SLIDE 6 Casing Introduction

Slide 1Introduction to Casing
© The Robert Gordon University 2006
After each section of hole has been drilled a string of casing is run to line the inside of the wellbore. The main reasons for casing off the open hole are:
to prevent caving of the wellbore, as if unsupported, the hole may be liable to fall in upon itself;
to provide support for weak or fractured formations from mud weights which may cause these zones to break down;
to isolate zones of abnormal pressure;
to seal off zones of lost circulation (i.e. thief zones where mud or cement slurry etc enters the formation);
to provide a means of completing and producing the well efficiently;
to provide structural support for wellheads and blow-out prevention equipment
Different Casing Strings
Types Of Casing
Conductor Casing
Conductor casing is the first casing string to be run, and consequently has the largest diameter. With continuous fluid circulation seabed formations would be eroded away leaving large washouts. The surface formations may also have low frictional strength which could easily be exceeded by the hydrostatic pressures exerted by the drilling fluid when drilling a deeper section of the wellbore. Conductor pipe may not be necessary in areas where the surface formations are stronger and less likely to be eroded away. The conductor provides a conduit for mud returns. Where conditions are suitable the conductor may be driven into the formation and is then called ‘stove pipe’.
Surface Casing
The main functions of surface casing are to seal off any fresh water sands and to provide structural support for the blow-out preventer (BOP) and wellhead equipment. In an area where abnormal pressures are expected the setting depth is important, as the control equipment will need to be capable of withstanding that pressure. If the casing is set too high there may not be sufficient formation strength at the shoe to handle a kick when drilling the next section.
Intermediate Casing
Intermediate, or ‘protection’ casing is used to isolate any troublesome formations which would/could cause drilling problems in the wellbore. Sloughing shale, lost circulation, and high pressure zones are just a few examples. Several strings of intermediate casing may be required depending upon the number of problems encountered, if rock formations are stable, drilling can be undertaken for relatively long periods of time prior to the setting of casing. The setting depth depends on a knowledge of pore pressures and fracture gradients. During drilling operations the mud weight controls pore pressures, but must not exceed the fracture strength of shallower zones not cased (and protected) from the drilling fluid.
Production Casing
This is usually the last string of casing to be run in the wellbore and is either run through the pay zone (reservoir) or set just above the pay zone for an ‘open hole’ completion. The main purpose of production casing is to isolate the production interval from other formations such as water bearing sands, and to protect the completion tubing (through which the reservoir fluids will be transported to the surface). Production casing should be thoroughly pressure tested. Usually the casing will be pressure tested to around 60% of its specified burst pressure, if the casing withstands that pressure it is expected to be capable of withstanding higher pressures.
Liner
A liner is a short string of casing which does not extend back to the surface. It is run back inside the previous casing string to provide some overlap. Liners may be used either as an intermediate or production string. The liner has the advantage of being much cheaper than a full length casing string. If required, a tie back string can be run to extend the liner back to the wellhead. A liner is usually less than 5,000 feet long. Overlap is somewhere in region of 200–500 feet and it is essential that the liner overlap is gas tight.
Casing Programmes
Casing makes up a considerable part of the overall well cost (<20%), so great care must be taken to design a casing string which will satisfy the requirements of each well. eg:
Must withstand expected loadings
Operational problems in running the casing
Be able to handle expected formation pressures
Be functional for the anticipated lifespan of the well
Be flexible enough to allow additional string to be run if operational difficulties are unexpectedly encountered
With a view to ultimate abandonment
Casings have to be cemented in place to ensure a competent pressure control system
More about cementing later...
Types of Casing
Conductor Casing
Surface Casing
Intermediate Casing
Production Casing
Conductor Casing
Conductor casing (sometimes called “pipe”) is the first casing string to be run – often driven into the formation using large hydraulic jack-hammers. It ...
consequently has the largest diameter
protects seabed formations - continuous fluid circulation will likely create large “washouts” through erosion
also protects surface formations which may have low frictional strength which could easily be exceeded by the hydrostatic pressures exerted by the drilling fluid when drilling a deeper section of the wellbore
provides a conduit for mud returns
Surface Casing
The main functions of surface casing are to seal off any fresh water sands, and ...
to provide structural support for the blow-out preventer (BOP) and wellhead equipment
In an area where abnormal pressures are expected the setting depth is important, as the control equipment will need to be capable of withstanding that pressure. If the casing is set too high there may not be sufficient formation strength at the shoe to handle a kick when drilling the next section
Intermediate Casing
Intermediate, or ‘protection’ casing is used to isolate any troublesome formations which would/could cause drilling problems in the wellbore - a few examples:
sloughing shale
lost circulation
high pressure zones
Several strings of intermediate casing may be required depending upon the number of problems encountered, if rock formations are stable, drilling can be undertaken for relatively long periods of time prior to the setting of casing
The setting depth depends on a knowledge of pore pressures and fracture gradients
During drilling operations the mud weight controls pore pressures, but must not exceed the fracture strength of shallower zones not cased (i.e. not protected) from the drilling fluid
You’ll hear a lot about .. “Pore Pressure”
It is .... The pressure of fluids within the pores of a reservoir (usually hydrostatic pressure) or the pressure exerted by a column of water from the formation's depth to sea level
When impermeable rocks (such as shales) form as sediments are compacted, their pore fluids cannot always escape and must then support the total overlying rock column, leading to anomalously high formation pressures
Production Casing
This is usually the last string of casing to be run in the wellbore and is either run through the pay zone (reservoir) or set just above the pay zone (for an ‘open hole’ completion). Its main purpose is to:
isolate the production interval from other formations such as water bearing sands, and
to protect the completion tubing (through which the reservoir fluids will be transported to the surface)
Production casing should be thoroughly pressure tested. Usually the casing will be pressure tested to around 60% of its specified burst pressure, if the casing withstands that pressure it is expected to be capable of withstanding higher pressures
Liner
A liner is a short string of casing which does not extend back to the surface. It is run back inside the previous casing string to provide some overlap
Liners may be used either as an intermediate or production string
The liner has the advantage of being much cheaper than a full length casing string
If required, a tie back string can be run to extend the liner back to the wellhead
A liner is usually less than 5,000 feet long. Overlap is somewhere in region of 200–500 feet and it is essential that the liner overlap is gas tight
Casing vs. Bit Size (illustrative)
Casing Size
Tugwell (AG)
Selection of bit and casing sizes can mean the difference between a well that must be abandoned before completion and a well that is an economic and engineering success. Recently there has been pressure on designers to develop slim hole designs based upon a conductor with (for example) a fourteen inch diameter. This means operationally there is no ability to run an intermediate or backup casing string if any hole problems are encountered. Small holes may therefore have to be abandoned due to drilling or completion problems. A well drilled in an area of high pressure will usually require additional casing strings or liners
Casing setting Depth
The initial selection is based on the pore pressures and fracture gradients anticipated in the wellbore – pressures at which fluid will come out of the formation and the pressures at which pumped fluid will fracture the formation. The drilling engineers should ensure, as far as possible, that relevant offset data has been considered in the estimation of pore pressures and fracture gradients, and the effect of hole angle on offset fracture gradient data has also been considered
The total depth of the well, and hence the setting depth of the production casing or liner, is driven by logging, testing, and completion requirements. The shoe must be set deep enough to give an adequate sump for logging, perforating, and to enable testing of the reservoir fluids
4.3) Move across to Point C which identifies the mud weight requirement for that depth
4.6) Point E is the normal pressure range and no further casing is required to withstand the associated mud weight. However, a structural and conductor casing are required, and the setting depth criteria for those strings are discussed later
1) Draw the mean pore pressure gradient curve along with the lithology, if available
2) Draw the mud weight curve. The mud weight curve should include a 200 to 400 psi trip margin
4.2) Move up to Point B which determines the initial estimated setting depth for the intermediate casing (actually run it 300–400 feet deeper)
4) To determine initial estimates of casing setting depths –First:
Enter the mud weight curve at Point A (Total Depth (TD))
4.4) Move up to Point D which determines the preferred setting depth for the surface casing/ intermediate string
3) Draw the predicted fracture gradient curve
4.5) Move across to Point E to identify the mud weight required at that depth
Other factors may affect the casing design programme...
if shallow gas zones are encountered whilst drilling, operations must stop and casing must be set;
if lost circulation zones are encountered, drilling should stop, mud returns should be checked and Lost Circulation Material (LCM) pumped downhole before the mud is conditioned to a more suitable rheology. The zone will then need to be drilled before casing can be set;
formation stability: if the formation is sensitive to the mud weight over time, casing may have to be set
directional well profile: it is important to line out the well trajectory before setting casing and attempt to achieve a consistent survey ahead of a tangent. Long open hole sections may require casing to reduce the occurrence of stuck pipe, and the level of torque;
side tracking requirements as specified in the drilling programme. For example, the 13-3/8” casing may be set high enough to allow 9-5/8” casing to be cut and pulled, enabling a side-track in 12-1/4” hole;
fresh water sands: i.e. have to protect drinking water, and not contaminate it with drilling fluid;
hole cleaning, particularly if a long section of 17-1/2” hole is required
salt sections, invariably associated with a good reservoir, should be drilled round rather than through;
high pressure zones;
casing shoe shall, where practicable, be set in competent formations;
uncertainty in depth estimating e.g., require a margin related to confidence limit when setting close to a permeable formation. Best source for this information is offset well data or area experience, but this should be documented
Kick tolerance
Once the initial casing setting depths are selected, the kick tolerance associated with those depths should be determined. Start from TD up to the surface to determine the kick tolerance and preferred setting depth for each casing string. The acceptability of kick tolerance values of less than 100 bbls should always be justified – by a review of the type of well, capacity of rig equipment for kick detection and operator/driller’s experience, area experience and geology
Design “Bottom-to-Top”
A design should be developed by well planning that provides for economic production from the pay zone consistent with safety requirements. The pay zone should be analysed for its flow potential and the drilling problems that will be encountered upon reaching it. The well should be designed from bottom-to-top. The opposite approach can result in a well that limits the production capacity of the pay zone
Design of the Completion Tubing
The design of completion tubing strings must be given consideration relative to its ability to transport oil or gas to the surface at economical rates. Small diameter tubing chokes the flow rate due to high frictional pressures, therefore small diameter tubing is to be avoided. Large diameter strings are preferable for good flow rate. Small completion tubing can also lead to operational problems due to reduced radial clearances making tool placement operations more difficult, and workover activities more complicated. The required completion characteristics must therefore be taken onto account when designing the casing string
Further Reading
SPE’s Applied Drilling Engineering (Red Book) :–
Chapter 7 “Casing Design”

SLIDE 6 Casing Introduction

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