Exploration and production, commonly called E&P, refers to the first major phase of the oil and gas industry: finding hydrocarbon reserves underground and then extracting them. It’s also known as the “upstream” sector, distinguishing it from the midstream (transportation) and downstream (refining and marketing) segments. In 2024, the global upstream industry generated $625 billion in cash from operations and spent $343 billion in capital expenditure, making it one of the most capital-intensive businesses in the world.
How Exploration Works
Before any drilling begins, companies need to figure out where oil and gas might actually be. Exploration is the detective work: locating underground rock formations that are likely to contain hydrocarbons. The primary tool is seismic surveying, which works by sending sound waves into the earth and recording how they bounce back. The reflections create a picture of the rock layers below the surface, revealing structures that could trap oil or gas.
Seismic surveys come in two main forms. 2D seismic reflection surveying produces a cross-sectional slice of the subsurface, useful for early-stage scouting. 3D seismic reflection surveying captures a full three-dimensional image, giving geologists a much more detailed view of the reservoir’s shape, size, and depth. Companies use this data, combined with geological mapping and sometimes electromagnetic surveys, to decide whether a site justifies the enormous cost of drilling an exploratory well.
Even with advanced imaging, exploration carries real financial risk. Many exploratory wells come up dry. The ones that do find commercially viable quantities of oil or gas are called “discovery wells,” and they kick off the transition from exploration into development and production.
The Production Phase
Once a reservoir is confirmed, production is the process of actually getting oil and gas out of the ground. This happens in up to three distinct stages, each pulling a different percentage of what’s trapped in the rock.
Primary recovery relies on the reservoir’s own natural pressure, or gravity, to push oil toward the wellbore. Pumps (called artificial lift) help bring it to the surface. This stage typically recovers only about 10% of the oil originally in the reservoir.
Secondary recovery extends the field’s life by injecting water or gas into the reservoir. This displaces oil and drives it toward production wells. Between primary and secondary methods, operators typically recover 20 to 40% of the original oil in place.
Tertiary recovery, also called enhanced oil recovery (EOR), uses more advanced techniques to coax out oil that the first two stages left behind. EOR can ultimately bring total recovery to 30 to 60% or more. Three commercially proven approaches dominate:
- Gas injection pumps natural gas, nitrogen, or carbon dioxide into the reservoir to either push oil toward wells or dissolve into the oil to make it flow more easily. This accounts for nearly 60% of U.S. EOR production.
- Thermal recovery introduces heat, usually steam, to thin out heavy, viscous oil so it moves through rock more readily. This makes up over 40% of U.S. EOR production, concentrated primarily in California.
- Chemical injection uses polymers or detergent-like compounds to improve waterflooding or reduce the surface tension that traps oil droplets in rock pores. It represents about 1% of U.S. EOR production.
Modern Drilling Techniques
Conventional vertical wells drill straight down into a reservoir. But much of today’s E&P activity, especially in shale formations, relies on horizontal drilling. A horizontal well starts vertically, then gradually curves 90 degrees until the wellbore runs sideways through the target rock layer. That horizontal section typically extends 5,000 feet or more, exposing far more of the oil- or gas-bearing formation than a vertical well ever could.
Guiding a drill bit through a precise curved path thousands of feet underground requires real-time measurement systems. Operators use tools that transmit data about the wellbore’s direction and angle back to the surface while drilling is underway. Motor assemblies steer the bit through the curved section, and the drilling program specifies exact build angles and lengths for each segment of the well’s trajectory.
In tight rock formations like shale, horizontal drilling is paired with hydraulic fracturing. After the horizontal section is drilled, the rock along its length is fractured mechanically, creating pathways for trapped oil and gas to flow into the wellbore and up to the surface. This combination unlocked vast reserves that were previously uneconomical, particularly in U.S. shale plays.
Some wells go further with multilateral designs, where additional side wells branch off from the main wellbore to reach different parts of the reservoir from a single surface location.
Offshore vs. Onshore Production
E&P happens both on land and at sea, and the economics differ significantly. Onshore production in the Middle East remains the cheapest source of new supply, with average breakeven prices around $30 per barrel. Deepwater offshore, once considered prohibitively expensive, has seen dramatic cost reductions. Average deepwater breakeven prices have fallen to about $43 per barrel, making it the second-cheapest source of new production and actually less expensive than some onshore plays.
Across all major upstream segments, unit costs have dropped roughly 30% compared to 2014 levels. This shift reshaped investment decisions: deepwater projects that were shelved during the 2014 oil price crash became viable again as operators streamlined designs and improved drilling efficiency.
Offshore operations require massive infrastructure (platforms, subsea pipelines, floating production vessels) and face harsher operating conditions, including storms, deep-sea pressure, and the logistical challenge of working far from shore. Onshore operations are generally simpler to set up but come with their own challenges, including land access, water sourcing for hydraulic fracturing, and community impact.
Environmental Regulation
The oil and gas industry is the largest industrial source of methane, a potent greenhouse gas, and of volatile organic compounds that contribute to smog. In the United States, the EPA regulates air pollution from onshore oil and gas operations under the Clean Air Act, with rules targeting equipment and activities across the upstream sector. The agency’s 2024 rules (known as OOOOb and OOOOc) expanded requirements for monitoring and reducing methane emissions from wells, storage tanks, and other infrastructure.
Beyond air quality, E&P operations face regulations covering water use and disposal, well integrity, land disturbance, and site remediation after a well is decommissioned. The specific regulatory framework varies by country and, in the U.S., by state.
Technology Reshaping E&P
The upstream sector increasingly relies on digital tools to manage risk and improve efficiency. One prominent example is digital twin technology, where operators build a virtual replica of a physical asset, such as a production facility or reservoir, that mirrors its real-time behavior. These digital models integrate sensor data and predictive algorithms to flag abnormal conditions before they cause equipment failures or safety incidents. Machine learning techniques like gradient-boosted tree algorithms have proven effective for predictive modeling in these systems, helping operators move from reactive maintenance to proactive risk management.
Other technologies now standard in E&P include real-time drilling data analytics, automated well control systems, and remote monitoring that allows engineers to oversee multiple offshore platforms from a single onshore control room.
The Economics of E&P
Exploration and production is a cyclical, capital-heavy business. Companies spend billions before a single barrel is sold, funding seismic surveys, drilling rigs, well completions, and production infrastructure with no guarantee of commercial returns. In 2024, global upstream capital expenditure fell 14% from the prior year to $343 billion, while cash from operations dropped 10% to $625 billion. Dividends to shareholders also declined, falling to $135 billion.
These swings reflect the industry’s sensitivity to commodity prices. When oil prices are high, companies ramp up drilling and exploration. When prices fall, capital spending contracts quickly. This boom-and-bust pattern defines the financial rhythm of E&P and influences everything from rig counts to employment in oil-producing regions.