Casing Design

RUNNING AND CEMENTING CASING

Reasons for Running CasingProvide a means of controlling well pressures.Permit circulation.Prevent collapse of hole.Prevent fluid migration.Isolate troublesome zones.Facilitate control of a production well.

Types of Casing and Common Size

Conductor 20:24 Surface Casing 13-3/8 Intermediate String 9-5/8 Production String 9-5/8:7 Liner 7:5"

Conductor Casing Characteristics:

Casing is usually large: 20 in. to 30 in. diameter.The hole may be severely eroded.

Conductor Casing The setting depth of the conductor can vary from as little as 20 ft to as much as a few hundred feet.

The most common pipe and hole sizes are a 16 in. pipe in a 20 in. hole and 20 in. pipe in a 26 in. hole.

Conductor Casing Conductor Casing is set to :

Prevent washing out under rig.Provide elevation for flow line.Provide support for part of the wellhead.

A BOP is usually not attached to conductor casings.

Conductor Casing Recommended CementsAccelerated neat.Thixotropic cement.Typical slurries used for conductor casings consist of Class A, C, G, or H with 2% calcium chloride as accelerator. Lost-circulation additives may be added without significant effect on slurry-thickening time or compressive strength. Where lost circulation is severe, a thixotropic cement can be used.

Conductor CasingOften cemented through drill pipe with sealing sleeve.When cementing down casing, plugs may not be used, cement is simply displaced.Large diameter casing plugs (30 in., 26 in., and 20 in.) are wooden body plugs. If bumped on baffle or float, be careful in pressuring up to prevent bypassing plug.Excess cement is usually determined by experience in the area.

Surface casingSurface casing is usually the second string of pipe set in the well.

when a conductor casing is not set because, the surface pipe becomes the first string set.

Surface casing Surface casing is set to:

Protect fresh water sands.Case unconsolidated formations.Provide primary pressure control (BOP usually nippled up on surface casing).Support future casings.Case off potential loss circulations zones.

Surface casing CharacteristicsCasing sizes normally range from 13-3/8in. on shallow wells to 20 in. on deep, multistring wells.Hole may be severely eroded.Shallow strings can be pumped out easily.Drilling muds often viscous with little water loss control.Casing may stick easily in unconsolidated formations.Loss of circulation may be a problem.Guide shoe, or float shoe, float collar and centralizers are commonly used.

Surface casingSurface casings are set from a few hundred feet to several thousand feet. The depth depends on the proposed total well depth, the competency of shallow formation encountered, and state regulations regarding protection of fresh water reservoirs. Recommended CementsShallow surface casings are cemented in the same manner as conductor casings. Completion cements with accelerated thickening times.

Surface casingThere is a cost advantage by using a high-yield completion slurry to cement the entire string. Sometimes, when the well is shallow or a significant load will be placed on the wellhead, a densified filler slurry can cement the entire casing. Economically, omitting the tail-in slurry will not save much.

Surface casingFiller cements (high water ratio) followed by neat or high strength tail in.

Usually accelerated.

LCM often used.

High strength cements often used on deep well surface casings to support future strings.

Summary Of Surface Casing

Large diameter strings often cemented through drill pipe with sealing sleeve.Use both bottom and top plugs because of mud contamination.Centralize the bottom joints and thread lock to prevent backing off while drilling.Regulator rules usually require a WOC time of 8 hours or 500 psi minimum compressive strength.

Summary Of Surface CasingA float collar placed two joints above the guide shoe helps prevent mud from contaminating the cement around the shoe joint. Centralizers are the final consideration of equipment on the casing.Centralizers center the Csg in the hole.

Intermediate CasingThe intermediate casing strings extend from the surface to formations able to hold the expected mud weights at greater depths. This depth can vary several thousand feet in a single stage job. When a second intermediate string is set, the casing is run to just below the weak zone to a firm formation and cemented at that point.

Intermediate Casing Purpose Separates hole into workable drilling segments and cases off loss circulation zones, water flows, etc.isolates salt sections.protects open hole from increases in mud weight.prevents flow from high pressure zones if mud weight must be reduced. Basic pressure control casing. BOP always installed.Supports subsequent casings.

Intermediate Casing CharacteristicsThe pipe and hole size are largely determined by the number of casing strings to be run below the intermediate string.Casing sizes range from 6-5/8 in. to 20 in. Most common are 9-5/8 in., 10-3/4 in.Some sections may erode severely, particularly salt sections.Strings may be very heavy and set on bottom.Both extremely weak zones and high pressure zones are covered by intermediate strings.

Intermediate CasingCement volume is dictated by wellbore condition.Guide shoe, or float shoe, and float collar are commonly used.Cement volumes usually largest in well.Often cemented in stages.Prolonged drilling may be done through this casing and damage is common.Completion may be made in intermediate casing.

Intermediate Casing Recommended CementsBecause of the large volume of cement, and the type of formations to be covered, both filler and composition cements are used to cement most intermediate casing. Sometimes, as many as three combinations of slurries are needed. Formation-fracture gradients, lost-circulation zones, formation temperatures, possible future producing zones, and well depth determine the number and types of slurries to use.

Intermediate CasingFor a single stage cementing job, the slurry requirements are similar to those for a long surface job. The filler slurry needs to be light enough not to break down weaker formations. The completion slurry needs to have enough strength to hold the pipe and provide a good seal between the pipe and formation.

Intermediate CasingThe bottom of the pipe is cemented (usually 1000 to 3000 ft) in a single stage intermediate job.because of cost, or because the uncemented section of casing may be reclaimed from the well later and re-used. In this case, only a high-strength completion slurry with a retarder is needed. Retarders insure sufficient pumping time to get the slurries in place and impart some friction-reduction.

Intermediate CasingUnlike the conductor and surface casings, additives such a friction reducers, fluid-loss additives, and retarders are required for intermediate slurries. Where the annulus is small, friction reducers lower pump pressures and reduce the chance of losing fluids in a lost-circulation zone. Fluid-loss additives prevent slurry loss into lost-circulation zones and dehydration in the annulus due to permeable zones and will give better bonding results.

Summary Of Intermediate Casing

Use a bottom and top plug to minimize cement contamination. As in other strings of casing, the bottom plug wipes the mud film off the casing and ahead of the cement. Heads that contain both plugs, or heads that are loaded with plugs are attached to casing.Pipe extends from surface to the bottom of the hole.Stage tools are occasionally used when cementing long strings of pipe where breaking down a weak formation becomes a concern.The number of slurries used may be determined by possible production, weak zones and wellbore temperatures. Use scratchers, centralizers and flushes.

Production CasingThe production casing is the last full string of pipe set in the well. It extends from below the deepest producing formation to the surface-Production tubing, downhole pumps, and other equipment needed to produce oil and gas are housed in this casing. The production-casing cement must give a pressure-tight seal between the formations and the production casing. It is essential to isolate the reservoir from fluids both within the producing zone itself and from other zones.

Production Casing PurposeComplete well for production.Effect zonal isolation.Protect pay zones from unwanted fluids.Provide pressure control.Cover worn or damaged intermediate casing.

Production CasingSince the production casing may extend from the total depth of the well to the surface, the setting depth can vary from a few thousand feet to as much as 14000 feet. Below 14000 ft, liners may be set because of cost savings and less pipe weight. The size of the casing depends upon the number of strings of production tubing to be run into the well and the size of production equipment used.

Production CasingCharacteristics

Common size 4-1/2in., 5-1l2 in., and 7 in. casing.Drilling mud usually of good condition.Usually not circulated. Generally cemented back to intermediate casing.Good cement job is vital to successful completion.

Production Casing Recommended Cement

Filler cements with high strength tail-in.All potential pay zones are usually covered by low water ratio cements.Densified cements are commonly used for high competency and pressure control.Fluid loss control.

Types of Liners Liners are classified as:production, intermediate liners, protective or drilling (which could be considered the same as an intermediate liner), scab, or stub liners.

Liner String The liner string consists of:The cementing head with a drill pipe wiper dart in place.A drill pipe swivel if movement is considered.Drill pipe.Liner-setting mechanism.Latch-in liner wiper plug.A mechanical set or hydraulic set liner hanger.Floating equipment.

Liner hangers are set mechanically or hydraulically.The float shoe and float collars are spaced two to five joints apart.The liner plug landing collar is located some distance above the float collar.Most liner hangers are equipped with a tie-back receptacle should the need arise to run a tie-back string to surface or to run a scab liner.The tie-back sleeve is usually a minimum of six feet in length and fluted for easier entry.Production liners are many times equipped with a polished bore receptacle to serve as a seal assembly placement facility when production string is run in the well.

Purpose of Intermediate Liner

Extension of intermediate casing.Cases hole for changes in mud weights.Requires less casing in hole.Permits running tie-back casing at future date to complete well with new casing.

Characteristics

Liners often long and heavy.Muds and cements usually above 12.0 ppg.Most often set to control high pressure gas.Casing may not be rotated or reciprocated.Effective mud displacement is impaired.Thickening times require careful control to have adequate pumping time on bottom and prevent over-retardation at top.

Common Cements

API Class C, G or H cements with filtration control and dispersants.High density.Some high water ratio cements for weight control may be required.

Cementing Procedure

Cementing head and plugs furnished by supplier of liner hanger.Liner hanger is set before cementing.Setting tool with sealing cups is kept in liner.Cement is placed, often circulated above liner top.Liner setting tool is pulled from hole.Sometimes, excess cement is reversed out through drill pipe.

Production Liners The purpose, cements characteristic and cementing procedures used on production liners are described below: PurposesCompletion casing.Require less casing in well.Permit completing with larger tubing for high flow capacities.

Production Liners Purposes (cont)Common CementsAPI Class G or H cement.Some high water ratio cements may be used for weight control.Slurries contain dispersants and fluid loss additives.High density cement and high strength cements most commonly used slurries for most deep liners.

Production Liners CharacteristicsOften covers long intervals.Usually small annular clearance.Casing is usually not rotated or reciprocated during cementing. Pumping rates often restricted to prevent fracturing. Effective mud displacement from annulus is impaired.

Production Liners Cementing Procedure (Same as intermediate liners)

Liner hanger is set before cementing. Setting tool with sealing cups is kept in liner.Cement is placed, often circulated above liner tops.Liner setting tool is pulled from hole.Sometimes, excess cement is reversed out through drill pipe.

Reciprocation vs. Rotation

Liner reciprocation, as does liner rotation, aids in mud displacement and fillup. When reciprocating the liner, you use a hanger with a longer barrel. The slips are set so that the liner can be moved some 5-15 feet without movement of the slip cage in the pipe. When liner reciprocation is employed during the cementing process, the liner tool is released after cementing.

Reciprocation vs. Rotation

Liner rotation is more sophisticated than liner reciprocation. Many liner hanger companies offer hangers that permit both rotation and reciprocation.When rotating, a power swivel is used that has plug release features. The liner rotation is normally done on liners up to 2000 feet in length and having clearances of 1 to 1-1/2 inches. Liner rotation is not quite as popular in hard rock areas as in soft rock country due to tighter clearances, crooked holes, long shale sections, etc.

Reciprocation vs. Rotation

The consequences of liner movement could cause hole problems such as:centralizers could become entangled with the hanger.pressure surges and lost circulation during displacement.The knocking off of debris in the annulus forming a bridge and causing the cement to be squeezed off.The liner sticking off bottom resulting in the liner being set in compression.the drill string could part or twist off.

Reciprocation vs. Rotation

Movement does provide good cementing jobs. Liner movement can eliminate costly trips to perform remedial work, e.g. expensive and unnecessary squeeze jobs. Some operators go to the expense of under-reaming the hole prior to running the liner to make sure that larger clearances are available.

Production LinersOnce the production liner is set, it may be desirable to run a tie-back casing which extends the production casing to the surface for maximum pressure control. When set and cemented, the tie-back string serves as the production casing. The purpose, characteristics, cements, and procedures used in tie-back cementing follow:

Purposes

Extend production casing to surface for maximum pressure control.Serve as new production casing.Cover worn or damaged intermediate casing.Case off exposed liner tops.

Characteristics

Primarily used on deep wells.

Often very long strings are set and cementing pressures are extremely high.

Conventional floats cannot be used.

Common Cements

API Class C,G or H.

High water ratio cements to control hydrostatic pressures.

Cements with silica flour for strength, stability, and casing support if temperatures warrant.

Cementing Procedures

Three different techniques commonly used:

Cemented through side ports in polished bore receptacles.

Cemented by reverse circulation.

Cemented by use of stage tool above tie-back receptacle.

Scab Liners

A scab liner is usually run to repair damaged intermediate casing. It may not extend back into the intermediate casing but only over that area where the casing is damaged. Scab liners are usually short sections and hung before cementing. They are not set into a receptacle.

Problem Areas When Setting Liners

Inability to break circulation. The logical solution is to bring the liner out of the hole and locate the cause of the difficulty.

The liner sticks while being moved or reciprocated. Continue as before but without further reciprocation.

Problem Areas When Setting LinersThe liner hanger sets when the drill pipe wiper plug picks up the liner wiper plug. Continue as before but eliminate further attempt to reciprocate.

Cannot release from liner hanger after setting it. The only logical solution is to retrieve the liner from the hole at a slow rate and fill the annulus with mud as the cement falls to bottom. Upon removal of the liner, drill out and renew the liner hanger and liner string.

Problem Areas When Setting LinersSqueezing the overlap is not successful. Run a liner top isolation packer with a scab liner and a tie-back seal mandrel. The plug does not bump the liner to the bottom. Hydraulically set the slips, leave the liner on bottom, and release from the liner hanger.

Hole Conditions

Sloughing In many cases, this is the purpose of setting an intermediate casing and it can create several cement problemssuch as bridging the annulus, sticking the casing, and increasing the annulus hydrostatic pressure.Drill Pipe Drag Where the drag is occurring, and exactly why it exists, could be important. This condition may indicate the need for centralized casing or the use of fluid loss control cements.

Hole Conditions

Low Pressure Zone: One of the most persistent problems is incompetent formations that will not support effective columns of cements.

Mud Condition: A well-conditioned mud greatly increases the mud removal capability of the flushes and cement slurry.

Hole Conditions

Fluid Movement Zone isolation fails any time fluid movement is allowed to move during the time a cement slurry is between the fluid and set state. If the cement moves during the hardening, the cement will not set.Formation Movement Are you located in an active fault zone? The most common formation movement occurs with salt intrusions.

General ConsiderationsTally all pipe, count, number and rabbit (gauge) all joints of casing on the rack.Check all casing threads for cleanliness and damage. Additionally, check the threads on all crossover equipment for proper thread type and cleanliness.Identify all joints by weight and thread type, and place them in proper order for running into the hole.Landing joint(s) should be spaced out so the cementing head can be installed from the stabbing board or rig floor after casing is landed.

Physical Properties

Length Rangesa.Casing comes in three range lengths:RI 10 to 25 feetRII 25 to 34 feet RIII > 34 feetb.There are different 'grades' of casing which indicate the strength of the sheet. These are color coded:

GradesYield Strength Colour codingH4040000No colour blackJ5555000 One band bright greenK5555000 Two bands bright greenC7575000Light blueN8080000RedC9595000Yellow bandP105105000WhiteP110110000WhiteV150150000

Couplings API couplingsSTC- Short round thread casingLTC- Long round thread casingBTC- Butress thread casingXL- Extreme line casing

Non-API couplingsHydril super EU, TSValorecVam

STRENGTH PROPERTIESYield strengthCollapse strengthBurst strength

Yield strength (Tensile Loading )Tensile loading is applied to casing as a result of its own weight and is at a maximum underneath the casing hanger at the surface. Buoyancy reduces the tensile loading on casing.Tensile loading on the casing is increased as a result of running it in directional hole.

Yield strength (Tensile Loading)A critical factor is the outside diameter of the casing which, if reduced, reduces the tensile loading on the casing. It is for this reason that smaller sizes of casing are selected to be run on the build up sections of directional hole, particularly if rapid changes of angle are expected. API defines it as the tensile stress required to produce a total elongation of 0.5 % of the gauge length

Yield strength (Tensile Loading )

Collapse LoadingThe maximum external pressure required to collapse a specimen of casing.If the casing is emptied of fluid completely the worst collapse situation exists. With no internal hydrostatic pressure of the mud, the full formation pressure is exerted on the casing at the shoe.At the surface the collapse pressure is clearly zero since only atmospheric pressure is acting on the casing. The collapse design line may now be drawn.

Collapse LoadingWhere exceptional circumstances occur such as casing run in salt formations or in earthquake areas, extra collapse resistance is required and must be designed for.TypesElastic collapsePlastic collapseTransition collapse

Burst Loading (or Internal Yield) strengthThe maximum value of internal pressure required to cause the steel of casing to yield.Burst loading is the net internal pressure load exerted on the casing. The worst case of burst loading usually occurs when a gas kick is taken and the well is shut in. The net burst load is the difference between the pressure inside the casing and the pressure outside.The point of maximum burst loading in this case is therefore at the top of the casing string where there is a high gas pressure.

Casing Design Casing design is required to ensure that casing run in the well will withstand the various loads applied to it. The principle loadings casing is subjected to are:BurstCollapseTensileThe worst case loading is considered in each case. Safety FactorsBurst pressure 1- 1.1Collapse pressure 0.85- 1.125Tensile force 1.6- 1.8

Burst Loading

Burst loading is the net internal pressure load exerted on the casing. The worst case of burst loading usually occurs when a gas kick is taken and the well is shut in. The net burst load is the difference between the pressure inside the casing and the pressure outside.The point of maximum burst loading in this case is therefore at the top of the casing string where there is a high gas pressure.

Collapse LoadingIf the casing is emptied of fluid completely the worst collapse situation exists. With no internal hydrostatic pressure of the mud, the full formation pressure is exerted on the casing at the shoe.At the surface the collapse pressure is clearly zero since only atmospheric pressure is acting on the casing. The collapse design line may now be drawn.Where exceptional circumstances occur such as casing run in salt formations or in earthquake areas, extra collapse resistance is required and must be designed for.

Tensile LoadingTensile loading is applied to casing as a result of its own weight and is at a maximum underneath the casing hanger at the surface. Buoyancy reduces the tensile loading on casing.Tensile loading on the casing is increased as a result of running it in directional hole. A critical factor is the outside diameter of the casing which, if reduced, reduces the tensile loading on the casing. It is for this reason that smaller sizes of casing are selected to be run on the build up sections of directional hole, particularly if rapid changes of angle are expected.

Biaxial LoadingCollapse and burst loading on casing are both affected by tensile loading.Tensile loading tends to reduce the collapse resistance of casing. This is a particular problem in deep wells with long casing strings.Tensile loading has the reverse effect on burst resistance. Burst resistance is increased due to the tensile loading. Temperature effects must also be considered as the elongation of the casing can effect all loadings. The Drilling Engineer will make use of standard tables and equations to allow for the effect of tension and temperature.

Casing Design Chart

We have seen how the casing design chart is constructed by considering burst and collapse loadings on the casing at the surface and the casing shoe.The engineer now has the task of selecting the correct weights and grades to be used in the string. More than one weight and grade of casing is used for economical reasons (less steel required with thinner wall casing) and to reduce tensile loading. A set of casing tables with the following information is used.

Casing Design ChartUsing the casing design chart, the engineer selects a casing weight and grade which has a burst resistance greater than the burst design line. He must also check to see that the same casing weight and grade has a collapse resistance greater than the collapse design line.In this way, several different weights and grades of casing will be used in a casing string. A check must always be made to make sure that the tensile yield strength of the casing is not exceeded.

Graphical Method for Casing Design Collapse LinePc = Pout - Pin, P = 0.052* (ppg)*D (ft) psiCalculate Psurface, Pshoe (empty casing).Draw collapse line

Graphical Method for Casing Design Burst LineBurst pressure = Internal pressure External pressureInternal pressure = Pf (TD CSD)*GExternal pressure = CSD* GmWhere Pf, formation pressure at total depthTD, total depth, CSD, casing setting depthG, formation fluid gradient (0.1 psi/ft)Gm, mud gradient (0.465 psi/ft)

Graphical Method for Casing DesignTensile forceTensile force = weight of casing in air Buoyancy force

Refer to Examples in the text

Running CasingCondition hole.Bakerlock shoe and first two or three joints.Check float equipment.Remove wear bushing.While running casing, check calculated displacement to trip tank.Keep pipe moving to avoid sticking and circulate.Rig up cement head and plugs.Pump water or chemical spacer to remove mud cake.Drop bottom plug.Load top plug (if not already in cement head).

ConclusionIt can clearly be seen that loading casing string of different weights and grades can be a logistical nightmare!

For this reason, the number of casing weight and grade changes is restricted to ensure that the casing is picked up and run into the hole in the correct order.