INTERMEDIATE CASING LOAD DETERMINATION EXERCISE

Instructions

Use the example well data from this document or the powerpoint notes handout to complete the calculations for each of the following. You may write your calculations on the Exercise Template, or use your own graph paper.

When complete, scan or photograph your work and upload it. Post questions to the discussion board.

String Load Phase Case

Intermediate Burst Installation Cementing

Intermediate Burst Installation Plug Bump

Intermediate Burst Install Pressure Test

Intermediate Burst Drilling Severe Gas Kick

Intermediate Collapse Installation Post Plug Bump

Intermediate Collapse Installation Lost Circulation

Intermediate Collapse Installation Cement Placement

The intermediate casing loading is often straight forward like the surface casing, except that the magnitude of the loads is generally greater. In many strings of intermediate casing the maximum pressure from a gas kick is not sufficient to fracture any formation below the shoe and hence the maximum surface pressure will be from a solid column of gas. In addition to that we will look at a procedure that has been used often in cases where the BOP installed at the surface is the weakest link in the pressure control and we must account for it in our casing design.

Our Example Well:

Depth Frm Press Mud Dens Frac Press Kick Marg Temp

Ft Ppg equiv Ppg Ppg equiv Ppg equiv °F

0 8.4 8.5 — — 74

3000 8.7 9.2 12.3 11.8 128

10,500 11.3 11.8 15.7 15.2 263

14,000 14.8 15.3 16.2 15.7 326

Intermediate Casing Data

· Size: 9-5/8

· Depth: 10,500 ft

· Mud Density: 11.8 ppg at 10,500 ft

· Frac Pressure at shoe: 15.7 ppg equiv at 10,500 ft

· Temperature at Surface and Shoe: 74 °F, 263 °F

· Maximum Mud Density and temperature before next casing string: 15.3 ppg, 326 °F

· Cementing Data: o Cement to 500 ft inside surface casing, 500 ft tail slurry at 15.9 ppg, 7500 ft lead slurry

w\50% excess at 14.2 ppg, 1000 ft spacer at 12.0 ppg, displace plug w/11.8 ppg mud, bump plug with 1000 psi above final displacement pressure. (Note this cementing program will prove inadvisable and will be revised in the next section.)

Intermediate Casing, Installation – Collapse Load

There is no collapse situation in the running process unless you consider failure to fill the casing. That is usually negligence or mistake rather than it is a design consideration. In the surface casing design we made the calculation for the empty string in our drilling collapse phase, but we may not do that for this deeper intermediate string so we will do it here.

psi

psi

o o i

10500

p p p 0 0 0

p 0.052(11.8 )(10500 ) 0 6443

Before calculating the post plug bump collapse we will verify our cement hydrostatics, such that the cement pressure is greater than the hydrostatic formation pressure but less than the formation fracture pressure. Here we must be careful because we are considering an open hole and there is no certainty in the height of the cement. We want a minimum column length of 7500 ft, and we have specified 50% excess in the lead slurry to achieve that minimum length and from experience in this area we are comfortable that we can achieve the minimum length using that amount of excess. But for purposes of calculating pressures we do not know how long that column will actually be. The longest it could be is realized if the hole is actually gage size, in other words exactly 9-7/8 in. diameter. If the hole is exactly that diameter then the column will be 1.5(7500) = 11250 ft in length. That means we will have cement all the way to the surface. So we must calculate both the minimum cement pressure and the maximum:

fm(10500)

frac(10500)

min cmt(10500)

max cmt(10500)

fm min c

0.052 11.3 10500 6170 psi

0.052 15.7 10500 8572 psi

0.052 15.9 1000 12.0 7000 12.0 1000 11.8 1500

6739 psi

0.052 15.9 1000 12.0 9500 6755 psi

p

p

p

p

p p mt max cmt frac OKp p

After the plug has bumped and the pressure released the collapse loads are:

0 o i

10500

0 0 0 psi

0.052 15.9 1000 12.0 9500 11.8 10500 312 psi

p p p

p

Notice that we used the worst case of cement pressure because we cannot know ahead of time the actual borehole capacity so we choose the worst case. This concludes our collapse loads for installation.

Figure 5-15 Intermediate casing, collapse, installation, post plug bump

Intermediate Casing, Drilling – Collapse Load

Since this string does not cover any high pressure zones the only drilling collapse loading should occur during a lost circulation event. At and below this shoe the lowest formation pressure is 13.6 ppg equivalent and for the sake of our example we will say that our data are very reliable and we can assume this is the lowest pressure we could have in a lost circulation event so no matter what mud weight we are using the casing should never be empty. The only remote possibility of that happening is a gas blowout that eventually bridges off at the shoe and then bleeds off completely at the surface. That sort of thing has happened, but we will not design for it here. The primary question we have to ask in our design situation is what is the fluid in the hole? In our case the maximum mud density we plan to use in the well is 15.3 ppg and that is what we will assume is in the hole when circulation is lost at the shoe which has a formation pressure equivalent to 11.3 ppg. What is the depth of the top of the 15.3 ppg mud supported by a 13.6 ppg formation?

mud

mud

air

0.052 15.3 0.052 11.3 10500

11.3 105007755 ft

15.310500 7755 2745 ft

h

h

h

The depth of the top of the mud is 10500 – 7755 = 2745 ft air down to that depth and mud inside the casing with a greater density than the mud outside. Not a likely collapse scenario, but for the sake of practice let us make the calculations and see how it looks.

Figure 5-16 Intermediate casing, collapse, drilling, lost circulation

For the fluid outside the casing we will use the mud density in which the casing is run, 11.8 ppg in this case. We could assume that the pressure is more nearly formation pressure over time, but we have no idea when it might reach that value. There is also a possibility of eventual gas migration behind the casing and in that case we might use the formation fracture gradient. However, this casing will be shortly superseded by the

production casing so it should not be of great concern what transpires over a period of months or even years.

0

2745

10500

0

0.052 11.8 2745 0 1684 psi

0.052 11.8 15.3 7755 1684 273 psi

p

p

p

So we see that in this scenario the collapse pressure is a maximum at 2745 ft and less than zero at the shoe which means that the pressure inside the casing at the shoe still exceeds the outside pressure by 273 psi.

Another possibility is that a depleted zone exists below the casing shoe and the possibility of lost circulation is a definite possibility. If we know the depleted pressure of the zone we can proceed as above, however, where we do not have that information we must make some assumptions. This gets us into a gray area where many times we rely on “company policy”. One common approach is to assume the worst we can expect is perhaps a zone that will just balance a column of salt water or even fresh water. Ignoring the consequences of an underground blowout that will probably accompany such an event, we will just concentrate on the collapse possibilities for now.

Another common approach is to assume the casing is empty (as a possibility during the running/installation process we postponed from earlier). For now we will look at both before we make a decision because in some cases the difference in casing selection is not too much different.

Figure 5-17 Intermediate casing, collapse, drilling, lost circulation with water or air inside.

The external fluid in these cases as already explained is usually taken to be the mud density in which the casing was run. It exceeds all the formation pressures that will be cemented behind the pipe.

In the case of fresh water in the pipe:

0

10500

0 psi

0.052 11.8 8.3 10500 1911 psi

p

p

For empty casing:

0

10500

0 psi

0.052 11.8 10500 6442 psi

p

p

We now plot these three possibilities.

Figure 5-18 Intermediate collapse load lines

Intermediate Casing, Installation – Burst Load

In the intermediate casing the installation burst possibilities are the same as in the surface casing. First we look at the possibility of the float plugging or the annulus packing off while the cement is still in the casing and the cementer pumping up to 1000 psi before shutting down. First we need the ratio of column lengths inside to outside.

2 2 2 2bit o

i/o 2 2i

12.25 9.6250.762

8.681

d dk

d

0

2000

4000

6000

8000

10000

12000

0 1000 2000 3000 4000 5000 6000 7000 8000 9000

Dep

th (

ft)

Pressure (psi)

Intermediate Casing Design

Collapse LoadLines

EmptyFresh Water

LC Drlg Mud

Cementing

Next we calculate the lengths of the cement columns inside the casing. Recall also that we are using 50% excess in our lead slurry to assure that we get cement to the surface, so while we used 2700 ft as the column length in the annulus for previous calculations we must account for the excess when it is inside the casing. So let us calculate the lengths of the cement internally.

spac

lead

tail

total

mind

L 0.762(1000 ) 762

L 0.762(1.5 )(7000 ) 8001 ft

L 0.762(1000 ) 762 ft

L 762 8001 762 9075 ft

L 10500 9525 975 ft

Figure 5-19 Intermediate casing burst, installation, cementing, float plugged with cement in casing.

There are two ways to look at this. One case would be that the spacer has reached the shoe and there is 975 feet of displacement fluid in the casing on top of the tail slurry. The other case of 975 ft of mud ahead of the spacer just as the last of the tail slurry is pumped into the pipe gives a greater differential burst pressure near the surface and through the string, although there is not a significant difference. The latter is the case we will use. With the mud ahead, spacer, lead slurry, and tail slurry just into the pipe and 1000 psi additional pressure before the pump can be stopped we have

0

762

8763

9525

10500

1000 0 1000 psi

1000 0.052 15.9 11.8 762 1162 psi

1162 0.052 12.0 11.8 8001 1245 psi

1245 0.052 12.0 11.8 762 1253 psi

1253 0.052 11.8 11.8 975 1253 psi

p

p

p

p

p

Next to consider, there is the differential placement pressure at final cement placement, and there is the plug bump which is identical to the placement pressure with the addition of the bump pressure, so we only need the larger of the two, the bump load.

0 bump max cmt 10500 dspl 10500

9500

10500 bump

1000 0.052 15.9 1000 12.0 9500

0.052 11.8 10500

1312 psi

1312 0.052 11.8 12.0 9500

1213 psi

1000 psi

p p p p

p

p p

Figure 5-20 Intermediate casing burst, installation, plug bump.

Pressure testing the casing after cement has set and before drill out with the same mud used to drill the hole will result in a differential pressure equal to the test pressure. We will use 2500 psi as the test pressure and no calculations are required. After drilling a few feet below the shoe it is usually the case with intermediate casing to perform a shoe integrity test before weighting up the mud and drilling farther. The test pressure

is equivalent to the maximum mud density that will be used in drilling below the shoe. The reason this test is performed before weighting up the mud is so that if it will not hold the pressure, then possible remedial steps can be taken with minimum mud loss. Otherwise if the mud had already been weighted up to 15.3 then a fracture during the test would result in loss of more expensive mud and the mud density would have to be reduced back to 11.8 ppg before taking remedial steps. With a column of 11.8 ppg mud, the surface pressure necessary to test the casing to the equivalent of 15.3 at the shoe is

test psiop 0.052(15.3 11.8 )(10500 ) 1911

Like the casing test pressure this pressure results in the same differential pressure all the way to bottom since we are assuming 11.8 ppg mud in the annulus after cementing. This is less than the test pressure.

Figure 5-21 Intermediate casing burst, installation, test pressure.

Intermediate Casing, Drilling – Burst Load

As we drill below the intermediate casing and begin to increase the mud density, to 15.3 in this case, the differential pressure between the inside and outside of the casing will increase. However, if we assume that behind the casing is still a minimum density of 11.8 ppg then the differential pressure is zero at the surface and increasing to 1911 psi at the shoe as we calculated for the shoe integrity test which is less than what we will encounter in a kick situation. In drilling further below intermediate casing a kick is the most common form of burst loading and in many wells it can be considerable in magnitude. There are three possibilities in order of decreasing severity are

· Gas kick

· Oil kick

· Salt water kick

The worst case is that of a severe kick that results in the casing being full of gas at either a pressure attributable to the zone of the kick or the weakest fracture pressure below the shoe whichever results in the least pressure at the surface. This is exactly the situation we examined at the surface casing though here we have a better fix on the maximum pressure than in the surface casing application because we plan to stop at the producing formation. (In some cases, though, there is a possibility of drilling into higher pressures below the target zone and that must always be considered.) So for our example we can see that the maximum formation pressure of 14.8 ppg occurs at 14,000 ft. The fracture gradient at the 10,500 ft shoe is 15.7 ppg. We now calculate the formation pressure at 14,000 ft and the gas pressure at the intermediate shoe due to the formation pressure.

fm (14000)

gas (10500)

frac (10500)

0.052 14.8 14000 10,774 psi

16 10500 1400010,774exp 10,268 psi

263 3261544 460

2

0.052 15.7 10500 8572 psi

p

p

p

From these calculations we find the formation gas pressure will exceed the fracture pressure at the shoe by about 1700 psi. We will then assume that the formation will fracture at the shoe, gas will enter that formation and that the maximum surface pressure will be determined by the fracture pressure at the shoei. With the fracture pressure at the shoe as the gas pressure at 10,500 ft we can now calculate the gas pressure at the surface.

gas (0)

16 0 105008572exp 7209 psi

74 2631544 460

2

p

We have our top and bottom internal pressures. The outside pressure at the top is zero so it remains to determine the outside pressure at the bottom. What is the fluid outside the casing? Earlier we used the mud in which the casing was run, 14.1 ppg. When our kick occurs it is now several days (or weeks?) later. Perhaps the annular space now has the pressure of the formations. Perhaps in setting the cement gave up free water to form a fresh water channel. We cannot know with any degree of certainty what is behind the casing. Rather than debate this as many individuals and companies continue to do we will select the worst case which is fresh water. Yes, this is a bit inconsistent with what we did with the test pressures and shoe tests, but this one is critical and failure always has disastrous results. So our differential pressures for burst are:

0

10500

7209 0 7209 psi

8572 0.052 8.3 10500 4040 psi

p

p

Figure 5-22 Intermediate casing burst, drilling, gas kick with injection into fracture below shoe.

Oil Burst Load: There are many in the world that never have to worry about gas in casing design because their fields produce oil with little or no gas. Some say they have never even seen an example casing design for oil. So let us use this same example and assume the production is oil rather than gas. Assume an oil gradient instead of gas and assume that the oil in our well is 35 API Gravity at 60° F. First we will determine if the oil pressure from the formation can cause fracture at the shoe. The average temperature of the oil from bottom to surface is 200°F, and that gives us an average API gravity of approximately 46. Then using the API formula relating specific gravity and API gravity

141.5 141.5Specific Gravity =

API Gravity + 131.5 46+131.50.80

We can then convert that to a gradient as follows

psi/ftoilg 0.052(08.0( 8.3 ) 0.345

(Please note that this is all approximate but close enough for casing design.) For a column of oil from 14,000 ft to 10,500 ft the pressure at 10,500 ft would be:

psioil( 10500 )p 10774 0.345(14000 10500 ) 9567

The oil pressure exceeds the shoe fracture pressure so the bottom pressure with oil will also be the shoe fracture pressure, and the pressure differential at the shoe will be the same as with the gas. The surface pressure differential with oil will be:

oil psiop 8572 0.345(10500 ) 4950

We now add this curve to our burst loads plot to see its relation to the previous loads.

Figure 5-25 Intermediate casing burst loads

Note: In Figure 5 - 25, it is only coincidental in this case that the oil burst load and mud load from the maximum load method intersect (almost) at the surface. The two lines are unrelated.

Again, we say that we are not recommending this last design method but to show you how it works and explain why it is used by so many. You can see that it reduces BOP cost and casing cost, but at a higher risk – too high in the opinion of many.

Intermediate Casing, Installation and Drilling – Axial Load

Because we cannot evaluate the axial loading until we make a preliminary burst and collapse design and selection we will have to wait until we do so in the next chapter. Next we will look at the burst and collapse for the production string.

0

2000

4000

6000

8000

10000

12000

0 1000 2000 3000 4000 5000 6000 7000 8000 9000

Dep

th (

ft)

Pressure (psi)

Intermediate Casing Loads

Burst LoadLines

Gas

OIL

Plug Bump

i For potentially high gas flow rates some casing designers will add some amount of pressure to account for friction

pressure loss at the injection point, say 100 to 500 psi depending on the conditions. We will not do that here, but

please be aware of the possibility.