●
IADC/SPE lADC/SPE 19923 Compressive Loading Casing Design E.M. Kooian and R.N. Mefford,Exxon Co. U.S.A.,and i-.B. Hilbert and IA. Kalll, Exxon ProductionResearch Co. SPE Members
Copyright 19S0, lAOC/SPE DrlllI.ig Conference. This paper wm prepared for praaenfatlon ●t the f 9S9 !AWSPE
Dr:lllng C $Iferenoe held In Hwafon, Texem February 27-March 2,1990.
7hla paper wea aeleofed for preaentaticn by an lADC/SPE Program Cernmlffea folbwlng rof Ifrformetkm oon!alned In ●n ebafrti aubmifted by the wfhofto). (W t%,.taof the paper, au p+eawrtod,have not km reviewed by the iWOtYOf PafroIeum EIWWfUoft~IntUrnatmal -Won of Drllfln9 Mtlmfof$ ●W are WWto ~m fWh Ja@f@@. rfre material, u preaanfeo, does not necaaauily refleot ●ny positionof the IAOC or SPE, ire offkera, or membars. Pepefa presented at MOO/SPE nreeflw ●re aubjeof to Pubflcatbn revbw by Editorial Oommltteaa of the IADO and SPE. Permiaalon to00PY 16reafrkfed to●!ebafrucf of not more than 300 words. Illuatrdona meY nor b. oopied. The ektraot ahoukt ~n~ti~&*ti&_tiWk~_ti. W*~_M~, ~,p.O. ~~, ~~, ~~~'*, T~,~~
ABSTRACT
As 1isted in Figure 1, a variety of sources combine to contribute to the overal1 compressive 1oad. One of the major sources is derived from the combined tensile loads imposed by the inner strings 1anded in the wel1head. Liners hung off below the outer string cement top, do not contribute to the tensile load and can therefore be neglected. The weight of the wellhead sections and BOPS stacked on top of the surface casing must i&ol be considered although the 1oad is relatively .
This paper provides compressive loading design guidelines for the provision of safe, economic casing for any type of onshore wel1. Compressive loading design is analyzed by looking at the nature of compressive loads, casing compressive failure mechanisins,and load distribution. Field data verifying such analysis is presented. Lastly, recommended procedures and design factors are offered to reach a final design.
In addition to the above, the landed tensile loads are affected by mud weight~ temperature~ and ;;~ssue~lchanges experienced during the life of To counter these, stability calculations ma; indicate additional tensile loading is required when an individual string is initially landed. This overpull must be included in summing all loads.
INTRODUCTI~
—
A compressiveloading failure can result in severe subsidence of the wellhead, circumferential bulging of the near surface tubulars, and collapse or buckling of the inner strings. While an abundance of industry literature exists for offshore pile and conductor compressive loading design, very little has been published for onshore locations. Historically, compressive loading has not been a majo? concern. In fact, it is often neglected, except in extremely deep wells. Because of the differences in the environment and load constraintsbetween offshore and onshore, and the everw~i~heasi;~l;rendtowards deep, expensive wel1s experience tenhigh sile/compressiveloading in the wellhead, design fui:~lines need to be established for land loca.
Even if no stability overpull is placed on a string, additional tension may still be generated with time. As shown in Figure 2, tension can be affected by changes in external pressure. A common example of this is the tension increase as the annulus mud weight decreases with time.1 If external pressure decreases, the resulting #ncrease in tension is defined by the following formulazderived from Hooke’s law:
AFa =0.471
Another increase in tensile loading on a string can occur later if a change in internal ressure occurs as shown in Figure 3. Host commonry, this develops when mud weight must be increased during
CASINGCiX4PRESSIVELOADS Before a design procedure can be prepared, one of surface must first look at the origination
compressive forces
(1)
Dz Ape
drilling
to adequately understand the
aftw
t!s
string
is set.
Anot’ler source
may be a casing ar tubing leak. It internal pressure incre~ses, the resulting increase in tension is also defined~ by a derivation of Hooke’s lr?c
nature and magnitude of all contributingloads. Referencesand illustrationsat end of paper.
m
I
. COMPRESSIVE LOADING CASING DFSIGV
2
AFa -0.471
(2)
dz AP+
Changes in wellbore temperatureover the well life can also affect tensile loading. A large decrease in temperature may result in a significant increase in tension as the casing contracts. An example would be a fracture or acid stimulation workover with a cold fluid. This force can be definedz by:
AFa
5
(3)
-58.8 W AT
In summary, all of the above forces contribute to the compressive load on the surface casing and/w conductor. CASING COMPRESSIVE FAILURE HECHANISHS .Casingmay fail due to excessive compressive loads or strains in several modes: ●
Casing material yield
●
Columnar or Euler buckling of section of casing
a
shown in Figure 5.
IAOC/SPE 19923
Fortunately, for the classes
of steels used in most conductor and surface casing designs, the yield stress of the steel in compression and in tens~h~sis, For all practical for casir,g design purposes, identical. purposes, the minimum tensi’1~yield strength as specified in API Standard 5CT4 can be used as an accurate approximation of the compressive yield strength. When casing is subjected to sufficiently large axial compression,and the casing is not laterally suppwted by cement or by the wellbore, it may deflect laterally, or buckle. Since casing is generally confined within a cylindrical bore and has little or no resistwce to bending, the post-buckled geometry is helical. This type of buckling may occur due to applied compression (i.e., S1acking off weight from the surface), due to an increase in internal pr~ssure, or due to increased compressive strains when the wellbore fluid tempf.ratureincreases. In addition, such buckling often occurs at loads well below the casing yield stress.
joint or
●
Cross-sectionalbuckling (i.e., a circumferential bulge)
o
Casing material fracture or splitting
●
Shear or fracture of connectionthreads
The mode of compressive failure may be one or a combinationof the above mechanisms, depending on the loading mechanism (strain or load controlled loading), the load magnitude, and the casin9 material properties. Casing design is the process of determining the casing size, wall thickness, and material strength required to prevent failure. Therefore, knowledge of the failure mechanism and a means of quantifying the failure load are importantfactors in casing design. Although yield of casing material may not be recognizedas a catastrophicfailure,yield of the material in a threaded connection may result in a loss of pressure integrity or a reduction in the tensile strength of the casing. The axial conpressive load required to yield the cross section of the casing pipe-body or the minimum cross section in a threaded connection is usually understoodto be the compressiveyield load of the casing. Calculation of the load is simple, since it involves merely calculating the product of the cross-sectional area and the compressive yield strengthof the casing. However, the compressive yield stress may not be so simply determined. It cannot always be assumed that the material behaves identicallyin compressionand in tension. For example, many corrosion-resistantal10Y (CRA) casing materials used in deep, high-temperature, high-pressure,sour gas wells exhibit a significant Bauschinger effect, in which the tension and compression strengths are quite different.$ An example is shown in Figure 4. Also, a casing steel may exhibit significantyield-point behavior in a tensile test, but none in a compression test, as
There are a considerable number of published studies of casing helical buckling. The methods used to calculate the buckling loads can be complicated. This type of buckling is most applicale to production and protective casing strings, in which there may be a considerable length of non-supported casing above the top of cement. Conductor and surface strings are in most cases cemented to the surface, and thus are not allowed to deflect laterally (unless there is a significantportion of washed out hole or cement). klhencasing is laterally confined by cement or the wellbore and is subjected to large compressive strains, it is not allowed to relieve the compression deformation by laterally buckling into a yield, helical shape. Instead, the casing will and under continued compressive de: Vmation, the casing pipe wall will buckle int~ a localized, Continued compressive circumferential bulge. deformationmay result in a fracture in the pipe body as the bulge deforms around a threaded connection, since the bulge forms near the connection due to local radial deformationsresulting from makeup. This type of failure occurs under large axial compressive deformation caused by formationcompaction,permafrostthaws, or general subsidence. Casing failure due to fracture occurs when the casing steel actually parts or separates. Fracture generally occurs in ductile steels after the yield stress is exceeded, and is usually associated with high tension loads or stresses. In compression, fracture generally occurs as a secondary failure mechanism subsequent to extreme material deformation. If the connection thread width or height is insufficient to support the compressive load, the threads will shear off and the pin will telescope into the coupling or box. In some other cases, a connection may permit sufficientradial deformation that results in the pin and coupling threads.riding over one another causing “jump-in” of the connection. In extreme cases, theeasing body may fracture in the tensile
.
.
. IADC/SPE 19923
E. H. KOCIAN, R. N. MEFFORD, L. B. HILBERT, 1. A. KALIL
3
of Hooke’s Law for the case where the underlying cement is not considered to contribute support and shows that the ratio of the casings’ cross-sectional areas is equal to the ratio of the distribution of load. For example, a conductor casing with a 4:1 ratio of cross-sectionalarea to the ~urface casing, theoreticallywould be designed to support 80% of the compressiveload.
ortion of a bend due to localized cross-sectional ~uckling or columnar buckling. It should be noted that the connections between joints of casing have an important role i? the compressive failure mode. As mentioned above, jump-in can occur. In many cases, large diameter conductor casing .Iointsare welded together~ or weld-on connections used. Usually, low-carbon, line-pipetype casing steels are used that provide a weld that is as strong as tie pipe body. In fact, the weld may be stronger than the pipe simply because the weld has material properties greater than the pipe. On the other hand, higher carbon-content steels, such as N-80 and P-11O, generally have lower strength welds due to problems associated with welding on these tyoes of materials (i.e., the heat affected zone around the weld has lower strength, or the weld material may be weaker than the pipe material).
The second support mechanism, cement compression, may only be considered when a bas~ plate is used to transmit load. Very often cement between the surface and conductor casing is placed to be in contact with the base plate, thus providing an additional shoulder to suFport compressive load. To ca!culate the contribution of the cement in this scenario,Hooke’s law is solved a second time by utilizing a modulus of elasticity for the cement. Appendix B documents the calculation for this case. The contribution of the cement may be initially significant because, despite its relatively low stiffness,the contact surface area may be large.
LOAD DISTRIBUTIONCONSIDERATIONS Once the calculation of the maximum anticipated compressive load is completed, the design of a wellhead support system can begin. The wellhead support.system is designed based on the compressive load distribution. Four aspects need to be 1) casing compression, considered, notably: 2) cement compression,3) cement bond, and 4) soil shear. The first two aspects, casing and cement compression,represent the capacity of the system components to resist applied compressive load. The final two aspects, cement bond and soil shear, representthe ability to transfer the applied load into surroundingmembers and/or surroundingsoil.
The compressive strength of the cement used will also influence it’s contribution as J secondary support member. Even if the cement yields in its secondary support role, it may be assumed to contributeto the overall compressive load capacity because, even at yield, it is confined by the casings present on either side. However, due to its low relative stiffness it may be prudent to ignore the compressive support of cement and assume that the casings must bear the total load. The third aspect of system design is cement bond which is independent ~f the compressive support mechanisms. Cement =wfd strength is the primary method of vertical load transfer and casing support. End bearing support can typically be ignored because, for normal casing strings, it is only a small contributor.The cement bnnd strength is a calculationof the shear resistancedeveloped between the casing and the surroundingcement and is consideredto be a function of the contact area and strength of the cement. Cement bond strength is equivalent to approximately 10% of the compressive strength.e
Casing compression is achieved through the distribution of wellhead loads to the casing string to which the first wellhead section is attached as shown in Figure 6. The primary casing string is usually designated “surface’ casing and the first wellhead section, or A-Section, is either welded or screwed onto the top joint. The first design calculation involves comparing the total worst case anticipated compressive load to the connection rating and the yield strength of the size of casing desired. The casing size is typically governed by the drift diameter that will accommodate the desired bit size for drilling the next section of hole.
If the desired casing cannot be located with additional sufficient compressive strength, compressive support components must be designed. The most common second step is to order the A-Sectionwith a base plate or landing base. The base plate is used as a vehicle to distribute compressive load to a member other than the surface casing string as shown in Figure 7. The most common secondarymember is the previously set initial casing string designated “conductor” casing, although some of the load may be distributed into cement underlying the base plate. The load distribution between the different members is largely governed by stiffness and may be simplistically estimated by application of Hooke’s Law. Appendix A documents the derivation
For example, assume 200 feet of 20-inch casing is cemented to surface with cement having a compressive strength of 3000 psi. Assuming full contact, the resulting shear restrainingforce is 4.5 x 107 lbs. It is obvious from this example calculation that cement bond capacity is typically not the governing factor in a wellhead support system. Cement/soil bonding will be greater than cement/casing bonding based on the greater surface area available and assuming similar contact efficiency. The last support system to be considered is soil shear capacity. This represents the ability of the surrounding soil to diffuse compressive load from the casing through shear transfer and hence, reduce the compressive load as the depth below ground increases. The soil shear capacity is a function of the cement/soilsurface area and the soil shear value.
a.-
. COMPRESSIVELOADING CASING DESIGN
4
.
The soil shear capacity is related to the type of soil and the soil properties. For sands, the shear value is related to the overburden pressure and the angle of friction. For clays, the shear value is related to the undrained shear strength. Undrained soil shear values can range from 25 lbs/ft for very soft clay to 4000 lbs/ft for hard clay. Because the variability in the properties of shallow soils is high, an assumption of shear capacity based on surface conditions is often erroneous. The most accurate method of detenining a wellsite soil shear capacity is with a soil boring.
IADC/SPE 19923
Setting of 7-inch 00 by 5-1/2-inch OD production casing
During each of the three casing running operations, the strain ga e data was collected iasaediately after the hoo[ weight was slacitedoff and again some eight to ten hours later. The-data-was then reduced to indicate an average load supported by the 30-inch conductor pipe and swsnarized in Table 1. The Table 1 data indicates that, with each successive string hung, the support offered by the conductor pipe is asymptoticallyapproaching some ,naximumpercentage of the total string weight landed in the wellhead as shown in Figure 9. The compressiveload supported by the 30-inch conductor pipe increased from 53%, or 611 kips of the 1,160 kips landed in the A-section for the 12-1/16-inchcasing, to 71%, or 532 kips of the 747 kips landed in the C-Section for the 7-inch x 5-1/2-inch production casing. Total load supported by the 30-inch casing through a sunsnation of the incrementalmeasure-lloads is 1663 kips out of a total wellhead load of 2647 kips (63%). The remaining984 kips of load would then be logically supported by the cement underlying the base plate and the 16-inch casing.
Soil borings are common to the offshore oilfield structures industry and the onshore construction industry, but not the onshore drilling industry. A conductor, or surface casing compressive load capacity curve can be generated from evaluationof actual field soil properties. An example of this is provided later in this paper. AS a sidenote, these same soil borings can be used to develop soil bearing capacity for designing drflling rig foundations. A destgn factor should be incorporated into the design procedure to account for tolerances and inconsistenciesassociatedwith the support system components. A 1.33 casing compression design fat or is often used to derate the cotipressive yield of casing based on API wall tolerance and potentialwear. No factor is typically associated with cement compression or bond strength due to reasons previouslydiscussed. A soil shear factor of 1.5 to 2.0 is the common industry practice to account for uncertainty associated with soil properties and, when applicable, to limit deformations to acceptablevalues.
Solving Hooke’s Law to determine the distribution of the 2647 kip compressive load results in 1615 kips (61% of total load) on the 30-inch, 744 kips (28%) on the cement between the 30-inch and 16inch, and 288 kips (11%) on the 16-inch. The strain gage data therefore compares favorablywith the design theory and calculations. The intent of the wellhead support system to distribute load without failing critical members also appears to be substantiated.
CONPARISONOF FIELD DATA TO LOADING PREDICTION DESIGN PROCEDURE In January 1989, Exxon instrumented the 30-inch conductor pipe on an ultra-deep sour gas well to determine the effectiveness of the landing-base design. In theory, the weight of the casing strings hung off in the wellhead would be transferred from the A-section to the 16-inch surface casing string, the 30-inch conductor casing, and the cement between the two, via the landing base.
This design procedure provides step-by-step compressive loading design guidelines for the provision of safe, economic tubulars. Burst, collapse, and tensile design considerationswill not be addressed in this paper. The design factors used in the design process are values frequently employed, but should not to be construed as industry standards which may widely vary.
To verify thi~t the conductor pipe would share in supportingthe compressive loads, Exxon installed strain gages on the conductor pipe exposed surface and gathered geometrical and dimensional data. The dimensional data was needed to determine any pipe ovality, wall eccentricity, and possible load-axis misalignment. T;;d orientation of the sites for data strain gage locations collection, referenced to geographic North, are shown in Figure 8. Strain gage data was collected and analyzed on three separate occasions. These included the fol1owing: ●
Setting of 12-1/16-inch
OD protectivecasing
●
Setting of 9-7/8-inchOD protectivecasing
.
To illustrate the design procedure, consider an example well with the data provided in Tables 2 through 7 and Figures 10 and 11. STEP 1:
I I I
I . .Mu
Calculate the total compressiveload due to the hanging weight of the tubulars hung off in the wellhead plus the stabiiity overpull required. From Table 2, the total load is 2635 kips.
STEP 2:
Calculate additional loads due to changes in internal and external pressure, and temperature versus initial casing settin conditions. Also include weight ofwel ?head sections and BOPS.
I
.
.
I
IADC/SPE 19923
E. H. KOCIAN, R. N. t4EFFOR0,L. B. HILBERT, 1, A. KALIL
From Table 3, the additionalload is 165 kiPS . STEP 3:
STEP 4:
STEP 10: Design a landing base that can transfer the required loads from the surface to the conductor casing.
Sum the tubular loads and the additional loads. TOTAL LOADS (WORST CASE~
iS
A landing base with a minimum rating of 3700 kips would be required to transfer the 1848 kips of compressive load from the surface casing to the conductorwith a 2.0 design factor. The 2.0 design factor is assumed to account for any deficiencies in the load bearing welds.
2800 kips.
Select a surface casing size to drift the desired bit size. In this example, a 14-3/4-inchhole size is desired to run the n-3/4-inch casing. The available 16-inch surface casing is shown in Table 4.
STEP 5:
STEP 11:
Compare joint strength of the available surface casing to the total load calcu1ated in Step 3.
Select a conductor casing size to drift the desired bit size.
In this example, a 20-inch hole size is desired to run the 16-inch casing. The available conductor casing is shown in Table 5. STEP 7:
Note in the tubular design that no contribution from the cement under the 1anding base was assumed to help support the wellhead system. A cement with a compressive strength of 3000 psi and a 1anding base/cement surface area of 205 inz (22.75-inchx 16-inch),would result in the cement shoulderinga total of 615 kips prior to yielding.
Compare the joint “strength of the available conductor casing to the total 1oad calculated in Step 3. None of the 24-inch casing available will support all of the 2800 kips of ;~~re~sive load with a 1.33 design
STEP 8:
Cement with high early” strength and minimal shrinkage should be specifiedto assure an effective soil-cement and cement-casing bond as soon as possible after cement placement. U=? standard industry cementing practices to achieve good mud displacement.
Perfo.7n a combination analysis to determine if the 16-inch x 24-inch combination will adequately support the total load calculated in Step 3. From Table 6, the third listed combination is the lowest cost design with adequate strength.
STEP 9:
Design the cement required to transfer the compressive loads into surrounding suppc. members and/or surroundingsoil. The 270 feet of 24-inch conductor casing has a surface area of 1696 ftz or 244 k inz to support 1848 kips of compressive load. Assuming full cement contact, a cement compressive strength of only 152 psi would be required to support the casing with a 2.0 design factor. The 180 feet of 16-inch surface casing below the conductor casing has a surface area of 757 ftz or 109 k inz to support 952 kips of compressiveload. Assuming full cement contact, a compressive strength of 175 psi would be required to support the casing with a 2.0 design factor.
None of the 16-inch casing available will support the 2800 kips of compressive load with a 1.33 design factor. Therefore, select a conductor casing that can offset a portion of the load through use of a landing base. STEP 6:
5
STEP 12: Summarize design. See Table 7 for summary considering compressive loading only.
Evaluate soil boring data to determine minimum depths to set surface and conductor casing.
CONCLUSION
From Figures 10 and 11, minimum depth of 24-inch conductor in a 30-inch hole is 270 feet to maintain a 2.0 design factor in supporting 1848 kips of compressive load. 14inimumdepth of 16-inch surface casing in a 20-inch hole is 450 feet to maintain a 2.0 design factor in supporting 952 kips of compressive load. Any casing run deeper than the minimum depths is no longer goverriedby compressive loading design assuming that full cement coverage of minimum depths has been achieved.
The field data gathered on instrumentedconductor casing closely corroborates with loading prediction achieved through the design theory, thus substantiatingthe design accuracy. In general, the above design procedure can be used to obtain safe, economic tubulars for land wells with regard to compressive loading. Of course, individual landing-basedesigns should be verified as suitable for the load rating prior to their application in the field.
---
. IADC/SPE 19923
COMPRESSIVELOADING CASING DESIGN
6
NOMENCLATURE
6)
Smith, D. K.: “Cementing”, SPE Monograph Series, Second Edition, 1976,
7)
Popov, E. P.: “Mechanics of Second Edition, 1952.
A = Area d -Casing inside diamater
.
1
Materials”,
D = Casing nominal diameter
A = Deformation AFa = Change in axial force Ape = Change in external pressure
Apt = Change in internal pressure AT = Change in temperature E = Elastic modulus L = Length
APPENDIXA DERIVATION OF HOOKE’S LAW FOR DISTRI~IU COMPRESSIVELOAD BEIUEEN CASINGS
OF
For axially loaded rods, the total deformation between two given points (A’ and B’) is7 A.
B’(jA= / A’
8’ p(x) A’ A(x)
J
dx E
(A-1)
For a tubular of constant cross-sectional area with length L, a constant load P, and one fixed and one free end, the deformationequation becomes
P = Force
A= Pt = Total force PC = Force on conductor casing Ps = Force on surface casing Pcmt = Force on cement u =
Stress
w = Casing weight per foot
‘L m-
Assuming the base plate is in simultaneouscontact with both the conductor and surface casing, and that the bottom of each casing is immobile,
Ac = As and therefore, Pc Lc
=
As Es
Ac Ec ACKNDMLEDGEMENTS The Authors wish to express their appreciationto Exxon Company, U.S.A. and Exxon Production Research Company for permitting the publication of this paper. Individual ack~;owledgementsare accordedto M. J. Morrison and D. J. Broussardwho contributedto the developmentand verificationof this well design technique. REFERENCES 1)
2)
3)
Cooke, C. E., Kluck, hi.P., and Hedrano, R.: “Annular Pressure and Temperature MeasureOperations”, Cementing ments Diagnose IADC/SPE Paper 11416, February 1983. Bourgoyne,A. T., Millheim, K. K., Chenevert, M. E., and Young, F. S.: “Applied Drilling Engineering”,First Edition, 1986. ~ie~er, G. E., Jr.: “MechanicalMetallurgy”, .
4)
API Specification 5CT: Specification for Casing and Tubing, American Petroleum Institute, March 15, 1988.
5)
Hirshberg, A. J., Moyer, M. C., Rickenbach, R. M.: “Surface Casing Strain Capacity for North Slope Operations”, SPE Drilling Engineering, September 1988.
Ps Ls
Unlike two independentsprings, both the conductor and surface casings are concentricallycemented, and therefore, compressive load is assumed to be distributedalong an equivalent length (or depth) of each string. Thus, Lc= Ls Additionally, Loth the conductor and surface casings are manufactured from carbon steel and thus have the same modulus of elasticity,so
Ec= Es The remainingequation becomes Pc=P& — Ac As or Pc —=— Ps
Ac As
Ac and As can be calculated for selected casings, and the maximum load, Pt, is equal to Pc + Ps. Thus two equations with two unknowns can be solved for Pc and Ps.
I
..-
1 IADC/SPE 19923
7
E. M. KOC14N, R. N. MEFFORO, L. 8. HILBERT, 1. A. KALIL —. Substituting the elastic moduli for cement and steel changes the equation to
APPENDIX B SOLVING lUiUE’S L/W FOR DISTRIBUTION OF CDNP~ESSIVE LOAD BETUEEN CASIN6S INCLUDING CEMENT UNDERLYING THE BASE PLATE
Pt = UC
Act [
As+
The total load on the casings and cement, Pt, can be equated to the sum of all forces,
so Pt = ac [Ac +A~
Pt = Pc + Ps + Pcmt
Dc = ~]~
~]~
flcm~
Pt Ac + As + 0.16 Acmt
Then multiply ac by Ac to yield Pc
Isolating the conductor stress and cancellin9 identical values based on the same logic as applied in Appendix A results in Pt=oc
+ 0.16 Acmt]
Rearrangethe equation to solve for ~c
Substitutingthe deformation equat!on for Pc, Ps and Pcmt changes the equation to ‘t=
1
(5X 10’) Acmt (30X 10’)
Pc = Uc Ac Solve for Ps and Pcmt in a like manner. values against Pt by
(EA)cmt Ac+As+—..———— Ec [
1
Pt = Pc + Ps + P~mt
TABLE I COMPRESSIVE LOAD SUPPORTED BY 30-INCH CONDUCTOR PIPE
STRING
LOAD SUPPORTED BY CONDUCTOR
STRING HOOK WEIGHT
INCREMENTAL SUP~ORT
TOTAL SUPPORT
(kips)
(kips)
1160
611
53
53
9-7/8-inch
740
520
70
60
7-inch x 5-1/2-inch
747
532
71
63
2647
1663
12-1/16-inch
TOTAL
._J&L_
●
TABLE 2 TUBULAR LOADS (SUSPENDEDIN WELLHEAD)
CSG SIZE WEIGHT -Q!!l-Q@_~u
MU SET IN
DEPTH
BUOYED WEIGHT (kips)
STABILITY OVERPULL TOTAL LOAD m_-.@i@-
11-3/4
60
10.0
15000
765
150
915
9-5/8
47
12.5
17500
665
100
775
7
41
15.0
20000
635
100
735
12.95
10.5
19500
210
3-1/2
TOTAL.................*.....*...........................4.*......
210 2635
NOTE: No change in buoyed weight due to “as cemented” conditionswas considered. Use air weight oftub{ng if latched into a packer. r
4=. 101
Verify
.,
TAME 3 ACOITIONALLMOS (KNKT CASE)
ITEH Changes In internal Temperature Qffects Weight
of wellhead,
E
pressure (stlmulat!on) (stimulation)
...............
50
.. ... .. . .. .. .. .. .. .. . .. .
100
......................................
&
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
165
TABLE 4 AVAILABLE
JOINT STREN~ffsWITH v)
THREAO —
GRAOE
HEIGHT M!&.
SURfACECASM
16-INCH
1.33
OF
COST Q&l
75
K-55
STC
565
31
84
K-55
STC
650
33
84
N-80
Butt
1427
45
TA3LE 5 AVAILABLE24-INCH C~
CASIfK
THREAO —
X-56
He14ed
171
B
Mel dad
1326
76
171
X-56
Uelded
2122
80
156
JOINT STRENG~slilTH
1.33
COST MM
GRAOE
NEWT f)?lw_.
OF
1932
61
TABLE6 COH61NATI~ ANALYSIS
X~W~T 16- INCH SURFACE CSG -
AREA RATIO 16- INCH/24 -lNCH (%)
xi&T 24-INCH C~~CToR CSG
mm
W
K, STC
21.4
156,
X-56,
M
45.9
32/68
896/1904
N
84 ppf,
K, STC
24.1
156,
X-56,
H
4s.9
34/66
952/1848
N
84 ppf,
N, Butt
24.1
156,
X-56,
U
45.9
34/66
952/1848
Y
84 ppf,
N, Butt
24.1
171,
B, W
50.4
32/68
896f1904
N
84 ppf,
N, Butt
24.1
171,
X-56,
50.4
31/53
896/1904
Y
Load ratio
fs calculated
W
by multiplying
total
TAM OESION-Y
I
COf4BI~T#)N
7S ppf,
NOTE:
I
LOAO RATIO 16- INC~{2~-lNCH rJ)
CSG SIZE 24 16.
GRAOE —.
156 .
64
(2800
k{ ps)
times
araa
7
6ASE0 W CU4PRESSNELWf REflUIRE%ENTS
HEIGHT Qlm
-M!)_
load
___
CONN
HIM. OEPTH m
HOLE ~;l
X-56
tislded
270
30
N-BO
6utt
460
20
162
IN
ratto
percent.
OX?
.
,.
!
CONOUCTOR
●
SURFACE ●
#
:
IMTERMEOIATE
L
TENSILE LOAOSF~M [EXCLUOE LINERS)
ANOBOPEQUl~ENT INNER CASING STRINGS
●
TENSILE LOAD FROM~DUCTIONTUSING
●
TENSILE LOAOFROM STABILIWOVERWLL
.
I
WEIGHT OF%LLHEAD
TENSILE LOADS FROM CHANGES IN EXTERNAL ANO INTERNAL PRESSURES
c TENSILE LOADS FROM CHANGES IN TEMPERATURE
LINER
TUBING
b
3
ONGATION
Pi
ONGATION /
/ —
1
1 1 I
I 8
t I I I I
1 t I 1 1 I I 1: t I t II 1
—
I I I 1
—
I
1
P*—
1
i
I
I I I 1 I
I I 1 t
r
,
I
p’
—
I
I
1 I I I I I I
t
I I
, I I
$ I I 1
—
I
~
T
----r ---
80,000
I 1 1 I I I
,,
1 t t t 1 I t
1 t
I I 1 I I I a I :
A lncr@wo In Intti
I
TENSILE
STRAIN,
INIIN
RowS.
60,000
affwt
m cm
kmdhw.
STRESS ml)
In3torisls. 1ss
STRAIN [lN/IN)
STRAIN (INIINI
COMPRESSION TEST
TESNILE TEST
cOMPRESSIONTEST
Ba=mw
pfa$surn CM csuso att hcrss8a In t-
TEST
_
Figuro4.
CONTRACTION
T
STRESS ml)
PSI
4
1
: .6
1
CONTRACTION
F&!ur@3.
STRESS,
i
Tor@onmd
cwmpm@mtomon8xnwotd
1 A-SECTION
.
A=L
o
BASE PLATE
SURFACE
CASING
L
LO
WEL
ENT
CIONDUCTOR
Figure 6. Surface casing compression
m
f-
pipE
SURFACEyASING
Figure7. Baseplatedistributes load
—---
t
30-INCH CONDUCTOR PIPE
I
//////////////////////////m
LEGEND (H.A1 = (HOOP. AXIALI
#1 (H,AI
HE [H,AI
#7 (H,A1
NUM8ER OF STRINGSflUN
#6 (H,AI #5 iH,Al SECTION A-A
Figure
8. Orimtatbn
of strain gsfps
_6-
..
.sEE
16-INCH CSG
IN 204NCH
LOAD
NOTES:
l) CURVE
lNCLUDES
2) SURFACE CASING ON INCREMENTAL
Figure 10.
.19925
HOLE
CAPACITY (KIPS)
2.OSAFETYFACTOR. CAPACITY
CURVE
IS BASED
LOAD BELOW 270’.
Surface casing capaeitycume.
24-INCH
CSG IN 30-INCH
HOLE
o
h
100
..-..,
200 ~ u-l
a
.——
300”
I 500
o
I
1
1000
—
I
1500
p 2000
LOAD CAPACITY (KIPS)
NOTE:
I
———
1) CURVE INCLUDES
Figure 11.
2.0 SAFETY FACTOR.
Conductor casing capacity curve. 1s8
.
