Natural Gas : Proving the Proved Reserves

In looking at the pathways and timelines for a transition to the use of Renewable Gas, it is necessary to consider the current and future position of Natural Gas within the global energy system.

Hydrogen is climbing up the ladder or flagpole of attention of late, as is the debate about the relative merits of a rainbow palette of hydrogens : from fully renewable hydrogen – known almost universally as “green hydrogen” – to so-styled “blue hydrogen”, which is essentially utilising Natural Gas to make hydrogen in some way, whilst at the same time permanently sequestering the carbon that is left over.

If the blue hydrogen strategy is to succeed, clearly, progress needs to be made in CCS – carbon capture and storage – as the continued use of fossil fuels must be accompanied by “carbon repatriation” to the long term carbon storage of Earth.

Perhaps more importantly however, there needs to be confidence in the longevity and chemical quality of Natural Gas supplies, and it is for this reason that I have recently re-visited my inspection of proven Natural Gas reserves.

Reported data is sometimes a bit nebulous. For example, some entities report only dry gas – Natural Gas that comes from gas-only reservoirs – also known as non-associated gas. As for the Natural Gas that is associated with liquid fossil fuels, it is often just lumped in with a total of hydrocarbons. I suppose this is because it does not make any sense to report it separately : Natural Gas that is associated with oil and Natural Gas Liquids (NGL) deposits is probably only going to be mined along with that oil and NGL. While the oil still flows, the Natural Gas will come with it; and not if otherwise.

Exactitudes are also lacking in terms of proven status. Field oil and gas engineers, along with their geologists, and management consultant accountants, can often offer expert opinion on OGIP or GIIP – (original) gas (initially) in place in a reservoir – but it is not known how much is accessible, or possible production flow rates, or the general chemical composition, until somebody tries.

In addition, codes, categories and standards on reporting proven, possible and probable levels of Natural Gas reserves are different throughout the industry. In the United States, they might talk of 3P (proven plus probable plus possible); however, in the Russian Federation and former Soviet states, the categories are likely to be A, B, C, D, 0, 1, 2, 3 – a set of reporting standards that has recently been modified, or is about to be.

Anyway, one of the things that has niggled with me for a while is that within the oil and gas industry, there have only been a few go-to trusted free-of-charge resources on resources – including the widely-cited annual BP Statistical Review of World Energy, the EIA, OPEC and the IEA. Surely, comprehensive data should be available from other entities, discovered in different ways, to allow analysis of the quality of this data ?

Also, along with reporting entities such as OPEC, IEA and EIA, the BP Statistical Review reports by country. Country-level analysis is too vague for me. It does not account for different behaviours and intentions amongst the industry actors.

I find this unhelpful in the same way that I find country-level commitments at the climate change talks to be too inactionable. Governments are not the only entities that need to be taking part in the treaties – without the participation of companies and corporations in adopting pledges and strategies, there will be no progress of any significant kind.

The transition of energy requires the transition of the oil, gas and coal industries. And the transition of the oil, gas and coal industries will come from cultural changes within individual corporations, companies, and national oil and gas concerns. We need to know the strategy of each upstream producing oil and gas entity about transition, and their shareholders and governments need to be asking for their strategies of transition.

But that’s a big ask. For now, all I can do is try to find some data.

I wanted to see if I could find out how the BP Statistical Review of World Energy is composed, and whether I had access to the underlying data.

So, armed with little except a broadband connection, I sought to try to build the equivalent of the BP Statistical Review on proved reserves from the bottom up, company by company. Because I figured there cannot be a huge number of entities in the field, so surely I could find a lot of the data I need from scanning a couple of dozen Annual Reports. Every company trading on the New York Stock Exchange (NYSE), the Nasdaq, and so on, has to report to the Securities and Equities Commission (SEC), and also publish for their shareholders.

What I found was irritating and concerning. There appear to be large gaps in the data as far as public reporting goes. There seems to be a lot of fudge. Some numbers appear to be withheld. A lot of data is reported in units of measurement that need conversion, and so do not allow easy comparison. Why is this information not forthcoming, when it is so important to the future of the world’s energy pathway ? Would I need to be working in the industry to have access to some of the missing information ?

Despite the holes in my analysis, I managed to find numbers that were in the same ball park as the BP Statistical Review, for a number of countries – except the United States of America and Canada.

Natural Gas Proven Reserves

Russian Federation
BP Statistical Review 37,400 bcm (billion cubic metres)
My bottom-up analysis 37,685 bcm

Islamic Republic of Iran
BP Statistical Review 32,100 bcm
My bottom-up analysis 34,080 bcm

State of Qatar
BP Statistical Review 24,700 bcm
My bottom-up analysis 24,404 bcm

The People’s Republic of China
BP Statistical Review 8,400 bcm
My bottom-up analysis 8,554 bcm

BP Statistical Review 2,400 bcm
My bottom-up analysis 1,614 bcm

United States of America
BP Statistical Review 12,600 bcm
My bottom-up analysis 6,563 bcm

I will need to check my spreadsheet, but here is how it stands right now :-

It is entirely possible that I have not yet found all the entities that own proved reserves of Natural Gas in North America.

At the moment, I have been looking only at publicly traded companies, but it might be that there are a number of private concerns that do not appear on the stock exchanges. Additionally, some of the reserves might be “held” by federal government or state agencies.

Also, I might have missed some international oil and gas companies from the list that have proved reserves in North America, but I haven’t found their reports as yet.

I can see now that I was wrong about the number of exploration and production entities in North America – there are hundreds – as witnessed to by the EIA data gathering exercise web page :-

“To prepare this report, we collected independently developed estimates of proved reserves from a sample of operators of U.S. oil and natural gas fields with Form EIA-23L. We use this sample to further estimate the portion of proved reserves from operators who do not report. We received responses from 371 of 404 sampled operators, which provided coverage of about 90% of proved reserves of oil and natural gas at the national level. We developed estimates for the United States, each state individually, and some state subdivisions”

As the market has seen large amounts of merger, acquisition and bankruptcy recently, I had to be careful to avoid double-counting reserves as far as I could, by keeping reporting years separate.

It might be that some proved reserves are being held by entities who are not actively producing oil and gas – perhaps because they are essentially bankrupt, and are still looking for transfer of ownership or restructuring.

In summary, I am frustrated and disappointed by the lack of detail in the proved reserves of fossil fuels in companies and corporations publicly trading on the stock exchanges. Sometimes, it is very hard to tease apart the Natural Gas from other numbers, and also, see the split between Conventional (dry, tight) and Unconventional (shale) Natural Gas. It is also not clear how much of the NGL Natural Gas Liquids are being used for both pipeline Natural Gas supplies and LNG (Liquid Natural Gas). There is also no understanding on how much petroleum oil ends up as pipeline Natural Gas or LNG after refining.

I suppose that, as usual, as I am a researcher outside the oil and gas industry, and with no funds for purchasing market research reports, I will not be able to get at better numbers.

One thing I noted along the way : it seems clear on cursory analysis that there are many companies in North America which are producing Natural Gas at high rates without significant proved reserves to fall back on. I suspect that the collapse of companies will continue – particularly in the shale gas arena.

Another big thing for me that I found : there are no numbers that discuss the chemical composition of the various fields in the proved reserves assets. What will help or hinder the use of Natural Gas in the “blue hydrogen” endeavour really depends on the percentages of methane, ethane, carbon dioxide, hydrogen sulfide and nitrogen in the accessible reserves in each gas field. Any propane and butane will probably be destined for LNG still, and not “blue hydrogen”. The hydrogen sulfide, just as much as the carbon dioxide, needs to be rejected in an environmentally appropriate way – with long-term sequestration. The hydrogen sulfide could be used to make hydrogen, but only if the sulfur can be properly disposed of. The nitrogen could be used for making agricultural chemicals, but it needs to be captured, and it cannot be used for hydrogen production.

The number of internal combustion vehicles that are likely to remain on the world’s roads could amount to somewhere between 1 billion and 2 billion by 2050. This means that liquid hydrocarbon fuels will continue to be needed in the economy, and this means that pressure to continue to mine raw petroleum oil will continue – unless synthetic fuels are ramped up. Hydrogen will inevitably be needed to make synthetic fuels, so this will create competition for its use : hydrogen will not only be used as a backup fuel to support renewable electricity, it will also be needed in industrial chemistry for synfuels. If it is accepted that the hydrogen for the synfuels will come from Natural Gas, this means that there could well be a tendency to continue mining oil wells for the associated gas – justifying the oil production as a means to get the gas. So liquid hydrocarbon fuels are unlikely to become universally synthesised. Oil and gas companies are unlikely to agree to stop pumping oil, and only pump non-associated gas required for “blue hydrogen” : it would not be in their best interests. The future of shale gas is potentially rocky – so any “blue hydrogen” strategy needs to take this into account. Importantly, without decent levels of carbon capture and sequestration (CCS) or carbon dioxide removal (CDR), continuing the use of any fossil fuels to support “blue hydrogen” is a self-limiting strategy : sooner or later carbon emissions limits or resource wobbles will impact the plan.


Air Liquide : Blue Hydrogen : Green Hydrogen

Hydrogen is once again in the news, but it’s not renewable. And in addition, its uses are not green, either.

Air Liquide, operating as ALAR – Air Liquide Arabia – has announced the start of commercial supplies of hydrogen, produced at YASREF, via a pipeline network within the Kingdom of Saudi Arabia.

A Reuters article, clearly based on an Air Liquide press release, reads, “Pressure has mounted on the world’s biggest fossil fuel producers to reduce their carbon emissions as concern mounts among policy-makers, investors and the general public about their impact on global warming. Many in industry are turning to hydrogen gas, which can be used to fuel vehicles and as a means to store green energy, as part of the solution.”

This all sounds great, but there are several things wrong with this picture.

The first catch is that the hydrogen in this case is not going to be used to fuel vehicles, or store green energy. As it says in the article, “Air Liquide Arabia (ALAR) on Tuesday began pumping hydrogen […] and will supply a Saudi Aramco refinery as the kingdom seeks to shift towards cleaner fuel. […] The Saudi Aramco Mobil Refinery (SAMREF), a joint venture between oil giant Saudi Aramco and a subsidiary of U.S. oil major ExxonMobil, will be the first company to use the Yanbu hydrogen grid […]”

So, the hydrogen here is going to be used to assist in the processing and refining of crude petroleum oil : such processes as hydrodesulfurisation, hydrotreating, hydrocracking.

The second nick is that the hydrogen is being made from Natural Gas, not renewable electricity with water. The Yanbu plant is a giant Steam Methane Reforming operation : “Large-scale hydrogen production unit in Yanbu : One of our many achievements in the region is the successful commissioning of a large-scale Steam Methane Reformer unit for the YASREF refinery (in Yanbu, Saudi Arabia), with a total hydrogen production capacity of 340,000 Nm3/hour. This is the first time in the Middle East that the hydrogen production for such a large refinery has been outsourced to a third party.”

Large gas projects, where the economics make sense, are normally gargantuan, leviathan, plants, covering large areas of land, and requiring high volumes of materials. This means that even plant that produce 100 times less than the Air Liquide operation at YASREF are highly centralised and capital-intensive.

Hydrogen plants are therefore a major capital commitment, and building these gigantic SMRs means that there is a strong lock-in to Natural Gas, a fossil fuel.

Air Liquide does say that they have a commitment to going green, however :-

“In practical terms, Air Liquide has made a commitment to produce at least 50% of the hydrogen necessary for these applications through carbon-free processes by 2020 by combining :
*   Biogas reforming
*   The use of renewable energies, through water electrolysis
*   The use of technologies for the capture and upgrading of carbon emitted during the process of producing hydrogen from natural gas”

2020. That’s now. I wonder how Air Liquide are doing with their capture and “upgrading” of carbon.

I haven’t seen any actual numbers yet, and there doesn’t appear to be a line in their annual accounts about this budget line, but warm words are being reported about cost reduction. Here’s the Hydrogen Council report “Path to hydrogen competitiveness : A cost perspective : 20 January 2020”.

Renewable Hydrogen will get ridiculously cheap, especially as renewable electricity becomes outrageously over-supplied.

I hope Air Liquide won’t come to rue the day they agreed to build the Yanbu project.