Petroleum Engineering Summer School Hole.

H M
Dubrovnik, Croatia.
Workshop #26 June 9 – 13, 08 June 2008

GEOTHERMAL WELL DESIGN – CASING AND WELLHEAD

Hagen Hole
Geothermal Consultants NZ Ltd., Birkenhead, Auckland, New Zealand.

• To counter losses of drilling fluid circulation

ABSTRACT during drilling.
The Geothermal well design process includes • Protection of the well and formation against
consideration of the objectives and purpose of the well, erosion, corrosion, fracturing and breakdown.
the subsurface conditions likely to be encountered
during the drilling process, and the identification of In general, the shallower and outer casing strings are
required equipment, materials, and drilling procedures necessary for the drilling operations, while the inner
needed to ensure a satisfactory well completion and an strings are required for production purposes. The
acceptable well life. drilling process follows a sequence of drilling to a
certain depth, running and cementing a casing string,
The design steps which are necessary to drill and establishing a wellhead (drilling or final), which allows
complete a deep geothermal well safely are: the drilling of the next smaller diameter section to
• Subsurface rock and fluid conditions. proceed. As a minimum two, but usually more,
• Depths of casings and well completion. completely cemented, concentrically located, steel
• Casing specification and cementing materials casing strings are obligatory both from a technical and
and programmes legal sense for a geothermal well.
• Wellhead specification
Casing strings and liner for a typical geothermal is
• Drilling fluids, drill string assemblies
illustrated below in Figure 1.
• The necessary drilling tools and equipment.

Perhaps the most critical aspects of these design steps

is the selection of casings, casing specification, casing Connection to permanent
wellhead assembly

shoe depths, and how the well is completed. This paper

reviews the casing and wellhead specification process. Conductor

Keywords: geothermal, well design, casing design and Surface Casing

specification.

INTRODUCTION Intermediate Casing

(Not always necessary)

The choice casing depths and specification of the

materials weights and connections is vital to the Anchor Casing

success and safety of the well drilling process and to

the integrity and life of the well. All casings fully
cement back
The casing design and specification process includes to surface

reviewing the required services of the casings, Production Casing

750 - 1500 m
determination of the setting depths and checking
possible failure modes.

CASING SERVICES
What is the purpose of the casing?
The reasons for including casing strings and liners Slotted Liner

include:-
• Prevention of loose formation material from
collapsing into and blocking the hole.
• Provision of anchorage or support for drilling NOTE: An intermediate casing
may be installed between the
anchor and production casing.
and the final wellhead.
• Containment of well fluids and pressures.
• Prevention of ingress or loss of fluid into or Figure 1. Casing strings and Liner for Typical
from the well, and “communication” or Geothermal Well.
leakage of fluids between different aquifers.

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Hole. H M Petroleum Engineering Summer School
Dubrovnik, Croatia.
June 2008 Workshop #26 June 9 – 13, 08
In a hot water or two phase field with boiling
CASING SETTING DEPTHS conditions as assumed above, it is possible (although
The casing setting depths for a typical geothermal well unlikely) at any stage of the drilling for the well to be
will be chosen from the following information and filled with a column of steam at a temperature and
expectation related to the following aspects: saturation pressure corresponding closely to formation
conditions at hole bottom, or at the level of greatest
• Surface or Conductor Casings Strings – permeability. As this pressure is more than that of the
These are the largest casings which are set at a formation fluid, there is a tendency for steam to escape
shallow depth and are employed to prevent into upper permeable formations, and in weak
loose near-surface material collapsing into the geological conditions blow out at the surface. Upper
hole. They are also utilised to support the casing depths should beset to seal off possible leakage
initial drilling wellhead, and to contain the paths to the surface and to limit the well fluid pressure
circulating drilling fluid. The setting depth of at the shoe to that imposed by the overburden pressure,
the casing shoe will estimated from geological or by the fracture gradient of the materials if this is
deduction, but may be altered to reflect known.
conditions found during the course of drilling, The competence of the rock and the incidence of
and may have to contain hot fluid under drilling circulation fluid losses are likely to govern
pressure if there is a thermal zone close to the casings depths, and thus the number of casing strings
surface. needed to allow the target depth to be reached most
economically.
• Anchor or Intermediate Casing Strings – This ‘competence of the rock’ can only be derived
These casings are intermediate in diameter from experience as suggested above, but usually falls
and in setting depth which are set to support somewhere between a theoretically derived fracture
successive wellheads (usually including the gradient and a theoretical overburden pressure.
permanent wellhead) and to contain drilling Figure 2 below illustrates a theoretically based casing
and formation fluids of relatively high shoe depth selection procedure.
temperature and pressure. Setting depths will
be chosen from expected formation rock and 0
Casing Depths

fluid conditions to provide adequate Surface Casing Shoe

permanent anchorage and additional security 200
Water Level

against drilling problems including blowouts. Anchor

Casing Shoe
400

• Production Casing –
This casing is smaller in diameter and set at 600

greater depth than previous casings, and is Production

used primarily to convey steam and water to 800 Casing Shoe

the surface, but it is also important in

facilitating drilling to total depth and to 1000

prevent unwanted leakage of fluids into or out

Depth (m)

of different aquifers. The depth of this string 1200

Theoretical Overburden

should be chosen first, on the basis of the

expected depths and temperatures of fluids to 1400

be included and excluded from production.

1600 Theoretical
Fracture Gradient

In the situation of appraisal or production drilling, the

1800
experience of earlier drilling and well testing in the
Steam in Well
area is the most useful guide in selecting casing depths.
2000
However, when drilling a first well in a new area,
Water in
reasonable assumptions must be made as to the Formation
2200
possible rock and fluid conditions to be expected down
to the total drilled depth. These will be deduced from 2400
consideration of surface scientific surveys possibly 0 5 10 15 20 25 30 35 40 45 50
Pressure (MPa)
supplemented by the results of drilling a shallow
investigation hole at the site. In the absence of a clear
understanding from the scientific data, it is frequently Figure 2. Example of Theoretical Casing Depth
assumed that the reservoir fluid can be approximated to Selection.
a column of water at boiling temperature throughout its This theoretical situation would require the production
depth – ‘Boiling Point for depth (BPD). If the ground casing shoe being set at a depth of 800 m depth; the
water level is known, the depth should be taken from anchor casing shoe being set at 300 m depth; and the
below that datum. surface casing shoe being set at around 60 m depth.

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Petroleum Engineering Summer School Hole. H M
Dubrovnik, Croatia.
Workshop #26 June 9 – 13, 08 June 2008
CASING DIAMETERS The design checks for axial stress can be separated into
The diameters of the various strings of casing in any two sets of conditions – before and after the casing is
well are chosen after consideration of the following cemented.
aspects:-
• Sufficient cross-sectional area to convey the Axial Loading before and during cementing
expected / desired flow of fluid; Until the annular cement sets around the casing the
• Sufficient annular clearances to run and tensile force at any depth includes the weight of the
cement concentric casing strings; casing in air less the buoyant effect of any fluid in the
• The use of casing sizes which are standard well.
manufactured products which are readily
available and match the handling tools usually T–
held by drilling contractors. Thus: Fp = [ Lz Wp – (Lz-Lw)Ap/n]g

Due to the manner in which different pipe thicknesses Where:

are manufactured, tubular sizes are identified by their Fp = the tensile force at the surface from casing
outside diameters and in accordance with the API weight
specifications. Lz = depth of casing
Wp = unit weight of casing
Lw = depth of water level in well
SERVICE CONDITIONS AND FAILURE MODES Ap = cross sectional area of pipe
n = mean specific volume of hot fluid
Whereas deep petroleum drilling considers the most
g = acceleration due to gravity
important parameters in casing design to be fluid
pressure, casing weight, and tensile loading, in
The design tensile force shall allow for the dynamic
geothermal service generally the most severe service
loads imposed during the running of the casing, which
occurs as a result of high temperature loadings. The
will include the drag force of the casing against the
problem is compounded by facts that the service
side of the well, particularly in a deviated well. This
temperatures can seldom be predicted at all accurately;
dynamic loading must be limited by specifying the
and that the various types of casing steel grades and
maximum hook load which may be applied.
casing connections are manufactured specifically for
petroleum service rather than geothermal service.
In a deviated hole the maximum bending stress induced
is:-
The effects of elevated geothermal temperatures on
Fb = EqD
well components include:-
• Change in length of unrestrained pipe – for
Where:
example, 1.8 m expansion over a length of
Fb = maximum stress due to bending
1000 m with a temperature change of 150°C.
E = modulus of elasticity
• Alternatively a compressive stress due to q = curvature of deviated hole (° per 30 m)
restrained (cemented) pipe – for the same D = pipe outside diameter
temperature rise of 150°C the compressive
stress will be 360 MPa (52,000 psi). This stress is additional to that caused by casing
• Reduction in steel strength – 5% or more in weight, temperature change etc.
casing tensile strength tests at 300°C, and
17% in wellhead equipment pressure ratings at Where axial loadings before cementing can occur
300°C under ANSI Standards. simultaneously they shall be added together and the
• Destruction of material competence – resultant maximum axial load checked against the
particularly flexible seals. minimum tensile strength of the casing.
The design factor applied to this is 1.8.
While loading in a longitudinal direction induces
secondary stressing in the circumference of a pipe, it is
convenient to separate the primary modes of failure Axial Loading After Cementing
into axial and radial.
The thermal stress built up can be calculated by
imagining that the pipe expands (using the coefficient
AXIAL STRESS CONDITIONS
of thermal expansion and the estimated temperature
Axial stressing occurs due to:- difference), and is then forced back to its original
• Casing self weight length by axial compression (using the modulus of
• Temperature effects – expansion and elasticity).
contraction
• Restraint from the surrounding cement and/or For the compressive stress quoted above:-
and connection at the wellhead or downhole
(such as a hanger). Unit extension = strain = coefficient x temp. change
= (12 x 10-6) x 150

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Hole. H M Petroleum Engineering Summer School
Dubrovnik, Croatia.
June 2008 Workshop #26 June 9 – 13, 08
= 1.8 x 10-3 programme. A slow and gradual cooling process
allows the stress to be uniformly distributed over the
Stress = modulus x strain = (200 x 103) x 1.8 x 10-3 full length of casing is essential.

= 360 MPa Tensile axial loading of the top section of casing,

which anchors the wellhead against the lifting force
The total axial stress in a cemented string varies applied by the fluid in the well is:-
continuously with depth and also with the difference in
temperature at any time between the neutral value Fw = (π/4)Pw d2
(when the casing was fixed in position) and that at any
time subsequently. It should also be noted that if the where
formation into which casing has been cemented moves Fw = lifting force due to wellhead pressure
differentially by faulting or subsidence, then this too Pw – maximum wellhead pressure
induces further stresses. An additional complication is d = pipe inside diameter
that when steel is loaded at high temperatures over a
long period of time, stress relaxation will occur. The design factor for all axial tensile and compressive
loading shall not be less than 1.2
The compressive force due to temperature rise when
the casing is constrained both longitudinally and
laterally by cement is:- Axial Loading with Buckling and Bending
The setting of un-cemented liners through the
Fc = Ct (T2 – T1)Ap production section of a well presents a number of
design problems. Liners are either hung in tension
Ct = Ea = 200 x 12 x10-6 = 2.4 MPa/°C using a liner hanger from just above the production
Where: casing shoe, or more preferably sat on the bottom of
Fc = compressive force due to heating the hole with the top of the liner sitting free inside the
Ct = thermal stress constant for casing steel production casing shoe – in this case the liner is in
T1 = neutral temperature (temp. at time cement set) compression.
T2 = maximum expected temperature The perforated liner in the production section of the
Ap = cross sectional area of pipe. well is not cemented and is therefore not radially
E = modulus of elasticity supported or constrained. Liners in this situation is
a = coefficient of linear thermal expansion subject to axial self weight compression and helical
buckling and therefore must be analysed for extreme
The tensile loading as calculated for the pre-cementing fibre compressive stress.
axial loading remains in the casing after cement setup
(ignoring stress relaxation with time), therefore the fc = Lz Wp g [(1/Ap) + (D e/2lp)]
resultant axial force (Fr) on the casing after cement
setup and heating will be:- where:
fc = total extreme fibre compressive stress due to
Fr = Fc - Fp axial and bending forces.
Lz = length of liner
The design factor to be utilised will be Wp = nominal unit weight of casing
g = acceleration due to gravity
minimum compressive strength Ap = cross sectional area of pipe
resultant compressive force D = pipe outside diameter
e = eccentricity (actual hole diameter minus D)
where the minimum strength refers to the lesser of the Lp = net moment of inertia of the pipe section,
pipe body or the connection. The design factor shall allowing for slotting or perforating.
not be less than 1.2.
While the hole is drilled with a drill bit of known
Many of the casing failures that occur are the result of diameter, the actual hole diameter is usually some
rapid cooling of the well. After the well has been greater – due reaming caused by stabiliser, hole erosion
completed and has heated and perhaps has been in and in some formations washouts. An uncemented liner
production for some time and if the well is re-entered string supported at the hole bottom and subject to
for subsequent drilling activities; undergoes a series of compressive self weight stressing, will bend helically,
pumping tests; or is used for reinjection, the within the limits set by the hole wall. The ratio of the
temperature reduction when cool fluid is pumped from hole diameter to the pipe diameter (eccentricity), will
the surface into the well causes contraction of the steel determine the amount of bending and therefore the
with a resultant tensile force. This tensile force can bending stresses.
exceed the original resultant axial force. The buckling analysis is sensitive to the eccentricity
Casing failures can occur if the well is not cooled in term. It is therefore necessary to analyses for a range
accordance with a strict well quenching and cooling of actual hole diameters from the bit diameter up to

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Petroleum Engineering Summer School Hole. H M
Dubrovnik, Croatia.
Workshop #26 June 9 – 13, 08 June 2008
around 1.5 times the bit diameter, depending formation with water as controlled by formation
integrity. pressure.
• A restriction within the casing, such as a
The design factor is – blocked float valve or a cementing plug which
will hold the differential pressure.
minimum yield stress x Rj This scenario is not a likely situation, but it is possible,
total compressive stress and therefore must be taken as a worst case scenario.
The differential burst pressure in this case is:-
where (Rj) – the connection joint efficiency does not
exceed 1.0. The hydrostatic pressure inside the casing at the
casing shoe caused by the cement slurry plus any
where (Rj) – the connection joint efficiency does applied pumping pressure – minus the hydrostatic
exceed 1.0., the design factor is – pressure in the annulus at the casing shoe caused by
the head of water in the annulus.
minimum yield stress
total compressive stress Pi = [(Lf Gf + Pp) – (Lz Gz)]g

and shall be not less than 1.2. Where:

Pi = maximum differential internal pressure
The ability of the casing string to resist the above Lf = height above casing shoe of cement column
loadings is governed by the steel grade (which inside casing
prescribes its strength), the type of connections, and the Gf = cement slurry density (eg 1.87 kg/l)
loading condition at the neutral temperature state. As Pp = applied pumping pressure
high strength steels are susceptible to stress corrosion Lz = height above casing shoe of water column in
cracking in a geothermal (H2S) environment, API annulus
Grade K-55 and L-80 grade steels are typically utilised. Gz = mean density of water in annulus
The “round” (Vee) threaded couplings typically used in
oil and gas wells, tend to jump threads under high The design factor is:-
compressive loads. Geothermal service requires a
square thread form and/or shouldered connections to casing internal yield pressure
transfer the full axial loading of the pipe body. API differential burst pressure
buttress threads and various proprietary square
threaded connections have been found to be suitable. and the design factor shall be not less than 1.5.

Once the cement has been successfully displaced to the

RADIAL STRESS CONDITIONS annulus and the well completed, the maximum
Radial (Hoop or circumferential) loadings are applied differential burst pressure will occur at the wellhead
primarily by internal and/or external fluid pressures. and will be as a result of the wellhead pressure.
The ability of tubulars to resist the resultant differential The design factor will be:-
pressures are listed in the API Standards.
In particular consideration must be given to;- casing internal yield pressure
• The differential pressures that occur before maximum wellhead pressure
and during cementing operations
• Well fluid pressures in the static condition or and the design factor shall be not less than 1.8.
when producing or reinjecting.
Typically the maximum wellhead pressure occurs
when the well is left shut in and a cold gas cap
Internal Yield – Bursting develops within the casing depressing that static water
level to the casing shoe.
The casing design must ensure that adequate safety In this case the casing internal yield pressure must be
margins exist against internal yield or ‘burst, resulting limited by the sulphide stress corrosion limit.
from high internal fluid pressure due to a range of
situations that occur during and after the cementing of If the casing being considered is the Anchor casing, to
the casing. which the wellhead is connected, biaxial stressing will
The maximum differential burst pressures usually apply – the combination of the radial burst stresses and
occur near the casing shoe or stage cementing collar the tensile stress caused by the lifting force of the
ports and will apply when- wellhead pressure against the wellhead.
• The casing is filled with high density cement The combined effects of axial and rradial tension is
slurry calculated by the expression:-
• The annulus is either completely filled with
water back to the surface or partially filled ft = √3/2 (Pw d)/(D-d)

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Hole. H M Petroleum Engineering Summer School
Dubrovnik, Croatia.
June 2008 Workshop #26 June 9 – 13, 08
Where: maximum allowable differential collapse pressure is
3.58 MPa.
F = maximum tensile stress This implies that the deepest this casing can be set and
Pw = maximum wellhead pressure cemented with a standard SG 1.87 cement slurry totally
D = casing outside diameter displaced to the annulus is 420 m depth.
d = casing inside diameter

Thermal Expansion of Trapped Fluid

The top section of the anchor casing – from surface to As the bulk modulus of thermal expansion of water is
around 25 m depth, also requires design compliance not constant, particularly at low temperatures and
with the ASME Boiler and Pressure Vessel Code pressures, the effect of heating water in a wholly
confined space is best calculated by reference to the
steam table, using a constant specific volume.
However, at temperatures above 100°C, the resultant
Collapse pressure rise due to change in temperature
The casing design shall ensure an adequate margin of approximates to 1.6 MPa/°C.
safety against pipe collapse due to external pressure
from entrapped liquid expansion, applied pressure The rated collapse pressure of 95/8” 47 lb/ft Grade L-80
during pumping, and/or static pressure from a dense casing is 32.8 MPa. In the event that a volume of
liquid column such as cement slurry. water was trapped between an outer casing and this
95/8” casing, the collapse pressure of the 95/8” casing
Typically, the maximum differential external pressure would be reached with a temperature rise of less than
occurs at the completion of displacement of high 20.5°C, although a large volume of trapped water
density cement slurry from inside the casing to the would be required to deform the pipe to failure.
annulus. At this time the annulus is totally filled with As indicated previously, a temperature rise from a
high density cement slurry, and the inside is filled with nominal neutral temperature of say 80°C to a formation
water. temperature of 240°C is typical, and therefore the
maximum pressure possible from the thermal
The hydrostatic pressure outside the casing at the expansion of a trapped volume of liquid between
casing shoe caused by the cement slurry plus any casings far exceeds the strengths of normal casings
applied pumping pressure (such as a cement squeeze strings in either burst or collapse. Because it is
pressure) – minus the hydrostatic pressure inside the important to retain the integrity of the production
casing at the casing shoe caused by the head of casing string, it is desirable that any failure should be
water in the casing. designed to occur in the outer string. Therefore, for the
final pair of cemented casings, the collapse resistance
pz = [ (Lz Gz+Pp) - (Lf Gf ) ]g of the inner string should exceed the burst resistance of
the outer string with a design factor of not less than 1.2,
Where: being the ratio of:-
Pz = maximum differential external pressure
Lf = height above casing shoe of water column production casing collapse strength
inside casing outer casing burst strength
Gf = mean density of water column inside casing.
Lz = height above casing shoe of cement slurry The added resistance to ‘burst’ provided by the cement
column in annulus sheath is to a degree countered by the secondary
Gz = density of cement slurry in annulus stressing effects of the thermal axial compression,
(eg 1.87 kg/l) which tends to reduce the resistance to burst and
Pp = applied pumping pressure increase the resistance to collapse.
For the purposes of design calculations and in the
The design factor is:- interests of conservative design, this support provided
by the cement sheath is ignored.
casing external collapse pressure
net external pressure

and the design factor shall be not less than 1.2. WELLHEADS
The permanent wellhead components include:
It is to be noted that the large diameter, relatively thin • Casing Head Flange (CHF) usually, and
walled surface and intermediate casings are particularly preferably, attached to the top of the Anchor
susceptible to this mode of failure. casing – but in some instances is attached
directly to the top of the production casing.
For example:- the standard 185/8” diameter 87.5 lb/ft, The casing head flange may incorporate side
Grade K-55 casing has a collapse pressure rating of outlets to which side valve are attached.
only 4.3 MPa. If the design factor of 1.2 is applied, the

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Petroleum Engineering Summer School Hole. H M
Dubrovnik, Croatia.
Workshop #26 June 9 – 13, 08 June 2008
• Double flanged Expansion / Adaptor spool. Wellhead Working Pressure Derating for Temperature

Side outlets may be incorporated in the

expansion spool (as an alternative to those on 45.00

the CHF).
• Master Valve 40.00
ANSI 2500

A typical wellhead assembly for a ‘Standard’ well

completed with an 8½” diameter production hole 35.00

section, 95/8” production casing and 133/8” anchor

casing is illustrated schematically in Figure 3 below.
30.00

25.00

Pressure Rating (MPa)

ANSI 1500

11" 3M 20.00
API 3000

10" 3M
expanding gate valve
15.00
ANSI 900
11" 3M API 2000
11" 3M

10.00
2-1/16" 3M Expansion 2-1/16" 3M ANSI 600
Spool

13-5/8" 3M ANSI 400

13-5/8" 3M
5.00
ANSI 300

Buttress Threaded ANSI 150

Connection
0.00
9-5/8" 0.00 50.00 100.00 150.00 200.00 250.00 300.00 350.00 400.00
csg
13-3/8" casing Temperature (°C)
20" casing
Cellar floor 30" casing
Figure 4. Wellhead Working Pressure Derated for
Temperature.

Figure 3. Typical Completion Wellhead.

In spite of the best efforts made in cementing the

casing strings, there is usually some residual relative
axial thermal expansion between casings at the surface.
If the wellhead is mounted on the anchor casing (which
is typical), the production casing movements relative to
the anchor casing is accommodated below the master
valve, within a double flanged spool such that
interference with the base of the master valve is
prevented.
The wellhead should be designed to comply with codes
of practice for pressure vessels or boilers, and in References
accordance with API Spec. 6A – and most importantly,
rated for the maximum pressure / temperature exposure Hole, H.M., 1996. “Seminar on Geothermal Drilling
possible at the surface under static or flowing Engineering – March 1996, Jakarta, Indonesia”,
conditions. The fluid at the wellhead may be water, Seminar Text, Geothermal Energy New Zealand
saturated steam, superheated steam, cold gas, or Limited, Auckland, New Zealand.
mixtures of some of these fluids. Due to the column of
fluid in the well, surface conditions cannot equate to Gabolde, G., Nguyen, J.P, 1999. “Drilling Data
downhole values, but in some circumstances can Handbook – Seventh Edition”. Institut Francais du
approach downhole conditions closely. Pétrole Publications.
The pressure ratings are derated as temperature NZS 2403:1991, “Code of Practice for Deep
increases in accordance with ANSI B16.5 and API 6A. Geothermal Wells” Standards Association of New
The derated pressures are plotted against temperature Zealand.
in Figure 3.