Chapter 2: Casing Design con't lec (10 )

Cementing

Cementing a liner in place requires very closely controlled application of existing technology4s46 and a fair amount of risk. Three cementing methods are generally accepted for liners.47 Calculating the volume of cement to be used in a liner cementing job is extremely difficult and requires more information than available from a simple caliper run. For maximum caliper information, a four arm device capable of determining elliptical holes should be utilized for hole volume. Cement excesses of between 20% and 100% have been used on a number of liner jobs with larger excesses being responsible for better bonding and less channels. There is also a direct correlation with absence of channels and pipe movement. In liners of 500 ft or less, Bowman and Sherer4s46 recommend 100% excess
over the calculated annular volume and on liners of 3000 ft or more at least a 30% excess is recommended. A single-stage cementing job in which cement is circulated to the top of a liner; much like a

primary cement job and may include pipe movement during cementing. A planned squeeze program in which the lower part of the liner is cemented and the top part of the liner is squeezed later. This technique does not have good middle support and should not be used to isolate high pressure zones. The procedure is more widely followed in worldwide operations because of perceived problems of disengaging the liner running assembly from the liner and of flash setting of cement. Disengaging from the liner before cementing eliminates the ability to move the liner and almost universally results in poor cement jobs.
A third procedure commonly reserved for short liners is to fill part of the hole with cement and then slowly run the casing string into the cement, forcing the cement to flow up around the pipe. While this method can be accomplished with the minimum amount of pumping, the lack of circulation can result in poor removal of drilling mud. The technique is called a puddle job. Most liner jobs do not include plans to move the liner during the primary ~ e m e n t i n g .T~h~e ?re~as~o ns for this include:
1. Detaching the drill pipe from the liner before cementing minimizes the risk of being unable to detach from the liner once the cement is in place.
2. It may be necessary to change to a higher strength drillstring to allow pipe movement.
3. Movement may cause the liner hanger to become tangled with the centralizers near the top of the string.
4. Swab or surge pressures may be created during liner movement, especially in close tolerance wellbores.
5. Movement of the liner during cementing may knock off debris from the borehole wall. The debris may cause bridges and reduce the possibility of circulating cement. Despite the quoted disadvantages of staying attached during the cementing operation, Bowman and
Sherer4346 site several serious disadvantages with releasing the liner before cementing.

1. If the liner is hung off, the small bypass area around the liner offers a greater restriction to flow and causes more lost circulation because of the backpressure on the flowing cement.
2. If a downhole rotating liner hanger is used (rotation only), additional torque is required to initiate rotation to overcome bearing friction. Pipe often rotates easier when it is being raised or lowered. The difference in torque required is often substantial.
3. The potential for sloughing shale and annulus bridging is lessened when the operator can alternate between rotation and reciprocation.
4. Premature shearing of the pins in the liner-wiper plug is less likely because there is no relative movement between the liner and the setting tool (these two pieces of equipment move together). 49
5. If cement channels and there is a large hydrostatic pressure difference between inside and outside of the running tools, the cups or seals can give way before cementing of the liner is complete.
6. The displacement efficiency of cement around the tubulars when pipe is not moved is lessened. When liners are close clearance, then the density differences between mud and cement should be as close as possible. This negates the advantages of hole cleaning by higher density cement. Reciprocation4’ of the string is helpful because it produces lateral pipe movement that causes the pipe to change sides in the wellbore while it is alternately compressed and stretched (slacked off and picked up).43 R o t a t i ~ hnelp~s b~y ~mix~in~g th~e ~cem ent into wellbore irregularities and displacing mud due to drag forces produced by the flowing cement.43 Although liner movement should be a goal in any liner operation, well conditions may prevent any type of movement. In many cases, however, liner movement can be achieved in a well conditioned hole. Two clear cases where liner should not be moved are:43
1. When a short or small liner (3-1/2 in. or smaller) is run in a deep well, the liner should be hung off first since it may be impossible to tell from the weight indicator whether the liner had been released from the drill pipe.
2. In cases of hole deviation over 35O, reciprocation may be difficult due to high drag forces.
Many of the problems in liner running can be lessened by drilling a usable hole. Problems with keyseats, ledges, washouts, and other nongauge problems intensify when close tolerance liners are to be run. For additional information on problems involved in drilling a usable hole, refer to the chapter on Drilling The Pay.
When cement is circulated from the liner bottom to over the liner top, the cement must remain fluid long enough to detach from the liner and to circulate the cement from the well or to pull up above the top of the cement with the drillstring. If the cement flash sets, then the drillstring will become cemented in place and the hole most likely will be lost. Cement may prematurely set, thicken, or cement circulation may be lost for a number of reasons
1. Improper thickening or pump times caused by a poor design, ineffective field operations, or bad test results.
2. Poor density control on the cement or poor mixing of the cement at the surface. ,
3. Bridging in the annulus caused by a buildup of cuttings. This is caused typically by the increased number of particles picked up by higher annular velocities with a liner in the hole (due to its larger ID) than around the drillstring.
4. Plugging from dehydration of cement caused by excessive water loss in openhole sections below the overlap.
5. Increased hole cleaning of the cement as compared to4he drilling mud.
One of the most troublesome problems in cementing design is inadequate hole cleaning prior to cementing. This is especially true when light weight, low viscosity muds are used and little attention is paid to cuttings removal. Heaving shales are also a problem in hole fill and may cause washouts. Under no circumstances should circulation be halted with the liner in the hole before all of the cement has been displaced. Due to the small clearances and the yield point of cement, it may be very difficult to start circulation again.

Chapter 2: Casing Design con't lec ( 9 )

Casing String Design - Deviated Wells
The basic difference in casing design for a deviated well is the magnitude of the loads encountered in the deviated or angle build section. This requires bending and torque considerations. Greenip offers three major points for consideration:
1. Axial and torque loads can be estimated by analyzing separate sections.
2. Relationships can be developed for various parameters in casing string design.
3. The pickup, set down, and neutral states produce sufficiently different loads and magnitudes to analyze each separately.
First, divide the string into three segments, (1) the extension or reach interval, (2) the build interval (containing the deviation) and (3) the vertical interval, Figure 2.20. As with conventional casing design, the casing in a horizontal well is designed from the bottom up. Interval (2), the build interval, is simplified by assuming the angle is constant. Interval (l), the extension or reach portion is assumed to be a constant inclination. An example of the magnitude of the forces at pickup, neutral and set down are shown in Figure 2.21.

Liner Design

A liner is a casing string that does not extend back to surface. Liners may be permanent or temporary and run for a variety of reason^:^*^^^
1. Wear protection of the permanent casing string from rotating drill pipe or frequent tubing movement, especially in a deviated section.
2. Correction of hole difficulty such as doglegs, Key seats, or ledges.
3. Zone isolation of a high pressure zone or a lost circulation zone.
4. As an economical alternative to a full casing string.
5. To allow adequate room above the liner top for a large diameter pump.
6. To reduce casing tension loads in deep wells or to allow use of an available, low strength connection.
7. For repair of leaks or buckled casing.
8. For casing strengthening in earth shift zones.
Most reasons for liner design incorporate the cost reduction factor of not running casing back to surface. Liners have drawbacks as well, including several problems related to liner cementing. From a design standpoint, perhaps the biggest concern is that the intermediate string or the last full string becomes the top part of the liner and must handle the burst force generated by the zones crossed by the liner. Before a decision is made on use of a liner, the strength of the top part of the last full string must be checked against the new maximum expected surface pressure. Unless proven otherwise by cement bond evaluation tools, the upper pipe strength alone (no assistance from the cement sheath) must be capable of withstanding the pressure. If the upper section will not withstand the forces, it should be protected by running a full string, or, the string should be run before perforating the well.
The first approach liner design is the same as for full casing strings. The collapse, burst, and tension safety factors and design equations are the same. The basic differences between liner and casing design come to light in the design of liners for deep wells, hot  environments, and very high pressure zones.

Burst failure of liners is usually caused by kicks while drilling below a liner,39p40 pressure when fracture stimulating, or a tubing leak while producing a deep, high pressure zone. All these factors are made worse by a poor cement job. Since filling the casing/openhole annulus with cement significantly strengthens and supports the pipe, a good cement job over high pressure or earth movement zones is a requirement in any deep well.
An illustration of the complications caused by a poor cement job 39*40 is illustrated in Figure 2.22. After a primary cement job on the 9-5/8 in. string, the 6-518 in. liner is run and a circulation cement job is initiated. The low pressure zone at 13,800 breaks down while cementing, returns are lost and the cement top peaks at 13,400 (Figure 2.23a). A top squeeze with cement seals the top of the liner but leaves an uncemented zone from 13,120 ft to 13,400 ft (Figure 2.23b). While drilling near TD to test a deep structure, the temperature of the mud goes from 270" (temp. of the zone at 15,400 ft) to the bottomhole temperature (at 18,500 ft) of 345°F. Since both ends of the liner are cemented, stress will be induced by the temperature rise

Liner Tie-Backs

Although the liner completion described in Figure 2.22 may be used only as a liner, there are some conditions when the liner may be run back to surface. This liner tie-back may be temporary, to protect

permanent casing strings from wear during drilling4' or permanently, with cement, to strengthen the casing string through a high pressure zone or isolate and stop a casing leak38 or a leaking liner top.42 To allow a tie-back, most liners are equipped with a liner tie-back receptacle. The receptacle is an internally polished receiver that will accept the seal assembly of the tie-back liner. The tie-back liner usually incorporates some type of cement port or sliding sleeve and seat that will allow cement to be circulated through to the annulus and up the annulus to surface. The seat, float equipment andlor plugs used in the cementing operation are of drillable material.

Chapter 2: Casing Design con't lec ( 8 )

Casing String Design

A complex solution (API method) requiring computer solution is discussed first, followed by a practical, hand calculated method.

API Equations

Collapse strength rating is the external pressure required to collapse the casing. There are several methods for designing casing strings that will produce an acceptable casing design. Most methods use an x-diagram graphical approach or a calculated design based on a single strength concern in each area of design. The API procedure recognizes the changes in steel behavior in elastic, transition, plastic, and ultimate yield. The procedure illustrated here for determining the collapse strength is defined in API Bulletin 5C3.15 This casing design section is merely an introduction to the process. For a complete treatment, refer to Rabia's Fundamentals of Casing Design.14 When exposed to external pressure from mud or reservoir fluids and the effects of axial tension from the weight of the casing below any point (plus other loads)," a piece of casing may fail in one of three possible collapse  mechanisms: elastic collapse, plastic collapse, and failure by exceeding the ultimate
strength of the material. Each failure mode is bounded by limits of the ratio of casing diameter to thickness, plus a transition collapse formula was added arbitrarily since the API minimum elastic and rninimum plastic curves do not intersect. The transition formula covers this area. The API minimum collapse resistance equations are shown in Figure 2.12.15

Axial loads generally result from two forces:
1. hanging weight of the casing string
2. temperature induced forces in thermal wells and in nonthermal wells where operating temperatures may change by over 100°F.

Buoyancy

When the hole is filled with cement or mud, there is a buoyancy force exerted on the casing by the fluid in the hole and opposed by the fluid in the casing. Buoyant force acts on the entire casing string and results in a reduction in hanging weight. The amount of buoyant force exerted by the mud is equal . to the weight of the mud displaced by the submerged casing. The weight of steel at 489.5 Ib/ft3 or 65.4 Ib/gal, is several times the heaviest mud weight, yet the buoyant contribution of the mud is a significant factor in the hook load during running and cementing of the casing. Hook loads change dramatically during running and cementing operations and conditions do exist (running closed end casing, dry) where hook load could diminish to zero (the casing floats).
Buoyant weight, Wb, for an open-ended casing string of air weight W,, filled and surrounded by one fluid. is:

When the fluid in the casing is different from the fluid outside the casing, the volumes contained in the casing and displaced by the casing must be calculated and the weights summed against the air weight of the casing.
For the special case of an additional surface pressure such as holding pressure on the mud in the casing while cement sets in the annulus, the surface pressure is incorporated with the load produced by the mud. The buoyant force, FB, applied to the air weight of the casing becomes:

The pressure terms affect buoyancy much the same way as pressure affects tubing forces.

Collapse Design - Non-API Method

A practical method that considers burst, collapse, and tensile forces is also available. This method may be worked by equations or by graphical methods. The design is conservative in collapse resistance because of the basic assumptions of an empty string in a hole full of mud. In practice, most casing strings are filled with mud as they are run. The design begins at the bottom of the string. The collapse force produced by fluid pressure from a homogeneous fluid in the well and an empty casing string is:

resistance of the inner string. It may also be used in some casing designs. Because outside surface pressure is rare, the term is generally dropped.
It is customary to design the primary strings for the worst possible case. Since the worst possible case will be when the pipe is empty, the equation reduces to:

The outside surface pressure is assumed to be zero.
The design on an empty pipe string may seem excessive but it is done to eliminate consideration of triaxial forces produced by hole irregularities and other factors3 The worst possible case design, therefore, covers a multitude of other forces. Because of buoyancy produced by changes in axial load following setting of the cement, portions of the casing string may be in compression rather than tension. Casing above the point of zero axial tension has less collapse resistance, and casing below the point of zero axial tension has more collapse resistance since it is in compression. The collapse forces on a casing are usually visualized as being applied by the pressure of the mud in which the string is 
run. The effect of tension in reducing the collapse strength of the casing is generally considered, but the effects of ballooning, ovality, and temperature changes during circulating are often neglected. These effects can be severe, especially in high collapse resistance casing such as some 95-grades. For the burst calculations, one of two API approved formulas may be used. For plain end (nonthreaded) pipe and pipe with premium couplings (couplings stronger than the pipe body), Barrow's formula is used.

Burst force design may also be considered graphically, Figure 2.14.35 Eqn. 2.26 can be used to make the start of the X diagram of Figure 2.1 5. The X diagram is constructed
by collapse and burst c a l c ~ l a t i o n s . ’T~h~e ~m~a ximum burst line is drawn between the calculated burst at the surface and the calculated burst at the casing shoe. The collapse line is drawn between U and the maximum collapse pressure at the casing shoe, calculated by Eqn. 2.24 or 2.25. Tension design is the last step for each section of the casing string. The top of each section should be checked to see that the tensile ratings are not exceeded. The common safety factor is 1.6 to 1.8. When the tensile limits are exceeded, a change to a higher strength joint should be made. Tension limits may be gathered from a table of casing properties or calculated by dividing the API 5C3 value for joint strength by the safety factor