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CHAPTER SIX
SPECIAL SERVICES IN WELL CONTROL
SNUBBING
Snubbing is the process of running or pulling tubing, drillpipe, orother tubulars in the presence of sufficient surface pressure to cause thetubular to be forced out of the hole. That is, in snubbing the force due toformation pressure's acting to eject the tubular exceeds the buoyed weightof the tubular. As illustrated in Figure 6.1, the well force, Fw, is greaterthan the weight of the pipe. The well force, Fw, is a combination of thepressure force, buoyant force, and friction force.
Stripping is similar to snubbing in that the tubular is being run intoor pulled out of the hole under pressure; however, in stripping operationsthe force resulting from the surface pressure is insufficient to overcome theweight of the string and force the tubular out of the hole (Figure 6.2).
Snubbing or stripping operations through rams can be performedat any pressure. Snubbing or stripping operations through a good qualityannular preventer are generally limited to pressures less than 2000 psi.Operations conducted through a stripper rubber or rotating head should belimited to pressures less than 250 psi. Although slower, ram-to-ram is thesafest procedure for conducting operations under pressure.
Some of the more common snubbing applications are as follows:
• Tripping tubulars under pressure• Pressure control/well-killing operations• Fishing, milling, or drilling under pressure• Completion operations under pressure
There are some significant advantages to snubbing operations.Snubbing may be the only option in critical well control operations. In gen-eral, high pressure operations are conducted more safely. For completionoperations, the procedures can be performed without kill fluids, therebyeliminating the potential for formation damage.
There are, however, some disadvantages and risks associated withsnubbing. Usually, the procedures and operations are more complex.Snubbing is also slower than stripping or conventional tripping. Finally,during snubbing operations there is always pressure and usually gas at thesurface.
EQUIPMENT AND PROCEDURES
The Snubbing Stack
There are many acceptable snubbing stack arrangements. The basicsnubbing stack is illustrated in Figure 6.3. As illustrated, the lowermostrams are blind safety rams. Above the blind safety rams are the pipe safetyrams. Above the pipe safety rams is the bottom snubbing ram, followed by aspacer spool and the upper snubbing ram. Since a ram preventer should notbe operated with a pressure differential across the ram, an equalizing loop
Figure 6.1 Snubbing. Figure 6.2 Stripping.
Wp= Nominal pipe weight, Ib/ftWhere:
MUD
MUD
M
U
D
M
U
D
A
I
R M
U
D
AIR
M
U
D
Ps
Ps
Wp
Fw
Fw
Wp
is required to equalize the pressure across the snubbing rams during thesnubbing operation. The pipe safety rams are used only when the snubbingrams become worn and require changing.
When a snubbing ram beginsto leak, the upper safety ram is closedand the pressure above the uppersafety ram is released through thebleed-off line. The snubbing ramis then repaired. The pump-in linecan be used to equalize the pressureacross the safety ram and the snub-bing operation continued. Since allrams hold pressure from below, aninverted ram must be included belowthe stack if the snubbing stack is to betested to pressures greater than wellpressure.
The Snubbing Procedure
The snubbing procedure isillustrated beginning with Figure 6.4.As illustrated in Figure 6.4, whensnubbing into the hole, the tool jointor connection is above the upper-
most snubbing ram, which is closed. Therefore, the well pressure is confinedbelow the upper snubbing ram.
When the tool joint reaches the upper snubbing ram, the lowersnubbing ram and equalizing loop are closed, which confines the wellpressure below the lower snubbing ram. The pressure above the lowersnubbing ram is released through the bleed-offline as shown in Figure 6.5.
After the pressure is released above the lower snubbing ram, theupper snubbing ram is opened, the bleed-offline is closed, and the connec-tion is lowered to a position immediately above the closed lower snubbingram as illustrated in Figure 6.6. The upper snubbing ram is then closedand the equalizing loop is opened, which equalizes the pressure across thelower snubbing ram (Figure 6.7).
Snubbing Ram
Bleed Off Line
Equalizing LoopSpacer Spool
Snubbing Ram
Pump In Line
Safety Pipe Rams
Safety Blind Rams
Figure 6.3 Basic Snubbing Stack.
The lower snubbingram is then opened and the pipeis lowered through the closedupper snubbing ram until thenext connection is immedi-ately above the upper snubbingram. With the next connectionabove the upper snubbing ram,the procedure is repeated.
Snubbing Equipment
If a rig is on the hole,it can be used to snub the pipeinto the hole. The rig-assistedsnubbing equipment is illus-trated in Figure 6.8. With thestationary slips released andthe traveling slips engaged,the traveling block is raisedand the pipe is forced intothe hole. At the bottom of thestroke, the stationary slips areengaged and the traveling slipsare released.
The counterbalanceweights raise the travelingslips as the traveling block islowered. At the top of the
stroke, the traveling slips are engaged, the stationary slips are released,and the procedure is repeated. The conventional snubbing system movesthe pipe. If drilling operations under pressure are required, a power swivelmust be included.
In the absence of a rig, a hydraulic snubbing unit can be used.A hydraulic snubbing unit is illustrated in Figure 6.9. With a hydraulicsnubbing unit, all work is done from the work basket with the hydraulicsystem, replacing the rig. The hydraulic system has the capability tocirculate and rotate for cleaning out or drilling.
Figure 6.4 Snubbing into the Hole.
Theoretical Considerations
As shown in Figure 6.1, snubbing is required when the well force,FW9 exceeds the total weight of the tubular. The snubbing force is equal tothe net upward force as illustrated in Equation 6.1 and Figure 6.1:
(6.1)
Where:
Wp = Nominal weight of the pipe, #/ftL = Length of pipe, feetFf = Friction force, lbfFg = Buoyant force, lbfFwp = Well pressure force, lbf
Figure 6.5 Snubbing into the Hole. Figure 6.6 Snubbing into the Hole.
Where:
Ps = Surface pressure, psiDp = Outside diameter of tubular exposed to Ps, inches
As shown in Equation 6.2, the diameter of the pipe within theseal element must be considered. When running pipe through an annular or
Figure 6.7 Snubbing into the Hole, Figure 6.8 Conventional or RigAssisted Snubbing Unit.
Traveling Block
Counterbalance
Traveling Slips
Stationary Slips
(6.2)
The well pressure force, Fwp, is given by Equation 6.2:
stripper, the outside diameter of the connection is the determining variable.When stripping or snubbing pipe from ram to ram, only the pipe body iscontained within the seal elements; therefore, the outside diameter of thetube will determine the force required to push the pipe into the well. Withdrillpipe, there is a significant difference between the diameter of the pipebody and the tool joint.
Figure 6.9
Hosebasket
Pumpmanifold
Riserspool
Bop Hydraulicequalizingvalves Power
pack
Stationaryslips
Stand pipeStripper
•Traveling slipsRotary table
ControlconsoleWork basket
Gin poleSwivelStabbingvalve
Powertong
Pipeelevator
Example 6.1 illustrates the calculation of the wellhead pressureforce:
Example 6.1
Given:
Surface pressure, Ps = 1500 psi
Work string = 4.5-inch drillpipe
Pipe OD, Dp = 4.5 inches
Connection OD, Dpc = 6.5 inches
Required:The well pressure force when the annular is closed on
1. The tube (Figure 6.10)
2. The connection (Figure 6.11)
Solution:1. When the annular is closed on the tube, the force associated
with the pressure can be determined using Equation 6.2:
Fwp = 0J854D2pPs
Fwp = 0.7854(4.52)(1500)
Fwp = 23,857»/
2. When the annular is closed on a tool joint, the force iscalculated using the diameter of the connection:
FH7? = 0.7854(6.52)(1500)
Fwp = 49,77 5 Ibf
In addition to the pressure area force, the friction force must beconsidered. Friction is that force which is tangent to the surface of contactbetween two bodies and resisting movement. Static friction is the force thatresists the initiation of movement. Kinetic friction is the force resistingmovement when one body is in motion relative to the other. The force
Figure 6.10 Snubbing Drillpipe through the Annular.
required to overcome static friction is always greater than that required tomaintain movement (kinetic friction).
Since friction is a resistance to motion, it acts in the direction oppo-site the pipe movement. Friction acts upward when snubbing or strippinginto a well and downward when snubbing or stripping out of a well. Themagnitude of the force required to overcome friction is a function of theroughness of the surface areas in contact, total surface area, the lubricantbeing used, and the closing force applied to the BOP.
Additional friction or drag may result between the snubbing stringand the wall of the hole. In general, the larger the dogleg severity, inclina-tion, and tension (or compression) in the snubbing string, the greater thefriction due to drag.
In addition to the forces associated with pressure and friction, thebuoyant force affects the snubbing operation. Buoyancy is the force exerted
P5 = 1500 psi
Drillpipe Body OutsideDiameter is 4.5 inches
Figure 6.11 Snubbing the Tool Joint through the Annular.
by a fluid (either gas or liquid) on a body wholly or partly immersed andis equal to the weight of the fluid displaced by the body.
As illustrated in Figure 6.12, the buoyant force, Fg, is given byEquation 6.3:
(6.3)
Where:pm = Mud gradient in annulus, psi/ftPi = Fluid gradient inside pipe, psi/ftDp — Outside diameter of pipe, inchesDt = Inside diameter of pipe, inchesL = Length of pipe below BOP, feetLi = Length of column inside pipe, feet
If the pipe is being snubbed into the hole dry, the density of theair is negligible and the ptDJLi term is negligible. If the inside of the
Drillpipe Tool JointDiameter is 6.5 inches
Ps=1500psi
Figure 6.12 The Buoyant Force.
pipe is full or partially full, the P[D1Li term cannot be ignored. If theannulus is partially filled with gas, the PynD
1L term must be broken into itscomponent parts. If the annulus contains muds of different densities, eachmust be considered. The determination of the buoyant force is illustratedin Example 6.2, and Equation 6.3 becomes
Where:L\ = Column length of fluid having a density gradient pm\L 2 = Column length of fluid having a density gradient pm2L 3 = Column length of fluid having a density gradient pm3Lx = Column length of fluid having a density gradient pmx
M
U
D
M
U
D
MUD
FB
Pm
Example 6.2
Given:
Schematic = Figure 6.12
Mud gradient, pm = 0.624 psi/ft
Length of pipe, L = 2000 feet
Tubular = 41-inch 16.6 #/ft drillpipe
Tubular is dry.Required:
The buoyant force.
Solution:The buoyant force is given by Equation 6.3:
With dry pipe, Equation 6.3 reduces to
In this example, the buoyant force is calculated to be19,849 Wf. The buoyant force acts across the exposed cross-sectional area which is the end of the drillpipe and reduces theeffective weight of the pipe. Without the well pressure force, Fwp,and the friction force, Ff9 the effective weight of the 2000 feet ofdrillpipe would be given by Equation 6.4:
(6.4)
Example 6.3
Given:Example 6.2
Required:Determine the effective weight of the 4\-inch drillpipe.
Solution:The effective weight, Weff, is given by Equation 6.4:
As illustrated in this example, the weight of drillpipe is reducedfrom 33,200 pounds to 13,351 pounds by the buoyant force.
The maximum snubbing or stripping force required occurs whenthe string is first started, provided the pressure remains constant. At thispoint, the weight of the string and the buoyant force are minimal and maygenerally be ignored. Therefore, the maximum snubbing force, Fsnmx, canbe calculated from Equation 6.5:
(6.5)
Where:
Fsnmx = Maximum snubbing force, lbfFwp = Well pressure force, lbfFf = Frictional pressure force, lbf
As additional pipe is run in the hole, the downward force attrib-utable to the buoyed weight of the string increases until it is equal to thewell pressure force, Fwp. This is generally referred to as the balance pointand is the point at which the snubbing string will no longer be forced outof the hole by well pressure. That is, as illustrated in Figure 6.13, at thebalance point the well force, Fw, is exactly equal to the weight of the tubularbeing snubbed into the hole. The length of empty pipe at the balance pointis given by Equation 6.6:
(6.6)
Where:Ltp = Length at balance point, feet
Figure 6.13 Balance Point.
Fsnmx = Maximum snubbing force, lbfWp = Nominal pipe weight, #/ftp = Mud density, ppgDp = Outside diameter of tubular, inches
After the pipe is filled, the net downward force is a positive snub-bing force as given by Equation 6.1.
In a normal snubbing situation, the work string is run to a point justabove the balance point without filling the work string. While snubbing,the well force must be sufficiently greater than the weight of the pipe tocause the slips to grip the pipe firmly. After the pipe is filled, the weightof the pipe should be sufficient to cause the slips to grip the pipe firmly.This practice increases the string weight and reduces the risk of droppingthe work string near the balance point.
MUD
Fw
M
U
D
AIR
M
U
DWpL
Ps
The determination of the balance point is illustrated inExample 6.4:
Example 6.4
Given:4 j -inch 16.6 #/ft drillpipe is to be snubbed ram to ram into awell containing 12-ppg mud with a shut-in wellhead pressure of2500 psi. The friction contributable to the BOP ram is 3000 Ib/.The internal diameter of the drillpipe is 3.826 inches.
Required:1. The maximum snubbing force required.
2. Length of empty pipe to reach the balance point.
3. The net downward force after the pipe is filled at thebalance point.
Solution:1. The maximum snubbing force is given by Equation 6.5:
Combining Equations 6.5 and 6.2:
2. The length of empty pipe at the balance point is given byEquation 6.6:
3. The net force after the pipe is filled is given by Equa-tion 6.1:
Since
The buoyant force, Fg, is given by Equation 6.3:
Therefore,
EQUIPMENT SPECIFICATIONS
In hydraulic snubbing operations, the hoisting power required isproduced by pressure applied to a multi-cylinder hydraulic jack. The jackcylinder is represented in Figure 6.14. Pressure is applied to different sidesof the jack cylinder depending on whether snubbing or stripping is beingdone. During snubbing, the jack cylinders are pressurized on the piston rodside and on the opposite side for lifting or stripping.
Once the effective area of the jack is known, the force required tolift or snub a work string can be calculated using Equations 6.7 and 6.8:
(6.7)
(6.8)
Where:f snub = Snubbing force, Ib/Fufl — Lifting force, lbfDpst = Outside diameter of piston rod in jack cylinder, inches
Lift Pressure
Figure 6.14
Nc = Number of active jack cylindersPhyd = Hydraulic pressure needed on jacks to snub/lift, psi
The determination of the snubbing and lifting force is illustratedin Example 6.5:
Example 6.5
Given:A hydraulic snubbing unit Model 225 with four jack cylin-ders. Each cylinder has a 5-inch diameter bore and a 3.5-inch
PISTON
Cylinder
Snubbing Pressure
Rod
diameter piston rod. The maximum hydraulic pressure is2500 psi.
Required:1. The snubbing force, Fsnub, at the maximum pressure.
2. The lifting force, Fuft, at the maximum pressure.
Solution:1. The snubbing force at 2500 psi is given by Equation 6.7:
2. Calculate the lifting force at 2500 psi using Equation 6.8:
The hydraulic pressure required to snub or lift in the hole can becalculated by rearranging Equation 6.8.
Example 6.6 illustrates the determination of the hydraulic pressurerequired for a specific lifting or snubbing force.
Example 6.6
Given:The same hydraulic snubbing unit as given in Example 6.5.The hydraulic jacks have an effective snubbing area of 40.06 in2
and an effective lifting area of 78.54 in2.
Required:1. The hydraulic jack pressure required to produce a snubbing
force of 50,000 lbs.
2. The hydraulic jack pressure required to produce a liftingforce of 50,000 lbs.
Solution:1. The hydraulic pressure required for snubbing is determined
by rearranging Equation 6.7:
(6.9)
2. The hydraulic pressure required for lifting is determinedby rearranging Equation 6.8:
(6.10)
Table 6.1 is a listing of the dimensions and capacity of snubbingunits normally utilized.
BUCKLING CONSIDERATIONS
After determining the required snubbing force, this force must becompared with the compressive load that the work string can support with-out buckling. Pipe buckling occurs when the compressive force placed onthe work string exceeds the resistance of the pipe to buckling. The smallestforce at which a buckled shape is possible is the critical force. Buckling
occurs first in the maximum unsupported length of the work string, whichis usually in the window area of the snubbing unit if a window guide is notinstalled.
In snubbing operations, buckling must be avoided at all costs. Oncethe pipe buckles, catastrophic failure will certainly follow. When the pipefails, the remainder of the string is usually ejected from the well. The flyingsteel can seriously injure or kill those in the work area. After that, wellshave been known to blow out of control and ignite.
When the work string is subjected to a compressive load, two typesof buckling may occur. Elastic or long-column buckling occurs along themajor axis of the work string. The pipe bows out from the center lineof the wellbore as shown in Figure 6.15a. Inelastic or local-intermediatebuckling occurs along the longitudinal axis of the work string as shown inFigure 6.15b.
Table 6.1Dimensions and Capacities of Snubbing Units
ModelNumber of CylindersCylinder Diameter (in)Piston Rod Diameter (in)Effective Lift Area (in2)Lifting Capacity at3000 psi (lbs)Effective Snub Area (in2)Snubbing Capacity at3000 psi (lbs)Effective RegeneratedLift Area (in2)Regenerated LiftCapacity at 3000 psi (lbs)Block Speed Down (fpm)Block Speed Up (fpm)Bore Through Unit (in)Stroke (in)Rotary Torque (ft-lbs)Jack Weight (lbs)Power Unit Weight (lbs)
15044.03.0
50.27150,796
21.9965,973
28.27
84,810
361281
8116
100058007875
22545.03.5
78.54235,619
40.06120,166
38.48
115,440
280291
11116
280085008750
34046.04.0
113.10339,292
62.83188,496
50.27
150,810
178223
11116
280096008750
60048.06.0
201.06603,186
87.96263,894
113.10
339,300
13711214
1684000
34,00011,000
Figure 6.15
Equations describing critical buckling loads were derived by thegreat mathematician Leonhard Euler in 1757. His original concepts remainvalid. However, in oil field work, these concepts have been expandedsomewhat.
As illustrated in Figure 6.16, the buckling load is a function of theslenderness ratio. In order to determine the type of buckling which mayoccur in the work string, the column slenderness ratio, Src, is comparedto the effective slenderness ratio, Sre, of the work string. If the effec-tive slenderness ratio, Sre, is greater than the column slenderness ratio,
Buckling Load - Function of Slenderness Ratio
Buck
ling
Load
(lbf
)
Slenderness Ratio(Sre)
Figure 6.16
Intermediate Column (Inelastic) andLong Column (Elastic) Buckling
Local (Inelastic) Buckling
A B
Src (Sre > S^)9 elastic or long-column buckling will occur. If the columnslenderness ratio, Src, is greater than the effective slenderness ratio, Src
(Src > Sre), inelastic or local-intermediate buckling will occur. The columnslenderness ratio, Src, divides elastic and inelastic buckling.
The column slenderness ratio, Src, is given by Equation 6.11:
(6.11)
Where:E = Modulus of elasticity, psiFy — Yield strength, psi
The effective slenderness ratio, Sre, is given by the larger result ofEquations 6.12 and 6.13:
(6.12)
(6.13)
Where:
UL = Unsupported length, inchest = Wall thickness, inchesDp = Outside diameter of the tubular, inchesDt = Inside diameter of the tubular, inches
Inelastic column buckling can occur if the effective slendernessratio, Sre, is less than the column slenderness ratio, SrCy and is equal to orless than 250 (Sre < Src). Inelastic column buckling can be either local orintermediate. Whether inelastic buckling is local or intermediate is deter-mined by a comparison of the effective slenderness ratios determined fromEquations 6.12 and 6.13.
If Equation 6.12 results in an effective slenderness ratio less thanthat obtained from Equation 6.13, local buckling occurs. If Equation 6.13results in an effective slenderness ratio less than Equation 6.12 (and alsoless than Src) (Src > SW12 > 5^13)» intermediate-column buckling occurs.
In either situation, a compressive load, which will cause a work string tobuckle, is known as the buckling load, Pbkh and is defined by Equation 6.14:
(6.14)
Sre < Src—Inelastic bucklingSreii < Sre\3—Local bucklingSrc > Sre\2 > Sre\3—Intermediate buckling
Where:
Fy = Yield strength, psiDt = Inside diameter of the tubular, inchesDp = Outside diameter of the tubular, inchesSre — Effective slenderness ratio, dimensionlessSrc = Column slenderness ratio, dimensionless
In inelastic buckling, the buckling load, Pbkh can be increasedby increasing the yield strength, size, and weight of the work string ordecreasing the unsupported section length.
Elastic (long-column) buckling is critical if the effective slender-ness ratio, Sre, is greater than the column slenderness ratio, Src, and theeffective slenderness ratio is equal to or less than 250(SV6, < 250). Whenthese conditions exist, the buckling load, Pbkh is defined by Equation 6.15:
(6.15)
for:Sre > Src and Sre < 250—Long-column buckling
Under this condition, the buckling load, Pbkh can be increased bydecreasing the unsupported section length or increasing the size and weightof the work string. Consider the following examples:
Example 6.7
Given:Work string:
Pipe OD = 2 § inchesr O
Nominal Pipe Weight = 5.95 lb/ft
Pipe Grade = P-105
Unsupported length, UL = 23.5 inches
Modulus elasticity, E = 29 x 106 psi
Yield strength, Fy = 105,000 psi
Outside diameter, Dp = 2.375 inches
Inside diameter, D1- = 1.867 inches
Wall thickness, t = 0.254 inch
Required:The buckling load.
Solution:The column slenderness ratio is given by Equation 6.11:
The effective slenderness ratio, Sre, will be the greater value ascalculated from Equations 6.12 and 6.13.
Equation 6.12:
Therefore, the correct effective slenderness ratio is the greater andis given by Equation 6.12 as 31.12.
Since Sre (31.12) is < Src (73.79) and Sre is < 250, failure will bein the intermediate (inelastic) mode and the buckling load is givenby Equation 6.14:
Consider the following example of a buckling load due to long-column mode failure:
Example 6.8
Given:Work string:
Nominal Pipe OD = 1 inch
Nominal Pipe Weight = 1.801b/ft
Equation 6.13:
Pipe Grade = P-105
Unsupported length, Ui = 36.0 inches
Modulus of elasticity, E — 29 x 106 psi
Yield strength, Fy = 105,000 psi
Outside diameter, Dp = 1.315 inches
Inside diameter, Di = 1.049 inches
Wall thickness, t = 0.133 inch
Required:The buckling load.
Solution:The column slenderness ratio is calculated using Equation 6.11:
The effective slenderness ratio, Sn,, will be the greater value ascalculated from Equations 6.12 and 6.13. Equation 6.12 gives
The greater effective slenderness ratio is given by Equation 6.12and is 85.60.
Since Src (73.79) is < Sre (85.60) and Sre is <250, failure willbe in the long-column mode and Equation 6.15 will be used todetermine the buckling load:
Local inelastic buckling is illustrated by Example 6.9.
Example 6.9
Given:Example 6.8, except that the unsupported length, UL, is 4 inches.
From Example 6.8:
Src = 73.79
SreU = 10.16
Required:The buckling load and mode of failure.
Equation 6.13 gives
Solution:The slenderness ratio is given by Equation 6.12:
Since Sren < Sre\3 < Srey the buckling mode is local inelastic.
The buckling load is given by Equation 6.14:
SPECIAL BUCKLING CONSIDERATIONS:VARIABLE DIAMETERS
In oil field snubbing operations, the most frequently encounteredproblems involve long column buckling. In these situations, the classicalEuler solution is applicable. There are several solutions for the Euler equa-tions depending on the end conditions. The classical approach assumesthat the ends are pinned and free to rotate without any restriction due tofriction. If the ends are fixed and cannot move, the critical load will beapproximately four times that calculated using pinned ends. With one endfixed and the other pinned, the critical load will be approximately twicethat determined with pinned ends. If one end is fixed and the other endcompletely free to move, the critical load will be one half of that calculated
assuming pinned ends. For oil field operations, the assumption of pinnedends is reasonable for most operations. However, field personnel shouldbe aware of the assumptions made and remain alert for changes in theend conditions that could significantly reduce the critical load. It must beremembered that once the critical load for a column is exceeded, fail-ure is imminent and catastrophic. The classic Euler equation for pinnedends is given as Equation 6.16:
(6.16)
Where:Pcr = Critical buckling load, Ib/E = Young's Modulus, 30(1O)6
/ = Moment of inertia, — (DAO - D])
64 V /D0 = Outside diameter, inchesDi = Inside diameter, inchesL = Column length, inches
The previous discussion involved only loading of columns ofconstant dimensions. The problems, which arise when different diam-eters are involved, have not been addressed in oil field operations.The exact solution of the differential equations is very complicated.Timoshenko1 described a numerical solution. Only the methodologywill be presented. For the theoretical aspects, please refer to thereference.
Consider a symmetrical beam as shown in Figure 6.17. Assume aseries of beams are to be snubbed into the hole. To determine the criticalbuckling load, it is assumed that the deflection of the beam can be describedby a sine curve. The critical buckling load is determined pursuant to themethodology presented as Table 6.2.
Consider Example 6.10:
Example 6.10
A series of 4-inch OD blast joints are to be included in a stringof 21-inch tubing and snubbed into the hole. The well head pres-sure is 7500 psi. Using the results developed in Table 6.2 and thefollowing, determine a safe snubbing procedure.
Figure 6,17
Given:Tubing dimensions:
OD = 2.875 inches
ID = 2.323 inches
Moment of inertia = 1.924 inches4
Cross-sectional area = 6.492 inches2
Blast joint dimensions:
OD = 4.000 inches
21 -inch Tubing
4-inch Blast JointOverall Length: 10 feet
Blast Length: 6 feet
Table 6.2Determining Critical Load for Beams with Varying Cross Sections
Delta 1/100PDelta 1/100E12
632
74.15
1010
0.00
0.0039.690.00
9
931
77.50
7.6932.013.977.81
8
859
59.00147.50
9.5922.427.178.23
77
8181.00
8.0314.389.418.61
6
695
95.00
9.434.96
10.858.76
55
100100.00
9.920.00
11.358.81
4
495
95.00
9.434.96
10.858.76
3
381
81.00
8.0314.389.418.61
22
59147.5059.009.59
22.427.178.23
1
131
77.50
7.6932.013.977.81
0
00
0.00
39.690.00
8.52
Column NumberStation NumberY1
Mi/EI
RAverage Slope
YiIY2
*lavg' ^2avg
Therefore, Pcr = 8.52 x El2Jl1.
Assume, l\ = OAl2.
Y\ = 100 x sine (180 x station number/number of stations)/= Mi/El = Y\/A (for members with /i, geometry) = Fi (for members with I2 geometry)Rn = (I/number of stations) x (fn_t + 10/w H- /w+i)/12 - for constant geometryRn = (I/number of stations) x (Ifn + 6/w_i - fn-2)/24 + (I/number of stations)
x (Ifn + 6/w+i - /w+2)/24 for changing geometryFor Column 3 ; i ? 3 =0.1x(7x 147.5 + 6 x 77.6 - 0)/24 + 0.1x (7x59 + 6x81-95)/24
Continued
Table 6.2 (continued)
109876543210Column Number
Average Slope, An = (R0 + R1 +R2 +R3 +R4 + Rs/2) -Rn- Rn-I - Rn-I...For Column 3; A3 = 39.69 - 8.03 - 9.59 - 7.69 = 14.38
F2w = (1/number of stations) x An
2.8752.323
1.926.49
43.5484.79
12.570.40
30,000,00010
750010,00058,689
104,24885,017
39,565.4998,443.52
Pipe 1OD, inchesID, inchesMoment of inertia, inches4
Cross sectional area, in2
Pipe 2OD, inchesID, inchesMoment of inertia, inches4
Cross sectional area, in2
hlhYoung's ModulusLength, feetWell pressure, psiRam friction, Ib/Snub Force, Pipe 1, IbfSnub Force, Pipe 2, Ib/Critical Load, Ib/
Euler Critical Load—2^Euler Critical Load—4 inch
ID = 3.548 inches
Moment of inertia = 4.788 inches4
Cross-sectional area = 12.566 inches2
Young's Modulus = 30,000,000
Unsupported stroke length = 10,000 feet
Ram friction = 10,000 lbf
Solution:
Snubbing force on 2 | , Fsnub ••
Snubbing force on 4-inch, Fsnub
EI2
Critical load, Pcr = 8 . 5 2 —
As a check on the critical load determined by numerical analysis inTable 6.2, the value determined should be between those obtainedusing the classical Euler equation (6.16) to calculate the criticalload for each member.
Critical load for 2g
andCritical load for 4-inch
Therefore, the numerical solution is between the Euler solutions and isreasonable. These calculations indicate the assembly can be safely snubbedinto the hole only if the snubbing rams are closed on the l \ and not onthe 4-inch. If the snubbing rams must be closed on the 4-inch due tospacing problems, the well head pressure must be lowered or the strokelength reduced. If the stroke length cannot be reduced due to spacingproblems, the only solution is to reduce the well head pressure.
FIRE FIGHTING AND CAPPING
Oil well fire fighting is as much an art as a science. Fire fightersfrom the United States are heavily influenced by the tradition and practicesdeveloped by Myron Kinley, the father of oil well fire fighters. Those fromoutside the United States follow the same general procedure, which is toremove the remnants of the rig or other equipment until the fire is burningthrough one orifice straight into the air.
FIRE FIGHTING
The equipment used to remove the rig or other equipment from thefire may differ slightly. The fire fighters trained in the tradition of MyronKinley rely heavily on the Athey Wagon such as illustrated in Figures6.18 and 6.19. The Athey Wagon was originally developed for the pipelineindustry. As shown, it is a boom on a track. The Athey Wagon tongueis attached to a dozer with a winch (Figure 6.20). The Athey Wagon ismaneuvered into position for a particular operation utilizing the dozer.The Athey Wagon boom is about 60 feet long and is raised and loweredby the winch on the dozer, and the end of the Athey Wagon (Figure 6.19)may be changed to adapt to different requirements. For example, the hookshown on the end of the Athey Wagon in Figure 6.19 is routinely used todrag pieces of a melted drilling rig from the fire around the well.
Protecting men and equipment from the heat of an oil well fire isdifficult. As in fighting any fire, water is used to cool the fire and provideprotection from the heat. Oil well fire fighters from the United States useskid-mounted centrifugal pumps such as the one illustrated in Figure 6.21.These pumps are capable of pumping as much as of 4800 gallons (morethan 100 barrels) per minute. At this rate, water supply becomes a criticalfactor. In order to support a full day of operations, pits are constructed with a
Figure 6.19
Figure 6.18
Figure 6.20
Figure 6.21
Figure 6.22
typical capacity of approximately 25,000 barrels. The pumps and monitors(see Figure 6.23) are often connected by hard lines or a combination ofhard lines and fire hoses. Rig up can be time-consuming.
Safety Boss, the Canadian oil well fire fighting company, has per-fected pumping equipment based on specially designed and modified firetrucks. Their fire trucks (Figure 6.22) are equipped with pumps capable ofdelivering water at a maximum rate of 2100 gallons (50 barrels) per minute.In addition, these trucks are capable of delivering a variety of fire retardantchemicals in addition to or in along with the water. Utilizing this equipment,water requirements can be reduced to an available capacity of approxi-mately 3000-4000 barrels. All connections between the fire trucks, thetanks, and the monitors are made with fire hoses, which reduces rig-up time.
Due to their mobility, fire truck response time is significantlyreduced in a localized environment. In Kuwait, for example, this mobileequipment was to the fire fighting effort while the cavalry was to the army.That is, in most cases utilizing mobile equipment, the fire would be out andthe well capped before the skid-mounted equipment could be moved and
Figure 6.23
rigged up. The mobility factor contributed significantly to the fact that theCanadian team fixed approximately 50 percent more wells than the nearestother team. In addition, in Kuwait, the mobile fire fighting equipment didnot require as much support as the skidded equipment.
All equipment such as dozers, trac hoes, front-end loaders, etc.and their operators are required to work near the fire and must be protectedfrom the heat. The hydraulic systems for the equipment are protected by acovering with reflective shielding and insulating material. The personnelare protected with heat shields constructed from reflective metal. Reflectiveprotection for a water monitor is shown in Figure 6.23. In addition, heatshields and staging houses constructed with reflective metal offer personnelrelief from the heat in the proximity of the fire.
Most organizations require that all personnel wear long-sleevedcoveralls made of fire-retardant materials. Around an oil well fire, ordinarycotton coveralls are a hazard. Some utilize more conventional fire fightingprotective clothing such as the bunker suit commonly used by local firedepartments. A fewer number use the perimeter suits, which can be worninto a fire.
In a typical fire fighting operation, the crew will approach the firefrom the same direction as the prevailing wind. The pumps will be spottedapproximately 300 feet from the fire. Water will provide protection asdozers on front-end loaders are used to move the monitor houses towardthe fire. Once the monitor houses are within approximately 50 feet of theburning well, other equipment, such as the Athey Wagon, is brought intothe proximity of the well to remove remnants of the rig and potential re-ignition sources. Work continues until the fire is burning straight in the air.Once the fire is burning straight into the air, the fire can be extinguishedand the well capped. If conditions require, the well can be capped with thefire burning.
EXTINGUISHING THE FIRE
In most instances, the fire is extinguished prior to the cappingoperation. However, in some cases conditions dictate that the fire con-tinue to burn until after the capping operation. For example, environmentalconcerns may dictate that the well be permitted to burn until the wellborefluids can be contained or the flow stopped. Further, in some areas theregulatory agency requires that sour gas wells be ignited and that controloperations be conducted with the well burning.
There are several alternatives commonly utilized to extinguish anoil well fire. Explosives are the most famous and glamorous techniqueused. Myron Kinley's father, Karl, was the first to extinguish an oil wellfire with explosives. In 1913, Mr. Kinley walked up to a well fire nearTaft, California, dropped a dynamite bomb onto the well head and ran.2
The subsequent explosion extinguished a fire that had been burning forseveral months.
Today, generally between 100 and 1000 pounds of dynamite, withthe lower being more common, are packed into a 55-gallon drum. Fire-retarding powders are included in the drum, which is subsequently wrappedwith insulating material. The loaded drum is attached to the end of an AtheyWagon. The water monitors are concentrated on the drum as the AtheyWagon is backed into the fire. With the drum positioned at the base of thefire, the driver and the shooter take cover in the blade of the dozer andthe charge is detonated. The explosion momentarily deprives the fire ofoxygen and, as a result, the fire is extinguished. The water monitors arethen concentrated on the well head in an effort to prevent re-ignition.
In Kuwait, the fires were usually extinguished with water. Severalmonitors were concentrated on the base of the fire. Usually in a matter ofminutes, the fire was cooled below the ignition point.
Safety Boss, the company of Canadian oil well fire fighters, hasrelied upon and perfected the use of fire-retardant chemicals and powders.Custom-designed and -constructed fire-extinguishing equipment is used tospray these chemicals and powders directly on the fire. These techniqueshave proven to be very reliable. In Canada, sour gas fires often have to beextinguished and re-ignited several times during the course of a day—aprocess which would not be possible using explosives or water monitors.
Countries associated with the former Soviet Union utilizedmounted jet engines to literally blow the fire out. Most often, the fire extin-guishing technique included a MIG engine mounted on a flat bed trailer.Water would be sprayed on the fire and the engine engaged. Using onlyone jet engine, the time to extinguish the fire would be extended and oftenexceeded an hour. In the opinion of this writer, one jet engine would notextinguish a large oil well fire. The most impressive wind machine wasdesigned and utilized in Kuwait by the Hungarian fire fighters (see Figure11.19). The Hungarian "Big Wind" used two MIG engines on a tank trac.The crew had the capability to inject water and fire-retardant chemicalsinto the flow stream. The "Big Wind" quickly extinguished the fire in everyinstance in Kuwait. However, it was never used in Kuwait on one of thebigger fires.
CAPPING THE WELL
Once the fire is out, the capping operation begins. The well iscapped on an available flange or on bare pipe, utilizing a capping stack.The capping stack is composed of one or more blind rams on top followedby a flow cross with diverter lines. The configuration of the bottom ofthe capping stack depends upon the configuration of the remaining wellcomponents.
If a flange is available, the bottom of the capping stack below theflow cross will be an adapter flange. A flanged capping stack is illustratedin Figure 6.24. If bare pipe is exposed, the bottom of the capping stackbelow the flow cross will be composed of an inverted pipe ram followedby a slip ram. A capping stack with an inverted pipe ram and a slip ram is
Figure 6.24
depicted in Figure 6.25. The capping stacks are placed on the well with acrane or an Athey Wagon.
In the case of exposed pipe, an alternative to the inverted piperam and slip ram is to install a casing flange. As illustrated in Figure 6.26,an ordinary casing flange is slipped over the exposed tubular. A crane orhydraulic jacks, supported by a wooden foundation composed of shortlengths 4 x 4's, are used to set the slips on the casing head. Concrete isthen poured around the jacks and foundation to the bottom of the casinghead. Once the casing head is set, the excess casing is cut off using apneumatic cutter. A capping stack can then be nippled up on the casingflange.
Another common technique used on bare pipe is to install a weld-on flange on the bottom of the capping stack. The stack is then loweredover and onto the bare pipe. If the fire has been extinguished, the stackis lowered with a crane. If the fire has not been extinguished, the stack isinstalled with an Athey Wagon. With the stack in place, the slip-on flangeis welded to the bare pipe. The flow from the well is far enough above thewelding operation to prevent re-ignition.
Figure 6.26
Figure 6.25
Figure 6.27
In all instances, it is important that the capping stack be larger thanthe wellhead. The larger stack will produce a chimney effect at the cappingpoint. A smaller stack would result in back pressure and flow at the cappingpoint.
In the worst cases, guides are required to bring the capping stackover the flow. If the flow is strong, the stack has to be snubbed onto thewell (Figure 6.27). There is almost always a period of time during cappingwhen visual contact is impossible (Figure 6.28).
Once the stack is landed, the vent lines are connected and the blindram is closed, causing the flow to be vented to a pit which should be at least300 feet from the wellhead. With the well vented, the capping operation iscomplete and the control and killing operation commences.
FREEZING
Freezing is a very useful tool in well control. Invariably, the topball valve in the drill string will be too small to permit the running of a plug.
Figure 6.28
In order to remove the valve with pressure on the drillpipe, the drillpipewould have to be frozen. A wooden box is constructed around the area tobe frozen. Then, a very viscous mixture of bentonite and water is pumpedinto the drillpipe and spotted across the area to be frozen.
Next, the freeze box is filled with dry ice (solid carbon dioxide).Nitrogen should never be used to freeze because it is too cold. The steelbecomes very brittle and may shatter upon impact. Several hours may berequired to obtain a good plug. The rule of thumb is one hour for eachinch in diameter to be frozen. Finally, the pressure is bled from abovethe faulty valve; it is removed and replaced and the plug is permitted tothaw. Almost everything imaginable has been frozen, including valves andblowout preventers.
HOT TAPPING
Hot tapping is another useful tool in well control. Hot tappingconsists of simply flanging or saddling to the object to be tapped and drilling
into the pressure. Almost anything can be hot tapped. For example, aninoperable valve can be hot tapped or a plugged joint of drillpipe can be hottapped and the pressure safely bled to the atmosphere. In other instances, ajoint of drillpipe has been hot tapped and kill fluid injected through the tap.
JET CUTTING
Abrasive jet cutting technology has been used in well control aswell as other industries for many years. However, since the extensiveuse of abrasive jet cutting during the Al-Awda Project (Kuwait), serviceproviders for the well control industry have designed and utilized muchmore sophisticated equipment.
An abrasive jet cutter used in well control is shown in Figure 6.29.These cutters attach to the end of the Athey Wagon. The jet nozzle ispositioned adjacent to the object to be severed using the Athey Wagonattached to a dozer. Frac sand at a concentration of about 2 ppg is transported
Figure 6.29 Jet Cutting. (Courtesy of BJ Services.)
by either water or a mixture of bentonite and water. The mixture is pumpedthrough nozzles at a rate of approximately 2 bpm and a pressure between5000 psi and 8000 psi. The nozzle size normally used is approximately
16 i n c h 'Just as often, a jet nozzle is attached to the end of a joint of pipe
and the assembly is moved into position by a crane or trac hoe. Cuttingcan be just as effective. The big advantage is mobility and availability.It is not necessary to import a large piece of equipment. The nozzles can betransported in a briefcase and the remaining required equipment is readilyavailable.
This technology has been used to cut drillpipe, drill collars, casingstrings, and well heads. The time required to make the cut depends on theobject to be cut and the operating conditions. A single piece of pipe can becut in a few minutes. Abrasive jet cutting is preferable to other methods inmost instances.
References
1. Timoshenko, S., Theory of Elastic Stability, McGraw-Hill, 1936.
2. Kinley, J.D. and Whitworth, E. A., Call Kinley: Adventures of an OilWell Fire Fighter, Cock a Hoop Publishers, 1996, p. 18.
3. Ibid.
