Stuck Pipe Mechanisms

O.C.T.G. Procter Consultancy Ltd

Stuckpipe Mechanism Book

NS-10

Written by O.C.T.G. Procter Consultancy Ltd 21 Rubislaw Terrace Aberdeen AB10 1XE Scotland http://www.octgprocter.com Copyright Notice © 2000, O.T.C.G. Procter Consultancy Limited No part of this document shall be reporduced in any materials (including photocopying or storing it by electronic means) without the prior written permission of O.T.C.G Procter Consultancy Limited, except as permitted by then Copyright, Design and Patents Act 1988.

Contents 1 Sticking Mechanisms ..................................................................... 1 1.1 Helpful Definitions ....................................................................... 2 1.2 Poor hole cleaning ...................................................................... 6 1.3 Barite Sag ................................................................................. 10 1.4 Hole collapse ............................................................................. 12 1.5 Unconsolidated formation/boulders ........................................... 14 1.6 Fractured rock ........................................................................... 15 2.0 Differential Sticking .................................................................... 16 2.1 Wire line Differential Sticking Issues ......................................... 19 2.2 Casing/Liner Differential Sticking Issues ................................... 20 2.3 Coil Tubing Drilling Differential Sticking Issues ......................... 23 3. Geometry - String / Hole incompatibility ...................................... 24 3.1 Dogleg & Stiff Assembly ............................................................ 24 3.2 Ledges ...................................................................................... 25 3.3 Undergauge Hole in Salt ........................................................... 26 3.4 Key-seat .................................................................................... 26 4 Junk .............................................................................................. 27 4.1 Metal Junk ................................................................................. 27 4.2 Cement Chunks ........................................................................ 28 4.3 Losses ....................................................................................... 29 4.3.1 Natural losses ........................................................................ 29 4.3.2 Induced losses - formation fracture pressure exceeded ........ 30 5. Available tools used to observe stuckpipe & tight hole ............... 31 5.1 Paper BHA Model ..................................................................... 31 5.2 Drag Charts ............................................................................... 32 5.3 Doglegs Severity v Depth Chart ................................................ 33 5.4 Cuttings Monitoring Systems ..................................................... 33 6. Coiled tubing drilling for the rotary driller. .................................... 38 6.1 What is coil tubing. .................................................................... 38 6.2 Hole Cleaning with coil tubing ................................................... 40 Appendix 1 ...................................................................................... 42

Stuck Pipe Mechanism

1

Sticking Mechanisms

This Chapter discusses the mechanisms by which the drill string (including coil tubing, casing, liner and wire line logging tools in open hole) can become stuck. Stuck! What does this mean? The Shell Expro ABC of Stuck Pipe (Ref 1) defines stuck as : the situation in which a sticking mechanism prevents movement of the string. Similarly a sticking mechanism is . the condition that causes force to be transferred between the wellbore and the string. The Stuck Pipe Plus Team divided sticking mechanisms into the categories shown below: StickingMechanism Mechanism Sticking Differential Differential Sticking Sticking

Solids Solids

PoorHole Hole Poor Cleaning Cleaning

Junk Junk

Geometry Geometry

Hole/String Hole/String Incompatibility Incompatibility

HoleCollapse Collapse Hole

Losses Losses

KeySeat Seat Key

CermentChunks Chunks Cerment Metal Metal

ST0001.FH8

StaticSolids SolidsBed Bed Static DynamicSolids Solids Dynamic Bed Bed BariteSag Sag Barite

CavingShale Shale Caving Unconsolidated Unconsolidated Formation/Boulders Boulders Formation/ FracturedRock Rock Fractured

Dogleg Dogleg StiffAssembly Assembly Stiff Ledge Ledge Undercut Lowside Undercut Lowside

Fig. 1 - Sticking Mechanisms Hierarchy

1

Induced Induced Natural Natural


1.1 Helpful Definitions

Fig. 2 - Sandstone viewed under a microscope

Porosity

Figure 2 shows a thin section of sandstone that has been impregnated with blue stained resin and ground flat. The blue shaded gaps in between the particles of sandstone shown here are called pores. When a formation has pore spaces it is said to have porosity.

Permeability

When the pore spaces are interconnected, fluid can flow through the formation and the formation is said to have permeability.

Formation pressure

The pressure of the fluids that exist in the pore spaces of a formation is called the formation pressure.

Fluid loss

When a formation with permeability is exposed to a wellbore fluid, with a higher pressure than the formation!, the filtrate from the mud system may flow into the formation. This increases the formation pressure. If the differ2


ential pressure is excessive, mud may be lost to the formation due to fracturing.

Filter cake

When a wellbore fluid flows into the formation, the solids from the fluid remain on the surface of the formation as they are too large to enter the pores. This layer of solids is referred to as the filter cake. The properties of the filter

Fig. 3 - A thinsection of sandstone viewed under a microsocope

cake are dependent upon the chemical content and solid content of the mud system as well as the overbalance. A thin impermeable and tough filter cake is desired. This minimises fluid loss to the formation and will minimise the risk of the string becoming stuck (contact area). Figure 3 shows a thin section of sandstone that has had drilling fluid passed through it under pressure. The white speckled area at the top is the resin used to set the sandstone before cutting it into thin layers. The dark area below it is the filter cake. As can be seen the filter cake has formed on the surface of the sandstone and has not entered further than the outer pores of the rock. The blue resin used to show porosity can be seen filling the pore spaces. 3


Overbalance

The overbalance is the difference between hydrostatic pressure of the mud column and the formation pressure. In most drilling operations overbalance is maintained to prevent formation fluid entering the wellbore (a kick!). For thick formations the overbalance can vary considerably with depth. In wells where depleted reservoirs exist the overbalance can be over 3000psi in one formation and as low as 200psi in the adjacent formations.

1.2 Poor hole cleaning

It is strongly recommended to read the ABC of Stuck Pipe - Supplement 2, Hole cleaning (Ref 5). The results of industry experiments using flow loops show that hole cleaning difficulty peaks between 45 and 60 degrees. This is because the solids bed is unstable and may slide down the hole. Above 60 - 65 degrees the solids bed becomes stable and hole cleaning becomes more predictable if not slightly easier. Figure 4 shows the mud characteristics that would give the best hole cleaning for each range of angles as well as showing hole cleaning difficulty vs hole angle. Often choices are compromised by ECD limitations. This causes us to look at hole cleaning in three phases, low angle (0 - 30 degrees), deviated with dynamic solids bed (40 - 65 degrees) and deviated with static solids bed (65 - 90 degrees). Wells with greater inclinations than 90 degrees will be covered later, in the 21st century!

Static Solids Bed

The string becomes stuck in a static solids bed which has built up on the low side of the hole. The solids bed will have formed due to a combination of low annular velocity, inappropriate mud properties and insufficient rotation and circulation to clean the hole (for example during motor drilling and coil tubing drilling). Sticking of a drill string in a static solids bed most often occurs in the 65-90 degrees section while pulling out of hole after drilling. It can occur whether in open hole or in casing. Although the assembly may be pulled out of the hole, leaving an unclean hole does not mean the subsequent casing will be easily run in.

4

Stuck Pipe Mechanism Thin M ud

Thick M ud

T hin M ud

H ole C leaning D ifficulty

0

15

30

45

55

60

75

90

H ole Inclination

Fig. 4 - Hole Cleaning difficulty variation with inclination

Design team prevention points

Optimise the well trajectory design to reduce the risk of hole cleaning problems. (Run cutxport or other hole cleaning computer model.) Plan the correct mud gradient to prevent hole collapse. Stress the 30k o/p rule in the well programme. Do not plan to backream out, only use Fig. 5 - Solids settling in an incline backreaming as a last resort unless recent local experience suggests differently. Plan to use a PWD sub (Pressure While Drilling) if long oriented drilling sections are expected.

Dynamic Solids Bed

The string becomes stuck in a solids bed which is moving down on the low side of the hole. This is called avalanching1 and it can occur somewhere in the well between 40 - 60 degrees both when the pumps are off as well as while circulating. It can occur when the string is moving or is stationary. The Video footage in the stuck pipe course illustrates avalanching and the topic is explained in the Shell Expro Booklet - ABC of Hole Cleaning, page 27. Anyone who has seen television pictures of a snow avalanche will know that avalanches can move very quickly. The same mechanism is involved in a solids avalanche in a wellbore. 1

5


Even with appropriate mud properties and high annular velocities avalanching may still occur. When it does, the effect can be quite dramatic, with stuck pipe occurring rapidly after the pumps are shut off. Solids that avalanche down the hole settle out somewhere in the well between 55 and 65 degrees, creating a static solids bed. This may be in open hole or in casing depending on the well design.


Minimise 40 - 60 degree section length in larger hole sizes, e.g. 17.5. If AVs are likely to be lower than 150 ft/min due to high pressure losses, consider using larger DP which will allow higher flowrates to be used. Consult stuck pipe offset data as this sticking mechanism is not formation specific. Plan in to the well programme adequate time for circulation prior to trips out of the hole. Plan for the use of hole cleaning pills (size, composition).

Rig Team prevention points for both static and dynamic solids beds Pooh

The highest risk of a stuck pipe incident due to solids beds is during pulling out of the hole. Beware of increasing drag, plot drag charts at all times so you will know when the drag is increasing. NB. Drag may be increasing even though the measured weight is decreasing. Do not initially apply more than 30k lbs overpull [ABC of Hole Cleaning Page 40] while pulling out of hole. If 30k lbs overpull is reached go back FL down one single or one stand and cirUID SF LO W culate the hole clean. If no improvement is observed after resuming tripping, increase the overpull limit with SO LID S caution. If the rig team suspect the existence of a cuttings bed when pulling out of Fig. 6 - Avalanching Solids the hole at section TD, then a wiper trip should be made to prevent stuck or mis-run casing. Exercise care when running in to an unclean hole or where solids are present. Subsequent packing off when attempting to start circulation can induce 6


losses. This induced loss zone will lead to lower maximum pump rates and hence poorer hole cleaning.

Circulating

Use full drilling flow rates to circulate the hole clean when required. Use rotation, reciprocation and circulation to clean the hole. Circulate solids bottoms up, not just fluid bottoms up, this can be 2 - 4 times longer. Slow rotation, below 80 rpm, will not have a significant hole cleaning effect. A rotational speed of 120 RPM is desirable for 5 drill pipe (see table below). Concerns about the maximum rotational speed for a motor with a bent housing (fatigue concerns) should be discussed with the motor supplier. Hole cleaning pills can be used in conjunction with rotation and reciprocation to clean the hole. (e.g, a viscous pill in near vertical wells). Circulate pills out of the well before reducing flowrate.

Monitoring

Monitor the volume flowrate of cutting over the shakers - using the minutes per mud bucket full method - to establish effectiveness of the hole cleaning methods you are using. Remember, the same methods may not be the most effective on the next well! Monitor ECDs (with PWD sub) for indications of a cuttings bed build up. When tripping out of the hole asses the likely areas for cuttings beds to be encountered and have a plan in place for removing them. Mud properties play an important part in preventing this sticking mechanism, ensure they are within the specified ranges by having the mud engineer plot a daily chart of values and acceptable ranges for the important parameters. D P Siz e R PM

3.5

5

5.5

6.675

60

55

79

86

105

80

73

105

115

140

100

92

131

144

175

120

110

157

173

210

140

128

183

202

245

160

147

209

230

280

Results - surface contact speed of drill pipe in ft per minutes for given RPM. 7


1.3 Barite Sag

This topic is not covered in the ABC of Hole Cleaning.

Definition

Sag is the settling of solids to form a bed of weighting material on the low side of an inclined wellbore. As with a normal cuttings bed, this bed can slide or avalanche downwards. Sag is characterised by variations in mud weight during the first bottoms-up circulation after an extended, circulation free period. Light weight mud is followed by heavy mud, followed by mud of original weight. Mud weight differences as large as 330 pptf have been recorded in the field. Although sag is associated with a lack of circulation, it is basically a dynamic settling problem. The barite (or other weighting agent) bed is formed while the mud is circulated, especially at low to moderate flow rates. Additional settling and most of the avalanching occurs during periods when the mud is static. Some estimates put the contribution from dynamic settling at four times the static settling rate. Weight variations are usually not apparent during normal circulation because the mud system tends to reach an equilibrium. This masks the formation of a barite bed. The thickness of the bed is a function of the fluid velocity, low velocities result in thicker accumulations. Beds rarely form when flow is turbulent. The higher the density of the weighting agent, the greater tendency to form a bed. As with a normal cutting bed, barite beds have the greatest tendency to avalanche at an inclination between 40 and 50 degrees.

Consequences of Barite Sag

Sag can have a dramatic impact on drilling, cementing and completion operations. It has been associated with incidences of stuck pipe, packing-off, lost circulation and the failure to run logging tools to td. It can also lead to well control problems.

Operational Factors

The physics of barite sag is such that even muds with ideal properties cannot fully suspend barite under all conditions. For example, weighted muds circulated at low flow rates for extended periods usually form barite beds regard8


less of the mud properties. Therefore, sag is not solely a mud problem. Failure to use proper drilling practices can easily outweigh the mud factor. Annular velocity is a key parameter in minimising sag. High annular velocities provide energy to minimise bed deposition and help remove existing beds. Even short lapses in velocity levels, however, may induce bed formation that cannot be prevented from avalanching. Drill pipe rotation and reciprocation enhance the benefits of high annular velocity Hanson et al (Ref 18) have proposed a number of guidelines to help minimise sag in the field. These include: Monitor mud weight and viscosity every five minutes during the first circulation after trips. Maintain annular velocities as high as possible for well conditions. Avoid excessive mud circulation at low flow rates, especially if the pipe is not rotating. Stage to bottom on trips, and circulate bottoms up at each point to reduce the length of heavy mud column in the annulus. In addition, the mud properties should be carefully controlled: Do not thin the mud excessively prior to running and cementing casing. Avoid overtreatment and excessive dilution.

The Yz Factor

A low shear rheometer is a useful tool in measuring the likelihood of a mud system sagging and correlation between laboratory measurements and field conditions have been good to date. However, such equipment is not suitable for use offshore. Until this equipment is available the Yz factor, calculated as twice the 3 RPM reading minus the 6 RPM reading, can be used as a crude indicator of low shear rheology. Maintaining the mud system based on Yz values rather than yield point is strongly recommended where sag potential is high. (Ref 19,20 & 21). A well is considered high risk if: The inclination is between 60 - 75 degrees The mud weight is high (greater than 600 pptf) The mud contains Barite or a similar particle weighting material Low shear operation will take place (logging, SCRs, running liner). 9


The minimum value of the Yz factor necessary to prevent sag will be dependent on mud density and hole angle but a value of 10 or greater will normally be sufficient, even in deviated 12 ¼ hole sections. Slightly lower numbers are acceptable in 8 ½ hole. As with many mud properties, trends are often more important than absolute values and a decreasing trend in Yz values should be taken as a strong indication of increasing sag potential. In such cases, it is important that remedial measures are taken quickly. The preferred method of treatment is normally the addition of sheared premix if available, or organophilic clay if not.

1.4 Hole collapse Caving Shale

It is strongly recommended to read the ABC of Stuck Pipe, Supplement 1 Borehole stability in shales. Approximately 70% of the footage drilled in Shell Expro is through shales. Experience shows that shales can be problematic to drill. Typical, but not exclusive, signs of hole collapse in shales are:

Cavings over the shakers, Overpulls when tripping out of hole, String holds up when running in hole, Sudden pack-off when starting circulation. An accidental sidetrack when washing or reaming past an apparent obstruction.

Causes of hole collapse (1) Insufficient mud weight

Shales are generally the weakest formations encountered during drilling. They need more support from the mud column to keep the hole open than most sandstones and limestones. This can be achieved by using a sufficiently high mud weight. Mud weight selection for shales should be based on offset experience and wellbore stability charts. (2) Hydration

Shales are water sensitive, i.e. they hydrate and slowly disperse in water. That is why shales are said to be reactive. The reactiveness of a shale can be quantified by measuring its surface area. When drilling with a water based mud system KCl needs to be added to the mud to prevent hydration of the shales around the borehore wall. Polymers need to be added to the mud to 10


prevent hydration of the cuttings while they are transported out of the hole. An insufficient KCl concentration will cause a gradual deterioration of the hole condition. When drilling with an oil based mud system, the water phase salinity needs to be kept at a sufficiently high level to prevent hydration. (3) Pore pressure penetration

Shales are water bearing with typical permeabilities ranging from 1 to 100 nDarcy (sand is in the 0.01 - 1D or 10 million times higher). When drilling with a water based mud system, pressure communication exists between the water in the wellbore and the water in the pores of the shale. Since nearly all drilling is overbalanced, the pore pressure will increase with time, thereby weakening the shale. Silicates or polyglycols need to be added to the mud to seal off the pore throats and prevent pore pressure penetration.

Pressure Surges

Starting the pumps slowly and keeping a careful watch on the pressure gauges will prevent pressure shock loading of the formation. Use of PWD subs significantly increases the information available to the driller on down hole pressures and ECD (Ref 3 - page 31). Specialist models exist for calculating mud weights required to prevent failure of the borehole wall (the socalled collapse gradients) of shales at different depths. These models use shale strength and in-situ (i.e. Fig. 7 - Wellbore Collapse downhole) stresses as input parameters. Shale strength is calculated from correlations with surface area (measured on cuttings) and sonic transit times (from petrophysical logs). The overburden stress is calculated from a density log and the minimum horizontal stress is estimated from leak-off charts. The collapse gradients are usually presented graphically versus vertical depth in a wellbore stability chart. Wellbore stability charts are available for almost all fields operated by Shell Expro. See Fig 35 for a typical example. 11


Usually, a number of collapse gradient lines are shown for different hole angles (i.e. inclination). The collapse gradient at an intermediate angle may be estimated by interpolating between the two nearest collapse gradient lines. Pore pressure and fracture gradient estimates are presented because they give a good indication of the margins for mud weight selection. The fracture gradients shown in the chart are only valid for low-permeable formations, i.e. not for sandstones. Collapse gradients can be related to actual formations by means of the lithology column on the right hand side of a wellbore stability chart. In the North Sea the overburden stress is greater than the maximum horizontal stress, causing the collapse gradient to increase with increasing inclination. In other words, for a shale at a particular depth the mud weight required to prevent failure is lowest for a vertical and highest for a horizontal hole.

1.5 Unconsolidated formation/boulders

Shallow formations can often be unconsolidated or contain boulders. Unconsolidated formations contain loosely packed particles, from sand to pebble size. The risk of the formation collapsing around the BHA is high, a similar situation to what would happen if you dug a hole in a beach, but often as the formation is loose sand the effect is only a temporary increase in pump pressure. Boulders occur at shallow depth and more frequently near to the coast. Drilling in a boulder area can cause high vibration levels or an accidental sidetracks as well as stuck pipe. A standard procedure is often adopted for top hole sections: If drilled with sea water pump viscous pills prior to connections, at TD sweep hole clean and POOH displacing to Bentonite/CMC. If overpulls are experienced run a wiper trip and redisplace to Bentonite/ CMC. Fig. 7 - Unconsolidated Formation

12



Unconsolidated formations are present under the Tern platform (consult Tern engineer for most up to date example procedures). Consider leaving out large string stabilisers, i.e., larger than 17 ½ A seabed survey can sometimes help identify the characteristics of shallow formations.

Rig Team prevention points

During drilling of an unconsolidated formation and packing off problems are experienced, drill 30ft then pull back 30ft and wait a couple of minutes before proceeding to drill. This allows the formation to collapse in on an empty hole, not on the BHA (as used on the Tern platform). If a riser is in use a riser booster will improve hole cleaning.

1.6 Fractured rock

Natural fractures can occur in all types of rock, most often in Limestone, chalk and cemented sandstones, near faults and in areas where there has been geological activity, e.g, near a salt dome. The presence of these fractures is often difficult to predict. Although drilling through natural fractures leads to lost circulation, the string can become stuck when the fractured rock collapses around the string. Induced fractures are caused by drill string vibration (Ref 4) or by pressure surges (Ref 3). This mechanism also often leads to losses.


Consult offset data for indications of natural fractures. Consider casing off troublesome zones as soon as possible.

Fig. 8 - Natural Fractures

13



The Critical Speed Analysis (CSA) module under Wellplan for Windows is available commercially. It can be used to predict rotational speeds that are likely to cause high vibration levels. MWD tools are usually fitted with a shock sensor that will detect vibration in the BHA - ask the MWD operator if this information is available from his tool. The use of a down hole pressure monitoring tool will assist the rig team in preventing both pressure shock loading and unintentionally exceeding the ECD. See Monitoring Tools section - PWD Sub.

2.0 Differential Sticking

This is the differential sticking equivalent of the well known fire triangle. For differential sticking to occur all four conditions must be present. However, it has been observed from studies of differential sticking cases (Ref 6) that the most important factor in the above triangle is LACK OF STRING MOVEMENT. Out of the four required conditions, string movement is the only factor under the control of the driller!

re W

ce

Permeable Formation

la n

ell bo

ba

Co

er

n ta

Ov

ct

When a string is left stationary the filter cake builds up and the string is embedded in the filter cake.

Lack of String Movement Fig. 9 - Differential Sticking Triangle

14


Sticking and freeing forces

The actual differential sticking force that acts on the drill string is calculated from the overbalance, the contact area and the friction factor of the well. The contact area is an estimate of the contact length (calculated using the Wellplan for windows - Wellbore Contact module) multiplied by the contact width (usually assumed to be 2 to 3 inches). The friction factor (ff) will depend on the mud type being used but an average value of 0.25 is good enough for estimating differential sticking forces. Where: Freeing Force = ff x contact length (inch) x contact width (inch) x overbalance (psi)

This calculation gives the force required at the stuck point to free the string and does not take into account hole drag. Example: Calculation of force required to free a differentially stuck string: overbalance = 700 psi contact length = 30ft = 360in Contact width = 3in friction factor = 0.25 FreeingForce = 0.25 x 360 x 3 x 700 = 189k lbs The surface freeing force required would be the Freeing Force + Up drag + additional drag due to the overpulls applied. Assuming 140klbs string weight above the stuck point, an updrag of 40klbs and calculating the extra drag due to the increase in tension due to overpull say 30% of overpull lost in extra drag [typical for a horizontal well] Surface freeing force = 189k lbs*1.43 + 140kl bs + 40k lbs =450k lbs If you loose 30% of the surface overpull in extra drag, then: 0.7 x surface overpull = 189k lbs surface overpull = 189klbs / 0.7 = 189k lbs * 1.43 From the above example it can be seen that differential sticking freeing forces can easily reach very high values that are beyond the limits of grade G and often grade S drill pipe. Consequently a high proportion of the mechanical methods for freeing differentially stuck drill strings are relatively unsuccessful. As high freeing forces are required in differential sticking cases prevention is the cure. 15


Thick, Soft Filter Cake

Thin, Hard, Tough Filter Cake

Width of Contact Area

Width of Contact Area

ST0002.FH8

Fig. 10 - Filter Cake Thickness


Use OBM rather than WBM. This reduces the risk of differential sticking by reducing the water loss to the formation and providing a thin, tough filter cake. This reduces the contact area as the filter cake will be thinner. (Freeing point - It also reduces the friction factor allowing a greater force to be applied to the stuck point). Consider using low torque subs to provide stand-off for BHAs and large sizes (6-5/8) of HWDP. Use jars and accelerators fitted with stand-off subs. A reduction in fluid loss will reduce sticking tendency. Liquid casing can be used in reducing the risk of differentially stuck pipe for sealing off potential lost circulation zones (i.e, high permeability). Agree the surveying time with the survey engineer before taking the survey. Do not allow the survey engineer or directional driller to re-take the survey if the first one fails, move the string for 10 minutes then re-take the survey. A further risky time for differential sticking is when rotating with a low ROP, when the string may not be moving due to stick slip conditions.

Rig team prevention points KEEP THE STRING MOVING Always know when the string is across a permeable formation. Make connections as quickly and safely as possible. Agree the surveying time with the survey engineer before taking the survey. Do not allow the survey engineer or directional driller to re-take the 16


survey if the first one fails, move the string for 10 minutes then re-take the survey. Agree an action plan for when the string becomes differentially stuck. Develop a flow check procedure that reduces the risk of leaving the string stationary across a permeable formation. Have contingency plans in place for Loss of power - go to non permeable zone Accidental power loss - maintain circulation if possible. Put mud weight back up after lowering it to get free unless specified otherwise in the plan Be aware that each formation is different.

2.1 Wire line Differential Sticking Issues

Contact logging sondes e.g. RFT, MCFT and FMT are, by their nature, in contact with permeable formations, exposed to an overbalance and stationary. Hence, these tools are very likely to become differentially stuck. Recommendations on maximum sampling time at each sample point should be made in the logging program. Wire line cables are also prone to getting stuck differentially as they are often forced into the filter cake across permeable formation by cable tension. Cable sticking is confirmed by surface and/or down hole tension measurements not matching; a lack of tension indicated on the tools internal tension measurement compared with indications of overpull on the surface tension instrument. The common remedial action for freeing a stuck wireline tool is to strip over the tool. This type of sticking should not be confused with mechanical sticking of formation testing tools and side wall core tools. In this case the sample catchers of the formation testing tool are pressed into the borehole wall of the formation in order to catch a sample of formation fluid or a pressure reading. The tools probe can become mechanically stuck in the formation. Sidewall core tools fire bullets, which are attached to the tool by wire ties. The bullets can embed in the formation and stick. Freeing can be successful by working the tool between the maximum working overpull and slack-off for a period of hours.

Rig team prevention points

Establish a maximum time for taking FMT/RFT pressure sample (suggest 15 minutes). Be aware of cable contact across a permeable formation. 17


2.2 Casing/Liner Differential Sticking Issues

It is often impossible to free a differentially stuck casing string. The contact area is usually very high and this combined with the weight of the casing/liner results in poor chances of freeing by force. Most of the differentially stuck casing incidents in Shell Expro have been due to secondary differential sticking, occurring only after the casing was caused to be stationary for another reason.


Consider making a wiper trip for hole cleaning purposes prior to running the casing.

18


Drill Collar - Wellbore Contact : 0 to 3 deg 120 ft

90 ft

17 1/2”

Poss

No

16” 12 1/4” 8 1/2”

Poss Yes Yes

5 3/4”

Yes

60 ft

30 ft

No

No

Poss Poss Yes

No Poss Poss

No No No

Yes

Yes

Poss

Fig. 11 - Wellbore Contact: 0 - 3 deg

Drill Collar - Wellbore Contact : 30 to 50 deg 120 ft

90 ft

60 ft

30 ft

17 1/2”

Yes

Yes

No

No

16” 12 1/4” 8 1/2”

Yes Yes Yes

Yes Yes Yes

No Poss Yes

No No No

5 3/4”

Yes

Yes

Yes

Yes

Fig. 12 - Wellbore Contact: 30 - 50 deg

These tables are based on the typical collar size used for that hole section, i.e, 9 in 17 ½ hole, 4 ¾ in 5 ¾ hole etc. Above 50 degrees contact does not increase significantly.

19


In wells with inclination less than 50 degrees the above tables can be used as a guideline for stabiliser spacing. If this results in more than 4 stabilisers, it is likely that the BHA is too long and either the WOB required should be reassessed, the collar wt/ft increased or more HWDP used. In horizontal wells (HWDP instead of DC) unstabilised BHAs with HWDP are often used as drill collars do not supply the weight on bit in a horizontal well. As a consequence the BHA may be very short containing only a motor, MWD, LWD, one or two stabilisers, a jar and a drill collar. This dramatically reduces the risk of sticking across the BHA. However, the risk of differential sticking in the drill string above the BHA can still be high when a permeable formation is drilled in the build/drop section. This is due to the relatively high wall contact forces in these sections of a well. Consideration is often given to running undergauge string stabilisers and/or two sets of jars (see Chapter 6). Combination of the Jar plus one drill collar is often the longest component of an unstabilised BHA. Externally oversized subs can be built into the jars to provide a reduction in contact length. (Figure 13). Always check the length between stabilisers on Motor, MWD and LWD combinations.

Fig. 13 - Jars with stand-off subs to prevent differential sticking

Case History

When drilling an S shaped appraisal well for the Shearwater field, the drill string became stuck across a 150ft sand body (Tay Sand), with 2500psi overbalance at 35 degrees. Although the drill string was freed by pumping a large base oil pill, the shales above the sandbody collapsed and the well had to be sidetracked. For the drilling of the production wells this was considered to be a high risk area and the build/drop section was consequently planned to be as much as possible above this sand body. Two jars were planned and consideration was given to running undergauge string stabilisers. 20


2.3 Coil Tubing Drilling Differential Sticking Issues Lack of rotation

Coil tubing drilling is at a disadvantage by not allowing string rotation to keep the string moving to prevent differential sticking. Coil cycles

Prevention of differential sticking requires constant coil motion. However, the life of the coil is considerably shortened by reeling in and out while containing pressure (while circulating). On a recent operation it was necessary to cut several sections from the coil due to a high number of cycles. A maximum number of 90 in/out cycles was all the coil could withstand before a section required cutting off to place a different section of the coil across the gooseneck and lubricator. No stabilisation

Coil tubing BHAs often have no stabilisation and there are no tool joints on the coil. This constant contact with the wellbore results in a high risk of the coil tubing becoming differentially stuck. Freeing by flowing the well

An advantage of coil tubing drilling on a platform is that, when differentially stuck and when planned as an option, the well can be flowed under controlled conditions to free the string. The maximum allowed reduction in mud weight should be established during the planning stage of the well. Offset data should be consulted to establish any potential wellbore stability issues for any shale formations exposed. Recent experience

On a recent coil tubing operation the kick-off point was deepened to leave an overlying shale formation cased off. This was to decrease the risk of wellbore stability problems if the well had to be flowed to free stuck coil tubing. Freeing differentially stuck pipe by reducing the mud weight temporarily has been done in some formations without observing any significant detrimental effects on shale stability. However, doing this has caused major problems in other locations and should only be done after consulting offset data and wellbore stability information for the formations exposed on a case by case basis. Recent experience of flowing the well to free a differentially stuck coil has been gained on one of Shell Expros Brent platforms. 21


Shell Expro have used under-balance techniques to free a stuck liner on a platform well drilled with coil tubing. This was done due to the liner getting differentially stuck while being run in.


Have a contingency plan in place. Check the coil string is free by moving the coil every 30mins if the ROP is less than 5ft/hr. Preventative maintenance on equipment will prevent unscheduled stationary time. Consider the effect on operations of platform shutdown procedures. Use constant running speeds, pump pressure, WOB etc., to standardise across shift changes. This will simplify the identification of deviations from normal trends in drilling parameters. In coil tubing drilling differential sticking can occur when putting weight on bit due to increased contact forces (buckling). This is less of a risk with a drill string as a drill string is not usually buckled when motor drilling.

Initial Response when stuck with a coil tubing string.

The procedure now used in the event of becoming differentially stuck with coil tubing is: Circulate to base oil and put well on balance. Flow the well (have an agreed procedure for this operation) long enough to free the string. Cleaning the well up may take a number of days after freeing operations.

3. Geometry - String / Hole incompatibility 3.1 Dogleg & Stiff Assembly

The BHA becomes stuck in a dogleg. A dogleg in this context is a dogleg over and above the planned dogleg. The consequence of a dogleg can vary greatly depending on the type of section being drilled. When running in with a stiffer BHA than the previously used more weight

Fig. 14 - Stuck BHA

22


will be required to push the string through the dogleg. The BHA can get stuck or cause an unintentional sidetrack. Example: Stabilised rotary assembly after a steerable assembly. Turbine after a steerable assembly. Bit and Stabilisers undergauge on previous BHA This mechanism can also occur while running casing, liners and pre-packed screens which will often be stiffer than the assemblies used for drilling the hole. Beware that if the drill string had to be reamed out of the hole problems may be experienced while running casing.


Minimise steering requirements when designing the well trajectory.


Ream doglegs. Sticking to the directional drilling planned line should be balanced against reducing doglegs Use caution when running in through a build section after a BHA change. After backreaming, perform a conventional check trip and wipe any areas of overpull prior to running casing.

3.2 Ledges

When interbedded formations are drilled, ledges can form which may cause the BHA to hang up. Ledges are formation related. Ledges may also be formed with a steerable assembly when circulating in one place. This is referred to as undercut lowside and is not formation related.


Consult offset data if formations are likely to give rise to ledges and highlight this in the drilling program.

Fig. 15 - Ledges 23



The use of a paper BHA model (see Monitoring Tools Section) will assist in locating which part of the BHA is hanging up. Rotate slowly while pulling the BHA past ledges. Do circulate in one place when a steerable assembly is being used. Ream ledges.

3.3 Undergauge Hole in Salt

Some formations, mainly salt, deform plastically when a hole is drill through them. The salt may slowly flow into the hole and reduce the hole diameter. This will often increase torque or stick the string by squeezing in on drill pipe or cause problems when pulling out of the hole. Salt can be dissolved in fresh water. If mobile salt is causing problems it can be washed away by pumping fresh water. Beware of any other formations that may cause problems later by being exposed to freshwater (e.g. reactive shales)


· High light the presence of mobile salt in the drilling programme

Fig. 16 - Keyseating

· Ensure sufficient fresh water is available


· Have fresh water ready to pump when drilling mobile salt formations.

3.4 Key-seat

A key seat is a slot cut into the wellbore by the drill pipe. The resulting shape of the wellbore is that of a keyhole. Key-seats develop where the wellbore contact forces are high and/or where the number of rotations of the string against the wellbore wall is high. Doglegs high up in a well or in a build / drop area result in high contact forces between the drill string and the wellbore. Slow drilling with high RPMs may create a keyseat even when the contact force is low.

24


Calliper logs have shown that slow drilling in horizontal wells can result in a groove being cut by the drill pipe in the low side of the horizontal section. Casing shoes can be damaged in this manner when a solids build up pushes the string into the highside of the casing. Since detailed records began in 1987 no stuckpipe case due to key seating has been recorded.

Fig. 17 - Stuck Casing


When pulling out of hole a keyseat may cause a flicker on the weight indicator every time a tool joint is pulled past it (every 30ft). When this is observed reduce the tripping speed. This will reduce the sticking force should the drill string get caught in the keyseat.

4 Junk 4.1 Metal Junk

The BHA can hang up on junk or junk can get trapped between the BHA components and the borehole wall, causing the string to become stuck. Sources of junk: · Material dropped down hole (spanners, dies). · BHA equipment failures (parts of MWD tools, cones from bit). · Milling operations (window or fish). · Casing centralisers (during cement cleanout run after pulling casing which failed to get to bottom or after a liner hanger failed to release). · Fish (when sidetracking). Fig. 18 - Metal Junk 25


Sticking due to metal junk often causes very erratic torque. Reduction of the torque limit is advised if erratic torque is experienced, this will help prevent a drill string twist-off.


· Consider ditch magnets. · BHA inspection criteria should include parts that are likely to form junk after failing (internal MWD parts). · Plan to use mud with sufficient carrying capacity.


· Good housekeeping. · Use correct handling equipment on surface. · Note that chrome completion tubing / casing (which is non-magnetic) will not be collected by ditch magnets. · Use junk baskets. · Note the weight of any milled material recovered.

4.2 Cement Chunks

Cement chunks can get trapped between BHA components and the wellbore wall causing the string to become stuck. Likely sources of cement chunks: · The casing shoe area. · A plugged back hole. · Cement from behind casing where a window has been cut. · Cement from a kick-off plug. Fibre cement minimises the risk of this mechanism occurring. Fibre cement binds the cement together even when it is fractured. However, it is sometimes difficult to mix and pump without the fibres all ending up at the top of the cement column (floating). This mechanism can be caused by reciprocating / rotating at one point ( e.g, in the 26

Fig. 19 - Cement Chunks


shoe area while running the next casing string). This may cause chunks of cement to drop off and wedge the casing. Acid soluble cement is sometimes used in workover operations. This type of cement can be acidised afterwards and hence minimise formation damage. Acid soluble cement can also be dissolved if sticking occurs.

Design team prevention points · Consider fibre cement. · Consider acid soluble cement


· Slow down when tripping the BHA past any areas containing exposed cement, e.g, window areas and casing shoe areas.

4.3 Losses 4.3.1 Natural losses

When drilling through formations that have fractures and vugs (small caverns) or a very high permeability, mud can flow into the formation. The various solutions for losses are well documented (Ref 14) and are covered briefly in this booklet. Loss rate Seepage Partial Severe Total

Fig. 20 Natural Losses

Solution 1-5 bbl 6-50 bbl/hr 51-250 bbl/hr >250 bbl/hr

Reduce the ECD or Mud wt if possible + add LCM while drilling Pump a 10-20bbl LCM pill Pump a 50bbl LCM pill Pump a large LCM pill >100bbl

Table 2 - Loss rates

For formulation of LCM pills consult your local mud specialist. Ensure that any LCM formulation will not destabilise overlying formations (e.g, reactive shales).


Provide the rig with LCM formulations based on local experience. Develop procedures based on offset experience. Consider cheap mud. 27



Be prepared when entering a formation with a high risk of natural losses.

4.3.2 Induced losses - formation fracture pressure exceeded

These losses are created by the actions of the rig team or as a consequence of a down hole problem. Reasons for induced losses are: A pack-off occurs and the formation fracture pressure is exceeded before the pump pressure can be reduced. High ECD due to poor hole cleaning. Starting circulation too rapidly. Running in the hole to rapidly (Pressure surges). When losses occur there is a risk of the string packing-off as solids fall back down the hole due to low or negative annular velocity (top hole drilling).


Consult offset data to asses the risk of borehole instability, induced losses and optimum mud gradient. Consider downhole PWD sub. Provide the rig with LCM formulation.


Keep the hole clean to minimise ECDs.

Fig. 21 The Enhanced Pre-Spud (EHP) Chart (Planning Tool) 28


Bring pumps up slowly.

5. Available tools used to observe stuckpipe & tight hole This Chapter discusses methods used to monitor a well for signs of stuck pipe and the passing on of this information in a driller friendly manner. After reading this chapter the rig team members should have a clear understanding of the monitoring tools available and how they can be applied to reduce stuck pipe problems.

5.1 Paper BHA Model

Create a large-scale printout of the wellbore lithology. On the same scale, create a strip of card or paper to simulate the BHA with all relevant components, MWD, stabilisers, jar etc, marked on the strip of paper.

ROP BHA

Notes

Lith

O/p 10 k

By sliding the BHA up and down against the lithology printout any problem depths can be interpreted.

O/p 10 k

Often the driller will have a list of bit depths where problems occurred. It is very difficult to tell what is causing these problems if there are more than one or two problem depths. If the BHA has three stabilisers and there are 3 ledges in the hole there are nine possible bit depths which may cause overpulls or set down weights to occur.

Swelling shale?

O/p 10 k

LEDGE !?

O/p 30 k (stab 1 at ledge above)

O/p 30 k (stab 2 at ledge above)

If the BHA is changed the new problematic bit depths can be seen easily Fig. 22 - Paper BHA using the model. The driller can be briefed either just as he goes on tour or while he is on the rig-floor at a convenient moment.

29


5.2 Drag Charts

The theory behind drag charts was explained in Chapter 1. Understanding a Drag Chart is important for drillers. The creation of actual drag charts by the drill floor team should be encouraged as this is a key monitoring tool.

Design Stage Drag Charts

During the well design phase the Well Engineer will create a drag chart to predict the torque and drag in the well. This will be used to select DP grade, weight and length. The drag chart will also be used to set MOP (margin of overpull) and to evaluate the risk of buckling in the string. A drag chart should be created to ensure casing and liners will get to bottom without buckling and locking up (lock up is when buckling prevents the string being run in any further and has happened in the past in the blank pipe between pre-packed screens). Coil tubing drilling operations require more accurate drag information as coil tubing is more susceptible to buckling and locking up than drill pipe. Special software and onsite continuous monitoring is used for coil tubing operations.

Drilling Stage Drag Charts

During the well creation phase the data used to make the predicted drag chart is updated with actual data. It is recommended that data be collected after every stand drilled. The data required being:-·

Bit depth. Up weight, Down weight, Rotating weight. BHA Run Number. Pumps on/off.

If data loggers are being used data can be obtained via their computers. This data should be verified with the drillers tally book record. The actual data drag chart is the one that should be used to evaluate the existence of problems while POOH. If the up weight line while tripping does not follow the up weight while drilling there may be a problem in the well and investigations should be made. Similarly when tripping in, if the down weight is less than when drilling -investigate the cause.

30


Actual information can be plotted by data loggers after each trip - this information will be useful to the Well Design Engineer on subsequent wells.

5.3 Doglegs Severity v Depth Chart

The DLS v depth chart will enable the driller to obtain an overview of potential hang-up depths with BHAs and casing. This chart should be displayed on the drill-floor.

Fig. 23 - Dogleg severity versus depth graph

5.4 Cuttings Monitoring Systems

Specially designed cuttings volume monitoring equipment is available and can be fitted to most shale-shakers. If your rig is not fitted with such equipment a rough estimate of volume rate of cuttings returning to the shakers can be made by the Shakerman. This is done by holding a bucket under the area of the shakers giving the most cuttings and timing how long the bucket takes to fill. This time can be recorded at intervals of say 30 minutes or one hour depending on requirements. Although not very accurate it can help to optimise hole cleaning actions such as rotation, reciprocation and circulation rates, and is better than judging volume rates by eye.

31


Time Keeper

A simple mechanical old style stopwatch can be used to time survey times or someone can be allocated the task, especially when the driller is performing some other task while the string is stationary. The timekeeper can remind everyone how long the string has been stationary every five minutes or every three minutes depending on risk. This might sound bit like overkill or a bit simplistic but Differential Sticking in 1996 caused the highest stuck pipe cost. In ref 6 (WIEN 727 Page 39 Chapter 7.2.4. Learning point 22.) excessive static time was identified as the main cause of differential sticking incidents.

Pressure while drilling sub (PWD sub)

The pressure while drilling sub is a down hole addition to the MWD system that can provide surface readout of down hole pressures and can record down hole pressures during all operations when a PWD-MWD is included in the drill string. By using the results of the pressure recording tool to calculate and plot the ECDs, information about down hole pressure conditions can be accurately monitored. There are two methods of using PWD subs, real time and recorded. Real time information is only available when the pumps are on. Recorded data is retrieved once the tool is returned to surface.

Pressure

Depth

Fig. 24 - PWD Readout showing downhole pressures after fast drilling

32


PWD tools have been used to gather information in the following areas: LOT/FIT test recording verification of Hydraulics software results down hole pressure changes due to string movement - Rotation, Surge, Swab, Reaming down hole pressure changes due to braking gels Mud weigh fluctuations Hole cleaning / cuttings loading In Fig 58, the increase in down hole pressure due to fast drilling followed by working the string up and down due to overpulls can be seen. Note that all the pressures during these operations are up to 45 pptf above the FIT test limit. Pressure

Depth

Fig. 25 - PWD2

Fig 24 illustrates the pressures seen when starting the pumps after running to TD. The initial surge could be due to breaking the mud gels or barite sag and the following undulations in mud weight are due to the mud becoming conditioned, possibly due to Barite sag. Increases in pressure are observed when the string is rotated. This occurs for two reasons, 1) the fluid path becomes longer as it spirals up the hole. This affect is most prominent in wells with small hole sizes and high mud weights. 2) Any cuttings on the low side of the hole are likely to be stirred up when rotation is started. This increases the effective mud gradient (s.g. of drilled solids = 2.6, more solids per unit volume exist therefore an increase in mud density is observed)

33


Rotary drilling

Cuttings are stirred up and influence ECD.

Sliding mode

Cuttings settle forming cuttings beds and have less effect on ECD

Fig 26 illustrates the pressure differences experienced between rotary and oriented drilling. Pressure spikes due to surge can also be clearly observed. Fig 27 shows the same pressure spike shown in Fig 26 on an expanded scale.

Fig. 26 - PWD 3

Fig. 27 - PWD 4

For more information and a full report see Shell/KCA report: Results, Dunlin DA 26 S4 8 ½ section, Results, Dunlin DA 26 S5 8 ½ section, 30 March 1996. 34


These days there are a number of hole sections which are very risky. If losses are induced causing a fracture it may prove impossible to drill. If pump rate is compromised by losses then hole cleaning becomes a secondary problem. The following recommendations are offered: Bring the pumps up slowly. Clean the hole after drilling in sliding mode. These two recommendations will help prevent stuck pipe due to induced losses.

Surface Monitoring tools

There are a number of surface monitoring tool that interpret the signals from the down hole MWD subs, such as PWD and DWOB, and set of alarms when the indications of a stuckpipe case or other problems are observed. Mostly these tools are in the early stages of development and require the dedicated resources of data loggers to keep them operational and help with interpretation.

35


6. Coiled tubing drilling for the rotary driller. Coil tubing has been used extensively for workover operations and most drillers will be familiar with it being used in this manner. Recently coil tubing has also been used for drilling sidetracks or multi-lateral wells. The coil tubing operator and rotary driller have been working closely together on the rig site. The coil tubing operator combining his knowledge of the tubing string with the drillers knowledge of downhole problems and the drilling rig.

6.1 What is coil tubing.

Coil tubing is a length of steel tubing (Fig. 28) Fig. 28 - Coil Tubing that is produced in sections 3500ft long. The tube is manufactured from flat steel strips and is welded longitudinally. Each 3500ft section is welded together using a bias weld. Several sections are welded together to create a full reel which can be up to 21000ft long depending on the reel size used. Reels of this length are usually tapered. Coil tubing is available in various sizes. The OD and ID can be specified as can the material from which the tubing is made. The Coil can also contain cables and control lines (Fig 29) to enable down hole equipment to be operated remotely and allow MWD / LWD signals to be sent to surface. The tubing is fed into the well by a set of tracks (Fig 30) that both straighten the tubing and hold the weight of the tubing in the well. Below the tracks is the lubricator that contains well pressure, Fig. 29 - Hepta cable even while the tubing is being & control lines fed in and out. (Similar to stripping operations with drill pipe). As coil tubing has a small cross sectional area the tensile yield strength is low. For 2 tubing the yield will be between 64k and 100k lbs (depending on material used). This limits the amount of overpull that can be applied in a stuck situation. 36

Fig. 30 - Injector head tracks


Buckling

When the coil tubing is being run into a deviated hole it can easily be buckled, more so than drill pipe which is much stiffer. Coil tubing has a limit, called lock up, where the tubing helically buckles causing an increase in side wallforces and hence drag. When this situation occurs the string cannot be run any further into the hole. If the drag in the well is higher than originally expected lockup (buckling) can occur before reaching TD, this is similar to motor drilling. In a rotary drilling situation the string can be rotated to turn drag in to torque enabling the string to be rotated to bottom. Coil tubing cannot be rotated and drilling is always performed using a motor.

Pressure & Combined Tension on Coil Tubing

The term bending cycle refers to the tubing being bent from straight or being straightened from bent. Coil tubing passes through six bending cycles between leaving the reel, entering the well and returning to the reel. This does not include any bending cycles it experiences while in the well. The number of bending cycles the coil tubing can handle without risk of failure decreases if the pressure inside the tubing is higher than the external pressure. Every time the tubing is cycled with pressure inside it deforms slightly. Ultimately the tubing will increased in ID, the wall thickness will decrease and the tubing become weaker. To combat this pressurised lubricators are currently under design but at present are not yet available.

Fig. 31 - Illustration of the pressure effects on coiled tubing

Fig. 31 shows the cross-section of a piece of tubing, cycled to failure with various pressures. The higher the pressure the less cycles before failure.

37


The consequences of this cycling phenomena is significant for coil tubing drilling. In conventional rotary drilling working the drill string in and out of the hole with full circulation is a routine operation for good hole cleaning (the drill string is usually being rotated as well!). This practice can not be done with coil tubing (for rotation is not yet practical!) and if the circulating pressures are high, say 5000psi, working the tubing in and out of the hole will shorten tubing life dramatically. Coil tubing operators have a set of curves for each tubing string. The curves specify the allowable pull with simultaneous pressure.

6.2 Hole Cleaning with coil tubing

Part of coil tubing drilling operations often takes place inside liner, completion strings or casing. This can give rise to low annular velocities. The pictures below illustrate the relative sizes of a 2 coil inside various casing strings.

2” Coil Tubing in 3.75” Hole

2” Coil Tubing in 7” Liner

2” Coil Tubing in 5” Liner

Fig. 32 - Relative sizes of coil and liner

Annular Velocity ft/min

2 Coil inside 7 liner is the same relative size as 5 DP inside 17.5. 2 Coil inside 5 liner is approximately the same relative size to 5 DP inside 12.25. 2 Coil inside 3.75 hole is approximately the same relative size to 4.5 DP inside 8.5. 300 250 200

.24 Bbl/m in

150

2.38 Bbl/m in

100

3.57 Bbl/m in

50 0 7" Liner

5" Liner

3 3/4 Hole

Fig. 33 - Annular Velocity resulting from various flow rate and tubing sizes 38


The annular velocities for a given flow rate can be seen in Fig. 33. In coil tubing operations the flowrate is usually measured in BPM (barrels per minute). To convert GPM to BPM simply divide by 42. If good hole cleaning practices are used problems with solids in the open hole section can be overcome. The illustrations in Fig 34 and 35 illustrate how a small cuttings bed in the open hole section of a 3.75 hole can have a significant effect on the drag in the well due to building up around the tubing. However, this process is self limiting, as the cuttings build up around the tubing the remaining cross-sectional area decreases causing an increase in the AV which scours away the cuttings from around the tubing. The AV when this occurs is called the critical velocity. The area where hole cleaning problems are likely is in the upper section of the old hole where the liner may be 7 or even 9 5/8 casing. Here the AV will fall dramatically. These are areas where cuttings accumulate. Fig. 34 - 10% Solids bed illustrated in a 3 ¾ hole without the coil.

When pulling out of the hole, changes in ID from large, where the cutting accumulate, to small may cause problems if cuttings are dragged into the smaller section by the BHA. Time should be spent circulating before the BHA is pulled into these areas. This is very specific to coil tubing as in conventional drilling this change in hole ID from large to small is rarely encountered. When this situation does occur in conventional drilling - e.g. washouts, it often leads to significant hole cleaning problems. Fig. 35 - 10% Solids bed illustrated in a 3 ¾ hole with 2 coil in the hole.

39


Appendix 1

Preventing stuck pipe is an integral part of designing and building a well. It is a balance between risk and no risk decisions. Most decisions made by the well designers and the well creators impact on the risk of getting stuck. Consequently information on preventing one particular stuck pipe mechanism is only useful when that mechanism is showing signs of becoming a problem. In drilling a well two groups of people are involved, the designers and the creators. The two groups must communicate effectively so that the creators create what the designers designed and the designers learn from the experience of the creators. Prevention of stuck pipe is so linked to the process of drilling that it must occur at every stage of the well planning and creation process.

Planning

1. (By Hole Section) Plan stuck pipe out of the well 2. (By operation) Conduct procedures and operations so as to avoid stuck pipe 3. (By operation) Monitor for signs of stuck pipe 4. (Initial reaction) React appropriately when stuck pipe occurs 5. (after getting stuck - freeing) Correct use of freeing equipment once stuck

Freeing

Initial actions - Pack-off The following paragraphs contain suggested actions to take in the first 30 minutes of a stuck pipe case. These may or may not be relevant to each individual incident. It is recommended that each rig should have these types of procedures in place as it reduces the chances of incorrect actions being taken during the initial stages of a stuck pipe case. Because hole cleaning is not location specific offset data may not be any help in determining the likelihood of hole cleaning problems. 40


Drill String Pack-off To recover from a pack-off situation one must first attempt to visualise the situation down hole. The pictures in the ABC of Hole Cleaning may help with this. In the majority of drill string pack-offs the string is moving up whereas for casing pack-offs the string is usually moving down. To free the string several things must be done: 1. Create a flow path through the packed-off solids This can be done by applying torque to the string then letting it off again (torsional cycling). This attempts to create a path down the side of the stabiliser. This is best attempted with some pressure under the pack-off. This pressure will bleed off when the path is created indicating to the driller when he is successful. It will also assist in the creation of the path by forcing its way though. If a flow path is not created using a low pressure (say 500 psi) then a higher pressure can be used (say 1500psi). If using a higher pressure consider the effect of the pressure on the formation, both fracturing and wellbore stability. 2. Reduce the amount of compacted solids with high flow rate. Once a flow path is created gradually increasing the flow rate will scour away the solids causing the pack-off. Care should be taken in doing this as a high flow rate combined with mechanical agitation can cause further pack-off problems. 3. Regain movement of the string It is better to regain rotation prior to reciprocation as this is less likely to cause a further pack-off. It is also important to begin moving the string in the opposite direction to which the pack-off occurred. This not always easy to determine as consideration must be given to how the string packed-off, and this is not always known. If packed-off whilst POOH then the initial direction should be down. If avalanching has cause the pack-off then down movement would be less likely to compact the solids further. Once movement of the string is regained a positive effort to clean the hole must be made. This may involve pumping pills and circulating several hole volumes until the shakers are clean. See section 5 of the ABC of Hole Cleaning for further information on hole cleaning techniques. An important point to reiterate is that the only solids returning over the shakers may be large amounts of fines. These are reground cuttings commonly 41


seen in ERD wells. The presence of large volumes of fines confirms a hole cleaning problem has existed and is now being cleaned up.

Casing Pack-off

When running casing into a hole containing a solids bed it is possible to hang up or pack-off. A drag chart (Fig 36) for casing can be created in advance using the friction factors from the drilling phase of the well. This will as an early warning if the casing runs into a restriction. M easured Weight at Surface

0

LEGEND Trip In Trip Out Min W eight Plastic Min W eight Buckle

Depth [ft]

2000

4000

6000

0

20

40

60

80

100

120

140

160

M easured W eight [kip]

Fig. 36 - Casing Running Drag Chart

42


Packed-off with coil tubing.

Due to the nature of coiled tubing no rotation is possible. If a pack-off occurs the mechanical means of recovery are very limited. The string should be worked as much as possible to maximum up and down weights. If neither movement nor circulation is regained the only option is to release the coil and fish or sidetrack.

Wireline Logging Tools - Solids sticking

Sticking in solids with wireline tools most often shows up as the inability to get logs to TD. Time spent cleaning the hole prior to running logs is sometimes considered a waste. If good hole cleaning practices are used when pulling out prior to running logs problems of this type are less likely to be encountered.

Initial Actions - Differentially Sticking

Once it has been determined that the sticking mechanism is differential sticking the following initial response can be used:

Initial Response when stuck with a drill string

The initial response to a differential sticking incident should be applied as soon as possible after sticking occurs. 1. Maintain circulation at drilling flowrate. 2. Apply 50% of make up torque and slack off string weight to below the down weight. Use a short sharp jarring action as would be used with a bumper sub. This is to attempt to work the torque down to roll the string off the wall of the hole. 3. If string does not come free pick up to the up weight and try again. Apply 80% of make up torque and try again. 4. Pull to safe limit of string if slumping and torquing does not work. 5. Pump a pipe release agent and allow to soak for 24hrs. Slump and torque and/or jar during this time. 6. If differentially stuck while using WBM consider circulating to OBM. This method freed a drill string that had been stuck for 5 days. 7. Utube the well if rig / platform considerations permit.

43


Initial response when differentially stuck with wire line logging tools.

Determine the stuck point by comparing tension applied to the cable with tension measured at the tool. If the cable is stuck then care should be taken in applying tension as the weak point is below the stuck point. Logging companies have procedures for freeing stuck logging tools. These should be implemented after discussion with the rig team .

Casing

The main point with differentially stuck casing is that except in the case of a liner on coiled tubing it cannot be under-balanced to free it.

Initial actions for Mechanical (Geometry) Sticking

This sticking mechanism is due to a mis-match between the size and shape of the BHA and wellbore. The string should be moved in the opposite direction to which it was moving prior to getting stuck. 1. Maintain Circulation. 2. If there is no risk of differential sticking, then spend some time working out what the problem is being caused by, consider all the options - see Sticking Mechanism Section. 3. Work string in opposite direction in which sticking occurred. 4. Jarring should commence with light blows initially.

Pipe Release Agents

When differentially stuck it is sometimes appropriate to pump a pipe release agent (PRA). The best application guideline is not to get into a situation where a spotting fluid is needed at all. Stuck pipe can often be prevented by maintaining good drilling-fluid properties and drilling practices. Planning is an essential part of the success of any spotting-fluid application. This first involves having everyone associated with the task aware of the steps to be taken when stuck pipe occurs. If sticking is caused by differential pressure, having sufficient supplies of spotting-fluid concentrate on the rig to allow quick mixing and placement enhances the chance of success. Mud circulation is recommended while mixing and making preparations to place the spot. The spot must be placed properly and enough volume must be used to cover the entire stuck interval. The spotting-fluid density should be equiva44


lent to that of the mud to prevent upward migration out of the stuck interval during the soaking time. Once in the hole, the pill must be allowed to soak for enough time to allow it to work. This time may be as long as 48 hours. If there is no willingness to let the spot soak for a sufficient length of time, a spotting fluid should not be used. The PRA can be weighted or un-weighted depending on whether a reduction in hydrostatic head is required. An example formulae for WBM is: For a reduction in hydrostatic head: Base oil + 2.5 U.S. Gal / bbl Mudban (or Pipelax) (gradient 370 pptf) If a weighted fluid is required use: Base Oil + 2.5 U.S. Gal/bbl Mudban (or Pipelax) + 12 - 15 lb/bbl Geltone (or equivalent viscosifier) + 7% seawater + Bayrite. If stuck in OBM use: 50 - 70 bbls of over-treated mud based on the following formulae: 50 - 70 bbls of mud + 55 gal Emulsifier + 40 - 50 gal fluid loss reducer Displacement of the pill

Displace a large pill of PRA slowly around the to the stuck zone. Once the pill is across the stuck zone pump 5 bbls/30 mins soak.

45

Stuck Pipe Mechanisms

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