Бурение грунтовых зондов, установка энергетических колодцев

When the internal and external loads have been quantified the maximum net radial loading on the casing is determined by quantifying the difference between the internal and external load at all points along the casing. If the net radial loading is outward then the casing is subjected to a burst load. If the net loading is inward then the casing is subjected to a collapse load. The internal and external loads used in the determination of the net load must be operationally compatible i. e. it must be possible for them to co-exist simultaneously.

Axial Load

Tensile Load

The axial load on the casing can be either tensile or compressive, depending on the operating conditions (Figure 16). The axial load on the casing will vary along the length of the casing. The casing is subjected to a wide range of axial loads during installation and subsequent drilling and production. The axial loads which will arise during any particular operation must be computed and added together to determine the total axial load on the casing.

Comnressive Load

Figure 16 Axial Loads on Casing

The sources of axial loads on the casing are a function of a number of variables:

W	the
ф	the
Ao	the
Ai	the
DLS	the
pi	the
As	the
AT	the
5Pi and d5Pe	the
V	the

(a.) Dry weight of Casing (Fwt)

The suspension of a string of casing in a vertical or deviated well will result in an axial load. The total axial load on the casing (the weight of the casing) in air and can be computed from the following:

Fwt = W cos Ф

(b.) Buoyant Force on Casing (Fbuoy)

When submerged in a liquid the casing will be subjected to a compressive axial load. This is generally termed the buoyant force and can be computed from the following:

fbuoy = pe (Ao — Ai) open ended casing

fbuoy = pe Ao — piAi closed ended casing

(c.) Bending stress fbend)

When designing a casing string in a deviated well the bending stresses must be considered. In sections of the hole where there are severe dog-legs (sharp bends) the bending stresses should be checked. The most critical sections are where dog­leg severity exceeds 10° per 100′. The axial load due to bending can be computed from the following:

fbend = 64(DLs) OD (W)

(d.) plug Bumping pressure fplug)

The casing will experience an axial load when the cement plug bumps during the cementation operation. This axial load can be computed from the following:

fplug = psurf Aj

(e.) Overpull when casing stuck fpt)

If the casing becomes stuck when being run in hole it may be necessary to apply an overpull’ on the casing to get it free. This overpull can be added directly to the axial loads on the casing when it became stuck:

fpt = Direct tension

(f.) Effects of Changes in Temperature ftemp)

When the well has started to produce the casing will be subjected to an increase in temperature and will therefore expand. since the casing is restrained at surface in the wellhead and at depth by the hardened cement it will experience a compressive (buckling) load. The axial load generated by an increase in temperature can be computed by the following:

ftemp = -200 (As)(DT)

(g.) Overpull to Overcome Buckling forces (Fop)

When the well has started to produce the casing will be subjected to compressive (buckling) loads due to the increase in temperature and therefore expansion of the casing. Attempts are often made to compensate for these buckling loads by applying an overpull to the casing when the cement in the annulus has hardened. This tensile load (the overpull) is ‘locked into’ the string by using the slip type hanger.. The overpull is added directly to the axial load on the casing when the overpull is applied.

fop = Direct overpull

(h.) Axial force Due to Ballooning (During pressure Testing) fBal)

If the casing is subjected to a pressure test it will tend to ‘balloon’. Since the casing is restrained at surface in the wellhead and at depth by the hardened cement,

this ballooning will result in an axial load on the casing. This axial load can be computed from the following:

fBal = 2v(Ai5pi — Ao5pe)

(i.) Effect of Shock Loading fshock)

Whenever the casing is accelerated or decelerated, being run in hole, it will experience a shock loading. This acceleration and deceleration occurs when setting or unsetting the casing slips or at the end of the stroke when the casing is being reciprocated during cementing operations. This shock loading can be computed from the following:

fshock = 1780 v As

A velocity of 5cm/sec. is generally recommended for the computation of the shock loading.

During installation the total axial load ft is some combination of the loads described above and depend on the operational scenarios. The objective is to determine the maximum axial load on the casing when all of the operational scenarios are considered.

Free Running of Casing: ft = fwt — fbuoy + fbend Running Casing taking account of Shock Loading: ft = fwt — fbuoy + fbend + fshock Stuck Casing

ft = fwt — fbuoy + fbend + Fop Cementing Casing:

ft = fwt — fbuoy + fbend + fplug + fshock When cemented and additional overpull is applied (‘As Cemented Base Case’): ftbase = fwt — fbuoy + fbend + fplug +fpt During Drilling and production the total axial load ft is ft = ftbase +fbal + ftemp Biaxial and Triaxial Loading

It can be demonstrated both theoretically and experimentally that the axial load on a casing can affect the burst and collapse ratings of that casing. This is represented in figure 17. It can be seen that as the tensile load imposed on a tubular increases,
the collapse rating decreases and the burst rating increases. It can also be seen from this diagram that as the compressive loading increases the burst rating decreases and the collapse rating increases. The burst and collapse ratings for casing quoted by the API assume that the casing is experiencing zero axial load. However, since casing strings are very often subjected to a combination of tension and collapse loading simultaneously, the ApI has established a relationship between these loadings

The Ellipse shown in Figure 18 is in fact a 2D representation of a 3D phenomenon. The casing will in reality experience a combination of three loads (Triaxial loading). These are Radial, Axial and Tangential loads (Figure 17). The latter being a resultant of the other two. Triaxial loading and failure of the casing due to the combination of these loads is very uncommon and therefore the computation of the triaxial loads on the casing are not frequently conducted. In the case of casing strings being run in extreme environment (>12,000 psi wells, high H2S) triaxial analysis should be conducted.

Design Factors

The uncertainty associated with the conditions used in the calculation of the external, internal, compressive and tensile loads described above is accommodated by increasing the burst collapse and axial loads by a Design Factor. These factors are applied to increase the actual loading figures to obtain the design loadings. Design factors are determined largely through experience, and are influenced by the consequences of a casing failure. The degree of uncertainty must also be considered (e. g. an exploration well may require higher design factors than a development well), The following ranges of factors are commonly used:

TOC o "1-5" h z Burst design factors 1.0 — 1.33

Collapse design factors 1.0 — 1.125

Tension design factors 1.0 — 2.0

Triaxial Design Factors 1.25

Figure 18 Tri-axial loading ellipse 8.2 Casing Design Rules Base The loading scenarios to be used in the design of the casing string will be dictated by the operating company, on the basis of international and regional experience. These loading scenarios are generally classified on the basis of the casing string classification. The following rules base is presented as a typical example of a casing design rules base.

When the load case has been selected the internal and external loads are calculated on the basis of the rules below. These loads are then plotted on a common axis and the net loading (burst or collapse) is computed. An appropriate casing string can then be selected from the casing tables.

Conductor:

The predominant concern in terms of failure of the conductor casing during installation is collapse of the casing. Whilst running the casing it is highly unlikely that the casing will be subjected to a differential pressure. When conducting the cement job the inside of the casing will generally contain the drilling fluid in which the casing was run into the well. The maximum external load will be due to the borehole-casing annulus being full of cement (assumes cement to surface). If a stab — in stinger cementation job is conducted there is the possibility that the annulus will bridge off during the cementing operation and since this pressure will be isolated from the annulus between the casing and the drillpipe stinger this pressure will not
be experienced on the inside of the casing. Hence, very high collapse loads will be experienced by the casing below the point at which the bridging occurs.

The design scenario to be used for collapse of conductors in this course (and the examinations) is when the casing is fully evacuated due to lost circulation whilst drilling. In this case the casing is empty on the inside and the pore pressure is acting on the outside.

The maximum burst load is experienced if the well is closed in after a gas kick has been experienced. The pressure inside the casing is due to formation pore pressure at the bottom of the well and a colom of gas which extends from the bottom of the well to surface. It is assumed that pore pressure is acting on the outside of the casing.

Note that it would be very unusual to close a well in due to a "shallow" kick below the conductor. It would be more common to allow the influx to flow to surface and divert it away from the rig. This is to avoid the possibility of the formation below the shoe facturing.

Operation Scenario	Load Condition	Internal Load	External Load
Installation — Burst and Collapse Load	1	Running Casing	Mud to Surface	Mud to Surface
2	Conventional Cement Job	Mud to Surface	Cement Colom to surface
3	Stinger Cement Job	Mud to Surface	Cement Colom to Surface
4	Stab-in Cement Job	Mud to Surface	CementColom to surface plus bridging pressures in the annulus
Drilling — Burst Load	5	Burst Loads — Development Well	Pressure due to Full Colom of Gas on Pore Pressure at DSOH Depth	Pore Pressure
6	Burst Load — Exploration Well	Pressure due to Full Colom of Gas on Pore Pressure at DSOH Depth	Pore Pressure
Drilling — Collapse Load	7	Collapse Load — Development Load	Full Evacuation of Casing	Pore Pressure
8	Collapse Load — Exploration Load	Full Evacuation of Casing	Pore Pressure

Table 4 Casing design rules for conductors

Surface Casing:

Once the surface casing has been set a BOP stack will be placed on the wellhead and in the event of a kick the well will be closed in at surface and the kick circulated out of the well. The surface casing must therefore be able to withstand the burst loads which will result from this operation. Some operators will require that the casing be designed to withstand the burst pressures which would result from internal pressures due to full evacuation of the well to gas.

The maximum collapse loads may be experienced during the cement operation or due to lost circulation whilst drilling ahead.

u[4]<?

The design scenario to be used for collapse of surface casing in this course (and the examinations) is when the casing is fully evacuated due to lost circulation whilst drilling. In this case the casing is empty on the inside and the pore pressure is acting on the outside.

The maximum burst load is experienced if the well is closed in after a gas kick has been experienced. The pressure inside the casing is due to formation pore pressure at the bottom of the well and a colom of gas which extends from the bottom of the well to surface. It is assumed that pore pressure is acting on the outside of the casing.

Operation Scenario	Load Condition	Internal Load	External Load
Installation	1	Running Casing	Mud to Surface	Mud to Surface
	2	Conventional Cement Job	Mud to Surface	Cement Colom to surface
	3	Stinger Cement Job	Mud to Surface	Cement Colom to Surface
	4	Stab-in Cement Job	Mud to Surface	Cement Colom to surface plus bridging pressures in the annulus
Drilling — Burst Load	5	Burst Loads — Development Well	Pressure due to Full Colom of Gas on Pore Pressure at DSOH Depth	P ore Pressure
	6	Burst Load — Exploration Well	Pressure due to Full Colom of Gas on Pore Pressure at DSOH Depth	P ore Pressure
Drilling — Collapse Load	7	Collapse Load — Development Load	Full Evacuation of Casing	P ore Pressure
	8	Collapse Load — Exploration Load	Full Evacuation of Casing	P ore Pressure

Table 5 Casing design rules for surface casing Intermediate Casing: The intermediate casing is subjected to similar loads to the surface casing.

The design scenario to be used for collapse of intermediate casing in this course (and the examinations) is when the casing is fully evacuated due to lost circulation whilst drilling. In this case the casing is empty on the inside and the pore pressure is acting on the outside.

The maximum burst load is experienced if the well is closed in after a gas kick has been experienced. The pressure inside the casing is due to formation pore pressure at the bottom of the well and a colom of gas which extends from the bottom of the well to surface. It is assumed that pore pressure is acting on the outside of the casing.

Operation Scenario	Load Condition	Internal Load	External Load
Installation	1	Running Casing	Mud to Surface	Mud to Surface
2	Conventional Cement Job	Mud to Surface	Cement Colom to TOC and Mud/Spacer above TOC
Drilling — Burst Load	3	Burst Loads — Development Well	Pressure due to Full Colom of Gas on Pore Pressure at DSOH Depth	Pore Pressure
4	Burst Load — Exploration Well	Pressure due to Full Colom of Gas on Pore Pressure at DSOH Depth	Pore Pressure
Drilling — Collapse Load	5	Collapse Load — Development Load	Full Evacuation of Casing	Pore Pressure
6	Collapse Load — Exploration Load	Full Evacuation of Casing	Pore Pressure

Table 6 Casing design rules for intermediate casing Production Casing: The design scenarios for burst and collapse or the production casing are based on production operations.

The design scenario to be used for burst of production casing in this course (and the examinations) is when a leak is experienced in the tubing just below the tubing hanger. In this event the pressure at the top of the casing will be the result of the reservoir pressure minus the pressure due to a colom of gas. This pressure will the act on the fluid in the annulus of well and exert a very high internal pressure at the bottom of the casing.

The design scenario to be used for collapse of production casing in this course (and the examinations) is when the annulus between the tubing and casing has been evacuated due to say the use of gaslift.

8.3 Other design considerations

In the previous sections the general approach to casing design has been explained. However, there are special circumstances which cannot be satisfied by this general procedure. When dealing with these cases a careful evaluation must be made and the design procedure modified accordingly. These special circumstances include:

• Casing through salt zones — massive salt formations can flow under temperature and pressure. This will exert extra collapse pressure on the casing and cause it to shear. A collapse load of around 1 psi/ft (overburden stress) should be used for design purposes where such a formation is present.

• Casing through H2S zones — if hydrogen sulphide is present in the formation it may cause casing failures due to hydrogen embrittlement.. L-80 grade casing is specially manufactured for use in H2S zones.

Operation Scenario	Load condition	Internal Load	External Load
Installation		Running Casing	Mud to Surface	Mud to Surface
2	Conventional Cement Job	Mud to Surface	Cement Colom to TOC and Mud/Spacer above TOC
Production — Burst Load	3	Burst Loads — Exploration and Development Well	At Surface: Pressure due to Colom of Gas on formation pressure at Producing Formation and At Top of Packer: Pressure due to Colom of Gas on formation pressure at Producing Formation acting on top of the packer fluid	Pore Pressure
Production — Collapse Load	4	Collapse Load — Exploration and Development Load	Full Evacuation of Casing down to packer	Pore Pressure

Table 7 Casing design rules for production casing

8.4 Summary of Design Process

The design process can be summarised as follows:

1. Select the Casing sizes and setting depths on the basis of: the geological and pore pressure prognosis provided by the geologist and reservoir engineer; and the production tubing requirements on the basis of the anticipated productivity of the formations to be penetrated.

2. Define the operational scenarios to be considered during the design of each of the casing strings. This should include installation, drilling and production (as appropriate) operations.

3. Calculate the burst loading on the particular casing under consideration.

4. Calculate the collapse loading on the particular casing under consideration.

5. Increase the calculated burst and collapse loads by the Design Factor which is appropriate to the casing type and load conditions considered.

6. Select the weight and grade of casing (from manufacturers tables or service company tables) which meets the load conditions calculated above.

7. For the casing chosen, calculate the axial loading on the casing. Apply the design factor for the casing and load conditions considered and check that the pipe body yield strength of the selected casing exceeds the axial design loading. Choose a coupling whose joint strength is greater than the design loading. Select the same type of coupling throughout the entire string.

8. Taking the actual tensile loading from? above determine the reduction in collapse resistance at the top and bottom of the casing.

Several attempts may have to be made before all these loading criteria are satisfied and a final design is produced. When deciding on a final design bear the following points in mind:

• Include only those types of casing which you know are available. In practice only a few weights and grades will be kept in stock.

• Check that the final design meets all requirements and state clearly all design assumptions.

Appendix 1 API Rated Capacity of Casing The API use the following equations to determine the rated capacity of casing: a. Collapse Rating

7′-1

Py = 2YP

2

Yield Strength Collapse (Theoretical)

A

— C

Pp = YP

— B

D

Plastic Collapse (Empirical)

t

F

— G

Pt = YP

D

Transition Collapse (Theoretical)

t

2

D f D— i t I t

2E, p‘=1—7 1 — v2

Plastic Collapse (Theoretical)

where: A = 2.8762 + 0.10679 x 105YP + 0.21301 x 10-10YP2-0.53132 x 10-16 YP3 B = 0.026233 + 0.50609 x 10-6 YP C = -465.93 + 0.030867YP -0.10483 x 10-7YP2-0.36989 x 10-13 YP3

r 3B/A x3

46.95x 106

2+B/A

F

‘ 3B/A 2 + B/A

3B/A 2+B/A

YP

G = FB/A YP = Yield Strength

P = 0.875

b. Internal yield pressure: /2YPt 3

D 2 Pipe Body

v

c. Tensile Rating:

TR = Ys As

d. Effects of Tension on Collapse Strength

Ypa = {^[l — 0.75 (g a/YP |] — 0.5 (g a / YP )YP

e. Triaxial Loading:

The triaxial Load is expressed in terms of the Von Mises Equivalent Stress. This is compared with the Minimum Yield Strength of the Casing.

Surface Casing (20” @ 3000 ft)

Burst Design — Drilling :

Internal Load: Assuming that an influx of gas has occurred and the well is full of gas to surface.

Gas Kick

Pore Pressure at bottom of 171/2” Hole = 9.5 x 0.052 x 6000

= 2964 psi

Pressure at surface = Pressure at Bottom of 171/2” hole — pressure due to colom of

gas

= 2964 — (0.1 x 6000)

= 2364 psi

Pressure at 20” Casing Shoe = 2964 -( 0.1 x 3000)

= 2664 psi

LOT Pressure at 20 “ casing shoe = 13 x 0.052 x 3000

= 2028 psi

The formation at the casing shoe will breakdown at 2028 psi and therefore it will breakdown if the pressure of 2664 psi is applied to it. The maximum pressure inside the surface casing at the shoe will therefore be 2028 psi.

The maximum pressure at surface will be equal to the pressure at the shoe minus a colom of gas to surface:

= 2028 — (0.1 x 3000)

= 1728 psi

External Load: Assuming that the pore pressure is acting at the casing shoe and zero pressure at surface.

= 8.6 x 0.052 x 3000 = 1342 psi = 0 psi

Pore pressure at the casing shoe

Depth	External Load	Internal Load	Net Load	Design load (Load x 1.1)
Surface	0	1728	1728	1901
Casing Shoe (3000 ft)	1342	2028	686	755

External pressure at surface S ummary of Burst Loads

Collapse Design — Drilling

Internal Load: Assuming that the casing is totally evacuated due to losses of drilling fluid

Internal Pressure at surface = 0 psi

Internal Pressure at shoe = 0 psi

External Load: Assuming that the pore pressure is acting at the casing shoe and zero pressure at surface.

Pore pressure at the casing shoe = 8.6 x 0.52 x 3000

= 1342 psi

External pressure at surface = 0 psi

S ummary of Collapse Loads Depth External Load Internal Load Net Load Design load (Load x 1.0) Surface 0 0 0 0 Casing Shoe (3000 ft) 1342 0 1342 1342

intermediate Casing (13 3/8” @ 6000 ft)

Burst Design — Drilling :

Internal Load: Assuming that an influx of gas has occurred and the well is full of gas to surface.

Pore Pressure at bottom of 121/4” Hole

= 11 x 0.052 x 10000 = 5720 psi

Pressure at surface = Pressure at Bottom of 121/4” hole — pressure due to colom of

gas

= 5720 — (0.1 x 10000)

= 4720 psi

Pressure at 13 3/8” Casing Shoe = 5720 — (0.1 x 4000)

= 5320 psi

LOT Pressure at 13 3/8” casing shoe = 16 x 0.052 x 6000

= 4992 psi

The formation at the casing shoe will therefore breakdown when the well is closed in after the gas has flowed to surface. The maximum pressure inside the casing at the shoe will be 4992 psi.

The maximum pressure at surface will be equal to the pressure at the shoe minus a colom of gas to surface:

= 4992 — (0.1 x 6000)

= 4392 psi

External Load: Assuming that the minimum pore pressure is acting at the casing shoe and zero pressure at surface.

Pore pressure at the casing shoe = 8.6 x 0.052 x 6000

= 2684 psi

External pressure at surface = 0 psi

Summary of Burst Loads DEPTH External Load Internal Load Net Load Design Load (Net Load x 1.1) Surface 0 4392 4392 4831 Casing Shoe (6000ft) 2684 4992 2308 2539

Collapse Design — Drilling

Internal Load: Assuming that the casing is totally evacuated due to losses of drilling fluid

Internal Pressure at surface = 0 psi

Internal Pressure at shoe = 0 psi

External Load: Assuming that the maximum pore pressure is acting at the casing shoe and zero pressure at surface.

= 9.5 x 0.052 x 6000 = 2964 psi

Pore pressure at the casing shoe 42

External pressure at surface = 0 psi

Summary of Collapse Loads DEPTH External Load Internal Load Net Load Design Load (Net Load x 1.0) Surface 0 0 0 0 Casing Shoe (6000ft) 2964 0 2964 2964

Production Casing (9 5/8” @ 10000 ft)

Burst Design — Production :

Internal Load: Assuming that a leak occurs in the tubing at surface and that the closed in tubing head pressure (CITHP) is acting on the inside of the top of the casing. This pressure will then act on the colom of packer fluid. The 9 5/8” casing is only exposed to these pressure down to the Top of Liner (TOL). The 7” liner protects the remainder of the casing.

Depth

Max. Pore Pressure at the top of the production zone

= 14 x 0.052 x 11250 = 8190 psi

CITHP (at surface) — Pressure at Top of Perfs — pressure due to colom of gas (0.15 psi/ft)

= 8190 — 0.15x 11250 = 6503 psi

Pressure at Top of Liner = CITHP plus hydrostatic colom of packer fluid

= 6503 + (8.6 x 0.052 x 9500)

= 10751 psi

External Load: Assuming that the minimum pore pressure is acting at the liner depth and zero pressure at surface.

Pore pressure at the Top of Liner = 9.5 x 0.052 x 9500

= 4693 psi

External pressure at surface = 0 psi

Summary of Burst Loads DEPTH External Load Internal Load Net Load Design Load (Net Load x 1.1) Surface 0 6503 6503 7153 TOL (9500ft) 4693 10751 6058 6664

Collapse Design — Drilling

Internal Load: Assuming that the casing is totally evacuated due to gaslifting operations

Internal Pressure at surface = 0 psi

Internal Pressure at Top of Liner (TOL) = 0 psi

External Load: Assuming that the maximum pore pressure is acting on the outside

of the casing at the TOL

Pore pressure at the TOL = 11 x 0.52 x 9500

= 5434 psi

S ummary of Collapse Loads v

Depth	External Load	Internal Load	Net Load	Design load (Load x 1.0)
Surface	0	0	0	0
TOL (9500 ft)	5434	0	5434	5434

C O N T E N T S

1. OILWELL CEMENTS

1.1 Functions of oilwell cement

1.2 Classification of cement powders

1.3 Mixwater Requirements

2. PROPERTIES OF CEMENT

3. CEMENT ADDITIVES

4. PRIMARY CEMENTING 4.1 Downhole cementing equipment 4.2 Surface cementing equipment 4.3 Single Stage Cementing Operation 4.4 Multi — Stage cementing Operation 4.5 Inner string cementing 4.6 Liner cementing 4.7 Recommendations for a good cement job SQUEEZE CEMENTING 5.1 High Pressure Squeeze 5.2 Low pressure squeeze 5.3 Equipment used for squeeze cementing

5.4 Testing the squeeze job

6. CEMENT PLUGS

7. EVALUATION OF CEMENT JOBS

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