The Overlooked Perils of Heterogeneous Oil and Gas

THE QUEST TO understand the different types of oil and gas that populate the earth goes all the way back to the industry’s early days. Oil was first used in the late 1840s to illuminate buildings in Halifax, Canada.1 Within a decade, the first modern-day oil well was drilled in northwestern Pennsylvania.2 Although the two kinds of hydrocarbons these two places produced were readily converted into kerosene-based lamp oils, they had little else in common. Pennsylvania’s rock oil was light, with more hydrogen than carbon.3 The Canadian variety came from heavy bitumen with more carbon than hydrogen.

A few years later, John D. Rockefeller launched Standard Oil, giving birth to the oil industry. The company coined its name as a nod toward the “standard quality of product that the consumer could depend [on].”4 This branding created the impression that everything associated with oil—its extraction, processing, and shipping—was standard. That impression is false. Hydrocarbons are not all the same: rather, they are incredibly diverse.

By the end of the nineteenth century, the vast Midway-Sunset Oil Field near Bakersfield, California, had turned into a gusher that has since produced billions of barrels from tens of thousands of oil wells.5 In 1901, oil was struck at Spindletop in Beaumont, Texas—tripling US production in a flash.6 Geologists at the time noted marked differences between the complex, thick (unconventional) oil from California and the (conventional) crude from Texas.7

The varying compositions and settings of conventional and unconventional oils and gas can make for marked differences in their respective carbon footprints. The Oil Climate Index + Gas (OCI+) estimates that the supply-side (production, processing, refining, and shipping) greenhouse gas (GHG) emissions of otherwise-equivalent barrels of oil and gas can vary by up to a factor of ten.8 Assessing the climate impacts of differing kinds of oil and gas depends largely on the techniques used to supply differing resources. Conventional oil and gas readily flow and are relatively easy to separate, resulting in lower supply-side climate risks. Thus, the majority of conventional oil and gas GHG emissions stem from the end uses of their petroleum products, such as natural gas, gasoline, diesel, and residual fuels.

Unconventional hydrocarbons, however, do not readily flow and are harder to produce, process, refine, and ship. These resources tend to be wedged in rocks, buried deep, bound to sand, solidified, acidic, or frozen. Some unconventional hydrocarbon resources yield byproducts, like petcoke, with high climate impacts of their own. As such, unconventional oil and gas currently have higher climate risks than their conventional counterparts.

Today, resource flows of conventional hydrocarbons are double those of unconventional resources.9 Looking to the future, however, nearly three times more technically recoverable unconventional resources exist worldwide compared to conventional oil and gas.10

This chapter compares volumes of different oil and gas resources. Next, the wide array of these hydrocarbons is surveyed, their various stages of development are discussed, and their different climate risks are gauged. Innovations in the oil and gas sector are enhancing the technically and economically recoverable prospects of unconventional resources. The better their supply chains are understood, the better the chances of successfully mitigating GHG emissions from unconventional oil and gas. The chapter concludes with a side-by-side assessment of GHG emissions from global supplies of different conventional and unconventional oil and gas resources.

Distinguishing Conventional from Unconventional Resources

Named for its Latin roots, petra (meaning rock) and oleum (meaning oil), petroleum is formed over time as dead organisms decompose underground, are washed into waterways, and are crushed under tons of rock and sediment. The unique combination of organic matter and geologic conditions in one place or another yields vastly different forms of conventional and unconventional hydrocarbons.11

Although hydrogen and carbon are the two main chemical ingredients of conventional and unconventional hydrocarbon resources, contaminants migrate in as they are formed and extracted. Carbon dioxide (CO2), oxygen, and nitrogen (air); heavy metals; water; acids; carcinogens; radioactive elements; and other impurities may be present, and some are more difficult to deal with and have higher GHG impacts than others. For example, the wastewater that is produced along with oil requires extra energy and emits more GHG emissions for it to be pumped, reclaimed, and recycled. But some contaminants return profits. Sulfur is used in the petrochemicals industry, and lithium recovered from wastewater can make rechargeable batteries.12

Conventional petroleum takes many physical forms. It can be a liquid with a consistency of water or molasses, it can be gaseous and resemble anything from dry wind to dense fog, or it can be a hybrid of these two phases like a fizzy soda. Conventional resources are typically graded on their weight, sulfur content, and heating value.

Oil density—its weight compared to the same volume of water—is measured in degrees of American Petroleum Institute (API) gravity. Conventional oil’s gravity typically ranges from 22 degrees API to 32 degrees API.13 Gas density (measured relative to air) ranges from 0.7 to 0.9 kilograms per cubic meter.14 Oil and gas that are high in sulfur (over 0.5 percent content by weight) are classified as sour, while low-sulfur varieties (less than 0.5 percent) are considered sweet. Conventional gas heating values (the amount of energy it contains) range from 950 to 1,150 British thermal units (Btu) per cubic foot, depending on its liquid content. Unfortunately, these characteristics cannot be used to quantify the lifecycle GHG emissions of oil and gas because they lack sufficient details on their compositions of the hydrocarbons in question and the processes employed to exploit them.

While conventional oil and gas are loosely defined as those that easily flow, unconventional resources can have too much (or too little) carbon or hydrogen, can contain too many impurities, can be situated in an unusual location, or can be difficult to extract or process for other reasons.15 In general, the characteristics, locations, volumes, and lifespans of unconventional oil and gas are less well understood and more complex than those of their conventional cousins, as are their technical challenges, economic prospects, and environmental tradeoffs.

The bulk of total GHG emissions from conventional resources (on the order of 90 percent of them16) stem from the end uses of their petroleum products. In the short term, the best way to reduce the climate risks of these hydrocarbons is to fine-tune their industrial processes and end-use efficiencies. In the long term, breakthroughs that sequester carbon and methane and produce only hydrogen hold promise in emitting net-zero GHGs.

Unconventional hydrocarbons, however, call for careful management when it comes to climate change. A significant share of their GHGs are emitted during extraction, processing, refining, and shipping—in other words, before their end uses even enter the equation. This difference shifts the climate burden unconventional resources pose from consumers to the petroleum industry. As unconventional stocks compose an increasing share of the oil and gas supply over time, knowing where in the supply chain GHGs are emitted and how best to reduce these emissions will be increasingly important.

While these general industry trends are important, some concrete numbers can be even more illuminating. As of 2019, an estimated 1.4 trillion barrels of conventional oil and 0.7 trillion barrels of oil equivalent (BOE) of conventional gas have been commercially produced since the 1850s.17 Conventional oil output has averaged 67 million barrels per day—fueling two-thirds of the global oil supply—and the rest has come from unconventional sources, including tight oil, oil sands, condensates, and biofuels.18 Conventional gas has accounted for 80 percent of worldwide production; the rest has been unconventional.19

As conventional oil and gas stores deplete, unconventional hydrocarbon development is on the rise. Figure 2.1 outlines the major classes of diverse petroleum resources.


FIGURE 2.1 Current Classifications of Conventional versus Unconventional Oil and Gas

Notes: Conventional gas is depicted in white squares, conventional oil and natural gas liquids are shown in gray squares, and unconventional oil and gas are listed in black squares. CNG, compressed natural gas; LNG, liquefied natural gas.

Sources: Author’s depiction with data from the following sources: Deborah Gordon, “Understanding Unconventional Oil,” 2013, https://carnegieendowment.org/files/unconventional_oil.pdf; and International Energy Agency, World Energy Outlook 2017, 2018, figure C.1, https://www.iea.org/reports/world-energy-outlook-2017.

Muddled Resource Definitions

Given the differing characteristics and compositions that oil and gas can take, it is not surprising that defining them has not been a straightforward task. Confusion over the definition of oil dates back to the 1970s when US legislation broadly stated that “oil means oil of any kind or in any form.”20 At the time, unconventional oil from fracking, bitumen, or synthetic fuel production had not yet appeared on the scene. In 1980, however, when new oils emerged,21 Congress specifically exempted all “unconventional” light tight shale oil, oil sands, coal-to-liquids (CTLs), and biomass from the legal definition of oil.22 This artificial divide carved out in the legal definitions between conventional and unconventional hydrocarbon resources set a precedent that has long hampered the effectiveness of environmental oversight of oil and gas.23

A generation later, unconventional oil and gas development took off. In 2010, as oil prices rose, shale gas and light tight oil were extracted by injecting substances into formations, fracturing formations, propping open rocks, and employing horizontal drilling in the United States.24 In Canada, increasing volumes of extra-heavy oil sands were mined or made to flow by injecting steam.25

Advances in technology enabled a widening array of hydrocarbon deposits in once-unreachable places to be extracted and processed into petroleum products.26 A new assortment of resources emerged in a sector that had long been stuck in familiar patterns.27 With this change came new uncertainty and risks, especially for the global climate. This sea change for the oil and gas industry underscores the importance of understanding unconventional resources, as detailed in the remainder of this chapter.

Understanding Unconventional Gas

There is an ample supply of unconventional gas to meet all imaginable levels of future demand, whether or not the global climate can bear it. Table 2.1 compares the current levels of production and the remaining recoverable reserves of nine unconventional gas resources to those of conventional gas. Since 2000, unconventional gas production has more than quadrupled in volume.28 The standout, shale gas, increased by over a factor of twenty.29 Smaller volumes of other unconventional gases have also gained footholds. Of the remaining technically recoverable gas sources, stores of unconventional varieties are collectively several multiples greater than those of conventional gas.

Table 2.1 Gas Production and Recoverable Resources (2019)

Gas Resource Type

Current Production (billion cubic meters [bcm]/year)

Remaining Technically Recoverable Resources (trillion m3)

Conventional Gasa



Unconventional Gas Sources

Shale Gas



Deepwater and Ultradeep Gas



Arctic Gas



Tight Gas



Coalbed Methane



Biogas and Syngas



Acid Gasb



Geopressurized Gasc


Methane Hydratesd


Subtotal Unconventional Gas



All Gas (Total Estimated Volumes)e



a To avoid double-counting, deepwater and ultradeep, Arctic, and acid gas volumes are subtracted from the International Energy Agency’s (IEA) conventional gas production volume.

b Acid gas is also referred to as “sour” gas because it often contains high sulfur along with the CO2; this value assumes 10 billion metric tonnes/year of “other” gas produced is acid gas.

c Geopressurized zones estimated at 8.5 quadrillion cubic meters worldwide with 10% technically recoverable, of which 2.5% is estimated to be produced over the next twenty years.

d Methane hydrates are not yet technically recoverable, but some 30 quintillion cubic meters are in place with 2.5 percent deemed technically recoverable, of which 1 percent is estimated to be produced over the next twenty years.

e Current gas consumption is estimated at 62 million BOE/day. Double-counting may occur due to resource overlap (including for deep resources that are located in the Arctic, geopressurized zones, or methane hydrates, for instance).

Notes: For the gas conversion figures, the calculations assume 164.3 billion cubic meters per BOE. All numbers rounded to the nearest whole number.

Sources: International Energy Agency, World Energy Outlook 2018, Tables 3.1, 3.5, 4.1 (Gas and Oil Production), https://www.iea.org/reports/world-energy-outlook-2018; International Energy Agency, World Energy Outlook 2017, Table 8.2 (Technically Recoverable Gas Resources), https://www.iea.org/reports/world-energy-outlook-2017; James Speight, “Unconventional Gas,” 2019, https://www.elsevier.com/books/shale-oil-and-gas-production-processes/speight/978-0-12-813315-6; Statista, “Global Proven Coal Reserves,” 2019, https://www.statista.com/statistics/265450/global-proved-reserves-of-coal/; Energy Information Administration, “World Shale Resource Assessments,” September 24, 2015 (Tight Oil and Shale Gas), http://www.ieee.es/Galerias/fichero/OtrasPublicaciones/Internacional/2015/EIA_World_Shale_Resource_Assessments_24sept2015.pdf; Wang Hongjun et al., “Assessment of Global Unconventional Oil and Gas Resources,” Petroleum Exploration and Development 43, no. 6 (December 2016), https://www.sciencedirect.com/science/article/pii/S1876380416301112; Statista, “Production of Biogas Worldwide From 2000 to 2017”, https://www.statista.com/statistics/481791/biogas-production-worldwide/; World Biogas Association; and UN Environment Programme, “Frozen Heat: A Global Outlook on Methane Gas Hydrate,” 2014, https://sustainabledevelopment.un.org/index.php?page=view&type=400&nr=1990&menu=35.

A brief description of each kind of unconventional gas resource follows in the order presented in Table 2.1. These types of gas resources include shale gas, deepwater and ultradeep gas, Arctic gas, tight gas, coalbed methane, biogas and syngas, sour gas, geopressurized gas, and methane hydrates. In addition to presenting some brief background information on these subtypes and assessing their future production prospects, the goal is to convey the current understanding of potential GHG emissions from these burgeoning unconventional gas resources.

Shale Gas: Trapped in Rocks

There is gas lodged in rock fissures that span thousands of miles on every continent. These continuous shale gas resources require special drilling techniques to fracture (or frack) rocks and recover the gas trapped in them.30 (Oil and condensates also can be present along with the gas.) Shale gas contains mostly methane—an extremely potent, short-lived, leak-prone GHG—along with other volatile organic compounds (VOCs). When burned (or flared), methane and other hydrocarbons are converted mainly to CO2, depending on the equipment used.

Fracking is not new. Prospectors in the mid-nineteenth century fractured rocks using explosives mostly in oil fields.31 Gas was produced with the oil, but the lack of pipelines meant that the produced gas was wasted and simply released into the atmosphere.

It took another century to find ways to successfully frack gas. In the late 1940s, the first commercial hydraulic fracturing applications were used in Kansas, Oklahoma, and Texas. Within a decade, petroleum service companies were acquiring licenses to frack gas as well as oil.32 High energy prices in the 1970s spurred fracking development in gas-rich regions of Colorado, Wyoming, and New Mexico. But the game changer came in the early 2000s, when independent producers coupled fracking with horizontal drilling in East Texas, enabling access to continuous shale plays.33 Through 2007, rising natural gas prices prompted fracking in numerous US states.34

The climate footprint of shale gas is largely due to methane leakage throughout the supply chain, from drilling, production, gathering, boosting, shipping, processing, storage, and end-use distribution systems. Undersized and leaky systems with old or faulty equipment have high GHG emissions that can go undetected.35 Maintenance like well workovers and accidents like blowouts can also generate high volumes of GHGs. Quantifying how much methane is emitted from routine leakage depends largely on operational factors, while how much accidental leakages produce depends on duration and shale gas composition, data that are currently sparse or missing altogether.

Ultradeep Gas: Buried Way Down

Ultradeep gas wells are drilled one-third of the way through the earth’s crust.36 By comparison, conventional hydrocarbon resources lie hundreds to a few thousand feet below the surface. The difficulties of going deeper—many miles (tens of thousands of feet) underground and underwater—have not thwarted the industry. The depth of a well only carries a relative penalty compared to shallower wells. For example, drilling Russia’s ultradeep Chayvo field is estimated to have five times more GHGs per barrel than Angola’s shallow Takula field.37 However, in absolute terms, Chayvo’s drilling emissions only contribute an estimated 5 percent to this asset’s GHGs and less than 1 percent to total lifecycle GHGs that include end uses.38 The vast pressures that ultradeep hydrocarbons are subject to make them flow. This translates into average GHG emissions from extraction, but methane can still leak through the rest of the supply chain and present climate risks.

The deepest wells are rarely drilled in a straight line. Instead, they are channeled from left to right, like a skier traversing back and forth down a steep slope. As extraction techniques improve extended-reach drilling, accessing even deeper hydrocarbon resources will become technically feasible. There are existing fields in Russia (the Barents Sea), Mozambique, and Egypt,39 and new discoveries have been posted in surprising places, including Israel, Tanzania, Mauritania, Senegal, Cyprus, and India.40

Gas wells accounted for over half of new deepwater gas volume brought online between 1990 and 2019.41 However, deepwater gas development has proven less commercially viable than its oil counterpart (discussed later) due to low natural gas prices and high development costs.42

Arctic Gas: Journeying Far North

Above the Arctic Circle lies a plethora of hydrocarbons—gas, oil, and natural gas liquids (NGLs)—that are poorly explored and their possession and access are heavily disputed. Cold, dark, dangerous, and remote conditions hinder the development of these unconventional resources. Six nations—Canada, Denmark (via Greenland), Iceland, Norway, Russia, and the United States—each have a jurisdictional claim over some of these hard-to-reach hydrocarbons, which are spread over seven geologic basins the size of Africa.43 The Arctic’s polar ecosystem is extremely fragile and highly susceptible to warming from the GHG emissions released there.44

The Arctic is reported to contain nearly seven times more gas than oil.45 Limited gas development in parts of Alaska and Siberia dates back to the 1960s. As of 2018, only Norway reported marketable Arctic gas production of 122 billion cubic meters (bcm), while the United States reinjects the bulk of the Arctic gas it produces due to the lack of takeaway capacity, and Russia is just mounting its plans for major Arctic gas developments.46

Numerous additional projects have been proposed in subsequent years, many of which have been canceled and not reached fruition. High costs and long lead times hamper Arctic projects, which are shelved when prices fall.47 Still, in 2020, Russia released its master plan for the Arctic, featuring major new gas and oil drilling and petrochemical processing.48 As of 2018, GHGs emitted in the Arctic are expected to have an outsized impact both locally and on global weather patterns. A change in the Gulf Stream—the strong current that carries warm water up the East Coast of the United States and onward to Canada and Western Europe—could lead to frequent blasts of Arctic winds in the Northern Hemisphere.49 Shrinking ice sheets will contribute to rising sea levels and greater ocean warming. And a dangerous feedback loop would enhance global warming as the methane and CO2 frozen beneath Arctic permafrost thaw and enter the atmosphere as regional temperatures rise.

Tight Gas: Scattered About

Unlike deposits of shale gas trapped between layers of shale, tight gas is dispersed in silt and sand in between hard rocks. Deposited some 250 million years ago, tight gas has been compacted, cemented, and recrystallized, reducing its ability to permeate the rock and readily flow.50 The large energy inputs needed to force gas through unconnected passages and the potential to leak methane in the process both contribute to the climate impact of tight gas deposits.

Tight gas production requires numerous wells. Detailed seismic data help guide and deviate drilling along various angles that traverse as much of a reservoir as possible. The more inroads that are made, the more gas that is recovered. In addition to unconventional drilling techniques, tight gas often calls for artificial stimulation to promote flow. This technique entails fracturing the rock or acidizing it to dissolve sediment. The goal is to re-establish the original fissures that were present before the source rock was compacted. Challenges arise because every tight formation has its own unique characteristics and engineers continuously are testing new methods. The volumes of GHG emissions stemming from these novel techniques remain highly uncertain.

Coalbed Methane: Nestled in Coal

Coal, a solid hydrocarbon composed of up to 90 percent carbon, also contains trapped methane, called coalbed methane or coal seam gas.51 To tap into complex coalbed methane systems, it is necessary to pump water out of coal seams to lower underground pressure, detach the gas from solid surfaces, and help get it flowing.52 Sizable energy inputs from pumping and reclaiming polluted water plus flared gas and methane leakage contribute to the climate risks of coalbed methane. Roughly 10 percent of global methane emissions are currently estimated from coal mines—and remote sensors are finding methane super emitters.53

Coal degasification dates back to late nineteenth-century Europe, where miners removed gas to mitigate explosions. China commercialized the extraction of coalbed methane in the 1950s, and the United States stimulated its development in the 1980s. Countries with large stores of coal—like Australia, India, Russia, and Indonesia—are at various stages of producing these gas resources. Production doubled worldwide between 2000 and 2017, accounting for 2 percent of gas supplied globally.54 Coalbed methane reserve estimates account for 6 percent of remaining technically recoverable natural gas.55

Biogas: From Recycled Feedstocks

Biogas is produced from organic matter in swamps and lakes, dams, landfills, industrial wastewater, manure ponds, food waste, and the contents of animals’ digestive tracts. Biogas can also be manufactured in tanks (anaerobic digesters) that simulate biological processes. Bacteria in the absence of oxygen forms mostly GHGs like methane and CO2. The climate impacts of biogas are wide-ranging and may result in net-negative GHGs, if more carbon is sequestered than emitted. Estimates of the GHG produced by biogas deserve more study and range from negative 85 to positive 251 grams of carbon dioxide equivalent (CO2e) per kilowatt hour, depending largely on methane leakage.56

In 2018, 350 US landfills, 44 biogas sewage and industrial wastewater treatment facilities, and 29 large dairies generated 0.3 percent of the country’s total utility-scale electricity.57 In the European Union, biogas plays an even bigger energy role with over 17,000 plants generating electricity and heat.58

Biogas can be reformed into synthesis gas (syngas), a mixture of carbon monoxide and hydrogen.59 Syngas cannot be directly consumed. It is used to generate steam or electricity or as a feedstock for petroleum fuels and chemicals. Many industrial products use syngas, including fertilizer, ammonia, sulfuric acid, and methanol. Researchers are adjusting syngas production methods to recycle increasing volumes of carbon captured from flue gas and directly from the air.60 Like biogas, the climate impacts of syngas vary widely and need to be assessed case by case.

Acid Gas: Chock Full of Carbon Dioxide

Acid gas is naturally high in CO2. It is often confused with sour gas because acid gas often contains high sulfur levels. Because acid gas has elevated carbon dioxide concentrations of 15 to 80 percent, its development depends on finding a use for the CO2 that is stripped off.61 One such use is injecting CO2 to enhanced oil recovery (EOR), a topic discussed more later. Another purpose is to get credit for carbon capture and sequestration (CCS). The most damaging route is to vent excess CO2. The climate risks of acid gas vary widely depending on whether its associated CO2 is used for EOR, is captured and sequestered underground permanently, or is released into the atmosphere.

Acid gas resources have been mapped globally, with large fields in Australia, parts of Southeast Asia, the US state of Wyoming, the Middle East, and North Africa. The latter three places are oil rich, so acid gas production there is typically used for EOR. In Australia, an acid gas project is utilizing CCS.62 Other acid gas fields in Russia and New Zealand, meanwhile, are known to vent their CO2, so they have four times the upstream GHG emission intensity posed by Australia’s operational CCS and twice the upstream GHG emission intensity posed by the United Arab Emirates (UAE) where EOR is employed.63 The wide-ranging GHG emissions of acid gas raise questions about companies’ motivation for developing acid gas fields. If CCS is not coupled with acid gas, its development has very large climate footprints.

Geopressurized Gas: Under Immense Stress

Hydrocarbons buried underground are subject to pressures that vary with depth, but formations under unusually high pressure (for their depth) are considered geopressurized zones. The gas resources situated in such zones are located up to 25,000 feet below the surface around geologic faults, making attempts to estimate their reserves highly uncertain. Although complex underground conditions can complicate extraction and elevate GHG emissions, geopressurized zones are thought to hold the world’s single largest gas reserves.64 More needs to be uncovered about these unconventional gases and the processes that would be employed to evaluate whether and how much they could elevate GHG levels.

Methane Hydrates: Frozen Slush

Methane hydrates are naturally occurring cages of ice that contain methane. They carpet the world’s oceans at depths over 1,500 feet, stacked hundreds of feet thick and extending horizontally over long distances.65 Methane hydrates also collect under Arctic permafrost. These hydrocarbons exist undisturbed in stasis, subject to enormous levels of pressure and frigid temperatures. When brought to the surface, 1 cubic foot of methane hydrate releases 164 cubic feet of natural gas, risking a massive methane release.66 Climate impacts of methane hydrates are highly uncertain.67 Altering their steady state could perpetuate a dangerous warming cycle with higher ocean temperatures that melt more methane hydrates.68

In the late 1970s, drilling expeditions confirmed abundant amounts of methane hydrates around the globe on every continent.69 Experimental extraction methods include surface dredging, sea mining, alleviating pressure to break down hydrates, and carbon dioxide injection.70

Notably, even before production is commercialized, methane hydrates can cause damage. During the Deepwater Horizon explosion and oil spill in 2010, for example, initial efforts to plug the well were thwarted because exploding methane hydrates formed an icy plug and clogged the gear deployed to collect the leaking oil.71 Moreover, thawing hydrates explosively release gas in the Siberian tundra and at the bottom of the Barents Sea, forming giant craters as large as 3,000 feet wide and nearly 100 feet deep.72 Since methane hydrates act like glue that hold their surroundings in place, even routine oil and gas extraction in hydrate-rich regions can cause landslides.73

While their impacts differ, the general trend toward more unconventional gas resources means that unless the outsized climate impact of such resources is properly tabulated, the industry is at risk of chronically undercounting their climate impact throughout the process from production to processing, shipping, and end uses.

Understanding Unconventional Oil

Like in the case of gas, there is more than enough unconventional oil to last centuries and lead to major climate damage. Table 2.2 compares the current production of and the remaining recoverable reserves of nine unconventional oil resources to those of conventional oil. Over the past two decades, the production of unconventional oil nearly tripled.74 For some subtypes of unconventional oil, the spike in production was even steeper. The supply of tight oil rocketed up from zero to 11 million barrels a day,75 while the supply of NGLs nearly doubled, the bitumen supply quadrupled, and biofuels grew by an order of magnitude as well.76 By comparison, conventional oil production remained essentially flat.

Three times as much unconventional oil is technically recoverable than conventional oil (see Table 2.2). Kerogen oil shale tops the list, followed closely by the other heaviest hydrocarbons. CTLs and biofuels remain wild cards with technically recoverable resources that stem from huge underlying resource bases.

Like with unconventional gas, there is a greater potential supply of unconventional oil than the global climate can safely accommodate. As a rule of thumb, the lighter the oil, the more methane factors into climate risks, and the heavier the oil, the more CO2 and unburned (black) carbon can elevate GHG emission levels.

Table 2.2 Oil Production and Recoverable Resources (2019)

Petroleum Resource Type

Current Production (million barrels/day)

Remaining Technically Recoverable Resources (billion barrels)

Conventional Oila



Unconventional Oil Sourcesb




Light Tight Oil



Extra-Heavy Oil and Bitumen



Deepwater and Ultradeep Oil



Arctic Oil



Depleted Oil









Oil Shale (Kerogen)



Subtotal (Unconventional Oil)



All Liquids (Total Estimated Volumes)



a To avoid double-counting, deepwater, ultradeep, Arctic, and enhanced oil recovery (EOR) oil volumes are subtracted from the International Energy Agency’s conventional oil volume.

b Recoverable reserves are derived from original oil in place, including tight oil = 8 trillion bbl; bitumen = 3–5 trillion bbl; and heavy oil = 3–5 trillion bbl.

c Biofuels depend on conversion technologies from a wide range of feedstocks.

d Coal-to-liquids (CTLs) depend on recoverable coal resources, while gas-to-liquids (GTLs) depend on the volume of natural gas production devoted to liquids conversion.

Notes: All numbers rounded to the nearest whole number.

Sources: International Energy Agency, World Energy Outlook 2018, Tables 3.1, 3.5, 4.1 (Gas and Oil Production), https://www.iea.org/reports/world-energy-outlook-2018; Journal of Petroleum Technology, December 2019; Gongcheng Zhang et al., “Giant Discoveries of Oil and Gas Fields in Global Deepwaters in the Past 40 Years and the Prospect for Exploration,” Journal of Natural Gas Geoscience, February 2019, https://www.sciencedirect.com/science/article/pii/S2468256X19300033; International Energy Agency, World Energy Outlook 2012, Table 3.3 (Technically Recoverable Oil Resources), https://www.iea.org/reports/world-energy-outlook-2012; Brandt et al., “Climate-wise Choices in a World of Oil Abundance,” April 5, 2018 (Oil in Place), https://iopscience.iop.org/article/10.1088/1748-9326/aaae76; US Energy Information Administration, “World Shale Resource Assessments,” September 24, 2015 (Tight Oil and Shale Gas), http://www.ieee.es/Galerias/fichero/OtrasPublicaciones/Internacional/2015/EIA_World_Shale_Resource_Assessments_24sept2015.pdf;  Wang Hongjun et al., “Assessment of Global Unconventional Oil and Gas Resources,” Petroleum Exploration and Development 43, no. 6 (December 2016), https://www.sciencedirect.com/science/article/pii/S1876380416301112.

A brief description of each unconventional oil resource follows in the order presented in Table 2.2. These subtypes of unconventional oil include condensates, light tight oil, extra-heavy oil and bitumen, ultradeep oil, Arctic oil, heavy depleted oil, biofuels, CTLs and gas-to-liquids (GTLs), and oil shale (or kerogen). In addition to outlining background information on them and their production prospects, the industry’s current understanding of their climate impact is summarized.

Condensates: Shifting States

Condensates are light hydrocarbons that readily shift from gas to liquid, depending on temperature and pressure conditions. These unstable, flammable mixtures are named for their ability to condense into liquid form at the surface.77 Their lifecycle climate impacts have been poorly studied. But each of their hydrocarbon components are GHGs with varying potency, and they also form ozone, a GHG that also deteriorates local air quality.

All condensates contain NGLs—ethane, propane, butane, pentane (natural gasoline), and hexane—but no two are alike. Those containing more pentane and hexane are volatile liquids, with wide-ranging API gravities between 50 and 120 degrees.78 NGLs with more ethane and propane are misty, wet gases. Table 2.3 details examples of the end uses of condensates. Their GHG emissions depend largely on how condensates are processed, leakage throughout the supply chain, and whether their end use involves combustion or not.

Condensate output worldwide is on the rise. Historically, the Middle East and Russia were the largest producers. But in the United States, production “more than doubled” between 2008 and 2017 and is now the top global NGL producer due to the boom in oil and gas fracking.79 Production is increasing in Australia too, due to growing interest in developing gas fields rich in condensates. Condensate demand is rising, as they can be used to make petrochemicals, and more studies are needed to ascertain the lifecycle GHG emissions of these resources.

Table 2.3 Value Propositions for Condensates

Condensate Compounds

Chemical Formula

Applications and End Uses

Primary Sectors



Petrochemical feedstocks, refinery fuel gas, plastics, antifreeze, detergent

Industrial and commercial

Propane (LPG)


Cook stoves, heating, barbeques, refinery fuel gas, petrochemical feedstock

Residential, commercial, and industrial



Petrochemical feedstock, lighter fluid, synthetic rubber, fuel blending

Industrial and transportation



Refinery inputs, aerosols, refrigerants, petrochemical feedstock




Natural gasoline, solvents, blowing agent for polystyrene foam

Transportation, industrial, and commercial

Pentanes plus

C5H12 and heavier

Gasoline, ethanol blends, oil sands production

Transportation and industrial

C, carbon; H, hydrogen; LPG, liquefied petroleum gas.

Sources: US Energy Information Administration, “What Are Natural Gas Liquids and How Are They Used?,” April 20, 2012, https://www.eia.gov/todayinenergy/detail.php?id=5930; International Energy Agency, “The Future of Petrochemicals,” 2018, https://www.iea.org/reports/the-future-of-petrochemicals.

Light and Tight Oil: Another Fracking Feast

Fracking not only liberates gas (as discussed previously) but also produces large volumes of light oil and condensates. Oil fracking emerged in the 1860s to increase oil production by detonating dynamite and nitroglycerine downhole.80 Next, acid was injected to melt rather than crack the source rock starting in the 1930s. A decade later, mixtures of sand and gelled gasoline were used to prop open rocks. It was projected that this technology would have been applied nearly 1 million times by the late 1980s.81 In the 2010s, modern-day fracking along with horizontal drilling breakthroughs took aim at light tight oils in gas-rich liquid plays. Prime candidates—including North Dakota’s Bakken formation, West Texas’s Permian Basin, and South Texas’s Eagle Ford Basin—began to undergo intense development.82

Table 2.4 illustrates the dramatic differences in gas and condensate contents of fracked resources.83 Unconventional plays with high gas levels require data on gas compositions and sufficient pipeline takeaway capacity to minimize GHG emissions. Economics are at odds with methane management because oil is priced higher than gas.84 Therefore, leaky systems that burn off unwanted gas or deliberately vent methane into the atmosphere are profitable. Unprepared, careless, or corrupt operators that emit a lot of potent methane emissions pose significant climate risks.

Table 2.4 Relative Shares of Oil, Gas, and Condensate from Texas’s Eagle Ford Basin

Resource Type

Energy Content

Total Production

Zone Type






Black Oil






Volatile Oil


















Notes: Gas production includes methane as well as ethane, propane, and butane. Further, asset specific, gas speciation is required to accurately model methane leakage from gas, condensate, and light oil assets.

Source: Abbas Ghandi et al., “Energy Intensity and Greenhouse Gas Emissions from Crude Oil Production in the Eagle Ford Region,” September 2015, https://www.researchgate.net/publication/303592051_Energy_Intensity_and_Greenhouse_Gas_Emissions_from_Crude_Oil_Production_in_the_Eagle_Ford_Region_Input_Data_and_Analysis_Methods.

Extra-Heavy Oil: Old and Dense

At the opposite end of the hydrocarbon spectrum from light tight oil lie heavy oils that contain so much carbon they are semisolid. Generally, the more carbon an extra-heavy oil contains, the higher its lifecycle emissions of CO2 and black carbon.85

These ancient oils have spent a very long time underground subjected to heat and pressure. Degradation occurs when their lighter hydrocarbon contents are eaten by bacteria, are dispersed or dissolved by water, or disperse into their surroundings.86 What remains is tarry, extra-heavy oil and semisolid bitumen, each with its own properties. Heat, steam, and chemicals are used to either reject their extra carbon or add hydrogen.87 Table 2.5 provides various climate-related details about different types of extra-heavy oil and bitumen.

Table 2.5 Characteristics of Different Extra-Heavy Oils and Bitumen


Extra-Heavy Oil

Raw Bitumen

Diluted Bitumen

Synthetic Crude Oil (SCO)

Partially Upgraded Bitumen


Heavy, sour crude


Heavy, sour crude

Light, sweet crude

Medium, sour crude or medium, sweet crude

API Gravity






Sulfur Content






Water and Solids






Heavy Metalsa






Acidity (TAN)











Partial processing

Highest GHG Emissions

Production and refining


Refining and shipping


Production, shipping, and refining

a Heavy metals include vanadium, nickel, iron, and others.

b Upgrading involves preprocessing to remove excess carbon and other impurities in the form of petcoke before the refining stage.

API, American Petroleum Institute; GHG, greenhouse gas; TAN, total acid number.

Source: Author’s estimations based on Oil Sands Magazine,https://www.oilsandsmagazine.com/technical/bitumen-upgrading; Jacobs Consultancy, March 2018, https://albertainnovates.ca/wp-content/uploads/2018/07/Bitumen-Partial-Upgrading-March-2018-Whitepaper-2433-Jacobs-Consultancy-FINAL_04July.pdf; Manik Talwani, Rice University Baker Institute, 2002, https://scholarship.rice.edu/handle/1911/91524.

The Western Hemisphere contains nearly 70 percent of the global supply of technically recoverable heavy oil and over 80 percent of its technically recoverable bitumen.88 Venezuela’s Orinoco Belt (the world’s single largest petroleum deposit) has the largest store of extra-heavy oil.89 The majority of bituminous oil is buried in Alberta, Canada. As early as the sixteenth century, what was then called black pitch was reported along the banks of the Athabasca River.90 In the 1960s, open pit mining began to produce oil sands. Today, most production in Alberta involves in situ steam-assisted gravity drainage, similar to Venezuela’s approach, which uses heat and steam to move viscous oil over long distances with downhole pumps.91

Foreign assistance has facilitated these highly complex techniques in Venezuela.92 But saturated markets, low oil prices, transport bottlenecks, and political instability have led to recent production cuts, buying time for cleaner technological breakthroughs.93 The prospects for low-GHG impact using various techniques, such as in situ gasification methods to extract hydrogen from oil sands and nanotechnology and microbial methods to transform oil sands into light oil and natural gas underground, could sequester its own massive carbon content.94 This may be the best way to safely access such a massive resource base from the world’s heaviest oils.

Ultradeep Oils: Extremely Far Down

Deepwater exploration has been underway for forty-five years, and recent developments are increasing unconventional oil reserves and production worldwide. In 2012, Exxon drilled the world’s deepest oil well on Russia’s Sakhalin Island—40,502 feet below the surface.95 Brazil and the US Gulf of Mexico hold the world’s largest recoverable reserves.96 As long as the associated gas in these fields is not vented or flared, ultradeep oil tends to have relatively low GHG emissions given the high natural pressure that facilitates oil extraction.

The use of floating production storage and offloading (FPSO) vessels has become increasingly common, especially for the production of deepwater and ultradeep offshore oil and gas resources that are largely exported. FPSO vessels have processing equipment on deck and hydrocarbon storage below board, are moored in place, and can rotate freely like a weathervane. An FPSO vessel offloads processed oil and gas to either a tanker or pipeline.97 The largest climate risk from FPSO vessels is methane leakage and flaring, and NASA has developed new techniques that can now monitor methane over reflective water surfaces using satellites and remote sensing devices.98

Arctic Oil: Back to the North Pole

More oil than gas is currently produced from the fragile Arctic. Together, just over 1 million barrels per day of oil and NGLs are marketed by the United States, Russia, and Norway.99 Installing infrastructure and operating there elevate climate risks due to melting ice and permafrost that then release significant amounts of stored CO2 and methane.

Although the first Arctic oil deposits were discovered in 1920 in Canada’s Northwest Territories, it was not until the early 1960s that BP drilled the first oil wells in the US Arctic (in Alaska). A decade later, the Trans-Alaska Pipeline was completed, sending Arctic oil to the United States. Exploratory drilling followed in the Canadian Arctic (on Melville Island) and the Russian Arctic (in Western Siberia). The first shipment of Russian Arctic oil to Europe commenced in 2014. Back in 2000, oil was discovered in the Norwegian Arctic (in the Barents Sea). The Arctic also contains several large deepwater oil fields with some of the world’s greatest drilling depths.100

Ongoing development in the Arctic has been erratic. In 2015, for example, Shell pulled out of the Arctic citing disappointing prospects, high costs, and mounting public opposition.101 BP sold off its assets in 2019.102 Conversely, in 2020, the Russian government began offering new incentives for Arctic oil and gas development.103 And ConocoPhillips, Equinor, and others have continued to pump oil and gas from Alaska’s North Slope over the past forty years while Hilcorp Energy is upping its presence. Despite recent well failure linked to thawing permafrost,104 development is more easily expanded once infrastructure is in place in sensitive ecosystems.105

Depleted Oil: Boosting Recovery

As oil and gas reservoirs decline, it takes more effort to extract their remaining resources. EOR is the third stage of the extracting process, following immediate (primary) and subsequent (secondary) extraction efforts.106 Depending on the characteristics of a given reservoir, production costs, and market conditions, EOR can liberate hard-to-produce oil remaining in place. There are between 350 and 400 active EOR projects around the world that account for 2 million barrels of oil per day.107 The three commercialized EOR categories include thermal recovery, gas injection, and chemical injection. EOR tends to require large energy inputs and have elevated climate risks unless GHGs are sequestered.

Thermal recovery uses steam, fire, or electric heat to make viscous oil flow. California’s heavy oil is injected with steam that operators make using natural gas. Substituting concentrated solar steam can significantly lower GHG emissions.108 Fire flooding, another thermal method, ignites the oil underground to make it flow by cracking heavy hydrocarbons, vaporizing lighter hydrocarbons, and turning entrained water into steam. Such in situ combustion may sound novel, but it is the oldest thermal recovery technique in the book and has been applied over the past century in Russia, Romania, India, Kazakhstan, Azerbaijan, Canada, and the United States.109

Gas injection uses CO2, natural gas, nitrogen, or exhaust flue gases that expand in a reservoir and push out additional oil. Gases also dissolve in oil to make it less viscous. In the United States, gas injection dominates most EOR production. Recently, EOR using CO2 has emerged because it simultaneously increases oil production and sequesters carbon. Its climate risks depend on the source of CO2. Anthropogenic CO2 from manmade sources such as direct air capture or industrial exhaust have net-negative GHG emissions. But CO2 obtained from natural reservoirs or producing acid gas exacerbates climate problems.

Chemical injection introduces manufactured molecules, such as polymers or detergents, into a reservoir to enable oil flow. This EOR technique is more expensive, is less predictable, and has greater climate uncertainties compared to other methods. Additional techniques are under development, including microorganisms (microbial EOR) that digest and transform the oil itself and enhance production as well as nanotechnology—using metal oxides, organic particles, and inorganic particles—to increase mobility, reduce viscosity, and shift internal reservoir forces.110 Expanding data analytics by companies like Amazon and others could help further improve cutting-edge EOR methods aimed at recovering not only depleted oil but also a growing share of the world’s remaining oil in place.111 Future EOR techniques that access only hydrogen and leave the carbon in place would be a game changer for slashing the GHG emissions of such oil and gas extraction.

Kerogen: Unformed and Immature

Kerogen contains solid hydrocarbons woven into sedimentary rock. It takes millions of years to mature and turn into oil and gas.112 By baking (or retorting) kerogen into select liquid hydrocarbons, engineers can accelerate this natural process.113 Turning immature oil shale into synthetic crude oil, gasoline, or diesel takes huge amounts of energy. Therefore, GHG emissions from mining, retorting, and refining oil shale are estimated to be as much as twice those of conventional oil.114

Oil shales are buried around the globe, but Estonia accounts for the majority of the world’s current oil shale production.115 Elsewhere, it takes high oil prices to spur oil shale development. In the late 1970s, the US Congress created a synthetic fuels program to jumpstart production of oil shale, which was subsequently shuttered when oil prices fell in the mid-1980s. In the mid-2000s, the US government awarded six oil shale leases on public lands in Colorado and Utah. The companies involved pulled out one by one, turning instead to fracking shale oil and developing deepwater gas.116 A sustained effort requiring ongoing government commitments and financial incentives will be needed for companies or countries to make long-term commitments to future oil shale developments around the world.

Other hurdles besides climate risks and costs exist. Oil shales contain toxic levels of sulfur, nitrogen, arsenic, iron, and nickel. Underground (in situ) operations that use earthen chambers to retort oil shale can contaminate groundwater. Above-ground (ex situ) methods have waste disposal problems, damage habitats, consume significant water in arid regions, and have restoration issues like coal mining does.

These are all important considerations because oil shale resources in place could contain more energy than the combined total of all other oil sources on Earth—roughly 30 trillion barrels of oil.117 But the climate and other environmental risks of oil shale mean that this supply may come at too high a cost.

Biofuels: From Plants to Fuels

Aside from the aforementioned categories, there are other subtypes of unconventional hydrocarbons that must be converted into a usable state using various methods. These include biofuels as well as CTLs and GTLs.

Biomass-based liquid fuels (biofuels) have also existed since cars were first introduced in the early twentieth century. Henry Ford himself once claimed that “the fuel of the future is going to come from fruit [because] there is fuel in every bit of fermentable vegetable matter.”118 Biofuel sources include food, food waste, nonedible plants, grass, and algae.

All biofuel production employs chemical reactions and heat to break down hydrocarbons and refine them into petroleum products. In 2019, just under 2 million barrels per day of ethanol was produced fermenting sugarcane in Brazil and starchy crops (such as corn) in the United States.119 Meanwhile, nearly 1 million barrels per day of biodiesel is currently being made from seed oils, including palm oil in Indonesia, the United States, Brazil, and numerous EU nations.120 In the United States, older refineries are being renovated to make renewable diesel and jet fuel from waste oils and animal fats.121 First-generation biofuels require large energy inputs and have not been found to reduce GHG emissions compared to conventional oil.122 Next-generation biofuels that convert cellulose in the cell walls of plants could reduce climate impacts and food security concerns, but air pollution could remain challenging because ethanol contributes to local smog formation.123

GTLs and CTLs: Turning Gas and Coal into Petroleum Fuels

Liquid fuels have a higher market value than natural gas. This economic proposition has spurred the complex conversion of gas to liquids, especially in countries that do not have ample oil resources, such as Germany and South Africa. Modern GTL technology is based on the Fischer-Tropsch process,124 which builds simple gaseous hydrocarbons into long-chain liquid fuels using a catalyst.125 The world’s largest GTL plant is located in Qatar and processes 1.6 billion cubic feet per day of gas from twenty-two offshore wells into 120,000 barrels per day of NGLs and ethane and 140,000 barrels per day of other assorted GTL products such as jet fuel and diesel.126 Different pathways of GTLs have variable GHG emissions. But higher energy inputs can increase the climate impacts of GTLs upward of 25 percent compared to conventional oil.127 Methane leakage is a major determinant of climate risk.

Meanwhile, coal is mostly used worldwide to generate electricity, but CTLs can also be obtained by converting this solid hydrocarbon, directly or indirectly, into diesel and gasoline. Direct liquefaction uses solvents to dissolve coal under high temperatures and pressure into a liquid that is refined into fuels. Indirect methods gasify coal and turn it into syngas, which is then converted into liquid fuels using the Fischer-Tropsch process. Countries with large coal reserves—such as China, India, the United States, and Australia—have advanced CTL production capabilities. The high economic costs and environmental impacts of CTLs have limited their applications worldwide. Efforts are underway to combine coal and biomass to convert these resources into liquids. When coupled with successful CCS, CTL could emit 5 to 10 percent fewer GHGs than conventional oil does. Without CCS, the climate penalty of CTL could be “twice” as high as that of conventional oil.128

Unconventional oils, like their gas counterparts, are likely to account for a growing share of future production. This general trend means that unless the outsized climate impact of such resources is closely charted, the industry is at risk of greatly increasing their climate impact throughout the oil supply chain from production to processing to shipping.

The Climate Footprints of Conventional and Unconventional Hydrocarbons

The oil and gas industry currently emits a reported 5.2 gigatonnes (Gt) of CO2e emissions annually by producing, transporting, and processing hydrocarbons.129 This figure excludes emissions from end-use consumers like motorists, truckers, and airlines. It also significantly undercounts the contribution from methane emissions.130 Unconventional oil and gas have wide-ranging GHG intensities that are previewed here and analyzed in detail in forthcoming chapters.

Collectively, if unconventional hydrocarbons (including both oil and gas) replace conventional resources by midcentury without effective mitigation measures in place, supply-side climate footprints are estimated to triple in size. Figure 2.2 plots the nearly 200 Gt CO2e that are poised to be cumulatively emitted from the development of technically recoverable unconventional oil and gas between 2030 and 2050 if current demand for these resources persists. GHG emissions of this magnitude represent a major share of the remaining carbon budget of safe levels of emissions that can be produced while still limiting global warming.131


FIGURE 2.2 Estimated Cumulative Industry GHG Emissions for Conventional versus Unconventional Oil and Gas Resources (2030–2050)

Notes: Industrial oil and gas sector emissions plotted do not include end-use fuel consumption. The numbers in Table 2.2 were used to calculated 10 percent of technically recoverable oil and gas through 2040 without climate mitigation measures imposed. Adjustments were made to volumes for methane hydrates (lowered due to technical barriers), EOR (lowered due to depletion rate), oil shale/kerogen (lowered due to technical barriers), and condensates (increased due to fracking outside the United States). Small sample of industrial supply-side GHG emissions only (production, refining, processing, and shipping) used to calculate average emission intensities. CO2e, carbon dioxide equivalent; EOR, enhanced oil recovery; GHG, greenhouse gas.

Sources: Author’s calculations, using the OCI+ model.

The Ultimate Unconventional

All this talk of the climate footprints of unconventional forms of oil and gas raises the question of whether or not there may be other, more climate-friendly alternatives. In 1980, I worked in a chemical engineering laboratory at the University of Colorado researching hydrogen—a simple, plentiful, carbon-free molecule with high energy content that was all the rage following the second energy crisis and resulting spike in oil prices. Back then, economics were not on hydrogen’s side. The precious metal catalysts, like platinum, that I used to boost the efficiency of chemical reactions were rare and costly. Hydrogen’s prospects are much more favorable today, given cheap renewable electricity, more catalyst options, and major climate concerns.132

Hydrogen can be made from renewables, and it emits only water when burned, eliminating carbon from the energy equation. Hydrogen can also be used to produce heat, store surplus renewable power, and serve as a chemical feedstock, and can be used as a component of fuel cells (for chemical batteries) to generate electricity (for both vehicles and stationary sources).

This simple element does not exist alone, however; it is locked up in enormous quantities of water, hydrocarbons, and other organic matter.133 Its climate risks depend on the carbon content of its source; the energy intensity of the separation processes used; and the leakage rate of CO2, methane, and other GHGs. The seemingly harmless water vapor that hydrogen forms when combusted is itself a weak GHG, as discussed in chapter 3.

Shades of Hydrogen

Hydrogen is produced via different pathways.134 Producing what is termed black hydrogen entails cracking coal and oil, while another method is to split methane gas via steam methane reforming (SMR). Its large energy inputs and vented CO2 generate high GHG emissions. Gray hydrogen also uses fossil fuels and vents CO2, but it substitutes renewable energy to generate steam, slightly lowering its GHG emissions. Natural gas (SMR) accounts for roughly half of current hydrogen production worldwide, while the rest is made from oil (30 percent) and coal (18 percent).135 New petrochemical pathways with uncertain climate risks could capture hydrogen shed when ethane is cracked to form ethylene.

Blue hydrogen is formed by splitting methane gas using catalysts while sequestering or utilizing the carbon.136 Because it still involves methane, blue hydrogen presents considerable climate risks. By contrast, green hydrogen produced from the electrolysis of water powered by wind, sun, or other clean forms of electricity presents the fewest GHG emissions. Green hydrogen exemplifies a truly circular economy whereby water yields hydrogen, which is then combusted back into water.137 Table 2.6 estimates GHG emissions from several hydrogen pathways using different feedstocks and processes.138

Table 2.6 Estimated Lifecycle GHG Emissions for Hydrogen Production Pathways

Production Pathway

Gaseous Hydrogen

Liquid Hydrogen

Commercialization Timeframe

Operational Scope

Grid Electrolysis



5 years


Animal Manure



20 years







Landfill Gas



5 years


Biomass Gasification



10 years


Solar Electrolysis



10–20 years


Wastewater Treatment



10–20 years


Notes: Assumes well-to-tank GHG emissions for centralized production pathways. GHG estimates from Intergovernmental Panel on Climate Change, AR4 systematically undercount emissions because the GWP used for methane is out of date.

GHG, greenhouse gas; GWP, global warming potential; SMR, steam methane reforming.

Source: Marshall Miller, Arun Raju, and Partho Sorothi Roy, “The Development of Lifecycle Data for Hydrogen Fuel Production and Delivery,” University of California, Davis, National Center for Sustainable Transportation and Institute of Transportation Studies, October 2017 (Used CA-GREET Tier 2, Life Cycle Analysis Model), https://escholarship.org/uc/item/3pn8s961.

Shifting the Focus on Unconventionals

Oil and gas have dominated energy and commodities markets for well over a century, but hydrogen possesses the flexibility and protection humanity will need in the future. Hydrogen can be used as energy carriers (fuel), storage devices (batteries), and feedstocks (inputs) to produce petrochemicals, fuels, and other goods.139 If produced using renewables, green hydrogen can cut carbon out of the process and safeguard the climate.

Oil refineries are today’s largest consumers of hydrogen (generated using SMR) to crack and treat crude to meet low-sulfur fuel specifications. Hydrogen consumption in US refineries increased by 60 percent between 2008 and 2014, and demand keeps growing.140 This may explain why oil companies, such as Shell and Equinor, are investing in a clean hydrogen future.141 Other industrial actors—automakers, chemical manufacturers, and steelmakers, as well as governments and banks in Europe, Asia, and elsewhere—foresee a future for green hydrogen production from excess renewable energy generation.142

Someday, hydrogen fuel will be key to powering rockets. Green hydrogen markets could become sizable, if and when commercial space travel takes off. Hydrogen for midcourse space refueling could be accomplished with technologies to convert water into hydrogen- and oxygen-based fuels.143

Academic research and government research and development (R&D) are underway on breakthrough technologies that could attract oil industry capital to transition energy markets.144 Refining oil and natural gas underground using nanoscale microbes, catalysts, and biotechnology could sequester the carbon in place and produce green hydrogen from fossil fuels.145 These areas of R&D are central to a clean-energy paradigm shift in the world marketplace.

Shrinking the climate footprints of unconventional oil and gas supplies is a top near-term priority. Over the long term, it will be critical to prevent the bounty of unconventional hydrocarbons from wreaking havoc on the climate. As discussed in chapter 3, new tools have been developed to assess the GHG emissions of different types of oil and gas, identify where in the petroleum supply chain emissions can be reduced, and help guide the world along the path to a clean energy transition.

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