Reservoir and wellheads
There are three main types of conventional wells. The most common is an oil well with associated gas. Natural gas wells are drilled specifically for natural gas, and contain little or no oil. Condensate wells contain natural gas, as well as a liquid condensate. This condensate is a liquid hydrocarbon mixture that is often separated from the natural gas either at the wellhead, or during the processing of the natural gas. Depending on the well type, completion may differ slightly. It is important to remember that natural gas, being lighter than air, will naturally rise to the surface of a well. Consequently, lifting equipment and well treatment are not necessary in many natural gas and condensate wells, while for oil wells, many types of artificial lift may be installed, particularly as the reservoir pressure falls during years of production.
There is no distinct transition from conventional to unconventional oil and gas production. Lower porosity (tighter reservoirs) and varying maturity create a range of shale oil and gas, tight gas, heavy oil, etc., that is simply an extension of the conventional domain.
- 1 Crude oil and natural gas
- 2 The reservoir
- 3 Exploration and drilling
- 4 The well
- 5 Wellhead
- 6 Artificial lift
- 7 ESP
- 8 Well workover, intervention and stimulation
- 9 References
Crude oil and natural gas
Crude oil is a complex mixture consisting of 200 or more different organic compounds, mostly alkanes (single bond hydrocarbons on the form CnH2n+2)and smaller fraction aromatics (six-ring molecules such as benzene C6H6)
Different crude contains different combinations and concentrations of these various compounds. The API (American Petroleum Institute) gravity of a
particular crude is merely a measure of its specific gravity or density. The higher the API number expressed as degrees API, the less dense (lighter, thinner) the crude. Simply put, this means that the lower the degrees API, the denser (heavier, thicker) the crude. Crude from different fields and from different formations within a field can be similar in composition or significantly different.
In addition to API grade and hydrocarbons, crude is characterized for other undesired elements like sulfur, which is regulated and needs to be removed. Crude oil API gravities typically range from 7 to 52, corresponding to about 970 kg/m3 to 750 kg/m3, but most fall in the 20 to 45 API gravity range. Although light crude (i.e., 40-45 degrees API) is considered the best, lighter crude (i.e., 46 degree API and above) is generally no better for a typical refinery. As the crude gets lighter than 40-45 degrees API, it contains shorter molecules, which means a lower carbon number.
This also means it contains less of the molecules useful as high octane gasoline and diesel fuel, the production of which most refiners try to maximize. If a crude is heavier than 35 degrees API, it contains longer and bigger molecules that are not useful as high octane gasoline and diesel fuel without further processing. For crude that has undergone detailed physical and chemical property analysis, the API gravity can be used as a rough index of the quality of crudes of similar composition as they naturally occur (that is, without adulteration, mixing, blending, etc.). When crudes of a different type and quality are mixed, or when different petroleum components are mixed, API gravity cannot be used meaningfully for anything other than a measure of fluid density.
For instance, consider a barrel of tar that is dissolved in 3 barrels of naphtha (lighter fluid) to produce 4 barrels of a 40 degrees API mixture. When this 4-barrel mixture is fed to a distillation column at the inlet to a refinery, one barrel of tar plus 3 barrels of naphtha is all that will come out of the still. On the other hand, 4 barrels of a naturally occurring 40 degrees API crude, fed to the distillation column at the refinery could come out of the still as 1.4 barrels of gasoline and naphtha (typically C8H18), 0.6 barrels of kerosene (jet fuel C12-15 ), 0.7 barrels of diesel fuel (average C12H26), 0.5 barrels of heavy distillate (C20-70), 0.3 barrels of lubricating stock, and 0.5 barrels of residue (bitumen, mainly poly-cyclic aromatics).
The previous figure illustrates weight percent distributions of three different hypothetical petroleum stocks that could be fed to a refinery with catalytic cracking capacity. The chemical composition is generalized by the carbon number which is the number of carbon atoms in each molecule - CnH2n+2. A medium blend is desired because it has the composition that will yield the highest output of high octane gasoline and diesel fuel in the cracking refinery. Though the heavy stock and the light stock could be mixed to produce a blend with the same API gravity as the medium stock, the composition of the blend would be very different from the medium stock, as the figure indicates. Heavy crude can be processed in a refinery by cracking and reforming that reduces the carbon number to increase the high value fuel yield.
The natural gas used by consumers is composed almost entirely of methane. However, natural gas found at the wellhead, though still composed primarily of methane, is not pure. Raw natural gas comes from three types of wells: oil wells, gas wells, and condensate wells.
Natural gas that comes from oil wells is typically termed “associated gas.” This gas can exist separately from oil in the formation (free gas), or dissolved in the crude oil (dissolved gas). Natural gas from gas and condensate wells in which there is little or no crude oil, is termed “nonassociated gas.”
Gas wells typically produce only raw natural gas. However condensate wells produce free natural gas along with a semi-liquid hydrocarbon ondensate. 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.
While the ethane, propane, butane, and pentanes must be removed from natural gas, this does not mean that they are all waste products. In fact, associated hydrocarbons, known as natural gas liquids (NGL), can be very valuable byproducts of natural gas processing. NGLs include ethane, propane, butane, iso-butane, and natural gasoline. These are sold separately and have a variety of different uses such as raw materials for oil refineries or petrochemical plants, as sources of energy, and for enhancing oil recovery in oil wells. Condensates are also useful as diluents for heavy crude.
The oil and gas bearing structure is typically porous rock, such as sandstone or washed out limestone. The sand may have been laid down as desert sand dunes or seafloor. Oil and gas deposits form as organic material (tiny plants and animals) deposited in earlier geological periods, typically 100 to 200 million years ago, under, over or with the sand or silt, are transformed by high temperature and pressure into hydrocarbons.
For an oil reservoir to form, porous rock needs to be covered by a nonporous layer such as salt, shale, chalk or mud rock that prevent the hydrocarbons from leaking out of the structure. As rock structures become folded and raised as a result of tectonic movements, the hydrocarbons migrate out of the deposits and upward in porous rock and collect in crests under the non-permeable rock, with gas at the top and oil and fossil water at the bottom. Salt is a thick fluid, and if deposited under the reservoir, it will flow up in heavier rock over millions of years. This process creates salt domes with a similar reservoir-forming effect.
These are common e.g. in the Middle East. This extraordinary process is ongoing. However, an oil reservoir matures in the sense that an immature formation may not yet have allowed the hydrocarbons to form and collect. A young reservoir generally has heavy crude, less than 20 API, and is often Cretaceous in origin (65-145 million years ago). Most light crude reservoirs tend to be Jurassic or Triassic (145-205/205-250 million years ago), and gas reservoirs where the organic molecules are further broken down are often Permian or Carboniferous in origin (250-290/290-350 million years ago).
In some areas, strong uplift, erosion and cracking of the rock above have allowed hydrocarbons to leak out, leaving heavy oil reservoirs or tar pools. Some of the world's largest oil deposits are tar sands, where the volatile compounds have evaporated from shallow sandy formations, leaving huge volumes of bitumen-soaked sands. These are often exposed at the surface and can be strip-mined, but must be separated from the sand with hot water, steam and diluents, and further processed with cracking and reforming in a refinery to improve fuel yield.
The oil and gas is pressurized in the pores of the absorbent formation rock. When a well is drilled into the reservoir structure, the hydrostatic formation pressure drives the hydrocarbons out of the rock and up into the well. When the well flows, gas, oil and water are extracted, and the levels shift as the reservoir is depleted. The challenge is to plan drilling so that reservoir utilization can be maximized.
Seismic data and advanced 3D visualization models are used to plan extraction. Even so, the average recovery rate is only 40%, leaving 60% of the hydrocarbons trapped in the reservoir. The best reservoirs with advanced enhanced oil recovery (EOR) allow up to 70% recovery. Reservoirs can be quite complex, with many folds and several layers of hydrocarbon-bearing rock above each other (in some areas more than ten). Modern wells are drilled with large horizontal offsets to reach different parts of the structure and with multiple completions so that one well can produce from several locations.
Exploration and drilling
When 3D seismic investigation has been completed, it is time to drill the well. Normally, dedicated drilling rigs either on mobile onshore units or offshore floating rigs are used. Larger production platforms may also have their own production drilling equipment.
The main components of the drilling rig are the derrick, floor, drawworks, drive and mud handling. Control and power can be hydraulic or electric. Earlier pictures of drillers and roughnecks working with rotary tables (bottom drives) are now replaced with top drive and semiautomated pipe handling on larger installations. The hydraulic or electric top drive hangs from the derrick crown and gives pressure and rotational torque to the drill string. The whole assembly is controlled by the drawworks.
The drill string is assembled from pipe segments about 30 meters (100 feet) long, normally with conical inside threads at one end and outside at the other. As each 30 meter segment is drilled, the drive is disconnected and a new pipe segment inserted in the string. A cone bit is used to dig into the rock. Different cones are used for different types of rock and at different stages of the well. The picture above shows roller cones with inserts (on the left). Other bits are PDC (polycrystalline diamond compact, on the right) and diamond impregnated.
As the well is sunk into the ground, the weight of the drill string increases and might reach 500 metric tons or more for a 3,000 meter deep well. The drawwork and top drive must be precisely controlled so as not to overload and break the drill string or the cone. Typical values are 50kN force on the bit and a torque of 1-1.5 kNm at 40-80 RPM for an 8-inch cone. Rate of penetration (ROP) is very dependent on depth and could be as much as 20m per hour for shallow sandstone and dolomite (chalk), and as low as 1m per hour on deep shale rock and granite.
Directional drilling is intentional deviation of a well bore from the vertical. It is often necessary to drill at an angle from the vertical to reach different parts of the formation. Controlled directional drilling makes it possible to reach subsurface areas laterally remote from the point where the bit enters the earth. It often involves the use of a drill motor driven by mud pressure mounted directly on the cone (mud motor, turbo drill, and dyna-drill), whipstocks – a steel casing that bends between the drill pipe and cone, or other deflecting rods, also used for horizontal wells and multiple completions, where one well may split into several bores. A well that has sections of more than 80 degrees from the vertical is called a horizontal well. Modern wells are drilled with large horizontal offsets to reach different parts of the structure and achieve higher production. The world record is more than 15 km. Multiple completions allow production from several locations.
Wells can be of any depth from near the surface to a depth of more than 6,000 meters. Oil and gas are typically formed at 3,000-4,000 meters depth, but part of the overlying rock may have since eroded away. The pressure and temperature generally increase with increasing depth, so that deep wells can have more than 200 ºC temperature and 90 MPa pressure (900 times atmospheric pressure), equivalent to the hydrostatic pressure set by the distance to the surface. The weight of the oil in the production string reduces wellhead pressure. Crude oil has a specific weight of 790 to 970 kg per cubic meter. For a 3,000 meter deep well with 30 MPa downhole pressure and normal crude oil at 850 kg/m3, the wellhead static pressure will only be around 4.5 MPa. During production, the pressure will drop further due to resistance to flow in the reservoir and well.
The mud enters though the drill pipe, passes through the cone and rises in the uncompleted well. Mud serves several purposes:
- It brings rock shales (fragments of rock) up to the surface
- It cleans and cools the cone
- It lubricates the drill pipe string and cone
- Fibrous particles attach to the well surface to bind solids
- Mud weight should balance the downhole pressure to avoid leakage of gas and oil.
Often, the well will drill though smaller pockets of hydrocarbons, which may cause a “blow-out" if the mud weight cannot balance the pressure. The same might happen when drilling into the main reservoir.
To prevent an uncontrolled blow-out, a subsurface safety valve is often installed. This valve has enough closing force to seal off the well and cut the drill string in an uncontrollable blow-out situation. However, unless casing is already also in place, hydrocarbons may also leave though other cracks inside the well and rise to the surface through porous or cracked rock. In addition to fire and pollution hazards, dissolved gas in seawater rising under a floating structure significantly reduces buoyancy.
The mud mix is a special brew designed to match the desired flow thickness, lubrication properties and specific gravity. Mud is a common name used for all kinds of fluids used in drilling completion and workover and can be oil-based, water-based or synthetic, and consists of powdered clays such as bentonite, oil, water and various additives and chemicals such as caustic soda, barite (sulfurous mineral), lignite (brown coal), polymers and emulsifiers.
A special high-density mud called “kill fluid” is used to shut down a well for workover. Mud is recirculated. Coarse rock shales are separated in a shale shaker before it is passed though finer filters and recalibrated with new additives before returning to the mud holding tanks.
Once the well has been drilled, it must be completed. Completing a well consists of a number of steps, such as installing the well casing, completion, installing the wellhead, and installing lifting equipment or treating the formation, if required.
Installing the well casing is an important part of the drilling and completion process. Well casing consists of a series of metal tubes installed in the freshly drilled hole. Casing serves to strengthen the sides of the well hole, ensure that no oil or natural gas seeps out as it is brought to the surface, and keep other fluids or gases from seeping into the formation through the well. A good deal of planning is necessary to ensure that the right casing for each well is installed. Types of casing used depend on subsurface characteristics of the well, including the diameter of the well (which is dependent on the size of the drill bit used) and the pressures and temperatures experienced. In most wells, the diameter of the well hole decreases the deeper it is drilled, leading to a conical shape that must be taken into account when installing casing. The casing is normally emented in place.
There are five different types of well casing. They include:
- Conductor casing, which is usually no more than 20 to 50 feet (7-17 m) long, is installed before main drilling to prevent the top of the well from caving in and to help in the process of circulating the drilling fluid up from the bottom of the well.
- Surface casing is the next type of casing to be installed. It can be anywhere from 100 to 400 meters long, and is smaller in diameter to fit inside the conductor casing. Its primary purpose is to protect fresh water deposits near the surface of the well from contamination by leaking hydrocarbons or salt water from deeper underground. It also serves as a conduit for drilling mud returning to the surface and helps protect the drill hole from damage during drilling.
- Intermediate casing is usually the longest section of casing found in a well. Its primary purpose is to minimize the hazards associated with subsurface formations that may affect the well. These include abnormal underground pressure zones, underground shales and formations that might otherwise contaminate the well, such as underground salt water deposits. Liner strings are sometimes used instead of intermediate casing. Liner strings are usually just attached to the previous casing with “hangers” instead of being cemented into place, and are thus less permanent.
- Production casing, alternatively called the “oil string” or '”long string,” is installed last and is the deepest section of casing in a well. This is the casing that provides a conduit from the surface of the well to the petroleum-producing formation. The size of the production casing depends on a number of considerations, including the lifting equipment to be used, the number of completions required, and the possibility of deepening the well at a later date. For example, if it is expected that the well will be deepened later, then the production casing must be wide enough to allow the passage of a drill bit later on. It is also instrumental in preventing blow-outs, allowing the formation to be “sealed” from the top should dangerous pressure
levels be reached.
Once the casing is installed, tubing is inserted inside the casing, from the opening well at the top to the formation at the bottom. The hydrocarbons that are extracted run up this tubing to the surface. The production casing is typically 5 to 28 cm (2 -11 in) with most production wells being 6 inches or more. Production depends on reservoir, bore, pressure, etc., and may be less than 100 barrels per day to several thousand barrels per day. (5,000 bpd is about 555 liters/minute). A packer is used between casing and tubing at the bottom of the well.
Well completion commonly refers to the process of finishing a well so that it is ready to produce oil or natural gas. In essence, completion consists of deciding on the characteristics of the intake portion of the well in the targeted hydrocarbon formation. There are a number of types of completions, including:
- Open hole completions are the most basic type and are only used in very competent formations that are unlikely to cave in. An open hole completion consists of simply running the casing directly down into the formation, leaving the end of the piping open without any other protective filter.
- Conventional perforated completions consist of production casing run through the formation. The sides of this casing are perforated, with tiny holes along the sides facing the formation, which allows hydrocarbons to flow into the well hole while still providing a suitable amount of support and protection for the well hole. In the past, “bullet perforators” were used. These were essentially small guns lowered into the well that sent off small bullets to penetrate the casing and cement. Today, “jet perforating” is preferred. This consists of small, electrically-fired charges that are lowered into the well. When ignited, these charges poke tiny holes through to the formation, in the same manner as bullet perforating.
- Sand exclusion completions are designed for production in an area that contains a large amount of loose sand. These completions are designed to allow for the flow of natural gas and oil into the well, while preventing sand from entering. The most common methods of keeping sand out of the well hole are screening or filtering systems. Both of these types of sand barriers can be used in open hole and perforated completions.
- Permanent completions are those in which the completion and wellhead are assembled and installed only once. Installing the casing, cementing, perforating and other completion work is done with small-diameter tools to ensure the permanent nature of the completion. Completing a well in this manner can lead to significant cost savings compared to other types.
- Multiple zone completion is the practice of completing a well such that hydrocarbons from two or more formations may be produced imultaneously, without mixing with each other. For example, a well may be drilled that passes through a number of formations on its way deeper underground, or it may be more desirable in a horizontal well to add multiple completions to drain the formation most effectively. When it is necessary to separate different completions, hard rubber “packing” instruments are used to maintain separation.
- Drainhole completions are a form of horizontal or slanted drilling. This type of completion consists of drilling out horizontally into the formation from a vertical well, essentially providing a drain for the hydrocarbons to run down into the well. These completions are more commonly associated with oil wells than with natural gas wells.
Wellheads can involve dry or subsea completion. Dry completion means that the well is onshore or on the topside structure on an offshore installation. Subsea wellheads are located underwater on a special sea bed template.
The wellhead has equipment mounted at the opening of the well to regulate and monitor the extraction of hydrocarbons from the underground formation. This also prevents oil or natural gas leaking out of the well, and prevents blow-outs due to high pressure formations. Formations that are under high pressure typically require wellheads that can withstand a great deal of upward pressure from the escaping gases and liquids. These must be able to withstand pressures of up to 140 MPa (1,400 Bar). The wellhead consists of three components: the casing head, the tubing head, and the “Christmas tree.”
A typical Christmas tree, composed of a master gate valve, a pressure gauge, a wing valve, a swab valve and a choke is shown above. The Christmas tree may also have a number of check valves. The functions of these devices are explained below.
At the bottom we find the casing head and casing hangers. The casing is screwed, bolted or welded to the hanger. Several valves and plugs are normally fitted to give access to the casing. This permits the casing to be opened, closed, bled down, and in some cases, allow the flowing well to be produced through the casing as well as the tubing. The valve can be used to determine leaks in casing, tubing or the packer, and is also used for lift gas injection into the casing.
The tubing hanger (also called a donut) is used to position the tubing correctly in the well. Sealing also allows Christmas tree removal with pressure in the casing. Master gate valve. The master gate valve is a high quality valve. It provides full opening, which means that it opens to the same inside diameter as the tubing so that specialized tools may be run through it. It must be capable of holding the full pressure of the well safely for all anticipated purposes. This valve is usually left fully open and is not used to control flow.
Pressure gauge. The minimum instrumentation is a pressure gauge placed above the master gate valve before the wing valve. In addition, other instruments such as a temperature gauge are normally fitted.
Wing valve. The wing valve can be a gate or ball valve. When shutting in the well, the wing gate or valve is normally used so that the tubing pressure can be easily read. Swab valve. The swab valve is used to gain access to the well for wireline operations, intervention and other workover procedures (see below). On top of it is a tree adapter and cap that mates with a range of equipment.
Variable flow choke valve. The variable flow choke valve is typically a large needle valve. Its calibrated opening is adjustable in 1/64 inch increments (called beans). High-quality steel is used in order to withstand the highspeed flow of abrasive materials that pass through the choke, usually over many years, with little damage except to the dart or seat. If a variable choke is not required, a less expensive positive choke is normally installed on smaller wells. This has a built-in restriction that limits flow when the wing valve is fully open.
Vertical tree. Christmas trees can also be horizontal where the master, wing and choke are on a horizontal axis. This reduces the height and may allow easier intervention. Horizontal trees are especially used on subseawells.
Subsea wells are essentially the same as dry completion wells. Mechanically, however, they are placed in a subsea structure (template) that allows the wells to be drilled and serviced remotely from the surface, and protected from damage, e.g., from trawlers. The wellhead is placed in a slot in the template where it mates to the outgoing pipeline as well as hydraulic and electric control signals.
Control is from the surface, where a hydraulic power unit (HPU) provides power to the subsea installation via an umbilical. The umbilical is a composite cable containing tension wires, hydraulic pipes, electrical power, control and communication signals. A control pod with inert gas and/or oil protection contains control electronics, and operates most equipment via hydraulic switches. More complex subsea solutions may contain subsea separation/stabilization and electrical multiphase pumping. This may be necessary if reservoir pressure is low, offset (distance to main facility) is long or there are flow assurance problems so that the gas and liquids will not stably flow to the surface. The product is piped back through pipelines and risers to the surface. The main choke may be located topside.
Wells are also divided into production and injection wells. The former are for production of oil and gas. Injection wells are drilled to inject gas or water into the reservoir. The purpose of injection is to maintain overall and hydrostatic reservoir pressure and force the oil toward the production wells. When injected water reaches the production well, it is called “injected water breakthrough.” Special logging instruments, often based on radioactive isotopes added to injection water, are used to detect breakthrough. Injection wells are fundamentally the same as production wellheads. The difference is their direction of flow and, therefore, mounting of some directional components, such as the choke.
Production wells are free flowing or lifted. A free flowing oil well has enough downhole pressure to reach suitable wellhead production pressure and maintain an acceptable well flow. If the formation pressure is too low, and water or gas injection cannot maintain pressure or are not suitable, the well must be artificially lifted. For smaller wells, 0.7 MPa (100 PSI) wellhead pressure with a standing column of liquid in the tubing is measured, by a rule of-thumb method, to allow the well to flow. Larger wells will be equipped with artificial lift to increase production, even at much higher pressures. Some artificial lift methods are:
Sucker rod pumps, also called donkey or beam pumps, are the most common artificial lift system used in land-based operations. A motor drives a reciprocating beam, connected to a polished rod passing into the tubing via a stuffing box. The sucker rod continues down to the oil level and is connected to a plunger with a valve. On each upward stroke, the plunger lifts a volume of oil up and through the wellhead discharge. On the downward stroke it sinks (it should sink, and not be pushed) allowing oil to flow though the valve. The motor speed and torque is controlled for efficiency and minimal wear with a pump off controller (PoC). Use is limited to shallow reservoirs down to a few hundred meters, and flows up to about 40 liters (10 gallons) per stroke.
A downhole pump inserts the whole pumping mechanism into the well. In modern installations, an electrical submerged pump (ESP) is inserted into the well. Here, the whole assembly consisting of a long narrow motor and a multiphase pump, such as a progressive cavity pump (PCP) or centrifugal pump, hangs by an electrical cable with tension members down the tubing.
Installations down to 3.7 km with power up to 750 kW have been installed. At these depths and power ratings, medium voltage drives (up to 5kV) must be used. ESPs work in deep reservoirs, but are sensitive to contaminants such as sand, and efficiency is sensitive to gas oil ration (GOR) (where gas over 10% dramatically lowers efficiency.
A gas lift injects gas into the well flow. The downhole reservoir pressure to the wellhead falls off, due to the counter pressure from weight of the oil column in the tubing. Thus, a 150 MPa reservoir pressure at 1,600 meterswill fall to zero in the wellhead if the specific gravity is 800 kg/m2 (0.8 times water). By injecting gas into this oil, the specific gravity is lowered and the well will start to flow. Typically, gas is injected between the casing and tubing, and a release valve on a gas lift mandrel is inserted into the tubing above the packer.
The valve will open at a set pressure to inject lift gas into the tubing. Several mandrels with valves set at different pressure ranges can be used to improve lifting and startup.
Gas lift can be controlled for a single well to optimize production, and to reduce slugging effects where the gas droplets collect to form large bubbles that can upset production. Gas lift can also be optimized over several wells to use available gas in the most efficient way.
The plunger lift is normally used on low pressure gas wells with some condensate, oil or water, or high GOR wells. In this case, the well flow conditions can be such that liquid starts to collect downhole and eventually blocks gas so that the well production stops. In this case, a plunger with an open/close valve can be inserted in the tubing. A plunger catcher at the top opens the valve and can hold the plunger, while another mechanism downhole closes the valve.
The cycle starts with the plunger falling into the well with its valve open. Condensed gas and oil can pass though the plunger until it reaches bottom. There the valve is closed, now with a volume of oil, condensate or water on top. Gas pressure starts to accumulate under the plunger and after a time pushes the plunger upwards, with liquid on top, which eventually flows out of the wellhead discharge.
When the plunger reaches the wellhead plunger catcher, the valve opens and allows gas to flow freely for some time while new liquid collects at the bottom. After a preset time, the catcher releases the plunger and the cycle repeats.
Well workover, intervention and stimulation
After operating for some time, a well may become less productive or faulty due to residue buildup, sand erosion, corrosion or reservoir clogging. Well workover is the process of performing major maintenance on an oil or gas well. This might include replacement of the tubing, a cleanup or new completions, new perforations and various other maintenance works such as the installation of gas lift mandrels, new packing, etc.
Through-tubing workover operation is work performed with special tools that do not require the time-consuming full workover procedure involving replacement or removal of tubing. Well maintenance without killing the well and performing full workover is time-saving and often called well intervention. Various operations that are performed by lowering instruments or tools on a wire into the well are called wireline operations.
Work on the reservoir such as chemical injection, acid treatment, heating, etc., is referred to as reservoir stimulation. Stimulation serves to correct various forms of structure damage and improve flow. Damage is a generic term for accumulation of particles and fluids that block fractures and pores and limit reservoir permeability.
- Acids, such as hydrochloric acid (HCL) are used to open up calcareous reservoirs and to treat accumulation of calcium carbonates in the reservoir structure around the well. Several hundred liters of acid (typically 15% solution in water) are pumped into the well under pressure to increase permeability of the formation. When the pressure is high enough to open the fractures, the process is called fracture acidizing. If the pressure is lower, it is called matrix acidizing.
- Hydraulic fracturing is an operation in which a specially blended liquid is pumped down a well and into a formation under pressure high enough to cause the formation to crack open, forming passages through which oil can flow into the well bore. Sand grains, aluminum pellets, walnut shells, glass beads, or similar materials (propping agents) are carried in suspension by this fluid into the fractures. When the pressure is released at the surface, the fractures partially close on the propping agents, leaving channels for oil to flow through to the well. The fracture channels may be up to 100 meters long. Hydraulic fracturing is an essential technology for unconventional shale gas and liquids extraction.
- Explosive fracturing uses explosives to fracture a formation. At the moment of detonation, the explosion furnishes a source of highpressure
gas to force fluid into the formation. The rubble prevents fracture healing, making the use of propping agents unnecessary.
- Damage removal refers to other forms of removing formation damage, such as flushing out of drill fluids.
Flexible coiled tubing can be wound around a large diameter drum and inserted or removed much quicker than tubing installed from rigid pipe segments. Well workover equipment including coiled tubing is often mounted on well workover rigs.