The energy transition and the petroleum engineer

At the end of Ethan's first year, his manager asks him to join a small team studying new business for Prairie Crest. Three ideas are on the table: storing carbon dioxide from a nearby fertilizer plant in a depleted part of the Tamarack Lake field, extracting lithium from the salty water that the field already produces, and testing whether two deep, abandoned wells could supply heat to a greenhouse. All three use what petroleum engineers already know: how fluids move through rock, how wells are drilled and completed, and how to keep fluids where they belong. This lesson looks at how the energy transition is changing the industry and the profession.

Oil and gas in a changing energy system

The world is trying to cut greenhouse gas emissions while energy demand continues to grow, especially in developing countries. Renewable electricity, electric vehicles and heat pumps are growing quickly, and forecasters disagree widely about how fast oil and gas demand will peak and decline. Most scenarios, including ambitious ones, still show substantial oil and gas use for decades, for transportation, petrochemicals, industrial heat and as backup for electricity grids. At the same time, existing fields decline every year, so new investment is needed simply to hold production steady.

For producers, this means two pressures at once. They must keep producing efficiently and profitably, and they must cut the emissions from their own operations, which come mainly from combustion in engines, heaters and compressors, from flaring, and from methane leaks and venting. Investors, lenders and governments increasingly expect companies to measure and report these emissions, to reduce their intensity per barrel and to plan for a lower-carbon future. Many companies have set targets to eliminate routine flaring and cut methane emissions sharply, as Lesson 11 described.

Carbon capture and storage

Carbon capture and storage (CCS) separates carbon dioxide from an industrial source, compresses it and injects it into deep rock formations where it is trapped permanently. It is the most direct application of petroleum engineering to emissions reduction. Suitable storage sites are deep saline aquifers or depleted oil and gas reservoirs, generally below about 800 m, where pressure and temperature keep the carbon dioxide in a dense, supercritical state that takes up far less space than gas. A thick seal above the formation, the same kind of seal that held oil for millions of years, keeps it in place.

Once injected, carbon dioxide is held by several mechanisms that strengthen over time. Structural trapping holds the buoyant plume beneath the seal, like oil in a trap. Residual trapping strands small bubbles in pore spaces as the plume moves. Solubility trapping dissolves carbon dioxide into the formation water, making it denser so that it sinks. Mineral trapping, over hundreds to thousands of years, converts some of it into solid carbonate minerals. Engineers model the plume's growth, design injection wells, monitor pressure and the plume with seismic surveys and monitoring wells, and plan for the site's eventual closure.

Alberta has two of the world's longest-running CCS projects. Quest, at the Scotford upgrader near Edmonton, has injected about a million tonnes a year since 2015 into a deep saline formation, and the Alberta Carbon Trunk Line carries carbon dioxide from a fertilizer plant and a refinery to enhanced oil recovery projects in central Alberta. The province has granted carbon sequestration tenure for dozens of storage hubs. The largest proposal, the Pathways Alliance project to capture emissions from oil sands facilities and store them near Cold Lake, would store up to 22 million tonnes a year; under the 2025 agreement with Ottawa, its first phase is linked to new pipeline capacity and targeted for the 2030s. Federal investment tax credits and the provincial industrial carbon price provide the economic incentive.

# Saline-formation storage capacity and years of injection
def capacity_t(area_km2, thickness_m, porosity, efficiency, rho_co2):
    pore = area_km2 * 1e6 * thickness_m * porosity
    return pore * efficiency * rho_co2 / 1000        # tonnes

cases = [  # label, area km2, thickness m, porosity, CO2 density kg/m3, injection Mt/yr
    ('small area, thin sand', 30, 25, 0.18, 650, 0.4),
    ('same area, thick sand', 30, 60, 0.20, 700, 0.4),
    ('regional hub', 400, 60, 0.20, 700, 2.0),
]
for label, a, h, phi, rho, rate in cases:
    print(f"{label}:")
    for eff in (0.01, 0.02, 0.04):
        cap = capacity_t(a, h, phi, eff, rho)
        print(f"   efficiency {eff:4.0%}: {cap / 1e6:6.1f} million tonnes = {cap / 1e6 / rate:5.1f} years at {rate} Mt/yr")

# Volume reduction from surface gas to supercritical storage
rho_surface = 1.87          # kg/m3 at 15 C and 1 atm
print(f"\nOne tonne of CO2: {1000 / rho_surface:,.0f} m3 as gas at the surface, "
      f"{1000 / 700:.2f} m3 at 700 kg/m3 in the formation")

small area, thin sand:
   efficiency   1%:    0.9 million tonnes =   2.2 years at 0.4 Mt/yr
   efficiency   2%:    1.8 million tonnes =   4.4 years at 0.4 Mt/yr
   efficiency   4%:    3.5 million tonnes =   8.8 years at 0.4 Mt/yr
same area, thick sand:
   efficiency   1%:    2.5 million tonnes =   6.3 years at 0.4 Mt/yr
   efficiency   2%:    5.0 million tonnes =  12.6 years at 0.4 Mt/yr
   efficiency   4%:   10.1 million tonnes =  25.2 years at 0.4 Mt/yr
regional hub:
   efficiency   1%:   33.6 million tonnes =  16.8 years at 2.0 Mt/yr
   efficiency   2%:   67.2 million tonnes =  33.6 years at 2.0 Mt/yr
   efficiency   4%:  134.4 million tonnes =  67.2 years at 2.0 Mt/yr

One tonne of CO2: 535 m3 as gas at the surface, 1.43 m3 at 700 kg/m3 in the formation

Carbon dioxide has also been used for decades in enhanced oil recovery. Injected into an oil reservoir at high pressure, it mixes with the oil, swells it and lowers its viscosity, freeing oil that water cannot move. A large share of the injected carbon dioxide remains in the reservoir. Projects in West Texas have used it since the 1970s, and the Weyburn and Midale projects in Saskatchewan stored tens of millions of tonnes while producing oil. Whether such projects reduce emissions overall depends on how the carbon dioxide is sourced and how the produced oil is counted, a question debated by policymakers.

Geothermal energy

Geothermal energy uses the earth's heat. Conventional geothermal power needs hot water close to the surface, found only in volcanic regions. Newer approaches use oilfield techniques to reach heat almost anywhere. Enhanced geothermal systems drill pairs of deep horizontal wells into hot, dry rock, fracture the rock between them and circulate water through the fractures to collect heat; a commercial project in Utah using multistage fracturing borrowed directly from shale development has demonstrated much higher flow rates than earlier attempts. Closed-loop systems circulate fluid through sealed wellbores without contacting the rock. Low-temperature systems use warm water from sedimentary basins for district heating, greenhouses and industrial processes.

Alberta passed the Geothermal Resource Development Act in 2020 and assigned geothermal regulation to the AER. Several projects use deep wells in the Western Canada Sedimentary Basin, where formations at 3,000 to 4,000 m can exceed 100 °C, and some test the reuse of old oil and gas wells. The province's large pool of drilling expertise, rigs and service companies is a major advantage.

Hydrogen, lithium and other opportunities

Hydrogen is a fuel that produces only water when burned or used in a fuel cell. Most hydrogen today is made from natural gas by steam reforming, which emits carbon dioxide; capturing and storing that carbon dioxide produces so-called blue hydrogen. Green hydrogen is made by splitting water with renewable electricity. Either way, hydrogen may need large-scale storage, and salt caverns and depleted gas reservoirs, developed and operated with petroleum engineering methods, are candidates. A related topic is natural, or geologic, hydrogen, generated in some rocks and now being explored with wells.

Critical minerals offer another link. Some formation waters contain lithium, used in batteries, at concentrations high enough to extract. Brines from the Devonian Leduc Formation and other units in Alberta have attracted lithium projects that would produce brine through wells, extract the lithium with direct extraction technologies and reinject the water. These projects need reservoir engineers to estimate brine volumes and deliverability, drilling and completion engineers to build the wells and facilities engineers to handle large volumes of corrosive water, the same skills used in oil and gas.

The petroleum engineer's career

The profession has gone through many booms and busts, driven by oil prices, and it will continue to change. The core skills remain in demand: understanding subsurface uncertainty, designing wells and facilities safely, working with data and economics, and managing risk. Data science and automation are now part of daily work, from machine learning on production data to automated drilling rigs and remote operations. Employers value engineers who can communicate with landowners, regulators, investors and the public, because the industry's licence to operate depends on trust.

For Ethan, the first year has covered the whole life of a well, from the geology that made the oil to the plugs that will seal it. Whether he spends his career producing oil and gas, storing carbon dioxide, drilling for heat or cleaning up old wells, the same principles apply: measure carefully, respect the uncertainty, keep fluids where they belong and leave the land as you found it. The rest of the petroleum engineering program, from rock and fluid properties to reservoir simulation and the capstone design, builds those principles into professional competence.

Professional bodies and universities are adapting too. Petroleum engineering programs now include courses on carbon storage, geothermal systems and data analytics, and professional societies publish standards and guidelines for these new applications. Licensing bodies expect engineers to practise only within their competence, so moving into a new field means learning its specific rules and risks, often through formal training and mentoring.