What Is Fracking? Hydraulic Fracturing Explained

Hydraulic fracturing means pumping water, sand and a small share of chemicals into a well at high pressure to crack open dense shale rock, with the sand propping those cracks open so trapped oil and gas can flow out. On its own it is old technology, first used commercially in 1949. What changed the world was pairing it with horizontal drilling — steering the well sideways through a thin shale layer for a mile or more — which exposes vastly more rock to each fracture job.

A conventional well finds oil that has already migrated into a porous reservoir and flows to the surface under its own pressure. Shale is the source rock itself: the oil never migrated out, and the rock is so impermeable that nothing flows without help. So instead of tapping a pool, a shale well manufactures permeability by shattering the rock along a long horizontal leg. That is why a conventional well can produce for decades at a gentle decline while a shale well loses 60 to 70 per cent of its output in the first year.

It turned the United States from a declining importer into the world's largest producer — from 4.95 million barrels a day at the 2008 trough to over 13 million today — and made it the biggest LNG exporter too. Just as important is the speed: a shale well goes from spud to first oil in one to four months, against years for a deepwater or oil-sands project. That short cycle made US shale the swing supply that answers high prices, which structurally weakened OPEC's ability to set them.

Producers told the Dallas Fed they need roughly $62 to $70 a barrel of WTI to profitably drill a NEW well, depending on the play, but only around $39 to $45 to keep pumping a well that already exists. That gap matters enormously: when prices fall, companies stop drilling long before they stop producing, so output keeps rising for months after the rig count turns down. The interactive table on this page compares those thresholds against the current WTI price.

The Permian Basin of West Texas and southeastern New Mexico, by an enormous margin — around 6.5 million barrels a day, more than every OPEC member except Saudi Arabia, and more than the Bakken, Eagle Ford, Niobrara and Anadarko combined. Its advantage is stacked pay: several productive layers sit on top of one another, so a single surface location can drill many wells into different depths.

Ten to twenty million gallons for a modern long-lateral well, which is roughly 15 to 30 Olympic swimming pools. Nationally that is a small fraction of what agriculture uses, but the framing that matters is local: the water is drawn in concentrated bursts in arid basins like the Permian, where it competes with farming and towns. Operators increasingly recycle produced water back into the next frac to reduce both freshwater draw and disposal volumes.

The fracture itself occurs two to three kilometres down, far below aquifers that sit in the top few hundred metres, and the EPA's national study found no evidence of widespread systemic contamination of drinking water. It did identify real, documented local cases — and those came overwhelmingly from failed well casings and cement, surface spills of fluid or produced water, and poor wastewater handling. In other words the risk is genuine but it is an engineering and operational failure mode, not the fracturing reaching up through kilometres of rock.

Injecting fluid underground does, and the link is firmly established — but the main culprit is wastewater DISPOSAL into deep injection wells rather than the fracturing itself. Oklahoma is the clearest case: magnitude 3.0+ earthquakes rose from about 20 a year to 903 in 2015, and fell back sharply after regulators cut disposal volumes. Fracturing can trigger small tremors directly, which is what led the UK to halt operations at Preston New Road.

Burning gas emits roughly half the CO2 of coal per unit of electricity, which is why US power-sector emissions fell as gas displaced coal. The catch is methane: unburned natural gas is a far more potent greenhouse gas than CO2 over a twenty-year horizon, so the advantage depends on keeping leakage low across the whole supply chain. Aerial measurement studies have repeatedly found leakage above official inventory estimates — one widely cited 2018 study put it near 2.3 per cent of gross production — which is why methane rules are the pivotal climate question for shale.

Jurisdictions weigh the same local risks differently. France, Bulgaria, Germany and the Netherlands ban it, as do New York and Maryland, while Texas, North Dakota and Pennsylvania host it at scale; the UK has an on-again, off-again moratorium tied to induced seismicity. The bans generally reflect precaution about water, seismicity and climate policy — plus the simple fact that dense, populated places bear the local costs without the geology to make it worthwhile — rather than one decisive incident.

Not imminently, but the character has changed. The best acreage — the "core of the core" — has largely been drilled, so operators are working tier-two rock and relying on longer laterals, denser fracs and consolidation to keep costs down. Record output now comes on far fewer rigs than the 2014 peak, which is a productivity story rather than an expansion one. The EIA still projects US crude production rising modestly through the forecast horizon.