The Oil and Gas Technology Centre (OGTC) is calling for technologies to transform how we develop the remaining UKCS hydrocarbons. That prompted me to think about transformational technologies I’ve seen in my 40-plus years as a chemical engineer. Could we learn from past innovations?
Three areas stand out.
Extended Reach Drilling
Extended reach drilling has done more than any other technology to transform the development of oil and gas reserves. Horizontal wells have made a huge contribution to reducing costs and increasing drainage from a single well. When I started in the industry, high angle wells were new and the furthest that could be reached was about 5,000metres.
I have been involved with the development of many oil and gas fields and have two standout examples where the horizontal well delivered a transformation. They were both in the 80s.
Firstly, I was working on the Harding field for Britoil and the concept was two drilling centres – a North and South Platform. At the time horizontal wells were in their infancy, but the drillers thought that by the time the two platforms were installed, horizontal wells would be proven technology. The adoption of horizontal wells meant they only needed one platform, instead of two – an enormous cost saving.
Secondly, when working for BP, further development of Wytch Farm’s Sherwood Reservoir was under investigation. Sherwood extended into Poole Bay off Bournemouth. It was not thought possible to drill from shore and reach the production zones. The creation of an artificial island with a drill rig and processing plant was the preferred concept. However, creating such an island within view of the shore was viewed as a very difficult concept from a permits and consents viewpoint. The visual intrusion was expected to arouse fierce local objections and was therefore a very real risk to project viability.
It was proposed that the remote parts of the reservoir could be reached by long horizontal wells drilled from shore. This strategy meant the artificial island concept could be dropped, the project was de-risked and successfully developed with land-based extended reach wells. Indeed, for many years, one of the wells held the world length record at over 10,000metres – inconceivable in the early 80s.
Floating Production, Storage and Offloading
Coming from onshore petrochemicals, the first time I saw this concept I thought – what, you’ve put the processing plant above the tank farm? Onshore tank farms are kept a considerable distance from hazardous processing facilities, not something you can do offshore.
The FPSO concept is testament to safety engineers’ ability to identify and manage hazards. Advances in hydrocarbon release and fire and explosion modeling allowed this concept to be designed to minimise residual risk, making possible the development of fields that would have otherwise remained commercially stranded.
In the early 80s I recall mentioning the subsea option to my then-engineering manager, a Texan at the British National Oil Company (BNOC). He said: “Tom, wellheads should be where God intended – where you can touch them”. At the time he was correct, our ability to model complex flow and chemistry interactions in long distance, subsea pipelines was too basic.
But subsea was seen as a transformational technology and significant effort and funding was released to help deliver the understanding required to de-risk the concept. I managed an R&D budget for BNOC/Britoil and spent a large part of my career on developing flow assurance technologies. Thirty years later, as technical director of Genesis, the tools my engineers have to analyse subsea flow assurance are jaw dropping. As we know, for the past 25 years, subsea has been the basis for most new UKCS developments thanks largely to a transformational understanding of the physics and chemistry going on inside subsea pipes. For example, Total’s Laggan-Tormore development would not be possible without advances in flow assurance.
I also have to comment on the transformation that computer aided design has delivered. As someone who started his first job at ICI Petrochemicals with a desk complete with a slide rule and log tables, the computational abilities of a desktop PC are astonishing. Used efficiently, software has transformed engineering design. However, we often use computing powers to do a lot of unnecessary things very quickly. In my view, coming from a generation where we could see the design methods we were following made for a greater understanding of processes. The methods used today are embedded in computer code that we don’t see, thus rendering insight more difficult.
The Next Leap Forward
So what might the next transformational technology be? The Murchison Field was recently decommissioned, leaving about 30% of the original oil in place. That’s about 250million barrels, an accumulation much larger than anything we are likely to develop or find in future. This will be the same for most of the first and second generation mega fields, for example, Ninian, Thistle and Dunlin, after cessation of production. Can we afford to leave so much oil in the ground?
For many years, industry has researched a range of enhanced oil recovery (EOR) techniques to produce some of this oil. This work includes the use of polymers, surfactants, adding heat and injecting high pressure gas. The effectiveness of these techniques is limited and they tend to be expensive.
There is though, an EOR technique that appears to have been given little attention; microbial enhanced oil recovery (MEOR) – the use of microbes to help release the trapped oil. One microbial technique that would be truly transformational is the use of methanogens to transform the trapped oil into methane (natural gas). Methanogens are present in the stomach of ruminants producing methane in cow farts, and in wetlands.
How would it work in an oilfield? Firstly, a methanogen capable of withstanding oil field conditions and eating oil and making gas at a rate that would make the process viable would have to be developed, which would be no mean feat. But assuming success, prior to cessation of production, the field would be flooded with the methanogens and nutrients. The microbes would colonise the oilfield and metabolise the trapped oil converting it to methane.
More mobile methane would migrate upwards, accumulating as a large gas cap. The gas cap would be then produced through the existing infrastructure.
It is a potentially low cost, highly effective hydrocarbon EOR recovery option for a mature province like the UK.
But where would funding come from? The OGTC has £180million to spend over the next 10 years. That sounds like a lot, but it is only the price of two or three complex high pressure, high temperature production wells. Supplemented by industry funding and spread over a range of R&D areas, will this funding be sufficient to progress a transformational technology?
When I recall the UK’s funding of subsea technologies in the 1980s, the answer would have to be … no. At that time, the development of the required flow assurance technologies was taking place in a number of centres like the Atomic Energy Authority, Imperial College, British Hydromechanics Research Association, National Engineering Laboratory, and the Strathclyde and Heriot Watt universities. Projects were initiated with typical investments of five and six figure sums. Although I can’t be sure, I would estimate the total UK subsea and flow assurance R&D spend to be less than £50million during a five year period.
Norway did the right thing and invested more. The old adage “you get what you pay for” springs to mind as Norwegian flow assurance models and subsea hardware now dominate the market.
If we do identify a transformational technology, let’s fund it properly.
Tom Baxter is a senior lecturer in chemical engineering at Aberdeen University
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