Casing/Tubing design manual october 2005 Chevron

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Figure 2-1 is typical of the plots used to select casing setting depths. In the

figure, the allowable drilling fluid weight range, plotted as density or pressure

gradient, is bounded by both upper and lower values. The upper bound is the

minimum pressure gradient that would cause:

• Fracturing of the formation

• Spalling of the borehole wall

• Efflux of wellbore fluids

For a vertical section of the wellbore, fracturing the formation is the primary

concern. For an inclined section of wellbore, fracturing is still usually the primary

concern; however, in special circumstances, it may be replaced by other

alternatives.

The lower bound of the allowable drilling fluid weight range is the maximum

pressure gradient that would cause:

• Influx of formation fluids (formation pore pressure)

• Shear failure/collapse of the borehole wall

• Differential sticking

For a vertical section of wellbore, the pore pressure gradient, relative to the

density of the wellbore fluid, is the primary concern. For an inclined section of

wellbore, pore pressure is often replaced by mechanical shear failure of the

borehole wall as the factor governing the lower limit of acceptable drilling fluid

density.

Figure 2-1. The Basic Concept behind Casing Seat Selection

Separate tools and procedures exist to aid in computing the bounds listed above

as summarized in Table 2-1.

Table 2-1. Auxiliary Tools for Casing Seat Selection

Equivalent Mud Weight/Pressure Gradient

True Vertical Depth

Surge Pressure +

Safety Margin

Trip Margin +

Safety Margin

Maximum Mud-Weight,

Frac Gradient or Wellbore

Stability

Minimum Mud-Weight,

Pore Pressure or Wellbore Stability

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October 2005

Tool

Availability

Use

Drillworks Predict by

Knowledge System,

Inc.

Windows

Pore pressure and

fracture gradient

prediction

WF-Surge by

Enertech

Windows

Surge pressure

prediction

RMA MS

Windows

Borehole

shear/collapse failure,

spalling, and fracture

For both the upper and lower bounds of wellbore pressure, a safety margin is

added to account for:

• Swab pressure, normally associated with tripping the drill string (trip margin).

• Surge pressure, normally a concern when running the casing string.

• A safety factor to account for, among other things, uncertainties in the pore

pressure and fracture gradient predictions.

Adams and Charrier [1985] suggest 25 to 35 kg/m

(0.2 to 0.3 ppg) as typical

ranges for the swab and surge pressures, and 12.5 to 17.5 kg/m

(0.1 to 0.15

ppg) for the safety margin to be applied to each.

2.2.1 Outline of Procedure

In Figure 2-1, it is conventional to design the casing program starting at the

bottom of the wellbore. Assuming the minimum mud-weight line to be governed

by pore pressure, Point 1 represents a drilling fluid density sufficient to prevent

the entry of formation fluids into the wellbore. From Point 1, a vertical line is

constructed of as great a length as possible. The line from Point 1 to Point 2 is

typical. Such a line corresponds to a drilling fluid weight that is sufficient to

maintain an open wellbore without causing a tensile failure of the formation. To

proceed higher in the hole, it will be necessary to change fluid weight in order to

protect shallower formations from fracture or other high drilling fluid weight failure

modes. It will, therefore, be necessary to set casing at the depth corresponding

to Point 2 to accommodate this density change.

The above procedure is repeated proceeding up the wellbore to the surface. In

this instance, the next fluid weight can be safely used from Point 3 to the surface,

because the mud-weight line upward from Point 3 does not intersect the line

representing tensile failure. If it does, then an additional casing string would be

necessary with the process continuing to the surface.

2.2.2 Adjustments to the Procedure

In addition to the setting depth optimization procedure outlined above, additional

considerations may apply to the following specific tubular string applications:

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2.2.2.1 Differential Sticking

Depleted or otherwise under-pressured zones are conducive to filter-cake

buildup and possible differential sticking of tubulars at the wellbore wall. This can

be particularly important when running the casing string. Adams and Charrier

[1985] suggest 13.8 to 15.9 Mpa (2,000 to 2,300 psi) as a range of differential

pressure between the wellbore and formation that can be tolerated before

differential sticking in a normally pressured zone. For abnormally pressured

zones, the tolerable differential pressure range is 20.7 to 22.8 Mpa (3,000 to

3,300 psi).

2.2.2.2 Formation Constitution

In all instances, the formation opposite the casing shoe should be of sufficient

strength to provide an adequate seal at the lower end of the string. This may

require adjustment of the casing seat to a point slightly deeper than that

determined by the base procedure.

Further, a strongly reactive shale may have to be isolated to provide wellbore

stability apart from (or in conjunction with) considerations of mechanical stability.

Flowing formations, such as salt, may also require special consideration.

2.2.2.3 Government Regulations

It is not uncommon for an additional shallow surface casing string to be set, for

example, for the purpose of isolating freshwater aquifers.

2.2.2.4 Conductor Casing

The setting depth for conductor casing is usually governed by the low fracture

gradient of surface formations, and the tendency of these weaker rocks to wash

out. Often, the depth of the conductor string is determined simply by the

resistance of the soil during the driving operation.

2.2.3 Example Problem

A deep, initially over pressured mature sandstone reservoir (“A-Sand”, 5,775-

6,220 m (18,950 to 20,400 ft.)) has been depleted by primary production. A new

drilling program is being initiated to not only fill in the current reserves, but also to

penetrate deeper sand [(“B-Sand”, 6,280 to 7,165 m (20,600 to 23,000 ft.)]. The

two sandstone formations are separated by a sealing and competent shale.

Further, a limestone marker above the “A-Sand” is known to consistently precede

this upper reservoir by approximately 6 m (20 ft.).

Shallow gravel beds have consistently caused lost circulation problems. These

beds are no deeper than 1,340 m (4,400 ft.). There is also a government

regulation requiring all freshwater sands + 500 ft. to be protected, but this

provision only extends to 915 m (3,000 ft.).

The pore pressure and fracture pressure are tabulated below and displayed

graphically in Figure 2-2. Previous drilling in this area has lead to the following

margins:

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October 2005

• Trip margin (swab) is 24 kg/m

(0.2 ppg)

• Running margin (surge) is 24 kg/m

(0.2 ppg)

• Safety factor (surge and swab) is 12 kg/m

(0.1 ppg)

• Kick margin is 48 kg/m

(0.4 ppg)

2.2.3.1 Pore Pressure Gradients

Table 2-2. Pore Pressures for Example Problem on Casing Seat Selection

Depth m (ft.) Pore Pressure Gradient KPa/m (ppg)

914 (3,000.0) 10.22 (8.70)

3,901 (12,800.0) 10.81 (9.20)

4,023 (13,200.0) 11.16 (9.50)

4,877 (16,000.0) 11.75 (10.00)

4,968 (16,300.0) 18.21 (15.50)

5,776 (18,950.0) 18.21 (15.50)

5,913 (19,400.0) 5.29 (4.50)

6,187 (20,300.0) 5.52 (4.70)

6,248 (20,500.0) 17.67 (15.04)

6,450 (21,160.0) 16.80 (14.30)

6,497 (21,314.0) 16.92 (14.40)

6,706 (22,000.0) 17.63 (15.00)

7,010 (23,000.0) 18.80 (16.00)

2.2.3.2 Fracture Gradients

Table 2-3. Fracture Gradients for Example Problem on Casing Seat Selection

Depth m (ft.) Pore Pressure Gradient KPa/m (ppg)

914 (3,000.0) 14.69 (12.50)

1,341 (4,400.0) 15.86 (13.50)

3,048 (10,000.0) 18.21 (15.50)

4,481 (14,700.0) 19.98 (17.00)

4,938 (16,200.0) 20.56 (17.50)

6,248 (20,500.0) 21.15 (18.00)

6,706 (22,000.0) 21.74 (18.50)

7,010 (23,000.0) 22.33 (19.00)

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0 2 4 6 8 101214161820

Pore Pressure

w/Margins

Fracture Pressure

w/Margins

Pressure Gradient, ppg

Depth, ft

Limestone Marker

Figure 2-2. Example Pore Pressure and Fracture Gradient Plot with Margins In Place

2.2.3.3 Step 1–Plot Upper and Lower Drilling Fluid Limits

with Margins

Figure 2-2 illustrates the lower limit of drilling fluid density based on pore

pressure, and the upper fluid limit based on fracture gradient.

• For simplicity, the wellbore is taken to be vertical and no consideration is

given for wellbore stability. If the wellbore is inclined, then a wellbore stability

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analysis is warranted. Such an analysis is likely to shift the lower bound of

the acceptable drilling fluid range to the right

, decreasing the acceptable

range of drilling fluid densities.

• The pore pressure curve indicates the effect of depleting the A-Sand.

Depleting the A-Sand will also lower the fracture gradient, but the extent to

which the fracture gradient is lowered may be difficult to determine without a

field test.

The combined margin for the lower bound of acceptable drilling fluid density is

the sum of the trip (swab) margin and the safety margin, or 36 kg/m

(0.3 ppg).

The combined margin for the upper bound of acceptable drilling fluid density is

the sum of the kick margin and the safety margin, or 60 kg/m

(0.5 ppg). The

running (surge) margin is covered by the kick margin.

Adjusted design lines, including the effects of margins on the upper and lower

bounds are plotted in Figure 2-2.

2.2.3.4 Step 2–Determine Initial Requirements for

Wellbore Integrity

Starting at the bottom, select the lowest acceptable drilling fluid density.

• Lower drilling fluid weight/wellbore pressure usually increases the rate of

penetration.

• Selecting the lowest fluid density will result in the greatest distance between

successive casing shoes.

In this case, the initial density is 1,955 kg/m

(16.3 ppg). Constructing a vertical

line from well depth as shallow as possible, the kick margin line for fracturing the

formation is intersected at approximately 4,270 m (14,000 ft.). Using 1,955 kg/m

(16.3 ppg) drilling fluid below this depth will endanger shallower formations, so a

casing string run to 4,270 m (14,000 ft.) to isolate shallower zones is in order.

Construct a horizontal line from 4,270 m (14,000 ft.) to find the lowest acceptable

drilling fluid density to drill upper portions of the wellbore. Such a line intersects

the lower acceptable margin at approximately 1,200 kg/m

(10 ppg).

A vertical line from (1,200 kg/m

, 4270 m) ((10 ppg, 14,000 ft.)) will extend to the

surface without intersecting the upper acceptable drilling fluid curve, indicating

the entire upper section of the hole can be drilled with 10-ppg mud.

Ignoring all other considerations, this initial step indicates that only two casing

strings are necessary, one at approximately 4,270 m (14000 ft.) and one at well

depth. The upper portion of the hole could be drilled with 1,200 kg/m

(10 ppg)

drilling fluid and the lower portion of the hole could be drilled with 1,955 kg/m

(16.3 ppg) drilling fluid.

That is, shear failure/collapse of the wellbore wall will occur at wellbore pressures

higher than that needed to simply balance formation pore pressure. This lower bound

constraint, because of rock strength, becomes more likely as the inclination of the

wellbore increases.

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w/Margins

Fracture Pressure

w/Margins

Drilling Fluid

Pressure Gradient, ppg

Depth, ft

Limestone Marker

Diff. Sticking?

Diff. Sticking? Lost Circulation?

Figure 2-3. Example Problem Following the Initial Selection of Casing Seats

2.2.3.5 Step 3–Check for the Possibility of Differential

Sticking

The check for differential sticking is the first of several tests that are applied to

the initial casing points from Step 2. The objective of these tests is to adjust the

draft casing seats to account for effects not covered by wellbore stability and fluid

influx.

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October 2005

Large excursions in the pore pressure plot are likely points to check for the

possibility of differential sticking. One such point in the current analysis is the

transition at approximately 4,880 m (16,000 ft.) to abnormal pressure. At that

depth, the differential pressure under the currently proposed program is 9.81

N/kg x (1,955 to 1,200) kg/m

x 4,880 m = 36.1 Mpa (0.052 psi/ft/ppg x (16.3 - 10

ppg) x 16,000 ft = 5,240 psi), which far exceeds the suggested 13.8 to 15.9 Mpa

(2,000 to 2,300 psi) tolerable range to avoid differential sticking. The implication

is that the normally pressured zones above 4,880 m (16,000 ft.) must be cased

off before increasing the drilling fluid to the densities necessary to drill the lower

portion of the well. The consequences of these results are as follows:

• Casing must be set at or just below 4,880 m (16,000 ft.). Here the casing

seat is set at 4,910 m (16,100 ft.).

• In order to drill to 4,910 m (16,100 ft.), the mud weight above this depth must

be increased. The original selection of 10 ppg could result in the influx of

reservoir fluids below depths of 4,270 m (14,000 ft.).

A similar situation exists in conjunction with the severely depleted A-Sand. Here

we can use the limestone marker as a target casing seat, allowing the drilling

fluid density to be decreased prior to drilling through this reservoir. Based on

Adams and Charrier’s differential sticking criterion, an acceptable upper limit for

drilling fluid density opposite the A-Sand, at an average gradient of 550 kg/m

(4.6 ppg), is 790 to 825 kg/m

(6.6 to 6.9 ppg). This is too low to be practical, but

it does alert us to the fact that sticking could be a problem in this interval.

The “B-Sand” also displays a pressure regression, but a check indicates a

potential differential pressure of 9.81 N/kg x (1,955 to 1,750) kg/m

x 6,450 m =

13.0 Mpa (0.052 psi/ft/ppg x (16.3 to 14.6 ppg) x 21,160 ft = 1,870 psi), which

meets the 13.8 to 15.9 Mpa (2,000-2,300 psi) tolerable range to avoid differential

sticking.

Incorporating the results of this step, a revised casing seat plot is presented in

Figure 2-3. Casing seats are now planned at 4,910 m (16,100 ft.), 5,770 m

(18,930 ft., e.g., the limestone marker), 6,250 m (20,500 ft., e.g., the competent

shale separating the A- and B-Sands) and at well depth.

2.2.3.6 Step 4–Check Formation Constitution

Experience indicates drilling fluid losses in shallow gravel beds above 1,340 m

(4,400 ft.). To avoid continuing problems between above 1,340 m (4,400 ft.) and

the casing seat at 4,910 m (16,100 ft.), a surface casing string is set at 1,340 m

(4,400 ft.) to isolate this trouble zone. Note that setting this string also honors the

government regulation regarding the isolation of shallow freshwater sands.

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October 2005

2.2.4 Final Results

The following table summarizes the casing seats for this example, with a brief

reference to cause.

Table 2-4. Final Casing Seats for Example Problem

Casing Seat m

(ft.)

Purpose Planned

Fluid Density

kg/m

(ppg)

1,340 (4,400) Formation constitution (shallow gravel beds) 1,235 (10.3)

4,910 (16,100) Differential sticking (normal/abnormal

transition)

1,235 (10.3)

5,770 (18,930) Differential sticking (entering depleted sand) 1,895 (15.8)

6,250 (20,500) Entering new sand 1,800 (15.0)

7,160 (23,500) Well depth 1,955 (16.3)

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Pore Pressure

w/Margins

Fracture Pressure

w/Margins

Drilling Fluid

Pressure Gradient, ppg

Depth, ft

Limestone Marker

Figure 2-4. Example Problem Following the Check for Differential Sticking

2.2.5 Sizing Tubulars for a Wellbore

The cardinal rule for sizing tubulars is to work from the inside outward. The first

tubular to be sized should be the production tubing, as optimizing productivity

from the reservoir has serious implications regarding the overall economics of the

well. Production tubing is usually sized by a production or completions engineer

using nodal analysis software. These tools model combined reservoir inflow

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October 2005