SURFACE CASING SELECTION FOR COLLAPSE, BURST AND AXIAL DESIGN FACTOR LOADS EXERCISE Instructions Use the example well data from this document or the powerpoint notes handout to complete the following graphs. Surface Casing Collapse Loads Surface Casing Burst Loads Surface Casing Axial Loads When complete, scan or photograph your work and upload it. Post questions to the discussion board.
Conductor Casing From the previous chapter we determined that our maximum collapse load might be as high as 70 psi and possibly 80 psi. The worst burst load we estimated to be about 150 psi. The lowest grade of 20 in. API line pipe is Schedule 10 grade A with a 0.25 in. wall thickness. It is pressure tested to 600 psi so it is more than adequate for burst. API does not give a collapse rating for line pipe, but we can calculate it from API formulas (in Chap. 7) and it is 94 psi. This gives us a design factor of 1.18 which should be sufficient. But since there is considerable uncertainty in our loading we might opt for a Schedule 20 grade A with a collapse pressure of 320 psi. The lightest API 20 in. casing is 94 lb/ft H40 which has a collapse rating of 520 psi. Surface Casing Collapse and Burst Design We start the surface casing design with the surface casing load curves. Using the curves developed in the previous chapter as an example we will look at the process for selecting the proper weights, grades, and connections necessary for a basic surface casing design. Figure 6-1 Surface casing collapse and burst loads The first thing we must do with our load curves is to include design factors. We mentioned earlier that we would use the following typical design factors for the surface casing:
Load Type Collapse 1.125 Burst 1.125 Tension Design Factors for this Example 1.6 or 100,000 lb After selecting the design factors we incorporate them into the load curves to give us design lines for collapse and burst. Note that we use only the worst case load line for the purpose of design. In the case where more than one line constitutes the worst case load we select a composite design line. Figure 6-2 Surface casing burst design line With the design lines completed we begin to make our casing selections to fit the design. Since there are so many different types of 13 3/8 casing available we will consider that we have an inventory of the following casing available for our use: Table 6-1 Surface Casing Inventory (13-3/8). Wt lb Grade Connection ID In. Collapse Pressure psi Internal Yield psi Joint Strength 1000 lb 54.5 K-55 ST&C 12.615 1130 2730 547 61 K-55 ST&C 12.515 1540 3090 633 68 K-55 ST&C 12.415 1950 3450 718
68 N-80 ST&C 12.347 2670 5380 1040 72 N-80 ST&C 12.347 2670 5380 1040 Surface Casing Collapse Design We could begin with either the burst or collapse design. For many surface casing designs, the collapse is the more critical so we will start with it. We start by plotting the collapse rating of 54.5 lb K55, and seeing that it will not be adequate all the way to bottom we add some alternatives. Figure 6-3 Surface casing initial collapse casing selection We can see that the 54.5 lb K55 can be run to 2100 ft and the 61 lb K55 to 2860 ft and the 68 lb can be run all the way to bottom with no problem in collapse. If we try to go with a minimum design we will have a string with three weights of K55 as follows: Type Casing Interval Section Length 13 3/8 54.5# K55 ST&C 0 2100 ft 2100 ft 13 3/8 61# K55 ST&C 2100 2860 ft 760 ft 13 3/8 68# K55 ST&C 2860 3000 ft 140 ft
Now we have already stated that we want to keep our design simple and that we do not want to run any short sections of pipe. This design has three different types of pipe and one of them is only 140 ft in length. We cannot eliminate the 68 lb pipe unless we relax our design factor. That might be a consideration in some cases, but we are not going to relax our design factor in this example. Another possibility might be to see what a 61 lb N80 section would work since it would have a slightly higher strength that the 61 lb K55. Unfortunately there is no 61 lb N80; the least weight of N80 is 68 lb so there is no real alternative there. It looks at this point like the best choice is to select our string as follows: Type Casing Interval Section Length 13 3/8 54.5# K55 ST&C 0 2100 ft 2100 ft 13 3/8 68# K55 ST&C 2100 3000 ft 900 ft Figure 6-4 Alternate intermediate burst selection Surface Casing Burst Design Now let us see how this string works with our burst design line. As can be seen this selection easily exceeds our burst design requirements, so there is no adjustment needed at this point.
Figure 6-5 Surface casing burst design is exceeded by revised collapse selection Next we consider the axial load. We have not prepared an axial load curve nor design line yet, because the axial load will depend on the weight of the casing string. Surface Casing Axial Load Design We discussed axial loading in the previous chapter and actually did sample calculations. We could not determine the axial load for a particular selection of the various weights in the string. Now that we have made our preliminary selection that meets our collapse and burst design requirements, we will calculate the axial load, calculate our axial design, and then verify whether or not our collapse and burst selection will satisfy the axial design. If it does not, then must make adjustments and again verify that it meets collapse, burst and axial design requirements. The good news is that if we have to increase the tensile strength of the casing string near the top it usually does not require further adjustment for collapse and burst, but we always check to be certain. Let us examine a plot of the axial load of our surface casing string in air (un-buoyed), the true axial load in 9.2 ppg mud, and the effective axial load in 9.2 ppg mud.
Figure 6-6 Surface casing axial loading, un-buoyed, effective, and true This is exactly the same a string used in the example calculation in Chapter 5. Notice the true axial load curve on the left. It is actually in compression at the bottom because of the hydrostatic pressure on the cross-sectional area of the tube at the bottom. Notice also that at 2100 feet the curve shifts slightly. That is due to the difference in cross-sectional area of the 54.5 lb/ft and the 68 lb/ft casing at that point. The tension increases, meaning that the net hydrostatic force is acting downward because the ID of the 68 lb/ft pipe below is smaller than the ID of the 54.5 lb/ft pipe above. Had the heavier pipe been on top, the curve would have shifted in the opposite direction. Another thing to notice about these curves is that the un-buoyed load curve essentially parallels the true load curve. It is much easier to calculate manually since there are no differences in cross-sectional areas and hydrostatic pressures to calculate. That is why in the past many used this as the basis for their design (along with an appropriate design factor). In fact many still do use it, especially when doing manual calculations for calculating the axial load line. For the axial load at node k, at the bottom of each section (just above the change of cross sectional area) the following equation applies. k F pˆ Aˆ p A w L p A A for k 0,1,2,, n1 k 0 0 o 1 i i i i 1 i i1 i1 k At node k, at the top of each section just below the change in cross section (and the top of the string) the following equation applies.
k k ˆ 1 k 0 0 0 1 i i i i1 i i1 i1 Fˆ pˆ A p A w L p A A for k 1,2,, n Note: Mathematically, the convention is that when a summation index (i) is initially greater than the summation limit (k or k -1) then the summation is zero. And in the case when k -1 < 0 then the summation is zero. While the above equations are the same as presented in your textbook, they are intended for a programmable algorithm rather than for manual calculations. We will show the manual procedure in a simpler manner below. True Axial Load Let us see how it works for our surface casing so far selected: Type Casing Interval Section Length 13 3/8 54.5# K55 ST&C 0 2100 ft 2100 ft 13 3/8 68# K55 ST&C 2100 3000 ft 900 ft Here we use the subscripts on the forces as in the above picture where:
F 1 force at the bottom of section 1 F 1 force at the top of section 1 So, for example the force at the top of section 1 is equal to the force at the bottom of section 1 plus the weight of section 1: F F W 1 1 1 To make it easier we will calculate all of the cross sectional areas first. Aˆ ( / 4)(13.375) 140.500 in 0 1 2 2 2 2 2 A ( / 4)(12.415) 121.055 in A ( / 4)(12.615) 124.987 in Then the section weights: W 68(900) 61,200lb W 1 2 2 2 54.5(2100) 114,450lb And the nodal pressures: pˆ 0.052(9.2)(3000) 1435psi 0 p0 0.052(9.2)(3000) 1435psi p 0.052(9.2)(2100) 1005psi 1 We will make a table of the variables that go into the equations first to organize things a bit. Section Number Weight lb/ft Length ft Area in 2 Section Weight lbf Depth at btm of section ft 2 54.5 2100 124.987 114,4500 2100 1005 1 68 900 121.055 61,200 3000 1435 Pressure at btm of section psi Calculate the true axial load at the bottom of each section and at the top of the well using Equation (6.1). Since the fluid inside and outside are the same the pressure at the shoe is the same inside and outside.
Section Depth ft Pressure psi Cross- Sectional Area in 2 True Axial Load lbf 2 (top) 0 0 124.987 151,698 2 (btm) 2,100 1,005 124.987 37,248 1 (top) 2,100 1,005 121.055 33,296 1 (btm) 3,000 1,435 121.055-27,904 Un-buoyed Axial Load Since we said we would also look at the unbuoyed weight, let us go through that calculation quickly. So for our two-section string Effective Axial Load We are not going to use the effective axial load, but we will calculate it one time here just to illustrate it. It is exactly the same calculation as the un-buoyed load above, but with the addition of a buoyancy factor. And the buoyancy factor is given by Here the density of the mud is in lb/gal (ppg) units. We calculate the buoyancy factor of 9.2 ppg mud. Then we use equation to calculate the effective axial loads.
Notice that the total buoyed weight at the surface for the effective axial load and true axial load differ by 639 lb when they should be exactly the same. Recall from our earlier discussion this is partly due to roundoff, but mostly due to using the nominal weight as opposed to the actual weight and not including coupling buoyancy separately. These values are already plotted above in Figure 6-6. Question: Before we leave the effective axial load calculation, suppose the pipe is closed on the bottom and has 8.5 ppg water inside with 9.2 ppg mud still on the outside. Now how do we calculate effective axial load? What is the buoyancy factor in this case? Now that we have shown the three methods of calculating the axial load curve let us proceed with the design of the surface casing string. Axial Load, Installation Running Load When the casing is run in the hole it reaches its greatest axial load when all of the casing is in the hole. We have just calculated that value as the true axial load above. Axial Load, Installation Plug Bump Just before the plug bumps the float collar there is usually a differential pressure between the denser column of cement, spacer, and mud in the annulus than the displacement fluid inside the casing. We calculated that value in the installation burst section of Chapter 5 and added the 1000 psi bump pressure to it, giving 1406 psi pressure at the surface when the plug is bumped. We use that value and the displacement fluid density to calculate the pressure at the depth points where the casing wall thickness changes occur to use in the true axial load formulas above. In our calculation above we assumed zero pressure at the surface and calculated the pressures at those points using the density of the mud in the casing. Everything in the above calculations remain the same except the pressures (internal at the nodes and external at the bottom). Everything else is the same as before so we now calculate the section forces:
We will not repeat those calculations manually but show the results from the spread sheet on your CD shortly. Axial Load, Installation Post Plug Bump After the plug bumps and we verify that the displacement volume is correct we release the bump pressure. The surface pressure is bled to zero and we watch it for a short time to verify that the float is holding. We do not hold pressure on the inside of the casing because we want the cement to set while the casing is in a mode of radial compression. Later as we increase the mud density while drilling deeper the casing is further expanded against the cement maintaining contact and assuring that micro channels do not form between the casing and set cement. Were we to maintain internal pressure in the casing while the cement sets and later release that pressure, the casing would contract more than the cement would expand and a micro annular channel might form between the casing and the cement. We calculate the true axial load just as before except we have the displacement fluid with no added pressure inside the casing to calculate the pressures at the points where the wall thickness changes. The only thing that changes for this case is the internal pressures at the nodes (external pressure at bottom is the same as the plug bump case above. Then we calculate the nodal forces
Next we plot the three axial load cases. Figure 6-7 Surface casing axial loads Notice that the plug bump pressure increases the axial load on larger diameter pipe considerably. We used a bump pressure of 1000 psi here for illustration, but it practice we might consider reducing that to maybe 500 psi above our final displacement pressure. For our axial design we will use the true axial load at plug bump, and we have already stated that we are going to use a design factor of 1.6 and 100,000 lb over pull, whichever is greater.
Figure 6-8 Surface casing axial design In this case the design factor of 1.6 is greater than the 100,000 lb over pull at all points of consequence so we use the design factor line as the design line. When we plot the casing we have already selected to meet the collapse and burst requirements we find that it easily exceeds the tension requirements also. This is fairly typical of many surface strings, but the tensile design should always be checked to be certain. As we have mentioned earlier some regulatory agencies require an un-buoyed axial design and since we have already done the calculations lets plot it and see if our preliminary selection also satisfies that design criterion. We see that it does.
Figure 6-9 Surface casing un-buoyed axial load and selection for comparison Our preliminary selection for collapse and burst still satisfy our axial design criteria. Notice though that the safety factor curve becomes the design line at the top of the string in the un-buoyed case.
Figure 6-10 Surface casing summary Axial Load Compression Our selection at this point accounts for common loading, but does not account for the compressive loads of out intermediate casing, production casing, tubing, and well head which it will eventually support. We will not know those loads until we select the other casing strings, therefore we will return to the surface casing later.