Onshore production is economically viable from a few dozen barrels of oil a day and upward. Oil and gas is produced from several million wells worldwide. In particular, a gas gathering network can become very large, with production from thousands of wells, several hundred kilometers/miles apart, feeding through a gathering network into a processing plant. This picture shows a well, equipped with a sucker rod pump (donkey pump) often associated with onshore oil production. However, as we shall see later, there are many other ways of extracting oil from a non free-flowing well. For the smallest reservoirs, oil is simply collected in a holding tank and picked up at regular intervals by tanker truck or railcar to be processed at a refinery.

Onshore wells in oil-rich areas are also high capacity wells producing thousands of barrels per day, connected to a 1,000,000 barrel or more per day GOSP. Product is sent from the plant by pipeline or tankers. The production may come from many different license owners, so metering of individual well-streams into the gathering network are important tasks.

Unconventional plays target very heavy crude and tar sands that became economically extractable with higher prices and new technology. Heavy crude may need heating and diluents to be extracted. Tar sands have lost their volatile compounds and are strip-mined or can be extracted with steam. It must be further processed to separate bitumen from the sand. Since about 2007, drilling technology and fracturing of the reservoir have allowed shale gas and liquids to be produced in increasing volumes. This allows the US in particular to reduce dependence on hydrocarbon imports. Canada, China, Argentina, Russia, Mexico and Australia also rank among the top unconventional plays. These unconventional reserves may contain more 2–3 times the hydrocarbons found in conventional reservoirs. These pictures show the Syncrude Mildred plant at Athabasca, Canada and the Marcellus Shale in Pennsylvania.

A whole range of different structures is used offshore, depending on size and water depth. In the last few years, we have seen pure sea bottom installations with multiphase piping to shore, and no offshore topside structure at all. Replacing outlying wellhead towers, deviation drilling is used to reach different parts of the reservoir from a few wellhead cluster locations.

Some of the common offshore structures are:

Shallow water complex, which is characterized by several independent platforms with different parts of the process and utilities linked with gangway bridges. Individual platforms include wellhead riser, processing, accommodations and power generation platforms. (This picture shows the BP Valhall complex.) Typically found in water depths up to 100 meters.

Gravity base consists of enormous concrete fixed structures placed on the bottom, typically with oil storage cells in a "skirt" that rests on the sea bottom. The large deck receives all parts of the process and utilities in large modules. Large fields at 100 to 500 meters of water depth were typical in the 1980s and 1990s. The concrete was poured at an onshore location, with enough air in the storage cells to keep the structure floating until tow-out and lowering onto the seabed. The picture shows the world's largest GBS platform, Troll A, during construction.

Compliant towers are much like fixed platforms. They consist of a narrow tower, attached to a foundation on the seafloor and extending up to the platform. This tower is flexible, as opposed to the relatively rigid legs of a fixed platform. Flexibility allows it to operate in much deeper water, as it can absorb much of the pressure exerted by the wind and sea. Compliant towers are used between 500 and 1,000 meters of water depth.

Floating production, where all topside systems are located on a floating structure with dry or subsea wells. Some floaters are:

FPSO: Floating Production, Storage and Offloading. Their main advantage is that they are a standalone structure that does not need external infrastructure such as pipelines or storage. Crude oil is offloaded to a shuttle tanker at regular intervals, from days to weeks, depending on production and storage capacity. FPSOs currently produce from around 10,000 to 200,000 barrels per day.

An FPSO is typically a tanker type hull or barge, often converted from an existing crude oil tanker (VLCC or ULCC). Due to the increasing sea depth for new fields, they dominate new offshore field development at more than 100 meters water depth.

The wellheads or subsea risers from the sea bottom are located on a central or bow-mounted turret, so that the ship can rotate freely to point into wind, waves or current. The turret has wire rope and chain connections to several anchors (position mooring - POSMOOR), or it can be dynamically positioned using thrusters (dynamic positioning — DYNPOS). Most installations use subsea wells. The main process is placed on the deck, while the hull is used for storage and offloading to a shuttle tanker. It may also be used for the transportation of pipelines.

FPSOs with additional processing and systems, such as drilling and production and stranded gas LNG production are planned.

A variation of the FPSO is the Sevan Marine design. This uses a circular hull which shows the same profile to wind, waves and current, regardless of direction. It shares many of the characteristics of the ship-shaped FPSO, such as high storage capacity and deck load, but does not rotate and therefore does not need a rotating turret.

Tension Leg Platform (TLP — left side in picture) consists of a structure held in place by vertical tendons connected to the sea floor by pile-secured templates. The structure is held in a fixed position by tensioned tendons, which provide for use of the TLP in a broad water depth range up to about 2,000m. The tendons are constructed as hollow high tensile strength steel pipes that carry the spare buoyancy of the structure and ensure limited vertical motion.

Semi-submersible platforms (front of picture) have a similar design but without taut mooring. This permits more lateral and vertical motion and is generally used with flexible risers and subsea wells. Similarly, Seastar platforms are miniature floating tension leg platforms, much like the semisubmersible type, with tensioned tendons.

SPAR consists of a single tall floating cylindrical hull, supporting a fixed deck. The cylinder does not, however, extend all the way to the seabed. Rather, it is tethered to the bottom by a series of cables and lines. The large cylinder serves to stabilize the platform in the water, and allows for movement to absorb the force of potential hurricanes. SPARs can be quite large and are used for water depths from 300 up to 3,000 meters. SPAR is not an acronym, and is named for its resemblance to a ship's spar. SPARs can support dry completion wells, but are more often used with subsea wells.

Subsea production systems are wells located on the sea floor, as opposed to the surface. As in a floating production system, the petroleum is extracted at the seabed, and is then "tied-back" to a pre-existing production platform or even an onshore facility, limited by horizontal distance or "offset". The well is drilled by a movable rig and the extracted oil and natural gas is transported by undersea pipeline and riser to a processing facility. This allows one strategically placed production platform to service many wells over a reasonably large area. Subsea systems are typically used at depths of 500 meters or more and do not have the ability to drill, only to extract and transport. Drilling and completion is performed from a surface rig. Horizontal offsets of up to 250 kilometers/150 miles are currently possible. The aim of the industry is to allow fully autonomous subsea production facilities, with multiple wellpads, processing, and direct tie-back to shore.

The wellhead sits on top of the actual oil or gas well leading down to the reservoir. A wellhead may also be an injection well, used to inject water or gas back into the reservoir to maintain pressure and levels to maximize production.

Once a natural gas or oil well is drilled and it has been verified that commercially viable quantities of natural gas are present for extraction, the well must be "completed" to allow petroleum or natural gas to flow out of the formation and up to the surface. This process includes strengthening the well hole with casing, evaluating the pressure and temperature of the formation, and installing the proper equipment to ensure an efficient flow of natural gas from the well. The well flow is controlled with a choke.

We differentiate between, dry completion (which is either onshore or on the deck of an offshore structure) and subsea completions below the surface. The wellhead structure, often called a Christmas tree, must allow for a number of operations relating to production and well workover. Well workover refers to various technologies for maintaining the well and improving its production capacity.

Onshore , the individual well streams are brought into the main production facilities over a network of gathering pipelines and manifold systems. The purpose of these pipelines is to allow setup of production "well sets" so that for a given production level, the best reservoir utilization well flow composition (gas, oil, water), etc., can be selected from the available wells.

For gas gathering systems, it is common to meter the individual gathering lines into the manifold as shown in this picture. For multiphase flows (combination of gas, oil and water), the high cost of multiphase flow meters often leads to the use of software flow rate estimators that use well test data to calculate actual flow.

Offshore, the dry completion wells on the main field center feed directly into production manifolds, while outlying wellhead towers and subsea installations feed via multiphase pipelines back to the production risers. Risers are a system that allows a pipeline to "rise" up to the topside structure. For floating structures, this involves a way to take up weight and movement. For heavy crude and in Arctic areas, diluents and heating may be needed to reduce viscosity and allow flow.

Some wells have pure gas production which can be taken directly for gas treatment and/or compression. More often, the well produces a combination of gas, oil and water, with various contaminants that must be separated and processed. The production separators come in many forms and designs, with the classic variant being the gravity separator.

In gravity separation, the well flow is fed into a horizontal vessel. The retention period is typically five minutes, allowing gas to bubble out, water to settle at the bottom and oil to be taken out in the middle. The pressure is often reduced in several stages (high pressure separator, low pressure separator, etc.) to allow controlled separation of volatile components. A sudden pressure reduction might allow flash vaporization leading to instability and safety hazards.

Most plants do not allow local gas storage, but oil is often stored before loading on a vessel, such as a shuttle tanker taking oil to a larger tanker terminal, or direct to a crude carrier. Offshore production facilities without a direct pipeline connection generally rely on crude storage in the base or hull, allowing a shuttle tanker to offload about once a week. A larger production complex generally has an associated tank farm terminal allowing the storage of different grades of crude to take up changes in demand, delays in transport, etc.

Metering stations allow operators to monitor and manage the natural gas and oil exported from the production installation. These employ specialized meters to measure the natural gas or oil as it flows through the pipeline, without impeding its movement.

This metered volume represents a transfer of ownership from a producer to a customer (or another division within the company), and is called custody transfer metering. It forms the basis for invoicing the sold product and also for production taxes and revenue sharing between partners. Accuracy requirements are often set by governmental authorities.

Typically, a metering installation consists of a number of meter runs so that one meter will not have to handle the full capacity range, and associated prover loops so that the meter accuracy can be tested and calibrated at regular intervals.

Utility systems are systems which do not handle the hydrocarbon process flow, but provide some service to the main process safety or residents. Depending on the location of the installation, many such functions may be available from nearby infrastructure, such as electricity. Many remote installations are fully self-sustaining and must generate their own power, water, etc.

Gas processing consists of separating the various hydrocarbons and fluids from the pure natural gas to produce what is known as "pipeline quality" dry natural gas. Major transportation pipelines usually impose restrictions on the makeup of natural gas that is allowed into the pipeline. Before the natural gas can be transported it must be purified.

Whatever the source of the natural gas, once separated from crude oil (if present) it commonly exists in mixtures with other hydrocarbons, principally ethane, propane, butane and pentanes. In addition, raw natural gas contains water vapor, hydrogen sulfide ( H₂S), carbon dioxide, helium, nitrogen and other compounds.

Associated hydrocarbons, known as "natural gas liquids" (NGL), are used as raw materials for oil refineries or petrochemical plants and as sources of energy.

Gas from a pure natural gas wellhead might have sufficient pressure to feed directly into a pipeline transport system. Gas from separators has generally lost so much pressure that it must be recompressed to be transported. Turbinedriven compressors gain their energy by using a small proportion of the natural gas that they compress. The turbine itself serves to operate a centrifugal compressor, which contains a type of fan that compresses and pumps the natural gas through the pipeline. Some compressor stations are operated by using an electric motor to turn the centrifugal compressor. This type of compression does not require the use of any natural gas from the pipe; however, it does require a reliable source of electricity nearby. The compression includes a large section of associated equipment such as scrubbers (to remove liquid droplets) and heat exchangers, lube oil treatment, etc.

Pipelines can measure anywhere from 6 to 48 inches (15–120 cm) in diameter. In order to ensure their efficient and safe operation, operators routinely inspect their pipelines for corrosion and defects. This is done with sophisticated pieces of equipment known as "pigs". Pigs are intelligent robotic devices that are propelled down pipelines to evaluate the interior of the pipe. Pigs can test pipe thickness, roundness, check for signs of corrosion, detect minute leaks, and any other defect along the interior of the pipeline that may either restrict the flow of gas, or pose a potential safety risk for the operation of the pipeline. Sending a pig down a pipeline is fittingly known as "pigging". The export facility must contain equipment to safely insert and retrieve pigs from the pipeline as well as depressurization, referred to as pig launchers and pig receivers.

Loading on tankers involves loading systems, ranging from tanker jetties to sophisticated singlepoint mooring and loading systems that allow the tanker to dock and load the product, even in bad weather.

Natural gas that is mainly methane cannot be compressed to liquid state at normal ambient temperature. Except for special uses such as compressed natural gas (CNG), the only practical solution to long distance gas transportation when a pipeline is not available or economical is to produce LNG at -162 °C. This requires one or more cooling stages. Cooling work consumes 6–10% of the energy to be transported. Special insulated tank LNG carriers are required for transportation, and at the receiving end, a regasification terminal heats the LNG to vaporization for pipeline distribution.