Gas Trap

I’ll use this tweet to kick off a post about associated gas:

When you produce crude oil through a well, it’s not just oil that comes up. You also get mud, water, gas, and certain nasty substances. The water is called “produced water” for obvious reasons, and the gas “associated gas”. This means it is associated with oil production, which distinguishes if from a field which is developed purely for its gas reserves (in which case it’s called unassociated gas).

The problem of what to do with associated gas is one that has plagued the oil industry since its founding. Produced water can be treated and put back into the sea or a water course, but you can’t do that with gas. Until a decade or two ago, oil companies would simply burn it off, which is why old pictures of oilfields showed enormous flares lighting up the entire region twenty four hours a day. This pumped some pretty nasty substances into the local environment, but important people only really got concerned when global warming came along and they started looking at how much CO2 was produced by this practice. So what is known as “operational flaring” got severely restricted or banned in most places. The tweet above is referring to the ongoing practice of operational flaring in the Permian basin, the home of the US shale revolution.

One small point before we continue: you still see flares on modern oil and gas facilities because they are part of the process safety system. If you have a problem on your plant, the option of last resort is to dump all your inventory to the flare and let it burn. It’s not good, but better than blowing up the whole plant, taking the neighbouring town with it. So this is why you still see a small, lazy flare burning at the top of a stack in a refinery: it’s burning fuel gas, just to keep it lit for when it’s needed. This is completely different from operational flaring.

So if you can’t flare the associated gas, you have two options. You can reinject it into the reservoir, either to increase reservoir pressure to aid production or just to stop it being emitted to the atmosphere. If that’s not possible either because the reservoir engineers will get upset or, in the case of shale, there is no reservoir, the other option is to monetise it somehow (which might be attractive even if you can reinject it). In many developments, this means running a pipeline to an existing gas plant. If your oilfield is close to other developments, this is often possible. LNG isn’t really an option with associated gas, but you might be able to build a gas plant providing power to local homes and businesses if there is a population centre nearby. Another option is an LPG plant where the gas gets treated and bottled and then trucked to a nearby population centre. I’ve heard of oil companies talking about giving away gas stoves to locals in order to create a market for LPG, but I’m not sure if it was ever done.

The problem comes when none of these options are feasible. I’ve been involved in lots of new development studies at the preliminary stages and the question always arises: what do we do with the gas? One project was in Kurdistan, miles from anywhere. The intention was to produce crude, store it in those huge tanks you see beside refineries, and then pipe it to a refinery or terminal somewhere or offload it into trucks. But we didn’t know what to do with the gas, and there was a lot of it. We couldn’t reinject it, and there was no population centre nearby. We then discovered the gas was full of nasty substances so when we crunched the numbers we’d find we’d be spending X of CAPEX to produce oil and 2X processing the associated gas, and then not knowing what to do with it. So the project got binned: too expensive.

This is why they still allow operational flaring in the Permian basin. It’s not good for the environment, but if it were banned there would be no shale revolution, the oil price would still be above a $100 per barrel, and I might still have a career. One option, and I don’t know how feasible this is without looking at the area in question, would be for the government to provide incentives to all players to build a central gas processing facility which could take all the associated gas and do something with it. But that might face all sorts of regulatory hurdles, let alone the pipelines associated with such a scheme. So they’re stuck between a rock and hard place: force them to dispose of the gas or charge them for emissions, and you’d kill the industry and America’s new-found energy independence. I expect we’ll see several battles played out over this issue in the years to come.


23 thoughts on “Gas Trap

  1. Shell have an ideas box called Gamechanger where staff can leave behind ideas that then go through a triage process towards rejection or delivery. I left an idea about Mini Gas To Liquids that only got so far before it died (too small scale to be of interest). We know that via Fischer Tropsch process one can turn AG or NAG into liquid fuels – but generally this is only good at large scale (witness Qatar GTL). My idea was to squeeze the plant into a single shipping container! Feed the gas in one end and get liquid fuels out the other. This might be a viable business model for someone with capital at the smaller end. The chemistry / chemical plant designs are already there and just need to built at the mini scale.

  2. “America’s new-found energy independence. I expect we’ll see several battles played out over this issue in the years to come.”

    For shale gas flaring I think the yanks will continue to do as the article states, fuck all. The market will take care of it with more distribution to get it to market, which is increasingly looking like export. There is a boom on now with building of new LNG ships. I havent seen the composition but I am guessing that is at sales gas spec ie clean and its just a CO2 whine.

    No one predicted where the US would be with gas as recently as three years ago, now a major exporter and even on the most conservative estimates continuing to grow rapidly and will be up there in the top three exporters of natural gas if not the biggest in the world. Europe can now seriously consider buying US liquefied gas.

    Thank God for the yanks driving the market price of gas down, electricity is still going up though because of subsidies for renewables and the war on coal. Remember when we liked coal and what the price of power was. The biggest driver of gas growth is for power generation.

    This US shale thing is only getting started, its mind blowing what they have achieved and in my opinion the trajectory will continue. That is the story here the market will take care of this wasted gas well before any regulator nobbles the industry.

  3. Why would the TXRRC (Texas Railroad Commission) issue flaring permits to oil and gas producers? I would have thought that would come under the TCEQ (Texas Commission on Environmental Quality) who do the monitoring, permitting, and such, for air, water, and waste in the state of Texas. And I thought the TCEQ was limiting flaring permits. I could be wrong.

    I know they’ve been building new pipelines in TX, but not sure where. as well as enlarging port facilities for export. So I also think the market will figure this out before the enviro bureaucrats start crippling the industry.

  4. “We know that via Fischer Tropsch process one can turn AG or NAG into liquid fuels ”

    Why be so complicated? Gas to fertilizer is essentially gas plus atmosphere. Waste gas to ammonium nitrate should be possible on small scale. Heck, I even know someone who would give us the money for a pilot plant if the tech even vaguely existed.

    I’ve seriously, seriously, wondered for a long time why people aren’t doing this. Presumably because it doesn’t work for some reason at which point, OK, what is it?

  5. A great post. Everyone should have an idea what field flaring means as opposed to the safety flares, say, at refineries.

    The 700 mmcfd number isn’t shockingly new – Rystad estimated flaring and venting in the Permian at 660 mmcfd in 1q19. Bakken is burning a little less, 500 mmcfd or so. In the big picture, the combined 1.2 bcfd isn’t that big – the US is expected to produce 90 bcfd of dry gas this year.

    The market is taking care of Permian gas already – Kinder Morgan plans to open two 2-bcfd gas pipelines to the Gulf this year. Not sure how wet gas is going to be treated though.

  6. This tweet is pertinent. As I said, I don’t know much about Permian:

  7. That is the story here the market will take care of this wasted gas well before any regulator nobbles the industry.

    I expect so, yes.

  8. witness Qatar GTL

    I never quite saw the purpose of that project, other than believing the rumour that Shell had to do it in order to get back into Qatar’s good books having upset them previously. It seemed a colossal effort to produce…what? Clean diesel?

  9. It would be useful to see the figures from a less partisan source than Deon Doughtery’s investigation. Every resource owner and every producing company is working hard to maximize net revenue. No-one flares gas unless that is the economically rational decision (as Tim points out). The current issue of E&P Magazine includes a map of Upstream & Midstream Permian Basin — there are already a lot of gas processing plants, and more are being built.

    As a side note to this, it is worth remembering that the Piper Alpha disaster (killing over 100 human beings) in the North Sea was ultimately caused by the efforts of the usual suspects to stop gas flaring. When Her Majesty’s government initially approved the Piper field development, the UK was bankrupt and needed the oil revenue ASAP; thus, flaring of associated gas was permitted.

    Later, when the UK government’s finances had improved somewhat, the usual suspects changed the rules to require the operator to stop offshore flaring. But at the same time, the UK government had made itself the monopoly buyer of gas, and refused to pay a sufficient price to make it economic to handle the gas. The compromise was a gas facility shoe-horned onto a platform which had never been designed to handle it — a facility which later blew up. Once again, environmentalists had blood on their hands.

  10. Tim Qatar GTL cost a fortune and came in late and ramped up slower than plan. But it’s a complete cash cow now. Supports the dividend. Some of the most profitable lines are waxes and greases so pure you can eat them. Literally. Much in demand across the food industry. Likewise the fuels which burn very clean.

    Tim W what is the chemical reaction for CH4 plus N2 that gets us to fertiliser? Is it exothermic? Fischer Tropsch can be powered by burning the gas. Tim N’s gas problem will only work for a gas conversion reaction that is self powering.

  11. How impractical is it to pipe the gas to shore, and shove it through some big gas turbine generating sets for some free electricity?
    Gas turbines are cheap and can usually be made to run on any old muck, and it’s probably not totally beyond the whit of man to scrub the worst of the nasties out of the exhaust gas.

  12. “I’ve seriously, seriously, wondered for a long time why people aren’t doing this. Presumably because it doesn’t work for some reason at which point, OK, what is it?”

    I was involved with the construction of the MAP/DAP fertilizer production plants at Phosphate Hill in Queensland, it was built to a Mistsui process design. This was a very big deal at the time, it may have been the biggest fertilizer plant in the world when it was built in the middle of nowhere. It wasn’t as simple as gas with environment equals fertilizer though. The plant location was chosen based on three major inputs, phosphate rock, natural gas and sulphuric acid, the actual produced fertilizer was then transferred 1000km to a storage and distribution facility at Townsville, where it was then sold to market mostly by train loaders.

    The chosen location in the middle of nowhere adjacent to Phosphate Hill (fossilized bird shit) in Qld. A gas pipeline lateral was built of the Mt Isa transmission line to feed gas to the plant, some gas turbines for power were also built there. The sulphuric acid was supplied from a new scrubbing facility at the existing Mt Isa Copper mine whereby the sulphuric acid by product of the existing copper smelting was further processed into a liquid state as opposed to a gaseous airborne waste with the benefit of reducing the very real and serious air pollution issue of the quantity of sulfur dioxide in the Mt Isa township atmosphere, this liquid acid was then transported to the plant four hours away.

    We also built the fertilizer storage and distribution facility at Townsville where we had a terrible problem with corrosion of the structures when airborne fertilizer dusts settled on steel and in combination with the humidity of the coastal air, became a live battery and corroded the plant rapidly and violently. We came up with a pretty neat solution for that as well but that is another story.

    So to answer your question I think the economy of scales and the inputs required to produce fertilizer are such that a mini trailer mounted skid type plant would not be viable.

  13. “The chemistry / chemical plant designs are already there and just need to built at the mini scale.”

    I have also had some exposure to the Fischer Trop process albeit at a slightly larger scale on the ill fated Linc energy pilot plant in Chinchilla Qld. This was gas to liquids, with the homogenized synthetic gas being produced from partially combusted underground coal, piped to the surface where it was liquefied and trucked to market.

    Interestingly enough most of their technology was derived from earlier process work of this type done in the Donbass coal fields region in Ukraine, where the commercial production of synthetic gas was actually viable and supplying the market in the mid nineties. Note it is different from Sasoil as the syn gas is produced underground and not on the surface.

    Again and just like fertilizer production I would say that economies of scale would be prohibitive to your suggested containerized solution.

    What I do think is commercially viable and the necessary technology available now such that it is something that I will see in my lifetime with respect to adding value to waste or excess natural gas, is the reforming of it into pure hydrogen.

    For mine, this would look something like an existing or lateral pipeline being routed to a nuclear power station or other major existing plant that has a super-heated steam by product. The methane is then reformed with the addition of supported steam to produce pure hydrogen.

    This is the logical end point of our continued effort to simplify the hydrocarbon compounds ie make them cleaner, by removing carbon that we have seen over history with the use of wood, coal, oil, gas and eventually the removal of all carbon molecules to produce pure hydrogen in our quest for energy efficiency. This will signal the advent of the hydrogen age.

  14. “”How impractical is it to pipe the gas to shore, and shove it through some big gas turbine generating sets for some free electricity?”

    Not impractical at all, bearing in mind that Tim’s example is for clean gas onshore though. There are many examples of what you have suggested in place and working now that I am aware of in the coal mining sector.

    Coal mining and coal seams have a residual quantity of methane gas that is produced and needs to be controlled more so as a hazardous atmosphere measure ie combustive and oxygen deficiency for miners safety. Prior to the greenhouse gas control days, this methane would be captured and “drained’ or vented directly into the atmosphere, such that there was no explosive risk or oxygen depletion risk to the miners.

    Nowadays it needs to be captured and dealt with. There are many busted ass schemes whereby this gas is captured and used as a fuel source for a beaten up generator on the surface that provides power to the mine site, reducing the need for it to draw down from mains supply or generate its own, the generators are skid mounted and are simply dragged around once the methane is drained and off to the next new coal seam location on the mine site. It is also possible to feed this power back into the mains but not sure if this is in place given that most coal mine sites are in the middle of nowhere.

    On a more sophisticated and larger scale there are many schemes at various stages of development in Indonesia. The one that a firm that I was working for were approached on about seven years ago was very beneficial and value adding to the coal mine owners. I have no idea if it got legs but in theory it was sound, we never got involved, to early, to risky after the QLD experience, plus the Indonesian factor. I have worked in Indonesia in the good old days when you could use expats.

    Most of the worlds underground gas to liquids or gas to energy gurus of the day were located in Queensland in the noughties. Once the greenies forbade it, a lot of them relocated to Indonesia which has shit loads of proven unconventional gas resources and development friendly regulators.

    The specific scheme that we were invited to participate in was for the value add of underground coal gas to energy on an existing coal mine site. The syn gas produced underground, would be piped to the surface to fuel permanent gas turbines that would provide all of the existing and very large coal mines power needs and the surplus power would have been fed back into the power hungry mains network.

    Not only does the mine reduce or remove its power costs and get paid for power supply back into the network, it also massively increases the mines asset value with this new found existing resource, infrastructure and increased cash flows.

    Win win, whether it got up, I dont know but if it didn’t them it may have somewhere else and if not, its only a matter of time until someone does it in Indonesia.

  15. “I expect so, yes.”

    I think that the US Congress may also expect so as well, as the geopolitical energy supply scenario in Europe is quite compelling.

    So Europe is an imported gas dependent region with 50% odd of its gas needs imported and rising, the yanks are flogging theirs there now and the evil Russians are having to drop their price below them to compete.

    U.S. Natural Gas Exports To Europe Soar Nearly 300% In Nine Months

  16. theProle asked: “How impractical is it to pipe the gas to shore, and shove it through some big gas turbine generating sets for some free electricity?

    Not impractical at all. It is done all over the world — when it makes economic sense. However, first someone has to pay for conditioning the gas to put it into a pipeline (eg remove water that would cause corrosion & leaks); then pay for the pipeline to shore (not cheap); then pay for the generating sets onshore and all ancillary facilities; and then pay for the staffing, maintenance, inspection.

    By the time someone has done all that, you know it is not “free electricity”. For comparison, wind and sunshine are free — but electricity generated from those sources has to be heavily subsidized because of the high capital and operating costs.

  17. Bardon: “Coal mining and coal seams have a residual quantity of methane gas …”

    Coal Bed Methane (CBM) — for some reason, Australians seem refer to it as Coal Seam Gas (CSG) — has been a major source of gas in the US for over 30 years. It is a good example of resource owners and operators working hard to maximize the value of their natural resources, by converting the problem of explosive gas in mines into an economic opportunity.

    Arguably, it is also an example of the benefits of private ownership of resources — in that CBM seems to have been much more successful in the US where minerals are often privately owned versus other countries where the Political Class controls minerals, nominally on behalf of the citizens. The greater success of unconventional oil & gas development in the US versus elsewhere may point to the same issue.

  18. “Coal Bed Methane (CBM) — for some reason, Australians seem refer to it as Coal Seam Gas (CSG) — has been a major source of gas in the US for over 30 years.”

    Yes and also not to be confused with shale gas or fracking either. We also do refer to it as CBM when draining coal seams, but CSG has taken the forefront as that is where all the action is and is feeding three QLD LNG plants as well. Which has played a big part in Australia now pipping Qatar as the biggest exporter of natural gas, although I see a day when the US will take the world lead in this measure.

    The CSG term was coined in Queensland, I was in that space at the time and also when the big guys like BG & Shell et all came in and bought up all the small payers that were working it, they were our clients at the time, we hated it and many multimillionaires in our original client teams were created overnight. Think farmer type, not even qualified engineers, nice blokes with it, receiving $3m+ windfalls overnight. All we got was client poms reporting to Peterborough that wanted to take a North Sea approach (I have worked there) to onshore low volume, low pressure, high quantity, CSG fields in central and remote Queensland and sack the Aboriginal elders that provided us with culture heritage cover. They learned the hard way.

    This all took place after the decision not to proceed with the gargantuan PNG to QLD gas pipeline project was made, I was working on that project and had my retirement planned at the moment it was shit canned. Had just returned from a week in Tokyo with the Exon Mobil buyers and all the letters of intent for the line pipe orders ready to go and the Project Director called us in on the Monday morning when we got back to the Brisbane office and said that the project was off!

    This meant that there was a huge looming gas shortage in the eastern states of Australia with its conventional sources in the Bass Strait and Cooper Basin and the like running down and having nothing like the growth potential that was urgently needed for industry and domestic demand. WA still has the abundant NW shelf conventional fields which are also gas to liquids export as well. This was a huge shot in the arm for the development of unconventional gas in QLD. NSW has had limited development and I think that the current CSG moratorium in NSW may still be in place.

    What was pioneered and developed in Queensland and don’t let any Texans tell you different, was a drilling method called Surface-in-Seam SIS drilling. To exploit the gas from coal seams, in non mining areas, clever HDD leaders of the day developed a process where you could literally drill down vertically until you reached the coal seam depth. Once at that level of narrow seam, the driller could then traverse the drill head on a 90 degree bend and then work up the horizontal seam, with a guidance device that was walked along the surface above the drill head, that is surface in seam drilling and then it became known as Coal Seam Gas, which does not involve fracking either. This technology was also first used in the UK in Stirling by an Australian company, I actually know the drillers that were there they are Aussies we recruited them.

    I also knew Alan Campbell (“Mate,” said Allan Campbell, the firm’s Australian founder, in an interview last month, “we are getting smashed.”) and JV’d with him on many projects, he was the mad Aussie kicking it off in the UK that was sacked after he had a tell all interview in the Telegraph about the benefits of wine women and song. His firm Lucas drilling (part owners Caudrialla in the UK) were heavily involved in the development of SIS technique in Australia which was first used in the UK by the Australian company Mitchell drilling in Stirling.

    Not sure if CSG technology is in use or being commercially exploited in the US, why would you when you have shit loads of conventional and shale gas anyway.

  19. Tim,

    Thanks for the oil industry article.

    I absolutely hate seeing things go to waste, so was appalled by those pictures I saw of oil wells flaring off huge quantities of what looked like perfectly good natural gas. But your piece confirms what I suspected: that recovering and using that gas usually isn’t economic, at least not with current technology. After all, if it were, the oil companies would do it, greedy, profit-obsessed entities that they are.

    Reading the other comments, I have to say your other contributors seem to have worked on some very interesting projects.

  20. This was a very interesting and informative post. I cannot comment on any of the oil industry or chemical engineering aspects of this post as that is not my field. However I’d like to comment on Tim’s mention of companies creating a market for LPG and one effect this might have had.

    As someone who has recently purchased a gas cooker I noticed that at least 25 to 35% of the gas cookers advertised came with LPG conversion kits as standard. There was no extra charge for the additional LPG fittings. I wonder if these additional fittings are being subsidised in some way by gas producers / distributors as to make the purchase of a cooker with LPG facilities more attractive to the consumer?

  21. I would suggest that having an LPG conversion kit is simply a low cost feature that provides a supplier with a wider customer market. Not sure where you live or whether it has mains gas or not, if main gas is available you would normally not use LPG. In areas with no mains gas then LPG is probably the only type of hydrocarbon fuel to be used for domestic cooking and heating and it makes sense that the customer has a normal gas cooker with some LPG bottles hooked up from the outside.

    LPG is common in Africa and is also far less hazardous than using wood or coal for heating or cooking indoors from an airborne pollution point of view.

    In Australia LPG is quite common in the more regional areas that do not have main gas supplies. You could of course go for electrical cookers and heaters.

    I have mains gas and my cooking and heating are by gas, I have an external big barbecue setting out the back that is main gas and a smaller portable Webber that is LPG ie I use bottled propane LPG to fuel it.

    We also have LPG vehicles in Australia but they are now very much in decline.

  22. Regarding theProle’s comment on July 16, 2019 at 8:24 pm:

    In the UK, the natural gas produced from Cuadrilla’s well at Elswick has been used to generate 1MW of electricity on site continuously during its early life. Gas extracted from the sandstone formation was sent to a small onsite generator, and electricity generated fed into the electric grid via underground cables. Natural gas rates have been declining over the producing life and the well has now approached the end of its producing life.

    Located off the main road into Elswick, the site is visually unobtrusive, with many people in the area unaware of its existence.

    Piccies are shown on the link:

  23. Really interesting post and comments. Would love more content like this in future…

    Thanks to everybody for sharing!

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