Casing/Tubing design manual october 2005 Chevron
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Casing/Tubing Design Manual 13-37
October 2005
Y(H
2
S) = Mole fraction in separated gas at STHP pressure and wellhead
temperature
pH
2
S = Partial H
2
S pressure [atm]
The SSC phenomenon is triggered off at the wellhead if pH
2
S >0.0035 atm and
STHP >18.63 atm.
13.16.3.4.2 Calculation of Partial Pressure in Case B
Calculation of partial pressure in the reservoir:
In the reservoir, the gas is already separated, FBHP <Pb, calculation of pH
2
S can
be approximated on the basis of the following:
If the PVTs are reliable, Y(H
2
S) >0.2%, the partial pressure is calculated as:
pH
2
S = Y(H
2
S) x FBHP 1 (13-29)
where:
Y(H
2
S) = Molar fraction in gas separated at FBHP and at reservoir temperature
(from PVT)
If the PVTs are unreliable, the material balance method can be used as in the
case of undersaturated oil; these are the worst conditions. The error made can
be high when Pb > FBHP.
13.16.3.5 Calculation of Partial Pressure at the Wellhead
The calculation method is that used for case A (FTHP <Pb)
2:
• If the percentage (ppm) of H
2
S in the gas under static conditions is
unknown, the corresponding value in reservoir conditions is assumed as
being partial pressure at the wellhead.
• If the percentage (ppm) of H
2
S in the separated gas under static
conditions is unknown, the corresponding value in reservoir conditions is
assumed as being partial pressure at the wellhead.
13.17 Corrosion Caused By CO
2
and Cl
In the presence of water, CO
2
gives rise to a corrosion form that is different from
the form caused by the presence of H
2
S. It also occurs only if the partial pressure
of CO
2
exceeds a particular threshold.
As in the case of SSC, the possibility that corrosions exist in water cut values
combined with the type of well and deviation profile is evaluated. If the conditions
described in 13.16.3.1 Sulfide Stress Cracking (SSC) exist, then the pCO
2
is then
calculated.
13.17.1 Gas or Condensate Gas Wells
The partial pressure is calculated:
13-38 Casing/Tubing Design Manual
October 2005
pCO
2
= SBHP x Y(CO
2
)/100 (13-30)
where:
SBHP = Static bottom-hole pressure [atm]
Y(CO
2
) = Mole fraction of CO
2
pCO
2
= Partial pressure of CO
2
[atm]
Corrosion occurs if pCO
2
>0.2 atm
13.17.1.1 Oil-Bearing Wells
The problem exists where there is wetting water; i.e.:
• Water cut >15% for vertical wells
• Water cut >1% for horizontal or highly deviated wells (>80 degrees)
13.17.1.2 Undersaturated Oil Wells
The partial pressure of CO
2
is calculated:
pCO
2
= Pb x Y(CO
2
)/100 (13-31)
where:
Pb = Bubblepoint pressure at reservoir temperature
Y(CO
2
) = Mole fraction of CO
2
in separated gas at bubblepoint pressure (from the
PVTs)
pCO
2
= Partial pressure of CO
2
[atm]
Corrosion occurs if pCO
2
>0.2 atm
The pCO
2
values calculated in this way are used to evaluate the corrosion at
bottom hole and the wellhead; i.e., pCO
2
at the wellhead is assumed as
corresponding to reservoir conditions.
13.17.1.3 Oversaturated Oil
The oil is considered oversaturated when the gas separates in the fluid because
the pressure of the system is lower than bubblepoint pressure. Two situations
may arise:
Case A
• FTHP <Pb
• FBHP >Pb
Case B
• FTHP <Pb
• FBHP <Pb
Casing/Tubing Design Manual 13-39
October 2005
13.17.1.4 Calculation of Partial Pressure in Case A
1. Calculation of pCO
2
in reservoir conditions
FBHP >Pb pCO2 is calculated in the same way as undersaturated oil wells
earlier in this section.
pCO
2
= Pb x Y(CO
2
)/100 (13-32)
where:
Pb = Bubblepoint pressure at reservoir temperature
Y(CO
2
) = Mole fraction in separated gas at bubblepoint pressure (from the PVTs)
pCO
2
= Partial pressure of CO
2
[atm]
Corrosion occurs if pCO
2
>0.2 atm
2. Calculation of pCO
2
at the wellhead
pCO2 = STHP x Y(CO2)/100 (13-33)
where:
Y(CO
2
) = Mole fraction in separated gas at STHP3
STHP = Static tubing head pressure [atm]
Corrosion occurs if pCO
2
>0.2 atm
If the percentage (ppm) of CO
2
in the gas under static conditions is unknown, the
corresponding value in reservoir conditions is assumed as being partial pressure
at the wellhead.
13.17.1.5 Calculation of Partial Pressure in Case B
1. Calculation of pCO
2
at reservoir conditions
pCO
2
= FBHP x Y(CO
2
)/100 (13-34)
where:
Y(CO
2
) = Mole fraction in separated gas at pressure
FBHP (from the PVTs)
2. Calculation Of pCO
2
at the wellhead
The calculation method is the same as the one used in the wellhead conditions in
case A:
pCO
2
= STHP x Y(CO
2
)/100 (13-35)
where:
Y(CO
2
) = Mole fraction in separated gas at STHP
4
There is corrosion if pCO
2
>0.2 atm.
13-40 Casing/Tubing Design Manual
October 2005
4
If the percentage (ppm) of CO
2
in the gas under flowing/static conditions is not
known, the corresponding value in reservoir conditions is assumed as being
partial pressure at the wellhead.
13.17.2 Corrosion Caused By H
2
S, CO
2
, and Cl
It is possible to encounter H
2
S and CO
2
besides Cl. In this case, the problem is
much more complex and the choice of suitable material is more delicate. The
phenomenon is diagnosed by calculating the partial pressures of H
2
S and CO
2
and comparing them with the respective thresholds.
13.17.2.1 Corrosion Control Measure
Corrosion control measures may involve the use of one or more of the following:
• Cathodic protection
• Chemical inhibition
• Chemical control
• Oxygen scavengers
• Chemical sulfide scavengers
• pH adjustment
• Deposit control
• Coatings
• Non metallic materials or metallurgical
• Control
• Stress reduction
• Elimination of sharp bends
• Elimination of shock loads and vibration
• Improved handling procedures
• Corrosion allowances in design
• Improved welding procedures
• Organization of repair operations
Please refer to Figure 13-18. Counter Measures to Prevent Corrosion for more
information.
Casing/Tubing Design Manual 13-41
October 2005
Figure 13-18. Counter Measures to Prevent Corrosion
13.17.2.2 Corrosion Inhibitors
An inhibitor is a substance which retards or slows down a chemical reaction.
Thus, a corrosion inhibitor is a substance that, when added to an environment,
decreases the rate of attack by the environment on a metal.
Corrosion inhibitors are commonly added in small amounts to acids, cooling
waters, steam, or other environments, either continuously or intermittently, to
prevent serious corrosion.
There are many techniques used to apply corrosion inhibitors in oil and gas
wells:
• Batch treatment (tubing displacement, standard batch, extended batch)
• Continuous treatment
• Squeeze treatment
• Atomized inhibitor squeeze - weighted liquids
• Capsules
• Sticks
13.17.3 Corrosion Resistance of Stainless
Steels
Stainless steel is usually used in applications for production tubing; however, it is
occasionally used for production casing or tubing below the packer depth. The
main reason for the development of stainless steel is its resistance to corrosion.
To be classed as a stainless steel, an iron alloy usually must contain at least
12% chromium in volume. The corrosion resistance of stainless steel is because
of the ability of the chromium to passivate the surface of the alloy.
Stainless steel may be divided into four distinct classes on the basis of their
chemical content, metallurgical structure, and mechanical properties. These
classes are:
13-42 Casing/Tubing Design Manual
October 2005
13.17.3.1 Martensitic Stainless Steel
The martensitic stainless steel contains chromium as its principal alloying
element. The most common type contains around 12% chromium, although
some chromium content may be as high as 18%. The carbon content ranges
from 0.08% to 1.10% and other elements, such as nickel, columbium,
molybdenum, selenium, silicon, and sulfur, are added in small amounts for other
properties in some grades.
The most important characteristic that distinguishes this steel from other grades
is its response to heat treatment. The martensitic stainless steel is hardened by
the same heat treatment procedures used to harden carbon and alloy steels.
Martensitic stainless steel is included in the “400” series of stainless steels. The
most commonly used of martensitic stainless steel is AISI Type 410. The only
grade of oilfield tubular used in this category is 13Cr. As its name indicates, the
microstructure of this steel is martensitic. Stainless steel is strongly magnetic
whatever the heat treatment condition.
13.17.3.2 Ferritic Stainless Steel
The second class of stainless steel is the ferritic stainless steel, which is similar
to the martensitic stainless steels in that it has chromium as the principal alloying
element. The chromium content of ferritic stainless steel is normally higher than
that of the martensitic stainless steel and the carbon content is generally lower.
The chromium content ranges between 13% to 27% but it is not able to be
hardened by heat treatment. It is used principally for their temperature properties.
Ferritic stainless steel is also part of the “400” series, the principal types being
405, 430, and 436. The microstructure of ferritic stainless steel consists of ferrite,
which is also strongly magnetic. Ferrite is simply body-cantered cubic iron or an
alloy based on this structure.
13.17.3.3 Austenitic Stainless Steel
Austenitic stainless steel has two principal alloying elements, chromium, and
nickel. Its micro-structure essentially consists of austenite, which is face-cantered
cubic iron or an iron alloy based on this structure. It contains a minimum of 18%
chromium and 8% nickel, with other elements added for particular reasons, and
may range to as high as 25% chromium and 20% nickel
.
Austenitic stainless steel generally has the highest corrosion resistance of any of
the stainless steels, but its strength is lower than martensitic and ferritic stainless
steel. It cannot be hardened by heat treatment, although it can be hardened, to
some extent, by cold working, and it is generally non-magnetic.
Austenitic stainless steels are grouped in the “‘300” series; the most common is
304. Others commonly used are 303 free machining, 316 high Cr and Ni, which
may include Mo, and 347 stabilized for welding and corrosion resistance. These
steels are widely used in the oilfield for fittings and control lines, but because of
their low strength they are not used for well tubulars.
Casing/Tubing Design Manual 13-43
October 2005
13.17.3.4 Precipitation Hardening Stainless Steel
The most recent development in stainless steel is a general class known as
“precipitation hardened stainless steel”, which contains various amounts of
chromium and nickel. This steel combines the high strength of martensitic
stainless steel with the good corrosion resistance properties of austenitic
stainless steel. Most of these steels were developed as proprietary alloys and
there is a wide variety of compositions available.
The distinguishing characteristic of the precipitation hardened stainless steel is
that, through specific heat treatments at relatively low temperatures, the steel can
be hardened to varying strength levels. Most of them can be formed and
machined before the final heat treatment and the finished product is hardened.
Precipitation in alloys is analogous to precipitation as rain or snow.
These are most commonly used for component parts in downhole and surface
tools and not as oilfield tubulars. Refer to Figure 13-19 for the various
compositions of stainless steel.
Figure 13-19. Stainless Steel Compositions
13.17.3.5 Duplex Stainless Steel
In general, ferritic-austenitic (duplex) stainless steel consists of between 40% to
70% ferrite and has a typical composition of 22% Cr, 5.5% Ni, 3% Mo. 0.14% N.
The resulting steel has properties that are normally found in both phases. The
ferrite promotes increased yield strength and resistance to chloride and hydrogen
sulfide corrosion cracking, while the austenite phase improves workability and
weldability.
This material is used extensively for tubulars used in severe CO
2
and H
2
S
conditions.
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October 2005
As a general note, there is a large gap between the 13Cr and Duplex Stainless
Steel used as tubulars for their good anti-corrosion properties. This gap is
attempted to be filled with “Super 13Cr” tubing that is being developed.
13.18 Ordering Specifications
When ordering tubulars for sour service, the following specifications should be
included in addition to those given in the previous figures:
• Downgraded grade N80, P105, or P110 tubulars are not acceptable for
orders for J55 or K55 casing
• Couplings must have the same heat treatment as the pipe body
• Pipe must be tested to the alternative test pressure (see API Bulletins 5A
and 5AC)
• Cold-die stamping is prohibited; all markings must be paint stenciled or
hot-die stamped
• Three copies of the report providing the ladle analysis of each heat used
in the manufacture of the goods shipped, together with all the check
analyses performed, must be submitted
• Three copies of a report showing the physical properties of the goods
supplied and the results of hardness tests (see bullet 3 above) must be
submitted
• Shell-modified API thread compound must be used
NOTE: Recommendations for casing used for sour service must be specified
according to the API 5CT for restricted yield strength casings. The casing should
also meet the following criteria:
• Steel used in the manufacture of the casing should be quenched and
tempered. (This treatment is superior to tubulars heated/treated by other
methods, e.g., normalizing and tempering.)
• All sour service casing should be inspected using non-destructive testing
or impact tests only, as per API Specification 5CT.
A
ACasing Design Spreadsheet
A variety of casing design spreadsheets may be used as a first pass for casing
design. A casing design spreadsheet is generally easy to use, but may not be
able to handle complicated loads and designs.
Generally, casing loads (burst and collapse) can be calculated on a spreadsheet
and the proper weight and grade of casing can be selected based on the
calculated burst and collapse loads and design factors. Then, the casing tension
load can be calculated from the selected weight of casing to check the casing
tension design factor.
The following example is used to illustrate the main procedures of using
spreadsheet for a first-pass casing design.
Design 9-5/8-in.
production casing set at
8,000 ft in 12-ppg drilling
mud (formation pore
pressure and fracturing
gradients are 11.5 ppg
and 15 ppg) in a vertical
wellbore. The well TD is
11,000 ft (7 in.)
production liner set at
11,000 ft, and 4-½-in.
tubing set at 10,000 ft
with downhole packer,
packer fluid density 9
ppg). Perforation is at
10,500 ft where reservoir
pressure gradient is 14 ppg.
Figure A-1. First-Pass Casing Design Example
Design factors:
• Burst 1.20
• Collapse 1.00
• Tension 1.60.
Design loads:
• Tubing shut-in leak (burst)
• Full evacuation (collapse), 100,000-lb overpull (tension)
Casing/Tubing Design Manual A-1
October 2005
Calculate casing burst load:
• Tubing leak pressure near surface: 0.052*14*10500 – 0.1*10500 = 6.594 psi
• Casing internal pressure at shoe: 6594 + 0.052*9*8000 = 10,338 psi
• Casing external pressure at shoe: 0.052*11.5*8000 = 4,784 psi
The design burst pressure is listed in the last column of the following example
spreadsheet, which is the internal pressure (load) minus the external pressure
(backup), when multiplying the burst design factor of 1.20.
DEPTH LOAD BACKUP RESULTANT DESIGN
(ft) (psi) (psi) (psi) (psi)
0 6,594 0 6,594 7,253
2,000 7,530 1,196 6,334 6,967
4,000 8,466 2,392 6,074 6,681
6,000 9,402 3,588 5,814 6,395
8,000 10,338 4,784 5,554 6,109
BURST CASING DESIG
N
7253
6967
6681
6395
6109
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000
11000
12000
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000
DEPTH (FEET)
PRESSURE (PSI)
LOAD BACKUP
RESULTANT DESIGN
Figure A-2. Burst Load Spreadsheet
Calculate casing collapse load:
• Casing external pressure at shoe: 0.052*12*8000 = 4,992 psi
• Casing internal pressure at shoe: 0 psi
A-2 Casing/Tubing Design Manual
October 2005