Technology is the path to near limitless hydrocarbons

No single discovery or invention in the short history of Homo sapiens has been more positively impactful to our quality of life and success in expanding into virtually any conceivable environment – including throughout the solar system – than the discovery of the utility of natural gas, oil, and coal.

The subsequent dependence of modern civilization on hydrocarbons has for generations stoked fears of an imminent depletion of these critical resources.

Considering that it takes 4 to 10 times more hydrocarbon calories to produce a single calorie of food in modern agriculture, it is of vital importance that we understand the idea and implications of peak hydrocarbons.

Figure 1 – World population growth over the Holocene interglacial.

Since time immemorial, oil seeps (Figure 2) and shallow coal outcroppings have been known and used by the ancients and up until the Industrial Revolution. However, not until the advent of the steam engine between 1698 and 1764 did both hydrocarbon products become supreme in modern civilization.

Figure 2 – McKittrick tar seep, California.

Fast forward to the present day and after 250 years of investing trillions of dollars on coal, oil, and natural gas infrastructure, we find that approximately 83% of primary energy consumption is supplied by hydrocarbons.

Figure 3 from Our World in Data shows the global energy mix from 1900 to present. Note that traditional biomass has more or less remained constant in its role within the global energy mix, underpinning the idea that sources of energy are additive throughout the modern era.

Figure 3 – Global primary energy mix from 1900 to present.

The phrase peak oil was introduced in 1956 by M. King Hubbert, who used the term to describe the point in time when the maximum rate of conventional oil production would occur in the United States, and after which production would begin to decline (The Story of Peak Oil).

Hubbert predicted that conventional U.S. oil deposits were being depleted and that by the 1970s, production rates would peak and decline. As shown in Figure 4a, this is indeed what occurred and has since been duplicated in many regions globally with respect to oil production and to a lesser degree with natural gas (Figure 4b).

Figure 4a – Oil production rates from United States, Norway, and United Kingdom.                    (1 terawatt hour = 588,000 barrels of oil equivalent).

Figure 4b – Natural gas production rates from United States, Russia, China, Canada, Norway, Saudi Arabia and United Kingdom. (1 TWh = 3.6 million gigajoules of natural gas)

Clearly, Hubbert did not foresee the massive uptick in unconventional oil and gas production in United States since the early 2000s.

For those unfamiliar with conventional versus unconventional oil and gas fields, it mostly comes down to porosity. In conventional oil and gas fields, hydrocarbons are concentrated in highly porous sweet spots that are readily extracted with minimal energy expenditure.

In unconventional shale oil and gas fields, hydrocarbons are tightly bound up in what industry experts refer to as source rock, which requires hydraulic fracturing to open artificial fissures to extract the hydrocarbons.

The phrase source rock originates from the idea that the hydrocarbons found in conventional hydrocarbon sweet spots (aka reservoir rock), originates in surrounding low-permeability material that we now call shale oil (and gas) deposits.

The 1970s peak in U.S. oil and gas production and subsequent 30-year decline shown in figures 4a and 4b is said to represent the depletion of conventional oil and gas deposits, while the transition seen in the early 2000s to higher oil and gas production rates coincides with the emergence of unconventional shale production and the advent of horizontal drilling and hydraulic fracturing (fracking) technologies.

In other words, technology negated peak hydrocarbons in the U.S.

Unconventional hydrocarbon resources include the Green River Formation’s kerogen (a type of hydrocarbon that requires high-temperature processing to convert into marketable crude oil) deposits in Wyoming/Colorado/Utah and bitumen from oil sands in Alberta, Saskatchewan, and Utah, which together represent over 7 to 8 trillion barrels of oil-in-place resource potential.

While we have extensive proof that conventional reserves ultimately peak according to Hubbert’s Law, we are still waiting for empirical evidence showing that U.S. shale oil and gas or Canadian oil sands reserves follow the same laws.

So did global conventional oil production peak in the early 2000s?

Figure 5 is from a 2022 study titled How much oil remains for the world to produce? Comparing assessment methods, and separating fact from fiction, which estimates that even though liquid hydrocarbon production has been growing year over year since 2000, actual conventional crude oil production (purple) peaked around 2005.

With global liquid hydrocarbon demand exceeding 103 million barrels per day in 2024, upstream exploration must find over 37 billion barrels of new reserves or face reserve depletion and potentially a peak in production.

Figure 5 – World oil production from EIA data and forecasts.

Gb: billion barrels. Mb/d: million barrels per day. NGL: Natural gas liquids. XTL: coal or gas to liquids. XH: Extra-heavy oil. LTO: Light-tight oil.

These authors suggest that the growth in liquid hydrocarbons since 2005 has been driven by natural gas liquids (NGL e.g., ethane, propane, butane), synthetic liquids derived from coal or natural gas (XTL), extra-heavy oil (XH e.g., Canadian oil sands), and light tight oil (LTO e.g., U.S. Permian Basin).

The study suggests that if it were not for unconventional hydrocarbon production in North America, global liquid hydrocarbon production would indeed have peaked in the first decade of the 21st century.

The wildcard that the authors overlooked, making only vague reference to, is the potential for massive growth in production of extra-heavy crudes (e.g., Canadian oil sands) and kerogen (oil shale) deposits.

Specifically, the Canadian province of Alberta could see significant expansion in its oil sands production and reserve volumes (currently 170 billion barrels), through technology advancements. Note that total oil in place or resource estimate for the entire oil sands resource in the province is 1.8 trillion barrels (Alberta Oil Sands Industry Quarterly Update, Fall 2016)

A 2016 conservative estimate set the total world resources of oil shale equivalent at 6 trillion barrels of oil, with the largest resource deposits in the United States accounting for more than 80% of the resource globally. In comparison, the world’s proven oil reserves are estimated to be 1,700 trillion barrels. (World Energy Resources 2016)

Moving on to coal production, Figure 6 shows us that China reigns supreme in coal production and, as of 2023, China produces 57% of global coal consumed on an annual basis.

The top 5 global coal reserves by country are as follows:

1. United States – 250 billion tonnes
2. Russia – 160 billion tonnes
3. Australia – 147 billion tonnes
4. China – 138 billion tonnes
5. India – 101 billion tonnes

Note that there is great uncertainty in both reserve and resource base estimates for coal. Case in point, the U.S. Energy Information Administration (EIA) estimates the coal resource in Alaska at 2.8 billion short tons, while  the U.S. Geological Survey says it is over 6 trillion short tons (U.S. Coal: Vast, Market Ready (Part I).

 Furthermore, there are huge differences between coal reserve numbers and resource estimates.

For example, while U.S. coal reserves are reportedly 250 billion tonnes, resource estimates are as high as 10 trillion tonnes. One of the main reasons for this is that most coal resources are simply too deep to surface-mine, or prices are too low to economically justify underground mining operations.

Global Energy Monitor (GEM) estimates that of the 2.2 billion tonnes of new mining capacity under development globally, 1.3 billion tonnes of mining capacity is being added by China as it seeks to aggressively grow its present capacity of 3.9 billion tonnes per year (Coal producers are planning a major push to develop new mining projects, China has more than 1 billion tons/year of new coal mines in pipeline, report says).

Figure 6 – Coal production in China, India, Indonesia, United States, Germany, Japan, and United Kingdom. (1 TWh = 123,000 tonnes of coal equivalent [TCE])

If no new coal mines are added to the current global queue and all 432 new mines under development are completed before 2030, global coal production will grow from 8.1 billion tonnes in 2021 to about 10.3 billion tonnes per year in 2030 (Deep Trouble 2021 – Tracking Global Coal Mine Proposals).

The growth in demand for coal in Asia goes beyond China.

According to GEM, over 90% of Association of Southeast Asian Nations (ASEAN) countries (Brunei Darussalam, Burma, Cambodia, Indonesia, Laos, Malaysia, Philippines, Singapore, Thailand, and Vietnam) power generation growth from 2020 to 2023 was fueled by coal (Coal has covered more than 90% of the electricity demand growth in ASEAN countries).

However, the demand for coal in Asia is being driven now by much more than simply the growing demand for electricity. The Asia-Pacific region is at the center of a rapidly growing global coal gasification market, which in 2023 was valued at USD 208 billion and is anticipated to reach around USD 614 billion by 2033, growing at a compound annual growth rate (CAGR) of 11% from 2024 to 2033 (Coal Gasification Market Size, Share, and Trends 2024 to 2033).

Coal gasification is the capital-intensive, go-to technology when a nation, rich in coal and poor in oil reserves, feels its access to international crude oil markets is threatened, sometimes militarily. As the name implies, coal gasification is a process that converts solid coal into a gas stream that can be used to create synthetic oil, refined fuels, plastics, and other petrochemicals. It can be used in power generation.

Currently, most coal-gasification capacity is restricted to specialized high-temperature reactors.

However, another form of coal demand growth in the Asia-Pacific region is in-situ gasification. As shown in Figure 7, in-situ gasification occurs at depths that are too deep to surface-mine.

According to the Petroleum Exploration Society of Australia (PESA), the growth of in-situ coal gasification in the Asia-Pacific region is on track to produce as much synthetic gas as it presently consumes as natural gas, within the next 20 to 30 years. The reason being, the area has abundant coal, which is cheaper than imported liquefied natural gas (LNG).

Figure 7 – Integrated in-situ coal gasification plus power generation (UCG Set to Spike in Asia Pacific due to Rising Coal Reserves, according to Future Market Insights)

In-situ gasification will increasingly become a method of recovering deep coal reserves as shallow coal and natural gas reserves are depleted.

For example, at current rates of natural gas production in North America (45 trillion standard cubic feet per year), it will take merely 25 years to consume its current shale gas reserves (1,100 trillion scf) (EIA/ARI World Shale Gas and  Shale Oil Resource Assessment). However, if 50% of North American coal resources are gasified in-situ (i.e., 5 trillion tonnes), there would be sufficient gas supplies to last over 200 years (i.e., 10,000 trillion scf)(U.S. Coal: Vast, Market Ready (Part I)).

 The last, yet surely not the least, example of an untapped unconventional resource with massive future potential is methane hydrates. The estimated global resource base for methane hydrates is vast, ranging from 100,000 to almost 300,000,000 trillion scf. The large uncertainty in resource potential reflects the early stage of exploration and quantification (Natural Gas Hydrates—Vast Resource, Uncertain Future).

Figure 8 – Global distribution of known methane hydrate deposits.

Considering that estimated global conventional and shale gas resources combined presently come in at around 27,000 trillion scf, methane hydrates represent an immense future source of natural gas.

Methane hydrates are found in oceanic sediments and permafrost regions, with the majority located along continental margins and in the Arctic. Currently, there are no active methane-hydrate production facilities in operation. Methane-hydrate extraction is still in the research and development phase, with various projects focused on understanding the resource potential and developing safe and economically viable extraction methods.

In conclusion, if we ignore the historical role played by technological developments in expanding reserve estimates and simply look at current reserve estimates and production rates for global coal, oil, and natural gas, we are approaching peak hydrocarbons in as little as a generation. Table 1 shows the years of consumption remaining based on global averages.

Table 1 – Worldometer statistics on global hydrocarbon reserves and annual consumption rates (Energy used in the world today) 

In view of the fact that hydrocarbons remain our principal source of primary energy and current consumption rates are astronomical, a pragmatic view is necessary when considering calls to divest and strand massive unconventional resources that we have hardly begun to exploit.