest, with a capacity of 128,000 bpd, but is by no means guaranteed to remain in operation with the owners, Viva Energy, accepting a government subsidy but refusing to rule out closure.   

An Infrastructure as Fragile as Any Other Given the Right Circumstances

The fragility of the sector as a whole was underlined not merely by the impact of the pandemic, which, in all honesty, left hardly any sector completely untouched, but also by the example of Texas, a part of the world which, over and above almost anywhere else, could surely be expected to be able to cope with any temporary issues caused by wider conditions. This proved not to be the case in February of this year, however, when unseasonably freakish arctic weather – temperatures dropped as low as -13°C in Austin, -15°C in Dallas and -23°C in Amarillo – led to the largest refineries in North America having to be shut down across the state. These closures were temporary, of course, but they serve to underline how fragile the infrastructure upon which the industry is based can be, and how external events of varying size and type can lead to not just interrupted operations but complete shutdowns.

Pre-Pandemic Predictions of a Downturn

Prior to the pandemic, experts were already predicting a major downturn in the oil refinery sector across Europe, with companies having to rationalise their presence across the continent, particularly in light of the ageing nature of many of the refineries themselves. Consultants WoodMac, writing in August of this year, predicted a 9% drop in capacity across Europe in the period between 2022-2023, with clients being sent a list of allegedly under-threat refineries which included BP’s 377,000 bpd Rotterdam refinery, Total’s 102,000 bpd Grandpuits refinery in France and Petroineos’ 200,000 bpd Grangemouth refinery in Scotland. At the same time, Goldman Sachs predicted refinery rates in 2021-2024 to be 3% lower relative to 2019, something which they felt would lead to more competition and permanent closures.  

Although the short term issues may well have been driven by the temporary impact of the pandemic, a study published as long ago as 2017 predicted exactly how things were going to unravel across the oil refining sector, with the key driver of change being a global switch away from fossil fuels prompted by concerns about climate change. The report was published by environment think-tank Carbon Tracker, Swedish investment fund AP7 and Danish pension fund PKA, and while the environmental think-tank might be expected to lean heavily toward predicting a bleak future for oil refining, the investment and pension fund are merely offering a clear-eyed assessment of where they think investors would or wouldn’t be wise to put their money. The report predicted companies such as Chevron CVX.N, Royal Dutch Shell RDSa.L, France' Total TOTF.PA and China's largest refiner Sinopec could see profits from refining drop by 70%, a prediction based on commitments to limit global warming to 2 degrees Celsius, under which, according to the International Energy Agency, the demand for oil would drop by 23% between 2020 and 2035.  

Another prediction is that overall earnings for refiners could fall by as much as 50% by 2035, from a figure of $147 billion in 2015. Given that the recent COP26 committed governments around the world to measures which would hit targets at or around 2 degrees Celsius – depending upon interpretations of the various conditional and unconditional commitments – the direction of travel identified in 2017 has clearly remained the same and has, if anything, accelerated.

Pivoting and Repurposing - with Renewables Front and Centre

The response, across many parts of the oil refining industry, has been to think of ways of repurposing the existing infrastructure in order to ensure that defunct sites can continue to bring in revenue. The obvious answer is to convert what was once an oil refinery into an oil terminal. This is the possibility being explored by ExxonMobil for the Slagen refinery in Norway, with the refinery continuing to operate until any such conversion – currently the subject of a consultation with employees – has taken place. Given that the longer term direction of travel is away from oil and toward renewables, however, the more forward thinking companies are probably those which are pivoting their refinery sites toward renewable technologies. There are examples of this approach from across Europe:

Total is planning to convert the Grandpuits refinery in France – which has been temporarily shut down since February this year – into a biofuels and plastics recycling complex.

Eni is evaluating the conversion of the Livorno refinery in Italy into a biorefinery. This would be the latest step in wider moves to shift the company as a whole onto a more environmentally sustainable footing, with two other refineries in Italy already having undergone a similar conversion. The long term aim is for the company to achieve carbon neutrality by 2050.

Neste, having ceased refining operations at the Naantali refinery in Finland, announced plans to develop the Porvoo refinery – in their own words - "towards co-processing renewable and circular raw materials."

In Germany, the Heide refinery has reduced staff numbers by 106 positions, but is looking to the future with confidence due to plans to change the business model of the plant to concentrate on the production of green hydrogen. 

The Greening of Infrastructure Starts with the Clean-up

We’ve written in the past about the repurposing of decommissioned oil and gas rigs as geothermal energy sites, and the redevelopment of oil refineries that are surplus to requirements follows the same pattern – older, environmentally damaging infrastructure being retained thanks to the role it can play in supplying the environmentally friendlier energy of the future.

At Separo we’ve spent many years earning a global reputation for the excellence and flexibility of our tank cleaning and recovery services. When an existing oil refinery becomes defunct and needs to be repurposed, one of the over-riding priorities is to deal with the remaining waste and pollution left by what have often been decades spent refining crude oil. The solutions we offer can be scaled up or down depending upon the size and scope of the refinery, and can play a key role in helping to ensure that the oil refineries of yesterday help to play a part in the green fuel revolution of tomorrow.

It would be a fairly simple task to produce predictions about the future of geothermal energy based on a combination of gut feeling and an extrapolation of existing trends. Between 2015 and 2021, for example, the global generation of geothermal power was estimated to have risen from 13 gigawatts to 17 gigawatts. It would not seem unreasonable, therefore, to predict a similar rate of growth for the next five years, given that growth over this period tended to involve an increase of one gigawatt initially every two years and then, from 2019 on, every year. There are several factors which caution against taking this somewhat pessimistic view, however, not least of which is the urgency of the on-going search for renewable energy solutions. While debate still rages over whether COP 26 was an over-cautions disaster or a cause for some optimism, there is no questioning the fact that the pressure on governments and corporations to find ways of replacing our existing reliance on fossil fuel is going to become more intense with each passing month, as the impact of climate change becomes something we all have to learn to live with, rather than a set of grim predictions for the future.

According to the International Energy Agency (IEA), geothermal electricity generation grew by just 2% in 2020, a reduction on previous years. While some of this can be ascribed to the impact of COVID-19, it does leave the sector trailing massively the 13% annual growth which the IEA says is needed for geothermal energy electricity generation to meet the targets needed to hit Net Zero emissions by 2050.

Statements of this kind seem certain to introduce even more urgency into the search for new ways to take advantage of the potential offered by geothermal energy, and a survey of recent news stories emanating from the geothermal sector seems to highlight several trends which might point the direction for future travel.

Repurposing

One of these trends is undoubtedly a drive to repurpose assets, sites and technology previously linked to the exploitation of fossil fuel and utilise them to develop geothermal energy. In the simplest form, this involves build on existing drilling technology and the expertise of the workforce currently employed getting fossil fuels out of the ground. The Pivot 2021 conference, held the University of Texas at Austin, with support from the U.S. Department of Energy (DOE), saw speaker after speaker pointing out that the US had a current workforce in the oil and gas industries who, while not necessarily suited to a switch to working in solar or wind power, have the exact skillset needed for drilling down to harness the power of geothermal energy. The situation was compared to the decline of the coal industry across the US, with oil and gas extraction gradually declining and leaving workers looking for other options.

In the US the talk is all about oil and gas workers pivoting to deliver geothermal projects, but here in the UK, with a much smaller historic legacy of oil and gas production (the North Seas aside – of which more later), a project in the North East is exploring the possibility of drilling into disused coal mines in order to extract sea-water which has flooded the abandoned sites. The project, based in Hebburn, involves two boreholes, an extraction hole and a re-injection well, and the plan is for the initial drilling to be completed by the middle of December. Once this has been done, test pumping will take place, and the ultimate aim of the scheme is to produce green energy which reduces existing carbon emissions by 319 tonnes each year. Initially, the plan is for the energy to power Hebburn central council buildings and local tower blocks before eventually being rolled out further in future years.

Another promising UK based geothermal project is located at the Eden Project in Cornwall. Drilling on a borehole started in May of this year and a statement from the project released in November stated that "The well has found its target fault structure and the early signs of high temperatures and good permeability at depth are promising." The current best estimate is that the well could produce heat which would be the equivalent of that needed to heat 35,000 homes.

New Locations

Both of these projects, being UK based, are indicative of the way in which the search for means of exploiting geothermal energy is shifting beyond the established major forces in the field – countries such as Turkey, Indonesia and Kenya which have large and as yet untapped resources – and on to countries which have previously concentrated on other renewables. Another recent example of this phenomenon can be seen in Singapore, where the Energy Market Authority (EMA) announced, in October, that the country would be taking advantage of ‘new developments in technology’ in order to tap into the potential for geothermal energy in parts of the country such as the Sembawang Hot Spring Park and Pulau Tekong. The advances in technology referred to are shifts which enable bores to be drilled deeper than in the past and at lower cost, and would enable the creation of ‘closed loop’ geothermal systems in which pipes pump water deep underground to be heated by travelling through – in this case – a granite layer, before the heated water is driven to the surface and used to generate electricity. A similar scheme to enable exploitation of previously untapped geothermal energy resources has also been announced in Northern Ireland, where a project funded by Invest NI and led by Ulster University with the support of a number of industry partners is currently assessing aspects of geothermal energy in the province. These include the distribution of resources, the utilisation of geothermal energy at the surface, including conversion to electricity, and the legislative and policy framework that would best support an accelerated development of geothermal energy.    

Another country which hasn’t, to date, been regarded as one of the geothermal ‘powerhouses’ of global production, but which is now ramping up development of the technology, is the Netherlands. In the year 2020 the use of geothermal energy in the country increased by 10% when compared to the year before, with this increase being driven by two technological factors. The first of these factors is the improvement in the operation and efficiency of the ‘doublets’ which are in operation. ‘Doublets’ is the Dutch term for well pairs, the geothermal technique which involves drilling two holes into the same source of underground hot water, with one pumping the water up for use and the other pumping cooled water back down to re-heat. Water of this kind is in fairly abundant supply in the Netherlands, with aquifers having been identified during past explorations looking for natural gas deposits. The second factor driving the rise of geothermal energy in the Netherlands is an increase in the number of ‘doublets’, with 3 new doublets on track to go into production during 2021 and more than 40 major projects in the pipeline, to coin a phrase. 

Presently, the bulk of geothermal energy generated in the Netherlands is used for heating greenhouses across the horticultural industry, but the longer term plans of the Dutch government involve a 3% compound annual growth rate (CAGR) in the geothermal energy market within the country between 2020-2025. This will involve the development of deeper geothermal wells, with the energy being used to generate electricity as well as heat. The current goal of the Dutch government is for geothermal energy to meet 5% of the country’s energy demand for heat by 2030 and 23% by 2050.     

One last example from the UK pulls together the themes of repurposing existing assets and tapping into previously ignored resources. It is a scheme, led by the Australian based Legacy Global Green Energy (LGGE), to repurpose abandoned gas and oil rigs in the North Sea as geothermal energy infrastructure. The company claims that there are currently 470 offshore platforms in the North Sea which will become obsolete in the next 30 years as the switch away from fossil fuel gains pace. The cost of decommissioning each platform is estimated to fall between £72.3m and £361.5m, and the bill would have to be picked up by the UK taxpayer. By repurposing the platforms to tap into geothermal energy beneath the sea bed the company claims that it could not only save the cost of decommissioning but also provide employment for the citizens of Aberdeen and Scotland as a whole, and turn the city into a geothermal hub for Scotland, the UK and Northern Europe. 

Dealing with Waste

One question which does still crop up in objections to the idea of geothermal energy is that of the waste products the process generates. The answers to this problem vary around the world. In Cornwall, Lithium rich geothermal water is being recovered from abandoned copper and tin mines. Lithium is a key component in the kind of lightweight batteries needed for millions of mobile phones, laptops and electric cars. Harvesting the lithium from geothermal waters is infinitely less disruptive to the environment than existing methods of sourcing lithium – which tend to involve blasting and roasting solid rock – and while the focus in Cornwall may rest squarely on the lithium itself, a project in Hell’s Kitchen, Southern California combines a geothermal electricity generating capacity of 140 megawatts with the harvesting of lithium from the water which is being used.

Across many existing geothermal sites a company like Separo provides the technology needed to deal with the waste products of the process in the most efficient and least environmentally damaging way possible. By efficiently collecting drill cuttings, for example, we make it possible to re-use and recycle the material involved, while our produced water treatment technology can be installed on site to quickly filter impurities from produced water. The same applies to our slop treatment technology, which recovers valuable drilling fluids and removes contaminants in a way which makes it possible to return the treated wastewater to the environment, at the same time as reducing the overall carbon footprint of a project.

If the news stories of today are any guide, then the future of geothermal energy will be driven by innovation built on the foundation of existing technology, and the desire for more and more countries to harness the geothermal power which rests beneath the earth’s core. As the technology enabling drilling becomes more advanced, and the urgency of the switch away from fossil fuel more apparent, the status of geothermal energy as the renewable that could be a complete game-changer seems likely to grow.

This project was undertaken for a market-leading steel manufacturer based in the UK.

The Project  

Having accumulated a significant quantity of sub-standard and reject iron ore our client was looking for a method of upgrading the ore to a quality that would allow it to be used within the steel making process. 

The Challenge 

For all steel manufacturers, the cost of essential raw materials can make the difference between profit and loss. It is widely accepted that 50% of the cost to produce steel in a Blast or Basic Oxygen Furnace comes from the purchase and transport of iron ore.

In its existing state the sub-standard ore could not be used and was essentially a waste material, degrading over time, taking up valuable space and delivering zero return on investment.

What We Did

Our challenge was to produce a higher quality product that could be of value within the steel manufacturing process. This involved the large-scale dewatering, grading and separating of a dense, variable and highly abrasive slurry. As well as the technical challenge the focus was on the cost-benefit ratio.

We had to deliver a process that was capable of producing usable iron ore at a cost-effective rate. With an unrivalled ability to scale our activities we were able to provide a mobile, robust and high-capacity processing unit.

Value Gained

According to ‘tradingeconomics.com’ the global price of iron ore during 2021 (at 14/10/21) peaked at 230 USD and is currently trading at around 120 USD. Taking an average of 175 USD, 6,000 tonnes of upgraded ore has a value in excess of 1M USD or almost 800K GBP. In addition, based upon the accepted ratio that 1.6 tonnes of iron ore produces 1 tonne of steel we can comfortably claim to have helped our client manufacturer almost 4,000 tonnes of its valuable end product. 

This exercise resulted in the following benefits for our client:

One year into the project we are proud of our health and safety performance with zero accidents or incidents. We have processed and upgraded approximately 16,000 tonnes of iron ore, producing over 6,000 tonnes for reuse in the furnace.     

Every day seems to bring news of another extreme weather event which might almost have been purposely designed to demonstrate the reality of man-made climate change, and most specifically the fact that the impacts are being felt in the here and now rather than some theoretical future.

Given that this is the case, the push for a net zero means of producing the energy the world needs has never been more urgent. This is why renewable sources of energy which make economic as well as ecological sense are sought after across the globe, with the understanding being that those countries which develop the technology of the future will not only find themselves at the forefront of efforts to protect the environment but also in a position of reaping huge economic benefits. All of which helps to explain the renewed focus on geothermal energy.

Geothermal energy occupies the unique position of being simultaneously one of the oldest technologies in the world and also one which is touted as offering the greenest possible future if delivered to sufficient scale.

Geothermal Energy

In simple terms, geothermal energy involves tapping into the heat which is trapped beneath the surface of the earth. In a country such as Iceland the presence of a range of geological factors such as the rift in the continental plates over which the country is located and a high concentration of volcanic activity makes it relatively simple to exploit this energy. This ease of access accounts for the fact that 25% of the country’s electricity production and 66% of its primary energy use is derived from geothermal sources.

The reference to geothermal energy being one of the oldest ‘technologies’ utilised by mankind is a nod to the fact that archaeological evidence points to human beings gathering to make use of natural hot springs – a basic and obvious form of geothermal activity – as long ago as 10,000 years.

The idea that it might offer the greenest possible energy source for the future is based upon the fact that a geothermal energy station, once up and running, can tap into a perpetual source of heat deep below the surface of the earth without having to burn any fuel to either use that heat directly or exploit it to generate electricity.

The issue which currently stands in the way of geothermal energy achieving a wide scale global take-up is, above all else, the expensive nature of the drilling process.

Geothermal Drilling

In geographical locations which offer pockets of what is known as ground source heat – fundamentally heat from the sun which is trapped in the fabric of the rocks themselves – the drilling involved often only has to go as deep as a maximum of 200 metres before tapping into the energy being sought.

In the vast majority of cases the drilling needs to be much deeper, however, in order to access deep wells of heat created by volcanic and magmatic systems heating igneous rocks, or hydrothermal systems involving high temperature water trapped at depth.

Accessing geothermal sources such as these can involve drilling as deep as 6000 metres or more, and it is in cases such as these that the front loaded nature of the capital required to create a geothermal energy plant makes it an investment which relatively few businesses or governments are willing to make. 

Existing Technology

Estimates of the percentage of any geothermal project funding which needs to be spent on the actual drilling of the well (as opposed to the creation of the plant and technology needed to harness the power tapped into) vary, but a figure of 40% was given in a 2018 study into geothermal wells in Turkey into geothermal wells in Turkey, published by Stanford University.

Given that, at the time of the study, there were more than 1000 geothermal wells in Turkey – a country with geological conditions which make it ideal for shallower geothermal drilling – the estimate of 40% is likely to be on the lower side.

Indeed, a feasibility study completed by the Scottish Government in 2016 estimated that the relatively deep wells needed to be drilled in the country would push the cost of drilling up to 80% of the cost of any geothermal project.

The reasons why drilling contributes to such a large percentage of the cost of a geothermal energy project are multiple.

The first of these is time. Geothermal drilling, by its very nature, often involves drilling through the kind of igneous and metamorphic rocks which would be avoided when drilling for oil and gas. Materials of this kind slow the drilling down considerably, pushing the price up to an estimated €2,200 - €2,500 per metre, when compared with the average rate for a shale gas well of €900 per metre.

The longer the drilling takes, the longer the full drilling rig has to be operated around the clock, and this is before the wear and tear on materials is taken into account. The depth and nature of geothermal wells means that utilising the same kind of drill bits and techniques used for conventional drilling leads to greater degree of non-productive time, as the bits are worn or damaged by the stronger and more abrasive rock and drill pipe has to be pulled from the hole for rerunning.

Another factor which leads to the higher incidence of drill bit wear and tear is the intensely higher temperatures at which the bits are being expected to work, as well as seals and additional instrumentation which happen to be nearer to the bit.

Cutting the Costs of Geothermal Drilling

One fact which needs to be borne in mind when considering the expense of geothermal drilling is that the more complex projects not only require a deeper hole to be drilled, but also, in many cases, need two holes drilling in order to function.

This is to enable a process known as enhanced geothermal, in which water is injected into a well, forced through hot areas of rock, and then pumped back put of another well in its heated form in order to generate energy. The presence of two wells, it hardly needs saying, doubles the amount of drilling required.

Many of the suggestions for cutting the costs of geothermal drilling involve altering the drilling technology itself. Down the hole (DTH) hammer systems, for example, use shock to break the rock through the bit, greatly increasing the speed at which the bit progresses - sometimes to as much as 10m per hour.

Various projects are currently underway in different parts of the world with the intention of delivering new forms of drilling technology capable of speeding up the geothermal drilling process even further. These include the utilisation of a plasma arc capable of heating the rock in question to 6000°C and drilling through it without the physical contact required of a bit, or steel shot drilling, which is claimed to make it easier to drill the kind of horizontal shafts which aid wider and more complex exploration of geothermal fields.

Another option being explored by the EU Horizon 2020 program is the use of high pressure water jets and fluid driven hammers to prime the rock for drilling and increase the standard rate of progress from 1-2 metres per hour to as much as 10 metres per hour.

What many of these suggestions share – despite the potential they offer – is the fact that they are still currently in development or, as is the case with DTH hammer systems, still being modified to meet the specific challenges of geothermal drilling.

Costs of Produced Water Management

One solution which can help to cut the costs of any geothermal drilling project in the here and now is the utilisation of the on-site produced water treatment technology pioneered by Separo.

Even without utilising a suggestion such as that put forward by the EU Horizon 2020 program, a geothermal drilling project creates a huge amount of water – ranging from slop and formation water to any rain which falls as the well is being drilled – creates massive amounts of waste, all of which needs to be purified before it can be disposed of and/or recycled and utilised within the programme.

Our SepSORB® systems can be installed in a matter of days and, once in situ, are simple to run and maintain. The huge cost of constantly shipping produced water away from the site to be dealt with is immediately negated, while our expertise in wastewater treatments, dealing with all types of impurities – from sand and mud to saline and anything else which might be present – means that any drilling site can be certain of complying with all relevant environmental legislation at the same time as greatly reducing their own carbon footprint.

Anyone involved in offshore oil and gas production is aware of the problem of produced water, particularly the regulations around hydrocarbons removal.

The large volumes of water produced during the process of extracting the oil or gas from the seabed have to be dealt with, and while the preferred option is re-injection of the produced water into other wells, ultimately the greater part of it has to be discharged back into the sea.

For the purposes of this discussion, we’ll be looking into the issues around the removal of hydrocarbons. No matter what the ultimate destination of the produced water is, the offshore facility has to find some way of dealing with the level of hydrocarbons it contains. More specifically, any facility operating within an area of water that covers the greater North Sea, Arctic waters, the Celtic Sea, the Bay of Biscay and Iberian coast and the wider Atlantic, will find itself having to comply with the standards put in place by OSPAR. This convention, with 15 signatory countries, is aimed at conserving this marine environment.

Intrusive and Expensive Consequences for Failure to Deliver

The relevant part of OSPAR we're examining in more detail here is around the topic of hydrocarbons in produced water for which there is a limit of 30ppm. To regulate on this, the levels in any water to be discharged into the sea are consistently monitored and tested and any facility producing levels in excess of 30ppm will find itself under intense scrutiny. Initially, this scrutiny will involve having to send samples of the produced water to onshore labs for analysis - on a daily basis.

Clearly, using a helicopter to fly samples between a facility and the mainland on a daily basis is an intrusive and expensive process that has the additional effect of impacting negatively on the carbon footprint of the facility in question. Even more damaging to business, if the level of hydrocarbons in the produced water can’t be lowered, all of the produced water being generated will need to be transported to the mainland for treatment before being returned to the sea via an overboard line.

Getting the Filtration Method Right

Of course, in an offshore environment, the most desirable solution is to clean the produced water in-situ, get the levels of hydrocarbons below 30 ppm - and then return it to the sea. This is only ‘easy’ with regard to the clear message around the desired result - get the levels below 30 ppm. However, the level of filtration required is often difficult to achieve and even more problematic when the potentially un-manned nature of an offshore facility is taken into account. Gas and oil producers have a range of obligations to meet. From the regulations governed by OSPAR and the health and safety of their own operatives to the impact of their operations on the environment.

Game-Changing

Making the right choice of produced water filtration solution that delivers the desired results consistently while simplifying and streamlining the process of meeting these obligations, can be game-changing.

Future-Proofing your Produced Water Filtration

Looking at these issues in the round, it's obvious that businesses need a trusted solution for treating produced water offshore.  SepSORB®, developed by Separo's Wastewater Treatment Services (WTS) Division, is a one-pass, plug-and-play, closed system solution that reduces the hydrocarbon content of produced water below 30ppm on a consistent basis.

5ppm to as Little as 1ppm

In practice, the SepSORB® option goes further than bringing the produced water below the OSPAR threshold and instead delivers filtered water which contains 5ppm and often less; sometimes dropping to as little as 1ppm which is, to all intents and purposes, clean water. This not only means that the facilities using SepSORB® are meeting their environmental obligations to the fullest possible degree it also offers full security against the very real possibility that the OSPAR threshold will drop below 30ppm in the years to come.

Plug-and-Play Filtration - Right for This Environment

There are several other produced water filtration methods in use in facilities across the world's seas. Our experience of helping many businesses address the challenges of produced water has proven that SepSORB® is superior in terms of both effectiveness and operation. The operational advantage lies in the fact that the filtration unit merely has to be installed and then switched on. Once this has been done it looks after itself until such time as the filter has to be replaced. As an example, a client in the Dutch sector previously utilised a twin system onboard requiring cartridge changeouts every second day. Following the introduction of our SepSORB® system this handling was significantly reduced with the SepSORB® filters lasting months before requiring any handling for change-outs.

The alternatives often require varying degrees of manual intervention – whether that means adding chemicals to break down the oil in the water or donning full hazmat gear in order to undertake the unpleasant task of cleaning out and replacing the cartridges. It's hugely problematic in the context of an offshore facility, especially one intended to be operated remotely. From ensuring the safety of personnel on the facility while carrying out these tasks to transportation costs alone there are clearly several advantages to the plug-and-play option. In terms of the operational advantages of SepSORB®, unlike alternatives that require high powered pumps to force the produced water through membranes, the system can operate at full effectiveness with a standard pump.

Complex systems are often used that require constant and homogenised fluids, the SepSORB® system is very flexible and can cope with peaks and fluctuations.

Behind this staggering result of 5ppm or less in the filtered water, is the use of a special blend of SepSORB® media which attracts and retains the hydrocarbons, allowing only the much cleaner water to pass through.

Customisable for Individual Operational Needs

In simple terms, SepSORB® is an ideal solution for produced water filtration. It's a system that can be tailored to suit the facility itself, is self-contained, requires little manual intervention for cleaning and changing filters, and delivers consistent, dependable results. It is also available in a range of sizes depending upon the capacity of the facility on which it is installed, and if needed, can be fitted with pre-filters designed to weed out the heavier solids often present in produced water.

When the time comes for the saturated media within the system to be replaced, it can be recycled for re-use, while the "waste" material persisting on the outer shell of the original filter – having been heat-blasted and removed – can be repurposed as a recycled form of heating fuel. 

The SepSORB® vessels are easy to swap. When the valves are closed and the pressure is taken off, the vessels can be uncoupled via Camlock couplers, taken away and replaced with new ones. The new vessels can be connected via the couplers ready for use again.

In short, SepSORB® offers a chance for oil and gas production operations to avoid the kind of damaging, intrusive and expensive scrutiny which comes as a result of failing to filter hydrocarbons from produced water correctly. It not only gets the job done, but it also gets the job done simply, operating in a plug and play manner and performing remotely - without the need for manual intervention.

If you're currently dealing with daily inspections of produced water this alternative solution is worth considering. You'll be in good company. Compulsory inspections will reduce as SepSORB® begins to turn the tide on the problem, dropping to weekly and then monthly intervals - leaving your operation to get on with the job in hand – much like SepSORB® itself.     

Produced water is a complex mixture of organic and inorganic compounds and is the largest volume of byproduct generated during oil and gas exploration and production.

Natural (or formation) water is always found within petroleum reservoirs that are routinely accessed via a well. The water is slightly acidic and sits within and below the hydrocarbons in porous reservoir media.

A well is a boring in the Earth and is generally created for the purposes of exploration, appraisal, production or injection.

Exploration

For an exploration well the geological target is chosen to confirm the existence of a viable hydrocarbon reservoir or to verify its extent.

Production

For a production well, the target is picked to optimise production from the well and manage reservoir drainage.

Injection

A third objective is established for the injection well, typically used to locate the point of injection in a permeable zone, which in some cases may support disposing of water or gas and/or pushing hydrocarbons into nearby production wells.

Produced Water Treatment

As produced water is generally contaminated (which varies from well to well and even over the life of the same well) it is classified as an industrial wastewater. In some cases, it may be re-injected, but this is not always an option. Therefore, there is the ever more common requirement for appropriate, environmentally compliant and cost-effective treatment.

Due to remote locations both onshore and offshore and the relatively large and continuous volumes produced, it is incredibly expensive to ship and treat produced water at a facility located elsewhere. Moreover, transporting these volumes has an adverse environmental impact.

Consequently, it is more attractive (financially, operationally and environmentally) to treat and dispose of produced water at source.

Produced Water Handling Offshore

A perfect example of this approach to produced water treatment is found 150km off the coast of Lincolnshire, UK. Operated by Neptune Energy, the Cygnus complex (which consists of two installations, Cygnus Alpha and Cygnus Bravo) has been producing gas since December 2016 and is now the largest single producing gas field in the UK, contributing around 6% of the country’s domestic gas demand.

The Cygnus Alpha installation consists of three bridge-linked platforms: a wellhead drilling centre (for extracting gas), a processing/utilities or PU unit (for processing and exporting gas) and a living quarters/central control room.

Gas from the Cygnus Field is exported via a 50km, 24" pipeline connection to the Eagles Transportation System (ETS). To meet the ETS entry specification the gas is processed via the PU unit, a process that includes:

• Separation (2 Trains)
• Condensate handling (2 Trains)
• Produced water handling
• Gas compression (2 Trains)
• Gas dehydration

Treating Produced Water At Source

Over a number of years, Separo's SepSORB® wastewater treatment system has successfully reduced hydrocarbon content in produced water on the Cygnus Alpha installation. By treating the water at source, our clients are able to meet regulatory and contractual demands, lower their carbon footprint and reduce costs.
The SepSORB® system meets the needs of operators who were asking for a compact, unobtrusive and efficient method of produced water treatment in isolated and often unattended locations.

A modular, plug and play system with a small footprint is perfectly suited for use on rigs, platforms and installations where space is at a premium. Because it has no moving parts and removes contaminants with a single pass and on a continuous basis, it operates without personnel which further increases its appeal to rig and platform operators.
Efficiency is key in the oil and gas sector, and real-time monitoring of input/output water quality provides the analytical data required to enable the system to be adjusted, optimised and effectively tailored to the specifics of almost any wastewater stream.

The SepSORB® units are designed to remove contaminants such as:

• Emulsified oil
• Volatile Organic Compounds (VOC)
• Benzene Toluene Xylene (BTX)
• Chromates
• Organo tin
• Poly chlorinated benzene
• Poly acrylic hydrocarbons

On-site sludge treatment is a process which saves time and money, reduces waste and makes it much easier to recycle vital resources.

About Our Client

Our client for this project is an Operator in the UK sector of the North Sea.

The Challenge

Our client was experiencing challenges with produced water contamination on a North Sea platform. Separo was approached to deliver a solution to reduce Oil in Water (OIW) content to meet the Operators internal targets and ensure environmental compliance.

The Operator was recording produced water contamination in excess of 1000ppm during startup, and in excess of 30ppm during normal operations. They were motivated to reduce the OIW levels to ensure environmental compliance and meet their own internal corporate standards.

Successfully reducing OIW levels would also avoid the risk of enforcement action from the environmental regulator, ensuring no impact to production.

What We Did

Through close collaboration with our client, we were able to provide an effective solution capable of handling high levels of contamination and flowrates of up to 40 m3/hr. Following the presentation of our solution and subsequent HAZOP, our SepSORB® system was approved for installation. Separo supplied all hoses and fittings to tie into the receiving point and the discharge point, along with a pre-filter system and the SepSORB® filter vessels.

A Separo Filtration Specialist installed the equipment and provided training in its operation to the platform's core crew.

Value Gained

Separo’s SepSORB® systems are effective in reducing OIW content to levels below 5ppm in a single pass. SepSORB® has enabled the platform to treat produced water at source, meet environmental compliance and continue with production.

The system was inspected by the environmental regulator who provided positive feedback that the Operator was meeting their obligations, allowing them to progress within the terms of their licence.

Project Statistics

Separo’s produced water treatment at source solution has enabled the Operator to meet environmental compliance and reduce their carbon footprint.

Some additional benefits gained by our client are:

• Plug-and-play system with no media handling, safer for platform personnel.
• Water treated at source, reduced transport costs and emissions.
• System can be scaled up to suit client requirements, OIW levels in excess of 1000ppm successfully treated.
• Reduction in sampling required on platform.
• Reduction in operational resources required to monitor OIW.