Wellhead The system of spools, valves and assorted adapters that provide pressure control of a production well CHOKE VALVE The choke valve, a main Description of Christmas tree, is design to control production rate of the oil well, with working pressure up to 10000psi. Choke valves can be classified as follows: adjustable choke valves and positive choke valves. By rotating hand wheel to drive the stem, the adjustable choke valve is designed to adjust the effective area available for the flow to accomplish control of production rate. The positive choke valve is design to accomplish control of production rate by changing flow beans. Christmas Tree In petroleum and natural gas extraction, a Christmas tree, or "tree", (not "wellhead" as sometimes incorrectly referred to) is an assembly of valves, spools, and fittings used for an oil well, gas well, water injection well, water disposal well, gas injection well, condensate well and other types of wells. It was named for its crude resemblance to a decorated tree. Overview Note that a tree and wellhead are separate pieces of equipment not to be mistaken as the same piece. A wellhead must be present in order to utilize a Christmas tree and a wellhead is used without a Christmas tree during drilling operations, and also for riser tie-back situations which would then have a tree included at riser top. Producing surface wells that require pumps (pump jacks, nodding donkeys, and so on) frequently do not utilize any tree due to no pressure containment requirement. Tree complexity has increased over the last few decades. They are frequently manufactured from blocks of steel containing multiple valves rather than made from multiple flanged valves.
This document is posted to help you gain knowledge. Please leave a comment to let me know what you think about it! Share it to your friends and learn new things together.
Transcript
WellheadThe system of spools, valves and assorted adapters that provide pressure control of a production well
CHOKE VALVE The choke valve, a main Description of Christmas tree, is design to control production rate of the oil well, with working pressure up to 10000psi. Choke valves can be classified as follows: adjustable choke valves and positive choke valves. By rotating hand wheel to drive the stem, the adjustable choke valve is designed to adjust the effective area available for the flow to accomplish control of production rate. The positive choke valve is design to accomplish control of production rate by changing flow beans.
Christmas Tree
In petroleum and natural gas extraction, a Christmas tree, or "tree", (not "wellhead" as sometimes incorrectly referred to) is an assembly of valves, spools, and fittings used for an oil well, gas well, water injection well, water disposal well, gas injection well, condensate well and other types of wells. It was named for its crude resemblance to a decorated tree.
Overview Note that a tree and wellhead are separate pieces of equipment not to be mistaken as the same piece. A wellhead must be present in order to utilize a Christmas tree and a wellhead is used without a Christmas tree during drilling operations, and also for riser tie-back situations which would then have a tree included at riser top. Producing surface wells that require pumps (pump jacks, nodding donkeys, and so on) frequently do not utilize any tree due to no pressure containment requirement.
Tree complexity has increased over the last few decades. They are frequently manufactured from blocks of steel containing multiple valves rather than made from multiple flanged valves. This is especially true in sub sea applications where the resemblance to Christmas trees no longer exists given the frame and support systems into which the main valve block is integrated.
Wellhead components
Well Casing
Installing 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 strengthens the sides of the well hole, ensures that no oil or natural gas seeps out of the well hole as it is brought to the surface, and keeps other fluids or gases from seeping into the formation through the well. A good deal of planning is necessary to ensure that the proper casing for each well is installed. The type of casing used depends on the subsurface characteristics of the well, including the diameter of the well and the pressures and temperatures experienced throughout the well. The diameter of the well hole depends on the size of the drill bit used. In most wells, the diameter of the well hole decreases the deeper it is drilled, leading to a type of conical shape that must be taken into account when installing casing.
There are five different types of well casing. They include:
Conductor Casing Surface Casing Intermediate Casing Liner String Production Casing
Conductor Casing
Conductor casing is installed first, usually prior to the arrival of the drilling rig. The hole for conductor casing is often drilled with a small auger drill, mounted on the back of a truck. Conductor casing is usually no more than 20 to 50 feet long. It is installed 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. Onshore, this casing is usually 16 to 20 inches in diameter, while offshore casing usually measures 30 to 42 inches. The conductor casing is cemented into place before drilling begins.
Surface Casing
Surface casing is the next type of casing to be installed. It can be anywhere from a few hundred to 2,000 feet long, and is smaller in diameter than the conductor casing. When installed, the surface casing fits inside the top of the conductor casing. The primary purpose of surface casing is to protect fresh water deposits near the surface of the well from being contaminated 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 being damaged during drilling. Surface casing, like conductor casing, is cemented into place. Regulations often dictate the thickness of the cement to be used to ensure that there is little possibility of freshwater contamination.
Intermediate Casing
Intermediate casing is usually the longest section of casing found in a well. The primary purpose of intermediate casing is to minimize the hazards that come along with subsurface formations that may affect the well. These include abnormal underground pressure zones, underground shale, and formations that might otherwise contaminate the well, such as underground salt-water deposits. In many instances, even though there may be no evidence of an unusual underground formation, intermediate casing is run as insurance against the possibility of such a formation affecting the well. These intermediate casing areas may also be cemented into place for added protection.
Liner Strings
Liner strings are sometimes used instead of intermediate casing. Liner strings are commonly run from the bottom of another type of casing to the open well area. However, liner strings are usually attached to the previous casing with 'hangers', instead of being cemented into place. This type of casing is thus less permanent than intermediate casing.
Production Casing
A Small Auger DrillSource: USGS
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 time. For example, if it is expected that the well will be deepened at a later date, then the production casing must be wide enough to allow the passage of a drill bit later on.
Well casing is a very important part of the completed well. In addition to strengthening the well hole, it provides a conduit to allow hydrocarbons to be extracted without intermingling with other fluids and formations found underground. It is also instrumental in preventing blowouts, allowing the formation to be 'sealed' from the top should dangerous pressure levels be reached. For more technical information on blowouts and their prevention, click here. Once the casing has been set, and in most cases cemented into place, proper lifting equipment is installed to bring the hydrocarbons from the formation to the surface. After the casing is installed, tubing is inserted inside the casing, running from the opening well at the top to the formation at the bottom. The hydrocarbons that are extracted go up this tubing to the surface. This tubing may also be attached to pumping systems for more efficient extraction, should that be necessary.
Completion
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 Completion Conventional Perforated Completion Sand Exclusion Completion Permanent Completion Multiple Zone Completion Drain hole Completion
The use of any type of completion depends on the characteristics and location of the hydrocarbon formation to be mined.
Open Hole Completion
Open hole completions are the most basic type and are used in 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. Very often, this type of completion is used on formations that have been ‘acidized’ or ‘fractured.’
Conventional Perforated Completion
Conventional perforated completions consist of production casing being run through the formation. The sides of this casing are perforated, with tiny holes along the sides facing the
Installing Well CasingSource: ChevronTexaco Corporation
formation, which allows for the flow of hydrocarbons into the well hole, but still provides a suitable amount of support and protection for the well hole. The process of perforating the casing involves the use of specialized equipment designed to make tiny holes through the casing, cementing, and any other barrier between the formation and the open well. In the past, 'bullet perforators' were used, which were essentially small guns lowered into the well. The guns, when fired from the surface, sent off small bullets that penetrated the casing and cement. Today, 'jet perforating' is preferred. This consists of small, electrically-ignited charges, lowered into the well. When ignited, these charges poke tiny holes through to the formation, in the same manner as bullet perforating.
Sand Exclusion Completion
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, but at the same time prevent sand from entering the well. Sand inside the well hole can cause many complications, including erosion of casing and other equipment. The most common methods of keeping sand out of the well hole are screening or filtering systems. These include analyzing the sand experienced in the formation and installing a screen or filter to keep sand particles out. The filter may be either a type of screen hung inside the casing, or a layer of specially-sized gravel outside the casing to filter out the sand. Both types of sand barriers can be used in open holes and perforated completions.
Permanent Completion
Permanent completions are those in which the components 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
Multiple zone completion is the practice of completing a well so that hydrocarbons from two or more formations may be produced simultaneously, yet separately. For example, a well may be drilled that passes through a number of formations as it descends; alternately, it may be more effective in a horizontal well to add multiple completions to drain the formation efficiently. Although it is common to separate multiple completions so that the fluids from the different formations do not intermingle, the complexity of achieving complete separation can present a barrier. In some instances, the different formations being drilled are close enough to allow fluids to intermingle in the well hole. When it is necessary to prevent this intermingling, hard rubber 'packing' instruments are used to maintain separation among different completions.
Drain hole Completion
Drain hole completions are a form of horizontal or slant drilling. This type of completion consists of drilling out horizontally into the formation from a vertical well, providing a 'drain' for the hydrocarbons to empty into the well. In certain formations, drilling a drain hole completion may allow for more efficient and balanced extraction of the targeted hydrocarbons. Drain hole completions are more commonly associated with oil wells than with natural gas wells.
The Wellhead
The wellhead consists of the pieces of equipment mounted at the opening of the well to manage the
A WellheadSource: NETL - DOE
extraction of hydrocarbons from the underground formation. It prevents leaking of oil or natural gas out of the well, and also prevents blowouts caused by high pressure. 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 wellheads must be able to withstand pressures of up to 20,000 pounds per square inch (Psi). The wellhead consists of three components: the casing head, the tubing head, and the 'Christmas tree.’
The casing head consists of heavy fittings that provide a seal between the casing and the surface. The casing head also serves to support the entire length of casing that is run all the way down the well. This piece of equipment typically contains a gripping mechanism that ensures a tight seal between the head and the casing itself.
The tubing head is much like the casing head. It provides a seal between the tubing, which is run inside the casing, and the surface. Like the casing head, the tubing head is designed to support the entire length of the casing, as well as provide connections at the surface, which allow the flow of fluids out of the well to be controlled.
The 'christmas tree' is the piece of equipment that fits on top of the casing and tubing heads, and contains tubes and valves that control the flow of hydrocarbons and other fluids out of the well. It commonly contains many branches and is shaped somewhat like a tree, thus its name, ‘christmas tree.’ The christmas tree is the most visible part of a producing well, and allows for the surface monitoring and regulation of the production of hydrocarbons from a producing well. A typical Christmas tree is about six feet tall.
Lifting and Well Treatment
Once the well is completed, it may begin to produce natural gas. In some instances, the hydrocarbons that exist in pressurized formations will naturally rise up through the well to the surface. This is most commonly the case with natural gas. Since natural gas is lighter than air, once a path to the surface is opened, the pressurized gas will rise to the surface with little or no interference. This is most common for formations containing natural gas alone, or with only a light condensate. In these scenarios, once the christmas tree is installed, the natural gas will flow to the surface without assistance.
In order to more fully understand the nature of the well, a potential test is typically run in the early days of production. This test allows well engineers to determine the maximum amount of natural gas that the well can produce in a 24-hour period. From this and other knowledge of the formation, the engineer may make an estimation on what the 'most efficient recovery rate', or MER will be. The MER is the rate at which the greatest amount of natural gas may be extracted without harming the formation itself.
Another important aspect of producing wells is the 'decline rate'. When a well is first drilled, the formation is under pressure and produces natural gas at a very high rate. However, as more and more natural gas is extracted from the formation, the production rate of the well decreases. This is known as the decline rate. Certain techniques, including lifting and well stimulation, can increase the production rate of a well.
In some natural gas wells, and oil wells that have associated natural gas, it is more difficult to ensure an efficient flow of hydrocarbons up the well. The underground formation may be very 'tight', making the movement of petroleum through the formation and up the well a very slow and inefficient process. In these cases, lifting equipment or well treatment is required.
Lifting equipment consists of a variety of specialized equipment used to help 'lift' petroleum out of a formation. This is most commonly used to extract oil from a formation. Because oil is found as a viscous liquid, it takes some coaxing to extract it from underground. Various types of lifting equipment are available, but the most common lifting method is known as 'rod pumping'. Rod pumping is powered by a surface pump that moves a cable and rod up and down in the well, providing the lifting pressure required to bring the oil to the surface. The most common type of cable rod lifting equipment is the 'horse head' or conventional beam pump. These pumps are recognizable by the distinctive shape of the cable feeding fixture, which resembles a horse's head.
Well Treatment
Well treatment is another method of ensuring the efficient flow of hydrocarbons out of a formation. Essentially, this type of well stimulation consists of injecting acid, water, or gases into the well to open up the formation and allow the petroleum to flow through the formation more easily. Acidizing a well consists of injecting acid (usually hydrochloric acid) into the well. In limestone or carbonate formations, the acid dissolves portions of the rock in the formation, opening up existing spaces to allow for the flow of petroleum. Fracturing consists of injecting a fluid into the well, the pressure of which 'cracks' or opens up fractures already present in the formation. In addition to the fluid being injected, 'propping agents' are also used. These propping agents can consist of sand, glass beads, epoxy, or silica sand, and serve to prop open the newly widened fissures in the formation. Hydraulic fracturing involves the injection of water into the formation, while CO2 fracturing uses gaseous carbon dioxide. Fracturing, Acidizing, and lifting equipment may all be used on the same well to increase permeability, widening the pores of the formation.
These techniques have been more common to oil wells, but are increasingly being applied to increase the extraction rate for gas wells, particularly hydraulic fracturing. As deeper and less conventional natural gas wells are drilled, it is becoming more common to use stimulation techniques on gas wells.
Click on the following links to learn more: hydraulic fracturing and shale gas.
The next step in the process of producing natural gas is processing. This involves taking the 'raw' natural gas obtained from underground, removing impurities, and ensuring that the gas is ready for use prior to being transported to its destination.
A well kill is the operation of placing a column of heavy fluid into a well bore in order
to prevent the flow of reservoir fluids without the need for pressure control equipment
at the surface. It works on the principle that the weight of the "kill fluid" or "kill mud"
will be enough to suppress the pressure of the formation fluids. Well kills may be
planned in the case of advanced interventions such as workovers, or be contingency
A Horse Head PumpSource: ChevronTexaco Corporation
This is similar to reverse circulation, except the kill mud is pumped into the
production tubing and circulated out through the annulus. Though effective, it is not
as desirable since it is preferred that the well bore fluids be displaced out to
production, rather than the annulus.
Lubricate and bleedThis is the most time consuming form of well kill. It involves repeatedly pumping in
small quantities of kill mud into the well bore and then bleeding off excess pressure.
It works on the principle that the heavier kill mud will sink below the lighter well bore
fluids and so bleeding off the pressure will remove the latter leaving an increasing
quantity of kill mud in the well bore with successive steps.
Well kills during drilling operationsDuring drilling, pressure control is maintained through the use of precisely concocted
drilling fluid, which balances out the pressure at the bottom of the hole. In the event
of suddenly encountering a high pressure pocket of, say gas (called a "kick"), it can
become necessary to kill the well. This is done by pumping kill mud down the drill
pipe, where it circulates out the bottom and into the well bore.
Reversing a well killThe intention of a well kill (or the reality of an unintentional well kill) is to stop reservoir fluids flowing to surface. This of course creates problems when it is desirable to get the well flowing again. In order to reverse the well kill, the kill fluid must be displaced from the well bore. This involves injecting a gas at high pressure, usually nitrogen since it is inert and cheap. A gas can be put under sufficient pressure to allow it to push heavy kill fluid, but will then expand and become light once pressure is removed. This means that having displaced the kill fluid, it will not itself kill the well. The reservoir fluids should be able to flow to surface, displacing the gas.
The cheapest way to do it is similar to bullheading, where the nitrogen is pumped in under high pressure to force the kill fluid into the reservoir. This, of course, runs a high risk of causing well damage. The most effective way is to use coiled tubing, pumping the gas down the coil and circulating out the bottom into the well bore, where it will displace the kill mud to production.
A well intervention, or 'well work', is any operation carried out on a oil or gas well
during, or at the end of its productive life, that alters the state of the well and or well
geometry, provides well diagnostics or manages the production of the well.
In some older wells, changing reservoir conditions or deteriorating condition of the
completion may necessitate pulling it out to replace it with a fresh completion.
Subsea well Intervention Subsea well interventions offer up many challenges and requires much advanced planning. The cost of subsea intervention has in the past inhibited the intervention but in the current climate are much more viable. These interventions are commonly executed from Light/medium intervention vessels or Mobile Offshore Drilling Units (MODU) for the heavier interventions such as Snubbing and Workover drilling rigs
In the oil and gas industry, the term wireline usually refers to a cabling technology
used by operators of oil and gas wells to lower equipment or measurement devices
into the well for the purposes of well intervention and reservoir evaluation.
Braided line can contain an inner core of insulated wires which provide power to
equipment located at the end of the cable, normally referred to as electric line, and
provides a pathway for electrical telemetry for communication between the surface
and equipment at the end of the cable.
Wire line toolsA wire line tool string can be dozens of feet long with multiple separate tools installed
to perform multiple operations at once.
Open Hole Electric Line Tools
Natural Gamma Ray ToolsNatural gamma-ray tools are designed to measure naturally occurring gamma
radiation in the earth caused by the disintegration due to Potassium, Uranium, and
Thorium. Unlike nuclear tools, these natural gamma ray tools do not emit any
radiation.
Natural gamma ray tools employ a radioactive sensor, which is usually a scintillation
crystal that emits a light pulse proportional to the strength of the gamma ray pulse
incident on it. This light pulse is then converted to a current pulse by means of a
photo multiplier tube PMT. From the photo multiplier tube, the current pulse goes to
the tool's electronics for further processing and ultimately to the surface system for
recording. The strength of the received gamma rays is dependent on the source
emitting gamma rays, the density of the formation, and the distance between the
When the operator, well, and facilities are ready to produce and receive oil or gas,
valves are opened and the release of the formation fluids is allowed to flow into and
through a pipeline. The pipeline then leads to a processing facility, storage depot
and/or other pipeline eventually leading to a refinery or distribution center (for gas).
Subsea wells and thus trees usually flow through flowlines to a fixed or floating
production platform or to a storage vessel (known as a floating storage offloading
vessel (FSO), or floating processing unit (FPU), or floating production and offloading
vessel or FPSO or other combination of structures).
A tree may also be used to control the injection of gas or water injection application
on a producing or non-producing well in order to sustain economic "production"
volumes of oil from other well(s) in the area (field).
On producing wells, injection of chemicals or alcohols or oil distillates to prevent and
or solve production problems (such as blockages) may be used. Functionality may
be extended further by using the control system on a subsea tree to monitor,
measure, and react to sensor outputs on the tree or even down the well bore.
The control system attached to the tree controls the downhole safety valve (scssv,
dhsv, sssv) while the tree acts as an attachment and conduit means of the control
system to the downhole safety valve.
Christmas trees are used on both surface and subsea wells (current technical limits
are up to around 3000 metres and working temperatures of -50°F to 350°F with a
pressure of up to 15,000 psi). The deepest installed subsea tree is in the Gulf of
Mexico at approximately 9000 feet.
ValvesSubsea and surface trees have a large variety of valve configurations and combinations of manual and/or actuated (hydraulic or pneumatic) valves. Examples are identified in API Specifications 6A and 17D.
A basic surface tree consists of two or three manual valves (usually gate valves because of their strength).
A typical sophisticated surface tree will have at least four or five valves, normally arranged in a crucifix type pattern (hence the endurance of the term "Christmas tree"). The two lower valves are called the master valves (upper and lower respectively) because they lie in the flow path, which well fluids must take to get to surface. The lower master valve will normally be manually operated, while the upper master valve is often hydraulically actuated, allowing it to be a means of well control while an actuated wing valve is normally the primary well remotely (from control room or control panel) controlled valve. Hydraulic tree wing valves are usually built to be fail safe closed, meaning they require active hydraulic pressure to stay open.
The right hand valve is often called the flow wing valve or the production wing valve, because it is in the flowpath the hydrocarbons take to production facilities (or the path water or gas will take from production to the well in the case of injection wells).
The left hand valve is often called the kill wing valve. It is primarily used for injection of fluids such as corrosion inhibitors or methanol to prevent hydrate formation. In the North Sea, it is called the non-active side arm (NASA). It is typically manually operated.
The valve at the top is called the swab valve and lies in the path used for well interventions like wireline and coiled tubing. For such operations, a lubricator is rigged up onto the top of the tree and the wire or coil is lowered through the lubricator, past the swab valve and into the well. This valve is typically manually operated.
Some trees have a second swab valve, the two arranged one on top of the other. The intention is to allow rigging down equipment from the top of the tree with the well flowing while still preserving the Two-barrier rule. With only a single swab valve, the upper master valve is usually closed to act as the second barrier, forcing the well to be shut in for a day during rig down operations. However, avoiding delaying production for a day is usually too small a gain to be worth the extra expense of a having a Christmas tree with a second swab valve.
Subsea trees are available in either vertical or horizontal configurations with further speciality available such as dual bore, monobore, concentric, drill-through, mudline, guidlineless or guideline. Subsea trees may range in size and weight from a few tons to approximately 70 tons for high pressure, deepwater (>3000 feet) guidelineless applications. Subsea trees contain many additional valves and accessories compared to Surface trees. Typically a subsea tree would have a choke (permits control of flow), a floline connection interface (hub, flange or other connection), subsea control interface (direct hydraulic, electro hydraulic, or electric) and sensors for gathering data such as pressure, temperature, sand flow, erosion, multiPhase flow, single phase flow such as water or gas.
(blind, shear, pipe, slip). Newer dual-BOPs combine some of these functions
together to need just two distinct rams (shear-blind, pipe-slip).
The BOP sits on top of the riser, which provides the pressurised tunnel down to the
top of the Xmas tree. Between the Xmas tree and the riser is the final pressure
barrier, the shear-seal BOP, which can cut and seal the pipe.
Onshore light coiled tubing unitA Coil Tubing Unit is a self contained multi-use machine that can approximately do anything a conventional service rig is capable of - with the exception of tripping jointed pipe. There are generally two types in shallow service - Arch and Picker. One uses a vertical elevator with a horsehead on top, and an injector hanging by winch line off it. The Picker units have a picker, and a horsehead bolted directly to the injector.
These type of coil tubing units have a permanent drum mounted amidships (They are generally tandem drive Class 3 trucks, long or so), and a large air compressor, usually good for 2500 psi at 660 CFM, mounted between the drum and cab. In lower pressure, natural gas wells, with no hydrocarbons, the compressor is actually used to blow air to bottom hole in these live natural gas wells, for the purpose of "cleaning out" mud and fluid from the wellbore and perforations. In higher pressure wells, or oil wells, nitrogen or carbon dioxide is the preferred, and much safer method.
Completion
In petroleum production, completion is the process of making a well ready for
production (or injection). This principally involves preparing the bottom of the hole to
the required specifications, running in the production tubing and its associated down
hole tools as well as perforating and stimulating as required. Sometimes, the process
of running in and cementing the casing is also included.
Lower completionThis refers to the portion of the well across the production or injection zone. The well
designer has many tools and options available to design the lower completion
according to the conditions of the reservoir. Typically, the lower completion is set
across the productive zone using a liner hanger system, which anchors the lower
completion to the production casing string. The broad categories of lower completion
Acidizing and fracturing (combined method)This involves use of explosives and injection of chemicals to increase acid-rock
contact.
Nitrogen circulationSometimes, productivity may be hampered due to the residue of completion fluids, heavy brines, in the wellbore. This is particularly a problem in gas wells. In these cases, coiled tubing may be used to pump nitrogen at high pressure into the bottom of the borehole to circulate out the brine.
Production tubing is a tube used in a well bore through which production fluids are produced (travel).
Production tubing is run into the drilled well after the casing is run and cemented in place. Along with other components that constitute the production string, it provides a continuous bore from the production zone to the wellhead through which oil and gas can be produced. It is usually between five and ten centimeters in diameter and is held inside the casing through the use of expandable packing devices.
If there is more than one zone of production in the well, up to four lines of production tubing can be run.
Annulus
The annulus (yellow area in diagram) of an oil well refers to any void between any piping, tubing or casing and the piping, tubing or casing immediately surrounding it. The presence of an annulus gives the ability to circulate fluid in the well, provided that excess drill cuttings have not accumulated in the annulus preventing fluid movement and possibly sticking the pipe in the borehole.
For a new well in the process of being drilled, this would be the void between the drill string and the formation being drilled. An easy way to visualise this would be to stand a straw (purple in diagram) straight up in the center of a glass of water. All of the water in between the straw and the sides of the glass would be the annulus (yellow area in diagram), with the straw itself representing the drill string and the sides of the glass representing the formation. While drilling, drilling fluid is pumped down the inside of the drill string and pushes the drill cuttings up the annulus to the surface, where the cuttings are removed from the drilling fluid (drilling mud) by the shale shakers.
In a completed well, there may be many annuli. The 'A' annulus is the void between the production tubing and the smallest casing string. The A annulus can serve a number of crucial tasks, including gas lift and well kills. A normal well will also have a 'B' and frequently a 'C' annulus, between the different casing strings. These annuli
do not normally have any connection to well bore fluids, but maintaining pressure in them is important in order to ensure integrity of the casing strings.
Though all annuli in a completed well are expected to be isolated from the production tubing and each other, connections allowing the flow of fluids between them may sometimes occur, either due to intervention or wear and tear. In these situations, it is said that there is "communication" between them.
During coiled tubing interventions, the void between the coil and the production tubing can also be considered an annulus and be used for circulation.
Casing
Casing is large diameter pipe that is assembled and inserted into a recently drilled
section of a borehole and typically held into place with cement.
PurposeCasing that is cemented in place aids the drilling process in several ways:
Prevent contamination of fresh water well zones.
Prevent unstable upper formations from caving-in and sticking the drill string
or forming large caverns.
Provides a strong upper foundation to use high-density drilling fluid to
continue drilling deeper.
Isolates different zones, that may have different pressures or fluids - known
as zonal isolation, in the drilled formations from one another.
Seals off high pressure zones from the surface, avoiding potential for a
blowout
Prevents fluid loss into or contamination of production zones.
Provides a smooth internal bore for installing production equipment.
A slightly different metal string, called production tubing, is often used without
cement in the smallest casing of a well completion to contain production fluids and
convey them to the surface from an underground reservoir.
DesignIn the planning stages of a well a drilling engineer, usually with input from geologists
and others, will pick strategic depths at which the hole will need to be cased in order
Cementing is performed by circulating a cement slurry through the inside of the casing and out into the annulus through the casing shoe at the bottom of the casing string. In order to precisely place the cement slurry at a required interval on the outside of the casing, a plug is pumped with a displacement fluid behind the cement slurry column, which "bumps" in the casing shoe and prevents further flow of fluid through the shoe. This bump can be seen at surface as a pressure spike at the cement pump. To prevent the cement from flowing back into the inside of the casing, a float collar above the casing shoe acts as a check valve and prevents fluid from flowing up through the shoe from the annulus.
Casing string is a long section of connected oilfield pipe that is lowered into a wellbore and cemented. The pipe segments (called "joints") are typically about in length, male threaded on each end and connected with short lengths of double-female threaded pipe called couplings. (Some specialty casing is manufactured in one piece with a female thread machined directly into one end.)
Specification 5C3 of the American Petroleum Institute standardizes 14 casing sizes from to outside diameter ("OD"). This and related API documents also promulgate standards for the threaded end finish, the wall thickness (several are available in each size to satisfy various design parameters, and in fact are indirectly specified by standardized nominal weights per linear foot; thicker pipe obviously being heavier), and the strength and certain chemical characteristics of the steel material. Several material strengths—termed "Grades" and ranging from to minimum yield strength—are available for most combinations of OD and wall thickness to meet various design needs. Finally, the API publications provide performance minimums for longitudinal strength ("joint strength") as well as resistance to internal (bursting) and external (collapsing) pressure differentials.
A typical piece of casing might be described as 9-5/8" 53.5# P-110 LT&C Rg 3: specifying OD, weight per foot (53.5 lbm/ft thus 0.545-inch wall thickness and 8.535-inch inside diameter), steel strength (110,000 psi yield strength), end finish ("Long Threaded and Coupled"), and approximate length ("Range 3" usually runs between 40 and 42 feet).
Casing is run to protect or isolate formations adjacent to the wellbore. It is generally not possible to drill a well through all of the formations from surface (or the seabed) to the target depth in one hole section. For example, fresh-water-bearing zones (usually found only near the surface) must be protected soon after being penetrated. The well is therefore drilled in sections, with each section of the well being sealed off by lining the inside of the borehole with steel pipe, known as casing, and filling the annular space (or at least the lower portion) between this casing string and the borehole with cement. Then drilling commences on the subsequent hole section, necessarily with a smaller bit diameter that will pass through the newly installed casing.
A liner is a casing string that does not extend to the surface, being hung instead from a liner hanger set inside of the previous casing string but usually within about of its
bottom. Other than the obvious cost savings, the liner installation allows larger drill pipe or production tubing to be used in the upper portions of the well. (A disadvantage is the occasional difficulty in effecting a pressure seal by squeeze cementing the casing-liner overlap zone.)
Depending on the conditions encountered (e.g., zones of differing formation pressure gradients), three or four casing strings may be required to reach the target depth. The cost of the casing can constitute 20-30% of the total cost of the well. Great care must therefore be taken when designing a casing programme that will meet the requirements of the well.