Millions of wells have been drilled since US explorers launched the modern oil industry a century and a half ago. In those 150 years, technology advances have gradually improved the chances that wells will find oil and gas, and of producing them profitably. Technology has also expanded the oil and gas industry’s horizons to areas where exploration was once unthinkable, such as the depths of the ocean. But in addition to the kind of technology you need to produce oil from 8,000 metres under the seabed and then through 3,000 metres of sea, successful oil exploration depends on the alignment of a host of economic and geological variables. The explorer needs an appetite for risk, access to financing, a high enough oil price to make exploration worthwhile and permission to operate. Oh, and fortuitous geological events to have occurred hundreds of millions of years earlier.
Three geological elements are required for the creation of an oil and gas field: source rock; reservoir rock; and cap rock. Over millions of years, organic matter in the source rock is cooked into petroleum and natural gas. A mixture of oil, natural gas and salt water then slowly migrates upwards – over thousands of years – through permeable layers of rock. An oilfield forms when the hydrocarbons accumulate in a porous, permeable reservoir rock – typically a sandstone or a carbonate – with an impermeable layer above it, which prevents further upward migration. In oil and gas production, a well punctures through this impermeable seal – cap rock – enabling oil and gas to flow to the surface. In some circumstances, source rocks may also be reservoir rocks.
Rights and contracts
Before any exploration gets under way, though, E&P companies need to secure permission to operate on the land and to agree – with the owner of the mineral-extraction rights – on who gets what in the event of oil or gas being recovered. Ownership rules vary by country. In the US and Canada, mineral rights may be in public or private hands. Everywhere else, the state owns the oil and gas. Whoever the owner is, a contract is needed to establish mechanisms for divvying up risks, costs and rewards from any future production. The local environment is an integral part of the business plan too. The explorer wants to maximise its chances of financial success while minimizing the impact of its operations on the local environment and local communities.
Deciding where to drill
No surveying technique can actually see oil and gas underground, but seismic and other technologies can help earth scientists identify rocks that are capable of holding oil or gas deposits. That can give an explorer reasonable confidence that a discovery is possible before incurring the high costs of drilling.
Seismic works by sending pulses of sound energy into the ground and timing reflected wavelets, as they bounce back off layer after layer of rock. This information allows geoscientists to build models of the subsurface and narrow down the best spots for drilling. Another important data source is information from nearby wells and producing fields.
Where there has been no exploration, geophysicists can start to identify suitable rocks by measuring their gravitational and magnetic properties. Soft, sedimentary rocks capable of holding hydrocarbons – limestone, for instance – are less dense than heavy, igneous rocks. Airplanes measure the Earth’s gravitational pull, searching for small differences caused by variations in the density of the underlying rocks. Variations in the Earth’s magnetic field can provide useful data too: the less magnetic the better – sedimentary rocks are virtually non-magnetic.
However, drilling is the only way of actually proving that an oil or gas field or reservoir exists deep below the surface.
Drilling a well is a 24/7 operation, with crews working in shifts. The process can last for weeks – depending on the hole’s depth, the rig’s power and the hardness of the rocks.
Most wells are drilled using rotary drilling rigs. A sharp-toothed drillbit is connected to the surface by the drillstring, lengths of drill pipe screwed together end to end. Machinery at the surface makes the drillstring rotate. As it does so, the rotating drillbit at the end of it cuts, grinds, scrapes and crushes rock at the bottom of the well. Drillbits – and the well’s diameter – decrease in size the deeper the hole gets. At the surface, the diameter might be about 60 centimetres, compared with perhaps just 15 in the pay zone – the section of producing rock. In most wells, drilling stops periodically so that the well can be lined with carbon steel casing (see below). A special fluid called drilling mud is continuously circulated around the hole, washing out cuttings and keeping the drillbit in contact with uncut rock. The mud also cools and lubricates the bit, provides the drillstring with buoyancy and counters the natural pressures of fluids in the rocks around the well, which would otherwise make it cave in.
Geologists and engineers cannot directly examine subterranean rock formations, but have special tools to do it for them. In wireline logging, sondes are lowered down the hole on an electrical cable – the wireline. Data relating to physical properties in or around the well are then transmitted to the surface along the wireline, and logged against depth or time – or both. Sondes can take numerous measurements. Electrical resistivity is one: oil and gas are more resistive than the salty water that fills most deeply buried rocks. Acoustic, radioactive and nuclear magnetic resonance instruments also yield data on the probable content of a rock layer. Core samples, in which cylinders of rock are retrieved from the well for analysis, also provide vital information. Mud logs keep track of the chemistry of cuttings washed out of the hole. Wireline tools are suitable in vertical wells – because, thanks to gravity, it’s relatively easy to lower them in and pull them out. But the emergence of directional and horizontal wells has resulted in the development of log ing-while-drilling and measurement-while-drilling tools (usually referred to as LWD and MWD tools), in which sensors are located just above the drillbit and transmit data to surface by fluid pulse telemetry (pulses are sent through the medium of the drilling mud and decoded at surface) or are retrieved later when the instrument is brought to surface.
Tripping, fishing and BOPs
If a drillbit stops drilling effectively, the drilling crew lifts the drillstring out of the hole – a process known as tripping pipe – and replaces the drillbit or makes other adjustments.
If junk or debris get in the way of drilling, they must be removed from the hole. Items left in a wellbore that impede the continuation of operations – broken drillbits, drillpipe or logging tools, for example – are called fish. Removing them is known as fishing.
During drilling, a safety device called a blow-out preventer, or BOP (pictured), seals off the well if pressure from inside the formation threatens to build up and cause oil and gas to spurt out of the well in a dangerous, uncontrolled manner. Pressure can then be relieved in a controlled way.
Types of wells
A well drilled to discover a new oil or gas reservoir is called a wildcat or exploratory well. The well that discovers a new field is called the discovery well for that field and subsequent wells – drilled to determine the field’s size and boundaries – are known as step-out, delineation or appraisal wells.
Developmental wells are drilled in a proved producing area and wells drilled between producing wells in an established field to increase production are called infill wells. Dry wells contain no oil or gas, or hydrocarbons in insufficient quantities.
Firming up the economics
Before drilling, the operator must evaluate the economic case for a well, calculating the chances of finding commercial quantities of oil or gas, how quickly a discovery would pay back the investment and how much of a profit it would eventually make – in light of the prevailing oil price.
Explorers bring expertise and risk capital to oil exploration, but seldom own, maintain or even operate the equipment. That and numerous other technical tasks are usually outsourced to specialist services companies.
An area is cleared for the drilling pad, water supply is established (by laying a water pipeline or digging a well) and a reserve pit is dug and lined with plastic to hold waste mud and cuttings from the well. Rig equipment is then installed, the most visible of which is the derrick, the metal framework that supports the weight of the drilling apparatus. The deeper the well, the heavier the load and the bigger and stronger the derrick needs to be.
Not one direction
Drilling a vertical well in a perfectly straight line is difficult: when the drillbit encounters a different type of rock, it tends to deflect slightly – or dogleg. But most wells in the US these days, and many more around the world, aren’t vertical. They’re designed not to be straight.
In directional drilling, special power tools build angles into the wellbore, mixing up vertical and curved sections, and building in variations in azimuth. Horizontal wells, a type of directional well, can deviate by 90 degrees from the vertical and, from that point, even start to drill upwards. Extended-reach wells have lateral sections stretching up to around 12 kilometres.
There are lots of reasons for drilling horizontally. Directional wells can navigate round underground hazards. They can minimize surface impact because several wells can be drilled from one point. They can reduce costs by enabling offshore deposits to be drilled from land – making costly platforms unnecessary. And a single horizontal well can encounter multiple reservoirs and replace the need for dozens of vertical wells.
Casing and cementing
Drilling periodically stops so that the well can be lined with steel casing, which is then cemented into place. Casing – hollow, heat-treated pipe often fabricated from carbon steel – gives the hole mechanical support and helps prevent the formation wall from caving into the wellbore. It also protects freshwater formations by stopping fluids inside the well from leaking out of it.
Sections of casing are screwed together, lowered into the hole and cemented in place by flowing cement down the centre of the casing string and then up into the gap (the annulus) between the newly inserted casing and the bare sides of the hole.
There are different types of casing for different phases of the well – conductor casing, surface casing and intermediate casing. Also, if a commercial decision is taken to produce from the well, most production zones are also lined with production casing or production liner. If the pay zone in a producing well is not cased (as in the inset image), the completion is known as a barefoot or open-hole completion. Like the hole itself, casing strings reduce in diameter the deeper it gets.
If a well is to become a producer, it undergoes completion. The completion process means the installation of the equipment in the well to facilitate the flow of oil and natural gas – safely and efficiently – out of the well. Completion equipment includes production tubing, a tubular inserted inside the well that serves as the conduit for the hydrocarbons. At the top of the well, the drilling rig is replaced with a Christmas tree, an assembly of valves, spools and instruments that controls the flow of fluids out of the well. Completions vary in complexity and may incorporate technologies to prevent sand from flowing into the well and causing damage or to boost the flow of oil and gas to the surface. Read more about completions on pxx.
A drillstem test is a temporary completion that identifies the types of fluids in the well, their flowrate, the producing zone’s permeability and the pressure of the reservoir. Combined, those data indicate the well’s production capacity and may result in a completion. It’s done by connecting a measurement device to the bottom of the drillstem and lowering the apparatus down into the formation. At the bottom of the well, the instrument measures the flow of oil or gas for a specified amount of time, usually an hour.
Production is the longest phase in the well’s life and may last for years or even decades. Over time, production declines and, eventually, will be too low to continue to operate the field. But, during a field’s productive life, the operator monitors well performance and intervenes periodically to perform maintenance and repairs, and try to stem the rate of decline.
Different phases of production are known as primary, secondary and tertiary recovery. Oil and gas in a reservoir is naturally under pressure and may need no encouragement to flow to the surface; primary recovery occurs when hydrocarbons flow spontaneously. In some wells, however, there is insufficient pressure or the oil is too viscous to flow freely. Various technologies, such as electrical submersible pumps, can be used to get the hydrocarbons moving.
Even in reservoirs that are highly pressured when production starts, the operator will eventually need to intervene to keep up the flow rate. In secondary recovery, natural gas or water are injected into the reservoir to displace oil and drive it to the surface. Tertiary recovery, or enhanced oil recovery, involves the injection of steam, gas, chemicals or microbes to change the properties of the hydrocarbons in the reservoir, and make them easier to extract. In unconventional wells, drilling is accompanied by hydraulic fracturing, which opens up pathways in the impermeable rock through which fluids in the rock may flow into a wellbore.
Abandonment and decommissioning
When an oilfield no longer contains sufficient hydrocarbons to justify the continuation of production operations, the operator fills in wells, dismantles and removes equipment from the site, and restores the area. Typically, around a third of reserves are economically recoverable and increasing recovery factors is one of the industry’s main aims.
Beyond the well
Oil and other liquids are separated from natural gas at the wellsite and stored in nearby tanks before being transported to a refinery by various means, such as pipelines, trucks and ships. Natural gas is usually processed near the point of production to remove natural gas liquids and other impurities. This leaves methane, which can then be piped to markets or to liquefaction plants.
Alternatively, natural gas may be injected back into the ground to help maintain reservoir pressure.