The loads to which the casing will be exposed during the life of the well will depend on the operations to be conducted: whilst running the casing; drilling the subsequent hole section; and during the producing life of the well. These operations will result in radial (burst and collapse) and axial (tensile and compressive) loads on the casing strings. Since the operations conducted inside any particular string (e.g. the surface string) will differ from those inside the other strings (e.g. the production string) the load scenarios and consequent loads will be specific to a particular string. The definition of the operational scenarios to be considered is one of the most important steps in the casing design process and they will therefore generally be established as a company policy.

Liners are run on drillpipe with special tools which allow the liner to be run, set and cemented all in one trip (Figure 12). The liner hanger is installed at the top of the liner. The hanger has wedge slips which can be set against the inside of the previous string. The slips can be set mechanically (rotating the drillpipe) or hydraulically (differential pressure). A liner packer may be used at the top of the liner to seal off the annulus after the liner has been cemented. The basic liner running procedure is as follows:

(a)    Run the liner on drillpipe to the required depth;
(b)    Set the liner hanger;
(c)    Circulate drilling fluid to clean out the liner;
(d)    Back off (disconnect) the liner hanger setting tool;
(e)    Pump down and displace the cement;
(f)    Set the liner packer;
(g)    Pick up the setting tool, reverse circulate to clean out cement and pull out of hole.

casing liner

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After the casing is run to the required depth it is cemented in place while suspended in the wellhead. The method used for landing the casing will vary from area to area, depending on the forces exerted on the casing string after the well is completed. These forces may be due to changes in formation pressure, temperature, fluid density and earth movements (compaction). These will cause the casing to either shrink or expand, and the landing procedure must take account of this. There are basically 3 different ways in which the casing can be cemented and landed:

1. landing the casing and cementing;
2. suspending the casing, conducting the cement job and then applying
3. additional tension when the cement has hardened;
4. landing the casing under compression;

The first case does not require any action after the cementing operation is complete.The casing is simply landed on a boll-weevil hanger and cemented in place. Additional tension (over and above the suspended weight) may however have to be applied to the casing to prevent buckling due to thermal expansion when the well is producing hot fluids. Additional tension can be applied, after the casing has been cemented, by suspending the casing from the elevators during the cementing operation and then applying an overpull (extra tension) to the casing once the cement has hardened.

The casing would then be landed on a slip and seal assembly. The level of overpull applied to the casing will depend on the amount of buckling load that is anticipated due to production. The third option may be required in the case that the suspended tension reduces the casing’s collapse resistance below an acceptable level. In this case the casing is suspended from the elevators during cementing and then lowered until the desired compression is achieved before setting the slip and seal assembly.

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(a) Before the casing is run, a check trip should be made to ensure that there are no tight spots or ledges which may obstruct the casing and prevent it reaching bottom

(b) The drift I.D. of each joint should be checked before it is run.

(c) Joints are picked up from the catwalk and temporarily rested on the ramp. A single joint elevator is used to lift the joint up through the “V” door into the derrick (Figure 10).

casing running

(d) A service company (casing crew) is usually hired to provide a stabber and one or two floormen to operate the power tongs. The stabbing board is positioned at the correct height to allow the stabber to centralise the joint directly above the box of the joint suspended in the rotary table. The pin is then carefully stabbed into the box and the power tongs are used to make up the connection slowly to ensure that the threads of the casing are not cross threaded. Care should be taken to use the correct thread compound to give a good seal. The correct torque is also important and can be monitored from a torque gauge on the power tongs. On buttress casing there is a triangle stamped on the pin end as a reference mark. The coupling should be made up to the base of the triangle to indicate the correct make-up.

(e) As more joints are added to the string the increased weight may require the use of heavy duty slips (spider) and elevators (Figure 11).

casing elevator

(f) If the casing is run too quickly into the hole, surge pressures may be generated below the casing in the open hole, increasing the risk of formation fracture. A running speed of 1000 ft per hour is often used in open hole sections. If the casing is run with a float shoe the casing should be filled up regularly as it is run, or the casing will become buoyant and may even collapse, under the pressure from the mud in the hole.

(g) The casing shoe is usually set 10-30 ft off bottom.

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(a) When the casing arrives at the rig site the casing should be carefully stacked in the correct running order. This is especially important when the string contains sections of different casing grades and weights. On offshore rigs, where deck space is limited, do not stack the casing too high or else excessive lateral loads will be imposed on the lowermost row. Casing is off-loaded from the supply boat in reverse order, so that it is stacked in the correct running order

(b) The length, grade, weight and connection of each joint should be checked and each joint should be clearly numbered with paint. The length of each joint of casing is recorded on a tally sheet. If any joint is found to have damaged threads it can be crossed off the tally sheet. The tally sheet is used by the Drilling engineer to select those joints that must be run so that the casing shoe ends up at the correct depth when the casing hanger is landed in the wellhead.

(c) While the casing is on the racks the threads and couplings should be thoroughly checked and cleaned. Any loose couplings should be tightened

(d) Casing should always be handled with thread protectors in place. These need not be removed until the joint is ready to be stabbed into the string.

There are two types of casing hanger in common use. Wellheads can be designed to accept both types of hanger.

Mandrel (boll weevil) Type Casing Hangers: This type of hanger (Figure 8) is screwed onto the top of the casing string so that it lands in the casing housing when the casing shoe reaches the required depth. Short lengths of casing, known as pup joints may have to be added to the string so that the casing shoe is at the correct depth when the hanger lands in the wellhead. The calculation which determines the length of pup joints required to achieve this positioning is known as spacing out the string. Although this is the most common type of hanger it cannot be used if there is a risk that the casing will not reach bottom and therefore that the hanger will not land in the wellhead.

Slip Type Casing Hangers: This type of hanger (Figure 9) is wrapped around the casing and then lowered until it sits inside the casing spool. The slips are automatically set when the casing is lowered (in a similar fashion to drillpipe slips) This type of hanger can be used if the casing stands up on a ledge and cannot reach its required setting depth. These types of hanger are also used when tension has to be applied in order to avoid casing buckling when the well is brought into production.

casing hanger

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The compact spool was developed as an alternative to the conventional spool discussed above. A compact spool enables several casing strings or tubing to be suspended from a single spool. The first step in using this type of wellhead is to install the 20″ casing head housing, as in the case of the spool type wellhead. After the 13 3/8” casing is run and cemented, the casing is cut off and the speedhead is connected to the casing head housing. The BOPs can then be connected to the top of the housing, and the next hole section drilled.

The 9 5/8″ casing is then run, with the hanger resting on a landing shoulder inside the speedhead. A 7″ casing string can be run, and landed, in the speedhead in a similar manner to the 9 5/8″ casing. The tubing string may also be run and landed in the speedhead. The Christmas tree can then be installed on top of the speedhead.

The disadvantage of the compact spool is that the casing programme cannot be easily altered, and so this system is less flexible than the separate spool system.

The procedure for installing a spool type wellhead system (Figure 6) can be outlined as follows:

(a) The conductor (30″) is run and cemented in place. It is then cut off just above     the ground level or the wellhead deck (on a platform);
(b) The 26” hole is drilled and the 20″ casing is run through the conductor and cemented. Sometimes a landing base is welded onto the top of the 20” casing so that it can rest on the top of the 30” conductor, to transfer some weight to the 30″ casing.
(c) The 20″ casing is cut off just above the 30″ casing and a 20″ casing head housing (lowermost casing head) is threaded, or welded, onto the top of the casing. The internal profile of this housing has a landing surface on which the casing hanger of the subsequent casing string (13 3/8”) lands. The housing has two side outlets which provide access to the 20”x13 3/8” annulus. The upper flange of the housing is used as the lower part of the connection to the BOP stack used in drilling the next hole section. A ring gasket is used to seal off the connection between the housing and the BOP stack.
(d) The 171/2” hole is drilled and the 13 3/8″ casing is run with the hanger landing in the 20″ housing. The casing is cemented in place. The BOP stack is disconnected and a casing spool (13 5/8″) is flanged up on top of the 20″ housing. The BOPs are made up on top of the 13 5/8” spool and the 12 1/4″ hole is drilled.

API wellhead

The process continues, with a new spool being installed for each casing string. Eventually a tubing head spool is installed. This spool allows the completion tubing to be suspended from the wellhead. The minimum I.D. of a casing spool must be greater than the drift I.D. of the previous casing. A protective sleeve known as a wear bushing is installed in each spool when it is installed and before the drillstring is run. The wear bushing must be removed before the next casing string is run. Finally the Christmas tree is installed on top of the wellhead (Figure 7). A ring gasket, approved by the API, is used to seal off the space between the flanges on the spools. The gaskets have pressure energized seals and can be rated up to 15000 psi.

The disadvantages of this type of wellhead are:
1. a lot of time is spent flanging up the spools;
2. the large number of seals, increases the chance of a pressure leak;
3. BOPs must be removed to install the next casing spool;
4. a lot of headroom is required, which may not be available in the wellhead area of an offshore platform.

xmass tree

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Individual joints of casing are connected together by a threaded connection. These connections are variously classified as: API; premium; gastight; and metal-to-metal seal. In the case of API connections, the casing joints are threaded externally at either end and each joint is connected to the next joint by a coupling which is threaded internally (Figure 5). A coupling is already installed on one end of each joint when the casing is delivered to the rig. The connection must be leak proof but can have a higher or lower physical strength than the main body of the casing joint.

A wide variety of threaded connections are available. The standard types of API threaded and coupled connection are:
•    Short thread connection (STC)
•    Long thread connection (LTC)
•     Buttress thread connection (BTC)
In addition to threaded and coupled connections there are also externally and internally upset connections such as that shown in Figure 4. A standard API upset connection is:

•    Extreme line (EL)
The STC thread profile is rounded with 8 threads per inch. The LTC is similar but with a longer coupling, which provides better strength and sealing properties than the STC. The buttress thread profile has flat crests, with the front and back cut at different angles. Extreme line connections also have flat crests and have 5 or 6 threads per inch. The EL connection is the only API connection that has a metal to metal seal at the end of the pin and at the external shoulder of the connection, whereas all of the other API connections rely upon the thread compound, used to make up the connection, to seal off the leak path between the threads of the connection.

In addition to API connections, various manufacturers have developed and patented their own connections (e.g. Hydril, Vallourec, Mannesman). These connections are designed to contain high pressure gas and are often called gastight, premium and metal-to-metal seal connections. These connections are termed metal-to-metal seal because they have a specific surface machined into both the pin and box of the connection which are brought together and subjected to stress when the connection is made up.

Surveys have shown that over 80% of leaks in casing can be attributed to poor make-
up of connections. This may be due to a variety of reasons:
•    Excessive torque used in making-up the connections
•    Dirty threads
•    Cross-threading
•    Using the wrong thread compound.
The casing string should be tested for pressure integrity before drilling the subsequent hole section. Most of the causes of connection failure can be eliminated by good handling and running procedures on the rig.

The recommended make-up torque for API connections is given in API RP 5C1. These recommended torques are based on an empirical equation obtained from tests using API modified thread compound on API connections. The recommended make up torque for other connections is available from manufacturers.

casing connection

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The chemical composition of casing varies widely, and a variety of compositions and treatment processes are used during the manufacturing process This means that the physical properties of the steel varies widely. The materials which result from the manufacturing process have been classified by the API into a series of “grades” (Table 3). Each grade is designated by a letter, and a number. The letter refers to the chemical composition of the material and the number refers to the minimum yield strength of the material e.g. N-80 casing has a minimum yield strength of 80000 psi and K-55 has a minimum yield strength of 55000 psi. Hence the grade of the casing provides an indication of the strength of the casing. The higher the grade, the higher the strength of the casing.

In addition to the API grades, certain manufacturers produce their own grades of material. Both seamless and welded tubulars are used as casing although seamless casing is the most common type of casing and only H and J grades are welded.

casing grade