Casing/Tubing design manual october 2005 Chevron
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Figure 12-7. Reservoir Fluid Gradient Distribution (kPa/m) with a Limited Chance of
Encountering Gas and a More Likely Gradient Oil Expectation
All three variables have expectations and bands of uncertainty. They can be
processed with statistic “Monte Carlo” software to calculate the distribution in the
range of maximum design loads. The distribution of the design loads (see Figure
12-8) can be modeled based on the above three geological uncertainty
distributions, and shows a 93% chance that the maximum design load would be
within 10,000 psi (70,000 kPa).
As a comparison, a deterministic well design without considering the probability
of the maximum design load would have resulted in a 15,000-psi well
requirement (full gas displacement criteria). The example well was drilled and
completed in Q2-Q3 1997 as a 10,000-psi well, resulting in a significant savings
over designing it as a 15,000-psi well. A successful production test was carried
out. Figure 12-9 shows the well schematics for the 10,000-psi probabilistic design
versus the deterministic (traditional) 15,000-psi design.
12-8 Casing/Tubing Design Manual
October 2005
Figure 12-8. Distribution of the Design Loads (kPa) Based on Geological
Uncertainties
Figure 12-9. Well Schematics for the 10,000-psi Probabilistic Design (left) and the
Traditional Deterministic 15,000-psi Design (right)
Casing/Tubing Design Manual 12-9
October 2005
12.3 Load and Resistance Factor Design
(LRFD)
Load and resistance factor design (LRFD) is a reliability-based design
philosophy, which explicitly takes into account the uncertainties that naturally
occur in the determination of loads and resistance (capacity). The LRFD format
was first developed in the 1930s in the USSR and Europe for use in the Civil
Engineering industry. Its development and use has continued in Civil Engineering
practices and is now widely accepted in many codes.
Beginning in late 1992, a major effort to incorporate the LRFD philosophy into its
casing and tubing design was started by a major oil company. The main aim of
this effort was to increase the reliability of the system and to quantify the risk of
design alternatives. The LRFD design approach can be simply expressed as:
Lf*Load = Rf*Capacity (12-3)
Lf and Rf are the load factor and resistance (capacity) factor. The load factor (Lf)
takes into account the uncertainty and variability in load estimation, while the
resistance factor (Rf) takes into account the uncertainty and variability in the
determination of the tubular resistance (capacity).
It is noted that the two factors look, in a sense, like they act in a similar way to
the safety factor used in detrimental (traditional) tubular design:
Lf/Rf = Design factor (12-4)
However, the load factor Lf and resistance factor Rf are chosen through a
process of calibration based on the estimated load and resistance and the
reliability. The calibration is the most time-consuming and rigorous step in the
LRFD procedure. Several reliability theory and statistical details, such as
uncertainty estimation, pre-processing of high reliability designs, zonation,
uniformity of reliability, etc. are involved. After the two factors are calibrated
based on the estimated load and resistance and the reliability, the rest of the
design procedure becomes the same as the traditional design approach, that is,
to select the grade and size of the tubular.
12.4 Probabilistic Casing Design
Applications
Probabilistic casing design demonstrated several benefits, including a better
understanding of real casing load and casing strength (capacity) behavior in
casing and tubing design and cost savings while maintaining or improving the
focus on safety. The casing strength probabilistic design, primarily based on
improved understanding and accurate qualification of materials and dimensional
tubular properties, is the relatively simple and effective approach to start the
design.
The other approaches on probabilistic casing design (casing load probabilistic
design and LRFD and full probabilistic casing design) are more complicated,
requiring more efforts to study and apply.
12-10 Casing/Tubing Design Manual
October 2005
The availability of supporting data on geometrical and mechanical properties of
the tubular is fundamental to probabilistic casing design. One barrier to efficient
implementation of probabilistic design techniques is the ability to obtain that
information from manufacturers in a cost-effective manner. Unfortunately, tubular
manufacturers usually provide data according to API minimum requirements,
which are inadequate to support the new design technologies.
12.5 References
1. Payne, M.L. et al.: “Select Topics and Applications of Probabilistic OCTG
Design,” paper SPE 48324, presented at the 1998 SPE Workshop on Risk
Based Design of Well Casing and Tubing, May.
2. Dahlin, A., et al.: “Probabilistic Well Design in Oman High Pressure
Exploration Wells,” paper SPE 48335, presented at the 1998 SPE Workshop
on Risk Based Design of Well Casing and Tubing, May.
3. Johnson, D.V., et al.: “Statistical Design of CRA Tubing String for Mobile Bay
Project,” presented at the 1994 OTC, Houston, Texas.
4. Adams, A.J., et al.: “Casing System Risk Analysis Using Structural
Reliability,” paper SPE/IADC 25693, presented at the 1993 SEP/IADC
Drilling Conference, February.
5. Brand, P.R., et al.: “Load and Resistance Factor Design Case Histories,”
presented at the OTC.
6. Keilty, I.D. and Rabia, H.: “Applying Quantitative Risk Assessment to Casing
Design,” paper SPE/IADC 35038.
7. Lewis, D.B. and Maes, M.A.: “The Use of QRA Technology in Drilling and
Well Operations,” paper SPE 48323, presented at the 1998 SPE Workshop
on Risk Based Design of Well Casing and Tubing, May.
Casing/Tubing Design Manual 12-11
October 2005
Casing/Tubing Design Manual 13-1
October 2005
13Tubing Design
13.1 Introduction.......................................................................................................................13-2
13.2 Tubing Features ...............................................................................................................13-2
13.2.1 Critical Factors..........................................................................................................13-3
13.2.1.1 Materials...........................................................................................................13-3
13.2.1.2 Tubing Size and Weight....................................................................................13-3
13.3 Anchoring Systems...........................................................................................................13-5
13.4 Tubing Connections..........................................................................................................13-6
13.4.1 CRA Connections.....................................................................................................13-6
13.4.2 Optimizing Tubing Size.............................................................................................13-6
13.4.3 Reservoir Pressure...................................................................................................13-8
13.4.4 Flowing Wellhead Pressure......................................................................................13-8
13.4.5 Gas-Liquid Ratio.......................................................................................................13-9
13.4.6 Artificial Lift ...............................................................................................................13-9
13.5 Tubing Stress Analysis...................................................................................................13-10
13.5.1 Load Considerations...............................................................................................13-10
13.5.2 Triaxial Stresses.....................................................................................................13-10
13.5.2.1 Von Mises Triaxial Design Equations .............................................................13-11
13.5.2.2 Hill’s Modification to Von Mises Triaxial Design Equations.............................13-11
13.6 Collapse Design .............................................................................................................13-12
13.7 Tubing Load Cases ........................................................................................................13-12
13.8 Pressure Testing ............................................................................................................13-13
13.9 Acid Stimulation..............................................................................................................13-13
13.10 Fracturing ...................................................................................................................13-13
13.11 Flowing.......................................................................................................................13-14
13.12 Shut-In........................................................................................................................13-14
13.13 Tubing Movement.......................................................................................................13-14
13.13.1 Piston Effect........................................................................................................13-15
13.13.2 Buckling Effect....................................................................................................13-17
13.13.3 Ballooning Effect.................................................................................................13-21
13.13.4 Temperature Effect.............................................................................................13-22
13.14 Evaluation of Total Length Change ............................................................................13-23
13.15 Tubing to Packer and Packer to Casing Force...........................................................13-23
13.15.1 Anchored Tubing ................................................................................................13-23
13.15.2 Floating Tubing...................................................................................................13-28
13.15.3 Landing Conditions.............................................................................................13-29
13.16 Materials and Corrosion..............................................................................................13-29
13.16.1 Corrosion Considerations for Development Wells ..............................................13-30
13.16.2 Contributing Factors to Corrosion.......................................................................13-30
13.16.3 Forms of Corrosion.............................................................................................13-31
13.16.3.1 Sulfide Stress Cracking (SSC)........................................................................13-31
13.16.3.2 Undersaturated Oil..........................................................................................13-32
13.16.3.3 Procedure for Calculating the Henry Constant................................................13-35
13.16.3.4 Oversaturated Oil............................................................................................13-36
13.16.3.5 Calculation of Partial Pressure at the Wellhead..............................................13-37
13
13-2 Casing/Tubing Design Manual
October 2005
13.17 Corrosion Caused By CO
2
and Cl...............................................................................13-37
13.17.1 Gas or Condensate Gas Wells............................................................................13-37
13.17.1.1 Oil-Bearing Wells ............................................................................................13-38
13.17.1.2 Undersaturated Oil Wells................................................................................13-38
13.17.1.3 Oversaturated Oil............................................................................................13-38
13.17.1.4 Calculation of Partial Pressure in Case A .......................................................13-39
13.17.1.5 Calculation of Partial Pressure in Case B .......................................................13-39
13.17.2 Corrosion Caused By H
2
S, CO
2
, and Cl..............................................................13-40
13.17.2.1 Corrosion Control Measure.............................................................................13-40
13.17.2.2 Corrosion Inhibitors.........................................................................................13-41
13.17.3 Corrosion Resistance of Stainless Steels ...........................................................13-41
13.17.3.1 Martensitic Stainless Steel..............................................................................13-42
13.17.3.2 Ferritic Stainless Steel ....................................................................................13-42
13.17.3.3 Austenitic Stainless Steel................................................................................13-42
13.17.3.4 Precipitation Hardening Stainless Steel..........................................................13-43
13.17.3.5 Duplex Stainless Steel....................................................................................13-43
13.18 Ordering Specifications...............................................................................................13-44
13.1 Introduction
More discussion on tubing design is presented in this chapter on tubing stress
analysis, (corrosion and material selection will be added in a later edition).
13.2 Tubing Features
The tubing string selection procedure and subsequent stress analysis is
fundamental to the completion design process, as it is during the two stages, that
the optimum solution is found through a sequence of approximations. By using
an iterative method, i.e., by choosing and verifying the various possibilities, the
correct safety factor for all calculated load conditions expected during the life of
the well can be obtained.
The approach to choosing the tubing string is similar to that followed when
designing any other mechanical part. A draft design is considered based on the
expected well conditions and then this design is checked to obtain the safety
factor(s). Alterations are then made to the draft completion until the ideal safety
factor, which may differ depending on the local environmental conditions and on
some parameters, discussed below, is reached.
Because the economic factor plays a primary role of importance when selecting a
completion, it is necessary to assess all the various possible solutions. A typical
example is that of wells with the presence of corrosive agents where either
strings and down hole equipment can be made in corrosion resistant alloy (CRA)
or carbon steel with inhibitors injected down hole can be used. In both cases the
problem of completing the well is solved, but it is necessary to verify both cost
and whether it is better to use on CRA, avoiding future workovers or if it is more
economical to use carbon steel with an inhibition system and scheduled
workovers.
Casing/Tubing Design Manual 13-3
October 2005
13.2.1 Critical Factors
The main factors driving the choice of the string are described below. Taking into
consideration the well conditions, it is then possible to identify the optimum
mechanical solutions.
13.2.1.1 Materials
The choice of material for the tubing string depends mainly on the well
environment, in terms of all the mechanical stresses and corrosivity of the fluids.
In general, the ideal material is determined by the results of corrosion studies
carried out prior to the tubing design stage, especially when the severity of the
conditions suggests the use of expensive CRA materials.
With regard to corrosion studies, it is always necessary to determine, the exact
quantities of H
2
S, CO
2
, chlorides and water from production tests and to enter
these data into an expert system, or for a quicker choice, using the engineering
diagrams supplied by manufacturers. However, this method does not provide a
solution to using carbon steel in conjunction with an inhibition system. In this
case, it is best to base the choice on an appropriate corrosion study which takes
into account many other parameters, e.g., thickness of the corrosion product,
economics, frequency of workovers, etc.
After the choice of materials has been identified, it is necessary to take into
consideration their mechanical properties to ensure that a suitable factor can be
verified in the subsequent stress analysis stage. Indeed, to complete a well with
the presence of corrosive agents (H
2
S and/or CO
2
) the use carbon steel with
controlled hardness and/or martensitic steel, is often sufficient though these only
reach a maximum grade of T95 (95-ksi yield), therefore do not always meet with
stress requirements in high pressures and great depth.
When CRA steels are used (which must be cold worked in order to obtain the
required mechanical characteristics), the possibility of anisotropies must be
checked into, as they generally imply a lower compressive yield load than tensile
yield load and corresponding reductions for their use at high temperatures. The
presence of residual tension may induce stress corrosion and over-stressing
problems which must also be taken into consideration.
13.2.1.2 Tubing Size and Weight
One of the main elements of the completion string design process is the choice
of the size, wall thickness, and grade of tubing which is optimum to requirements
outlined below. The inside and outside diameter of the tubing, if the string has
more than one size of tubing as in a tapered string, and the length of each
section needs to be determined at this point.
Given that the dimensions of the tubing and components of the string (safety
valves, landing nipples, etc.) must fit inside the production casing and/or liner, it
is essential to establish the size in order to find out if it impacts on the casing
design.
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October 2005
NOTE: It is vital that any detrimental impact caused by the casing program is
discussed with the drilling engineers to solve any problems, whether this entails
changes to either the casing program or the completion design.
The first indications of tubing size obtained are from tubing inflow performance
analysis. These studies can generally be completed quickly using software which
directly provides the diameters of tubing for the expected flow rates and
projected rates and takes into account the type of fluid, surface pressures,
bottom hole pressures and other parameters. Calculation of the tubing inflow
performance is very complicated and time consuming in most cases and is not
covered in this manual.
After the projected size of the tubing is established for the required flow rate, then
in gas or gas condensate wells, it is necessary to calculate the velocities in the
string during production. This rate must be lower than the rate at which erosion
occurs. These threshold velocities can be found in API RP 14E.
The most important value to be determined on the selected tubing is its
mechanical strength. As explained in the following section, loads resulting from
the various load conditions (acid jobs, production, etc.) are applied to the
selected string and the safety factor under these loads against the yield strength
are calculated. After this calculation has been made, it may be necessary to
increase the weight or grade because the string is too weak. In some situations,
non-traditional solutions must be chosen as some parameters, such as cost, limit
the choices. In the case of a very expensive super austenitic steel string, for
example, it may be more appropriate to choose more structurally efficient
solutions, which use a tapered string with different diameters, thus reducing the
amount of material needed and the cost.
Wells in which hydrocarbons containing corrosive agents are produced are
sometimes completed using carbon steel and it is accepted that a certain amount
of the material will be lost through corrosion during the life of the well. The strings
of these wells, which generally will be equipped with a corrosion inhibitor injection
system, should have added thickness so as to have sufficient material to last until
the scheduled workover. The two cases, i.e., the new string (maximum thickness,
maximum weight) and the workover stage (minimum thickness, minimum weight)
must be taken into consideration when calculating the string’s stress resistance.
It is also prudent to reduce through tubing interventions, which knock off the
corrosion exposing fresh material and, hence, faster wall thickness reduction.
When choosing the thickness of the tubing forming the string, it is useful to
consider the thickness tolerance adopted by the manufacturer of the selected
tubing. API standards for carbon steels define a 12.5% eccentricity tolerance,
which means one point on the tubing’s circumference probably has less
thickness. This value for CRA tubing’s is often only 10%, which provides a better
safety factor under similar conditions. Another reduction of thickness which must
be taken into account on used tubing may be due to repairs by grinding carried
out to remove tong marks.
The above factors can often lead to a variety of solutions, so it is necessary to
evaluate each one in order to obtain the most suitable solution in terms of cost,
mechanical strength and practical feasibility.
Casing/Tubing Design Manual 13-5
October 2005
13.3 Anchoring Systems
As illustrated earlier, the operations carried out during the life of a well cause
movement of the tubing string, which can depend on the type of tubing/packer
seal system used between the bottom of the tubing and the packer, generate
different loads in the string.
From Figure 13-1, which shows the three most common types of packer/tubing
systems, it is clear from this that the least-severe system is where the tubing seal
assembly is free to move in the packer bore. This system does, however, have
some disadvantages which are often unacceptable such as dynamic seals.
In very deep wells with high pressures and temperatures, the movements of the
lower end of the tubing may reach several feet in magnitude and very long seal
units would need to be used in the packer, which brings related assembly and
protection problems during running in. Another important problem of free tubing
is the continuous movement of the seal elastomers, which may become
damaged due to wear or from the debris deposited in the annulus above the
packer.
The best solution, because of the use of static seals, are systems to screw the
tubing to the packer using a threaded connection on retrievable packer systems
or to a tubing anchor (which allows the packer to be released when necessary)
on permanent packer systems. This type of anchoring provides the solution to
seal life, but leads to greater stressing of the tubing string. In preference, the
free-moving system is the first choice and if the loads it creates do not allow for a
suitable safety factor during well operations, other systems are considered.
Free Movement Limited Downward
Attached
Movement
Figure 13-1. Tubing/Packer Systems
The second preference is where downward tubing movement is restricted. For
example, using a No-Go locator shoulder fitted above the seal assembly where it
is positioned to prevent the elongation of the string while leaving it free to
shorten. This will reduce movement of the packer seal assembly by eliminating
downward movement and upward movement would only occur in certain limited
lead conditions (stimulations or fracturing). This will extend seal life.
13-6 Casing/Tubing Design Manual
October 2005
13.4 Tubing Connections
The company policy for tubing connections is to select tubing connection by the
“Tubular Connection Selection Guideline”.
13.4.1 CRA Connections
Steels with a high chrome content (>13%) have a tendency to gall during make
up. This requires special surface treatment in the connection’s pin and box. The
anti-galling treatments (e.g., Bakertron or copper plating) are always applied to
the couplings to ensure the utmost coating and protection.
13.4.2 Optimizing Tubing Size
The optimum tubing size is selected to obtain the desired off-take rates at the
lowest capital and operating costs. This usually means at the maximum initial
flow rate and maintaining it as long as possible; however, depending on the
inflow, it may be possible to accelerate off take by the early installation of artificial
lift. Whatever the case, the selection process inevitably involves analysis of the
gross fluid deliverability and flow stability under changing reservoir conditions to
confirm that the production forecast can be met and to determine when artificial
lift or compression is required.
A fixed flow rate, as tubing size increases, decreases fluid velocities and reduces
the frictional effects. The net result should be higher production rates only if the
IPR/TPC intercept remains to the right of the TPC minimum. If the PI was infinite,
one increase in API tubing size would double the maximum theoretical capacity.
The example well #1 in Figure 13-2 shows that the 4-1/2” tubing size should be
selected to ensure the off take exceeds the target of 8,000 to 9,000 stb/d and,
perhaps, even larger tubing could be investigated. However, at low rates, the
reduced fluid velocities experienced in larger tubing increase the hydrostatic
head because of slippage. This shifts the TPC minimum to a higher rate,
therefore, widening the flat uncertain portion around the minimum. If the IPR
curve intersects the TPCs in the region near the minimum, the optimum tubing
size will be a compromise maximizing flow rate and having steady producing
conditions. For example, using the IPR for well 2, the maximum flow rate is
obtained with ½” tubing but only a slight reduction in flow rate is seen if the 2-
7/8” tubing is selected which gives steadier and regular flow.
It is generally recommended to select a tubing size such that the flowing
pressure, Pwf, is greater than 1.05 of pressure minimum, pmin to ensure stability.
As previously mentioned, the changing conditions over the life of the well must
be considered when selecting tubing size. These changes are normally declining
reservoir pressure and increasing water cut which will reduce flow rates. This
trend is downwards towards cessation of flow and obviously the tubing selected
for the start of production will not be the optimum size after some period of time.
The choice at that time will be to reduce wellhead pressure, replace the tubing
with a smaller size or to implement artificial lift which will have associated costs.