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Study and Experiment on Bottom Hole Problems Related to Stuck

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Study and experiment on bottom hole problems related to stuck-pipe and fishing operations Report submitted in partial fulfillment of the requirement for the award of the degree of BACHELOR OF TECHNOLOGY IN PETROLEUM ENGINEERING Under the Guidance of Dr. Ajit Kumar N. Shukla By JIGNESH DHOLIYA 09BT01079 KRISHNA KUMAR 09BT01106 SAIF HASAN RIZVI 09BT01078 SAURABH HATHIA 09BT01064 PRASHAM BHUTA 09BT01105 CHETAN MUNDHAVA 09BT01217
Transcript

Study and experiment on bottom hole problems related to stuckpipe and fishing operations

Report submitted in partial fulfillment of the requirement for the award of the degree of

BACHELOR OF TECHNOLOGY IN PETROLEUM ENGINEERING

Under the Guidance of

Dr. Ajit Kumar N. Shukla

By

JIGNESH DHOLIYA KRISHNA KUMAR SAIF HASAN RIZVI SAURABH HATHIA PRASHAM BHUTA CHETAN MUNDHAVA JIGNAV CHAUDHARI

09BT01079 09BT01106 09BT01078 09BT01064 09BT01105 09BT01217 09BT01129

SCHOOL OF PETROLEUM TECHNOLOGY PANDIT DEENDAYAL PETROLEUM UNIVERSITY GANDHINAGAR, GUJARAT, INDIA

Study and experiment on bottom hole problems related to stuckpipe and fishing operations

Report submitted in partial fulfillment of the requirement for the award of the degree of

BACHELOR OF TECHNOLOGY IN PETROLEUM ENGINEERING

Under the Guidance of

Dr. Ajit Kumar N. Shukla

By

JIGNESH DHOLIYA KRISHNA KUMAR SAIF HASAN RIZVI SAURABH HATHIA PRASHAM BHUTA CHETAN MUNDHAVA JIGNAV CHAUDHARI

09BT01079 09BT01106 09BT01078 09BT01064 09BT01105 09BT01217 09BT01129

SCHOOL OF PETROLEUM TECHNOLOGY PANDIT DEENDAYAL PETROLEUM UNIVERSITY GANDHINAGAR, GUJARAT, INDIA

CONTENTS

Certificate by internal / external guide Acknowledgement List of Tables, if any List of Figures, if any Abbreviations used, if any

(TITLE AND SUBTITLE WILL BE IN THE FOLLOWING FORMAT) 1. Chapter I - INTRODUCTION 1.1. XXXXXX 1.2. YYYYYYY.. 2. Chapter II XXXXXXXXXXXXXXX 2.1. XXXXXXXXXX.. 2.1.1. XXXXXXX.. 2.1.2. XXXXXX 2.1.3. 3. 4. 5. Chapter III Chapter IVChapter VXX 1

Certificate--

AcknowledgementWe wish to express our sincere gratitude to School of Petroleum Technology, Pandit Deendayal Petroleum University for providing us with the opportunity to, carry out the project under their guidance and support. We thank all the university personnel involved in the arrangement of the above mentioned programme including, but not limited to Prof. Paritosh Banik (Director General, PDPU) and Dr. Anirbid Sircar (Director, SPT - PDPU) . We are extremely grateful to our mentor and guide Dr. Ajit Kumar N. Shukla, for his valuable contributions and thoughtful guidance throughout the gamut of our project work.

IntroductionDefining the Problem of Stuck Pipe Drilling a well requires a drill string (pipe & collars) to transmit the torque provided at the surface to rotate the bit, and to transmit the weight necessary to drill the formation. The driller and the directional driller steer the well by adjusting the torque, pulling and rotating the drill string. When the drill string is no more free to move up, down, or rotate as the driller wants it to, the drill pipe is stuck. Sticking can occur while drilling, making a connection, logging, testing, or during any kind of operation which involves leaving the equipment in the hole.

We can define: MO (maximum overpull): the max. force that the derrick, hoisting system, or drill pipe can stand, choosing the smallest one. BF (background friction): the amount of friction force created by the side force in the well. FBHA: The force exerted by the sticking mechanism on the BHA (Bottom Hole Assembly)

The drill string is stuck if BF + FBHA > MO

The drill string is stuck when the static force necessary to make it move exceeds the capabilities of the rig or the tensile strength of the drill pipe. A stuck pipe can result in breaking a part of the drill string in the hole, thus loosing tools in the hole. The consequences of a stuck pipe are very costly. They include:

Lost drilling time when freeing the pipe. Time and cost of fishing: trying to pull out of the hole the broken part of the BHA. Abandon the tool in the hole because it is very difficult or too expensive to remove it.

When the pipe becomes stuck, there are two key actions that will best influence the chance of freeing the pipe: Determination of the cause of the stuck pipe incident. The initial response of the Driller and subsequent actions taken.

Table 1: Pipe Sticking Mechanisms and Causes

There are basically two mechanisms for pipe sticking: 1. Differential Sticking 2. Mechanical Sticking

Mechanical sticking can be caused by: Hole pack off or bridging, Formation and BHA (wellbore geometry)

Differential StickingCAUSES OF DIFFERENTIALSTICKING During all drilling operations the drilling fluid hydrostatic pressure is designed and maintained at a level which exceeds the formation pore pressure by usually 200 psi. In a permeable formation, this pressure differential (overbalance) results in the flow of drilling fluid filtrates from the well to the formation. As the filtrate enters the formation the solids in the mud are screened out and a filter cake is deposited on the walls of the hole. The pressure differential across the filter cake will be equal to the overbalance. When the drillstring comes into contact with the filter cake, the portion of the pipe which becomes embedded in the filter cake is subjected to a lower pressure than the part which remains in contact with the drilling fluid. As a result, further embedding into the filter cake is induced. The drillstring will become differentially stuck if the overbalance and therefore the side loading on the pipe are high enough and acts over a large area of the drillstring. This is shown diagrammatically in Figure 1.

Figure 1: Differential Sticking

The signs of differential sticking are the clearest in the field. A pipe is differentially stuck if: Drillstring cannot be moved at all, i.e. up or down or rotated. Circulation is unaffected

Mathematically, the differential sticking force depends on the magnitude of the overbalance and the area of contact between the drillpipe and the porous zone. Hence, Differential force = (mud hydrostatic formation pressure) x area of contact

Figure 2: Magnitude of differential Sticking force

Hence for the data shown in Figure 2, and assuming the formation contacts only 4" of the drillpipe perimeter, then the differential force is given by: Differential Force = (5000-4000) psi x 4 x 00 = 1,200,000 lb

The force required to free a differentially stuck pipe depends upon several factors, namely: The magnitude of the overbalance. This adds to any side forces which already exist due to hole deviation. The coefficient of friction between the pipe and the filter cake. The coefficient of friction increases with time, resulting in increasing forces being required to free the pipe with time. Hence, when differentially stuck, procedures to free the pipe must be adopted immediately. Figure 3 shows the coefficient of friction vs. time for a bentonite filter cake which shows a 10 fold increase in less than 3 hours.

Figure 3: Increase in friction factor with time

The surface area of the pipe embedded in the filter cake is another significant factor. The greater the surface area, the greater the force required to free the pipe. Thickness of filter cake and pipe diameter will obviously have a great effect on the surface area. It is for reasons of reducing available surface area that spiral drill collars are often specified when drilling sections which exhibit the potential for differential sticking problems. Statistically, differential sticking is found to be the major cause of stuck pipe incidents, hence great care should be taken in the planning phase to minimize the overbalance wherever possible. However, in certain circumstances, drilling with minimum overbalance is not be possible, as is the case for large gas reservoirs where the pressure differential across the reservoir starts at the minimum overbalance (200 psi) and increases substantially with depth to a maximum of 1300 psi. In these cases, strict adherence to precautionary drilling practices and good communication between personnel will help reduce the incidence of stuck pipe.

Freeing Differentially Stuck Pipe.

There are basically two ways in which a differentially stuck pipe can be released: Reduction of hydrostatic pressure Spotting pipe release agents

REDUCTION OF HYDROSTATIC PRESSURE The reduction of hydrostatic pressure is the obvious and most successful method of freeing a differentially stuck pipe. The lowering of the hydrostatic pressure reduces the side loading forces on the pipe and therefore reduces the force required to free the pipe from the filter cake. There are several methods by which this may be achieved. However prior to implementing this action the following factors should be seriously considered: 1. Are there other pressured zones in the open hole section? 2. Will these exposed zones kick if the hydrostatic pressure is reduced? 3. The confidence level in the accuracy of pore pressure estimates made while drilling and the pressure control equipment. 4. The effects of a reduction in hydrostatic pressure on the mechanical stability of all exposed formations. 5. The volumes of base oil or water required to achieve the required reduction in hydrostatic pressure. (This may well influence the method chosen). All the above factors need to be carefully considered prior to reducing the hydrostatic pressure as the potential for inducing well control problem or formation instability are considerably increased. The following methods for reducing hydrostatic pressure can be used: Circulation & reducing mud weight Displacing the choke The U tube method

CIRCULATION & REDUCING MUD WEIGHT In this method, the drilling mud is circulated and its weight is gradually reduced. The minimum mud weight required to balance the highest pore pressure in open hole should be determined and the mud weight cut back in small stages. Close attention must be made to all kick indicators whilst circulating down (reducing) the mud weight, frequent flow checks should also be made. Whilst reducing the mud weight, tension should be held on the pipe. Disadvantages of these methods are: It is slow, and remembers the force required to free pipe is time dependent. The volume increase required may overload the surface pit handling capability. This maybe a serious problem when OBM is used. The active volume will be increasing during the reduction in mud weight, making kick detection difficult.

DISPLACING THE CHOKE This method is applicable to floating rigs where BOPS are placed on the seabed. The hydrostatic pressure can be quickly and effectively reduced by displacing the choke line to base oil or water. The well is shut in using the annular preventer and the displaced choke line opened thereby reducing the overbalance. Note that the annular preventer isolates the wellbore from the hydrostatic head of mud in the riser from rig floor to the annular preventer. The advantage of this method is that if any influx is taken, the well can be immediately killed by closing the choke and opening the annular. This action again exposes the well to the active hydrostatic pressure from rig floor to TD. The disadvantage of this method is that the amount of reduction in hydrostatic pressure is limited to the water depth. This may well result in a limited reduction in shallow water, or in the case of deep water, an excessive reduction in hydrostatic pressure.

THEU TUBEMETHOD The U-tube method is used to reduce the hydrostatic pressure of mud to a level equal or slightly higher than the formation pressure of the zone across which the pipe got differentially stuck. the objective is to free the differentially stuck pipe safely without losing control of the well by inadvertently inducing underbalanced conditions. A pipe free agent should be spotted across the permeable zone prior to adopting the U tube method. SPOTTING PIPE RELEASE AGENTS The severity of differentially stuck pipe can be reduced by the spotting of pipe release agents. Pipe release agents are basically a blend of surfactants and emulsifiers mixed with base oil or diesel oil and water to form a stable emulsion. They function by penetrating the filter cake, therefore making it easier to remove and at the same time, reduce the surface tension between the pipe and the filter cake. Due to the time dependency of the severity of differential sticking, the pipe release agent should be spotted as soon as possible after differential sticking is diagnosed. Typically the pill will be prepared whilst initially attempting to mechanically free the pipe; i.e. by pulling and rotating.

Mechanical Sticking

CAUSES OF MECHANICAL STICKING

In mechanical sticking the pipe is usually completely stuck with little or no circulation. In differential sticking, the pipe is completely stuck but there is full circulation. Mechanical sticking can occur as result of the hole packing off (or bridging) or due to formation & BHA (wellbore geometry). Hole-pack-off (bridging) can be caused by any one or a combination of the following processes: Settled cuttings due to inadequate hole cleaning. Shale instability. Unconsolidated formations. Fractured and faulted formations. Cement blocks. Junk falling in the well.

The formation & BHA (wellbore geometry) can also cause mechanical sticking as follows: Key seating Mobile formations Under-gauge hole Ledges and micro doglegs

Understanding the cause of the mechanical sticking problem is key to solving the problem. This is because the cause determines the action required to free the pipe. For example, if the pipe

becomes stuck while running in an open hole, it is likely that the BHA has hit a ledge or gone into an under-gauge hole. In other words, the sticking problem is due to the geometry of the wellbore. As will be seen later, the freeing action depends largely on identifying and curing the problem that caused mechanical sticking. A discussion of each of the above processes will now follow. HOLE-PACK-OFF CAUSES

SETTLED CUTTINGS Settled cuttings due to inadequate hole cleaning (Figure 4) is one of the major causes of stuck pipe. Best hole cleaning occurs around large OD pipe such as drill collars, while cuttings beds can form higher up the hole where the pipe OD is smaller. The problem of settled cuttings is particularly severe in horizontal and high directional wells. In these wells, when the pipe is moved upwards, the cuttings may be compacted around the BHA. This can result in complete packing off of the drillstring and eventual pipe sticking.

Figure 4: Settled Cuttings Due To Poor

With increasing deviation of the wellbore, drilling fluid parameters, drilling practices and hydraulics should be optimized in order to effectively clean the hole. In vertical wells, good hole cleaning is achieved by the selection and maintenance of suitable mud parameters and ensuring that the circulation rate selected results in an annular velocity (around 100-120 ft/min) which is greater than the slip velocity of the cuttings. Highly inclined wells are particularly difficult to clean due to the tendency of drilled cuttings to fall to the low side of the hole. In a highly deviated well, the cuttings have only a small distance to fall before they settle on the low side of the hole and form a cuttings bed. Cuttings beds develop in boreholes with inclinations of 30 degrees or greater, depending on the flow rates and suspension properties of the drilling fluid. Complete removal of cuttings beds by circulation may be impossible. Once cuttings beds have formed, there is always a risk that on pulling the pipe up the hole, the cuttings are dragged from the low side of the hole forming a cuttings pile (Figure 4). If this pile accumulates around the BHA, it may plug the hole and cause the pipe to mechanically stuck. Besides causing stuck pipe, settled cuttings can result in: formation break down due to increased ECD slow ROP excessive over pull on trips increased torque

Hole cleaning is controlled by a number of parameters, these include: Mud rheology, in particular the YP and gel strength Flow rate Hole angle Mud weight ROP Hole diameter Drillpipe rotation Presence of wash outs

SHALE INSTABILITY Shale represents 70% of the rocks encountered whilst drilling oil and gas wells. Also shale instability is by far the most common type of wellbore instability. Shales are classified as being either brittle or swelling. Brittle Shales

Figure 5: Safe mud weights envelope

Instability in brittle shales is caused mainly by tangential stresses around the wellbore which are induced as a result of the well being drilled. The induced stresses depend on the magnitude of the

in-situ stresses, wellbore pressure, rock strength and hole angle and direction. Formation dip may also be a contributory factor to brittle shale failure. A safe mud envelope may be established which can be used to determine the safe mud weights to prevent either tensile failure or collapse (compressive) failure. Brittle shales tend to fail by breaking into pieces and sloughing into the hole. Rig indications of brittle shale failure include: large amounts of angular, splintery cavings when circulating the well drag on trips large amounts of hole fill.

Swelling Shales

Figure 6: Swelling of reactive shales

Shales swelling (Figure 6) can be caused by hydrational processes or by the osmotic potential which develops between the pore fluid of the shale and drilling fluid salinity. The swelling of shales (Figure 6) is controlled by several complex factors including: Clay content Type of clay minerals (ie hydratable or inert) Pore water content and composition Porosity

In-situ stresses Temperature

The degree of clay hydration depends on the clay type and the cation exchange capacity (CEC) of the clay content. The greater the CEC, the more hydratable is the clay. In drilling operations the following clay types are encountered: Smectite with CEC of 80-150 meq/100g. Most of the hydratable shales (termed gumbos) belong to this group. Bentonite clays belong to the smectite group. Illite with CEC of 10-40 meq/100g. Chlorite with CEC of 10-40 meq/100g. Kaolinite with CEC of 3-10 meq/100g.

To aid the understanding of shale swelling, the following points must be considered: The permeability of shales is very low, typically in the range of 10-9 to 10-6 Darcy. (1 md = 1013m2) Thus, filter cakes do not form on shale surfaces. However, water can still migrate into the shale (helped by the mud overbalance). Water infusion into the shale will allow chemical effects to start working inside the shale and at the exposed surfaces of the wellbore. The pore pressure inside the shale section will also increase, contributing to destabilization. The low permeability of shale means that swelling effects can take considerable time and shale instability can be a delayed effect.

Water can flow into or out of the shale through several processes; the most important ones are hydrational and osmotic forces: Hydration: This is by far the most common cause of shale hydration where water flows into the shale and hydrate the clay plates. Highly hydratable shales are composed of predominantly smectite- based clays. These clays (e.g. montmorillonite) absorb water into the inner-layer space due to the high negative charge on the surface of the clay platelet. This process results in the expansion of the clay to several times its original volume. Hydratable shales are usually found near the surface, ft. At grater depths, the process of diagenesis converts the clay minerals into more stable forms. However, hydratable shales have been found in some wells at depths greater than 7000 ft due to the inhibition of the diagenetic processes. Chemical osmosis: This type of flow occurs at semi-permeable membranes which are permeable to water and impermeable to solute ions or molecules. Shale surface acts as a semi-permeable membrane allowing water to flow into or out of the shale depending on the solute concentration of the mud and pore water of the shale. Water flows through the semi-impermeable membrane from the low concentration to high concentration solution. In terms of chemical jargon, water flows from solutions of high water activity to solutions of low water activity until the concentrations of the two solutions are equalized. (Water activity (aw): ratio of vapour pressure of water in a solution, drilling mud or shale pore water to the vapour pressure of pure water at the same temperature.) Chemical diffusion: This is caused by the flow of solutes (soluble solids) from areas of high concentration to low concentration. Hence if the concentration of certain ions or molecules inthe drilling mud is greater than those in the formation water of the shale then the solute will flowinto the formation provided there are no barriers to flow. Solutes can also flow outof the shale if their concentration is greater than that in the drilling mud. No flow will occur ifsolute concentration is the same in mud and shale. Hydraulic diffusion; water flows in the direction of decreasing hydraulic pressure gradient (Darcys Law). This flow can only occur if the rock has permeability.

Shale hydration Rig Site Indications Soft, hydrated or mushy cuttings Clay balls in the flow line Torque and drag fluctuations Shale shaker screens blind off Increase in LGS, filter cake thickness, PV, YP and MBT (Methylene blue test) Increase or fluctuations in pump pressure Circulation is restricted or sometimes impossible Bit and stabilizer balling when POH Generally occurs while POH (Tight hole) and problems while logging Problems increase with time.

Shale hydration Prevention and Cure Use Inhibited mud system or displace to OBM system if possible Maintain mud properties as planned Addition of various salts (potassium, sodium, calcium) willreduce chemical attraction between shale & water Addition of encapsulating polymers to WBM Reduce exposure time and case off the hydrated shale as soon as possible Regular wiper trips Good hole cleaning (especially in extended reach wells, ERW)

UNCONSOLIDATED FORMATIONS

Figure 7: Collapse of unconsolidated formations

Unconsolidated formations are usually encountered near the surface and include: loose sands, gravel and silts. Unconsolidated formations have low cohesive strengths and will therefore collapse easily (Figure 7) and flow into the wellbore in lumps and pack off the drillstring. Surface rig indications of an impending stuck pipe situation near top hole are: increasing torque, drag and pump pressure while drilling. Other signs include increased ROP and large fill on bottom. A common remedial action is to use a mud system with an impermeable filter cake to reduce fluid invasion into the rock. Reduction of flow rate, and in turn annular velocity, will reduce erosion of the hole and removal of the filter cake.

FRACTURED AND FAULTED FORMATIONS This is a common problem in limestone and chalk formations. Several symptoms can be observed on surface including: large and irregular rock fragments on shakers increased torque, drag and ROP small lost circulation

These fractured and faulted formations may fall into the Wellbore as soon as they are drilled as the stresses which originally held them together are relieved by the drilling of the hole. In addition, excessive drillstring vibrations cause the pipe to whip down-hole and break and dislodge the exposed fractured/faulted rocks. Therefore it is important to reduce drillstring whipping to prevent dislodging of rock fragments when drilling fractured and faulted rocks. In all cases, it is imperative to keep the hole clean in order to reduce the chances of hole packing off. If the drillstring is stuck in limestone or chalk formations and cannot be freed by jarring, an inhibited hydrochloric acid pill may be spotted around the stuck zone. The acid will react with the chalk/limestone, dissolving the rock around the pipe. If the pill is successful the pipe will be freed quickly. CEMENT BLOCKS Stuck pipe can be caused by cement blocks falling from the rat hole beneath the casing shoe or from cement plugs. Cement plugs were discussed in detail in Chapter 6.This problem may be prevented by minimizing the rat hole to a maximum of 5 ft and also by ensuring a good tail cement is placed around the shoe. The drillstring can also be stuck in green cement which has not set properly. This usually occurs after setting a cement plug inside the casing or open hole. If the drillstring is run too fast into the top of the cement and if the cement is still green then the cement can flash set around the pipe and cause the pipe to be permanently stuck.

The author has come across several situations where the top of the cement is soft when tagged, but literally within seconds of tagging the cement, the cement flash sets around the BHA causing mechanical sticking. One possible explanation for this sudden flash setting is that the energy release while circulating and rotating is enough to cause flash setting. It is recommended that circulation is started two to three stands above the expected top of cement and that WOB should be kept to absolute minimum.

JUNK Several recorded incidents of pipe sticking occurred as a result of junk falling into the hole. This includes junk falling into the wellbore from the surface or from upper parts of the hole. Typical junks dropped from surface include pipe wrenches, spanners, broken metal, hard hats etc. This problem can be minimized by keeping the hole covered when no tools are run in the hole. Junks can also fall from within the well including broken packer elements, liner hanger slips and metal scarf from milling operation.

FORMATION AND BHA (WELLGEOMETRY) CAUSES KEYSEATING

Figure 8: Ket Seating

Key seating (Figure 8) is caused by the rotating drillstring coming into contact with soft, easily drillable formations. The rotational action causes the tool joint to erode a narrow groove in the formation which is approximately equal to the diameter of the drill pipe tool joint. The created groove or slot is smaller in size than the larger BHA components below. When pulling out of hole (POH), the BHA may be pulled into the narrow -sized key seat resulting in BHA being stuck. Key seats are often seen in soft formations or in wells with ledges and doglegs. The doglegs and ledges allow the drillstring to bend and provide points of contact between the tool joint and the walls of the hole. Key seats may also develop in casing shoes in highly deviated wells. Pipe stuck in a key seat can be recognized by the following symptoms: Circulation is free when the pipe is stuck Hole is tight on tripping out only.

Tight hole position can be correlated with the positions of large OD members of the BHA. Tight hole will occur at the same depth on trips.

Pipe stuck in a key seat must be worked and jarred downwards (and only downwards) until free movement and rotation is established. Once the drillstring isfree in a downwards direction, the string should be slowly pulled past the key seat using minimum tension and slow rotation. MOBILE FORMATIONS The term mobile or plastic formations usually refer to halites and claystones. These formations posses plastic properties enabling them to deform and flow under applied stress. The majority of problems encountered in mobile formations have been across halite (salt) sections12.9. Salt is encountered in drilling operations from pure sodium chloride to very complex blends of mixed chloride salts. The main salt types are Halite (NaCl) Sylvite (KCl) Bischofite (MgCl26H2O) Carnalite (KMgCl36H2O) Polyhalite (K2MgCa2(SO4)42H2O) Tachydrite (CaCl2MgCl212H2O)

Order of Precipitation 1. Carbonates: calcites and dolomites. Some dolomite reservoirs formed 2. Sulphates: anhydrite and gypsum. These rocks have poor porosity and permeability and therefore act as perfect seals. 3. Chlorides: Halites 4. Mixed Salts: carnalite, bischofite, sylvite and kieserite

Salt problems

The main problems from salt sections are: Salt washout Salt movement & casing collapse

SALT WASHOUT When water-based muds (WBM) are used to drill salt sections the water phase of the WBM dissolves the salt causing a large washout in the hole, Figure 9. Factors affecting salt washout are summarized as follows: Salts generally have a high solubility in water Large washouts are usually found across complex salt sections Washouts beyond current caliper logs limit (22") have been observed Sodium chloride saturated drilling fluid will dissolve potassium, magnesium and calcium salts.When Mg, K and Ca ions in the mud increase, the rate of solution will decrease and no further washing out of the salt occurs (probably too late by then) Mixed salt mud systems were used as drilling fluids, but have largely failed to become standard.This is because these systems rae designed to be saturated for particular ions at surface conditions. At bottom hole conditions, the temperature is high and further dissolution of salt occurs. Mixed salt systems are also costly and difficult to maintain. OBM is usually the best drilling fluid for preventing salt washout.

SALT MOVEMENT Salt movement (or creep) is a very complex process and is controlled by several factors relating to depth, temperature, earth stresses and water content. The following points summarize the current knowledge regarding salt movement around oilwells. Salt behaves like a super-viscous fluid Rate of movement of the salt section depends on depth, temperature, composition, water content and impurities

Halites are relatively slow moving

Figure 9: Salt Plastic Deformation (left) And Washout (right)

Movement rate can be as high as 1"per hour (pipe gets stuck while drilling) More complex salts containing more water content give more movement than pure halites. Flow of salt can be into or out of the well depending on mud hydrostatic pressure. Mud weights should always be designed to hold back salt movements into the wellbore. Anhydrites and carbonates underneath salt sections are immobile The main problems caused by salt movement are casing collapse and stuck pipe while drilling.

Drillstring stuck in salt sections while drilling can be easily freed by spotting a water pill around the stuck zone to dissolve the salt and free the pipe. Large washouts and poor cement jobs usually result when water pills are used to free stuck pipe in salt sections. SALT- INDUCEDCASING COLLAPSE If the movement of the salt is into the wellbore, it will cause the drillstring or any pipe in hole to be stuck. If the salt movement occurs after the well is drilled, it is likely that the salt will, in time, contact the casing and subject it to extremely high forces. These forces can, in some recorded cases, be greater than the collapse strength of casing resulting in casing failure by collapse. The actual problem results when mobile salt is washed out during drilling leaving a hard ledge of carbonate or sulphates as the only rock in the washed out section. When casing is run and cemented, it is likely that the washed out section will be poorly cemented or not cemented at all.

Salt movement starts as soon as drilling and cementing operations stop. This movement causes the ledges in the washed out section to move, contact and subject the casing to point loadings. These point loads can be extremely high and often exceed the collapse strength of casing, causing it to fail in collapse. It has been reported that the magnitude of these point load forces can be as high as 19,000 psi. Casing collapse by salt is called Salt-Induced Casing Collapse (SICC), Figure 10. Several wells in the Southern North Sea and Gulf of Sues have suffered SICC.

Figure 10: Salt Induced Casing Collapse

Salt-induced casing collapse across mobile salt sections is the most common type of casing collapse observed in the oil industry. Other types of casing collapse have been observed in the following situations: During cementing when using high cement weights When casing is run partially or totally empty Due to fluid heating in the annulus. This is caused by collapsing pressures from excess pressure produced due to temperature effects. During inflow testing of liner laps

In all situations where SICC was recorded, the wells had to be sidetracked as either the internal diameter of the casing is greatly reduced or the casing is physically damaged beyond repair.

There are recorded incidents where casing collapse occurred during drilling operations causing the drillstring to be collapsed as well. The most common method of resisting SICC is to use heavy-walled casings rather than high collapse strength casings. Tests have shown that high tensile strength steels are more brittle and less effective across salt sections than thick-walled casings. Under the action of point loads, a heavy-walled casing with low tensile strength bends more easily than high tensile strength steels; ultimately failing but after a considerable long time compared with high tensile strength steels. It has been established that the casing creep resistance increases linearly with casing strength and to power two (square) with wall thickness. Another widely used solution in the Gulf of Suez (Egypt) is the use of concentric cemented casings across mobile salts. Practical tests showed that the combined collapse strength of the concentric casings is greater than the combined collapse strengths of the individual casings. This solution practically eliminated all problems relating to casing collapse across mobile salts but, of course, limited the size of the production casing. The authors recommendation is to always use heavy walled casings across mobile salt sections.

UNDER-GAUGE HOLE

Figure 11: Under-gauge Hole

The drilling of abrasive formations such as sandstones can result in bit and stabilizer gauge wear. This loss of gauge (diameter) causes an under-gauged hole to be drilled. Development of undergauge hole is to be avoided as it results in costly reaming operations on the subsequent bit run. In addition, incidence of stuck pipe has occurred as a result of running full gauge bits and stabilizers into the under-gauge section, Figure 11. Extra caution should always be exercised when tripping in the hole after pulling an under-gauge bit. MICRO DOG-LEGS AND LEDGES Micro doglegs and ledges develop when drilling formations of varying strengths or dipping formations. A gauge hole is drilled in the harder zone and an oversized hole, caused by fluid erosion, is drilled in the softer zone. This oversized hole causes the bit and the BHA to be deflected to the low side of the hole causing a small dogleg when the next hard section is drilled. The drilling of several successive layers of varying strengths result in both hole ledges and micro -doglegs to develop.

Fishing OperationsOnce the pipe is backed off or severed as outlined in the previous section, the remaining portion of the drillstring is called the "fish". Oil well fishing is defined as the process of retrieving a stuck pipe which is left in hole after back-off or twist off operations. Fishing involves running a set of equipment to the top of the fish, engaging it and then retrieving it.

FISHING EQUIPMENT The standard fishing assembly should comprise the following elements: Fishing Tool - Bumper Sub - Jar - DCs - Accelerator - HWDP Circulating sub - DP. The actual assembly chosen will depend upon tool availability and the specific situation encountered.

FISHING TOOLS

OVERSHOTS

Figure 12: Overshots

An overshot (Figure 12) is used for engaging, packing off and retrieving a tubular fish. A basic overshot consists of three parts: top sub, bowl and guide, The overshot can be dressed with a spiral grapple if the fish OD is close to the maxi-mum catch of the overshot or a basket grapple if the fish diameter is around 1/2" below maximum catch size.

The bowl of the over-shot is designed with helically tapered spiral section in its inside diameter where the gripping member (spiral grapple or basket grapple) is fitted. The spiral grapple is a helical spring the basket grapple is a segmented, expandable cylinder. The grapple is held inside the bowl by a grapple control and a guide shoe. The inside surface of the grapple has a whickered surface and has a slightly smaller circumference than the fish it is designed to catch. To engage the fish, the overshot is rotated to the right and lowered onto the top of the fish. The grapple will expand when the fish is engaged, allowing the fish to enter the grapple. Rotation is then stopped and an upward pull exerted to allow the grapple to be contacted by the tapers in the bowl and its deep wickers to grip the fish firmly. The fish is released by a sharp downward bump, rotation to the right and slowly elevating the overshot. SPEARS

Figure 13: Fishing Spears

Spears are used to catch and engage the fish internally. A fishing spear typically consists of: a mandrel, grapple or slip segments, release ring, and a nut, Figure 13.

A spear containing slip segments has its body machined into several stages of identical cone sections; this surface is matched by tapered surfaces on the slip segments. This design allows the slip segments to expand when moved downwards relative to the body of the tool. Both the grapple and slips type designs are run in hole in the retracted position by the use of J slots or appropriate mechanisms. When the spear enters the fish, the spear is rotated to the right to release the slips or grapple placing them in the engaging position. A straight pull will then wedge the grapple or slips into positive engagement with the fish. Release of the spear is achieved by bumping downwards and rotating the string two to three turns to the right. BUMPERSUBS Bumper Subs are used to provide upwards or downwards blows to the stuck drillstring. The main component of the bumper sub is a hexagon-shaped mandrel which slides in a similar shaped mandrel body to provide continuous torque capability. Most tools have a standard 20" stroke but longer strokes designs are also available. Bumper Subs are designed to bump down, jar up, or help disengage a fish after retrieval. If used, the bumper sub should be installed immediately above the fishing tool for maximum effect. Bumper subs are most effective at shallow depths and in vertical wells drilled from floating rigs. JARS Jars provide a means of supplying powerful upward or downward blows to the drillstring. There are two types of jar, mechanical and hydraulic, see Chapter 10for details. JAR ACCELERATORS An accelerator (see Chapter 10) concentrates the jarring action within the drill collars above the jar, preventing the jarring force from dissipating up the string. This results in a higher hammer velocity which increases both impact and impulse of the jarring action.

MISCELLANEOUS FISHING EQUIPMENT

WASH-OVER STRINGS

Figure 14: Washover operation

Figure 15: Rotary Shoes

A wash-over string (Figure 12.14) is run if an overshot and jarring assembly fails to remove the fish. Wash-over strings are generally used to remove debris that is surrounding a fish. It may be required in any of the following instances: Where the formation has bridged and stuck the string. Where the string has become cemented. To dress the top of OD of a fish in preparation for running a fishing tool. Casing has collapsed on the pipe and mud solids are accumulating on the stuck point.

The wash-over string is a pipe with an ID larger than the OD of the fish and is run with a rotary shoe, Figure15. IMPRESSIONBLOCKS

Figure 16: Impression Blocks

An impression block (Figure 16) is a short sub with a flat bottom covered with a soft layer of lead. An impression block is run into the hole to ascertain the shape of the fish inside the hole in order to determine the appropriate fishing tool to run. TAPER-TAPS AND BOX-TAPS

Figure 17: Taper tap and box tap

Taper taps (Figure 17) are used to engage the inside of a fish when the use of a conventional releasing spear is not feasible. It is designed to cut threads into the steel so that the fish can be retrieved or the fishing job continued. A box tap functions the same way as a taper tap, except it is designed to engage the outside diameter of the fish.

FISHING ECONOMICSThe option of abandoning fishing operations and sidetracking the well should be taken on economic grounds unless there are exceptional logistical, legislative or safety grounds. Before giving up on a fishing job the cost of sidetracking operations together with re-drilling to the original depth needs to be calculated. This cost when converted to equivalent rig day rate days can be used to assess the amount of time that it is economic to pursue fishing operations. The procedure is as follows: a) Calculate the total cost of the fish to be left in hole. b) Calculate the cost of backing-off and setting of a cement plug prior to sidetracking. This c) should include all rental and consumable items, including personnel. d) Calculate the cost of the sidetrack including directional equipment and casing milling equipment (if applicable). e) Calculate the cost of drilling to the original depth. This should be based on the time to drill the original section plus an additional 10%to account for the directional aspects.

Total cost is therefore = a + b + c + d.

This should be converted to rig days by dividing the total cost by the rig day rate. Abandonment of fishing operations should be considered when the fishing time has reached the above number of days, and the probability of completing the fishing operation is gradually becoming small.

Early Detection Of Stuck PipeIntroduction A system for real time monitoring of wellbore friction using surface measurements logged by a computer system in order to give advanced warning of changing borehole conditions before they result in stuck pipe. The basis of the friction monitoring system is a method of recording representative values of hook load and torque to produce depth indexed "profiles" of expected values for a particular well. The profiles form a template which serves to indicate when measurements exceed expected values and conditions are worsening. A "Smart Alarm" has been developed to detect these differences and to trigger a warning directly to the driller. Automatic processing of hook load and torque measurements while drilling identifies anomalies which may be indicative of sticking problems. As part of the MDS* System, a friction monitor is being developed to address the stuck pipe problem by giving the facility, when tripping, to display directly to the driller an expected hook load profile which has been I calculated from previous trips and from connections made while drilling. Some previously reported techniques for monitoring wellbore friction utilize down hole and surface measurements to obtain losses due to friction. FRICTION MONITOR FUNCTION The monitor performs the following five key functions during tripping and drilling operations : (1) Generation of new pull-out-of-hole and run in- hole profiles. These are sets of reduced data with each point representing the averaged hook load over a preset depth range. The monitor performs signal processing to ensure that accurate, repeatable values are logged. The recorded profiles can be analyzed off-line using a workstation which is included as part of the computerized monitoring system. (2) If, during tripping, the display is indexed against depth, the expected hook load profile is displayed over the entire depth range of the screen to give advanced warning of possible problem zones. (3) If the tripping display is indexed against time, a log of the expected hook load at the current time is displayed in addition to the actual hook load. (4) Generation of over pull indication for the driller's display during tripping using the depth Indexed hook load profiles as the baseline measurement. (5) Raise alarm to warn the driller of increasing trend in over pull or slack-off during tripping and in over pull at connections when drilling.

OPERATION OF THE MONITOR

The basis of the friction monitor is a system of recording representative values of hook load under similar conditions to produce profiles of expected hook load for a particular well. The profiles are generated by continuous monitoring of the string-speed, rpm, slip-status and bit position (on or off bottom) as shown schematically in Figure 1.

This allows the status of the system to be continuously monitored and data can be added to the profiles whenever the system is logging valid data for a particular profile type. For example, to add a data point to the pull-out-of-hole profile, the following conditions must be satisfied : (1) Bit is off bottom. (2) Drill-string velocity is upwards at a speed greater than a predefined minimum but less than an upper limit. (3) Drill-string is not rotating. (4) Above parameters must hold true for a preset time interval.

Before the profile point is generated by averaging data logged when the above conditions are detected, the values are filtered to exclude transient values. In some cases, this contains useful information which may be incorporated in future releases. By carefully selecting the logged values, the aim is to generate a depth indexed profile of accurate, repeatable data points against which future information will be compared. The same approach, but using different parameters, is used to obtain profiles for running-in-hole and rotating-off-bottom hook load as well as for off-bottom torque. Generation of pull-out-of-hole and run-in-hole profiles using field drilling data over two connections is illustrated in Figure 2. Before making each connection, the pipe is lifted off bottom and reciprocated over a few meters, as shown by the elevator position changes around 4 minutes and 36 minutes plotted in Figure 2a. The slip events are marked by the rapid hook Ioad drops shown 'in Figure 2b at 7 minutes and at 38 minutes. The reciprocation of the drill string is detected by the friction monitor for a sufficiently long interval that accurate pull-out of-hole and run-in-hole profile values can be obtained. The values which are appended to the corresponding hook load profiles are shown in Figure 2c. The increase in the pull-out-of-hole (POOH) and reduction in run-in-hole (RIH) values for the second stand show that there has been a slight increase in borehole friction conditions. This is easily seen by noting the increase in "A2" over "Al", which are the differences between the pull-out and run-in profiles at each connection in Figure 2c.

As drilling progresses and the appropriate string movement conditions are detected, depth indexed profiles are built-up over the drilled depth range. These can be analyzed on a workstation and can be compared with other channels which help to diagnose the cause of the excess hook load as shown in Figure 3

When the driller starts to pull out of hole, the expected hook load profile is immediately visible to give a hook load prediction during the trip. Since the expected hook load is displayed ahead of time, the driller has advanced warning of problem zones and so can plan the trip accordingly. With the display indexed against depth, the expected hook load profile is displayed along with

the actual hook load and gives a prediction of the anticipated hook load behavior during the trip. AUTOMATIC ALARMS When tripping, the system automatically monitors the string length tripped and the volume change measured in the trip tank. The friction monitor uses the hook load profiles to identify trends of increasing friction. A "Smart Alarm" system then warns the driller of worsening friction conditions while tripping and of worsening connection over pull while drilling in the following way: (a) While tripping, a check is made on the measured profile to identify a trend of increasing hookload (as recorded in the profile) while pulling out of hole or decreasing hook load while running in hole. If a significant trend is detected, then an alarm is raised. The driller can change the alarm sensitivity to make the trend detection proportionately more or less sensitive. If hookload data from previous trips or from drilling is available, then an alarm will be generated if the new measured profile value is significantly different from the expected profile value at the same depth. (b) While drilling, the friction monitor continues to build and extend hook load profiles every time the correct string speed conditions are detected when the bit is off bottom for example when making a connection. An alarm is raised if an increasing trend in hookload is detected in this new profile. (c) While running casing, the monitor warns of worsening hole conditions by detecting trends in the profile which is generated during the casing run. DIAGNOSING THE PROBLEM In addition to forming profiles of hookload or torque data with which to compare current measurements, there are often additional friction indicators which warn of potential problems while drilling. The hookload data shown in Figure 5a, was recorded by the computerized monitoring system until drilling had reached 6778 R (2066m) in a fairly unstable clay stone formation. When penetration rate dropped, a decision was made to trip, however after pulling one stand the pipe became stuck on slips despite an over pull of 75 klbs (333 kN). Detailed analysis of the drilling data shown in Figure 5 shows how monitoring a variety of data channels can identify signs that friction is worsening during drilling operations. The hookload profiles which are shown as dotted lines in Figure 5a give clear evidence that friction is increasing, in this case probably caused by unstable formation that is falling into the hole and packing off the BHA. The pull-outof- hole profile has increased by over 22 klbs (100 kN) while drilling the final two stands and the gap between the run-in-hole and pull-out-of hole measurements has increased by a similar amount. In Figure 5b, monitoring standpipe pressure and torque during a one hour period prior to tripping and comparing it with an earlier one hour drilling period gives further indications that borehole conditions are deteriorating. During the earlier period, both torque and standpipe

pressure are reasonably uniform. During the later period, however, there are several pressure pulses of up to 50 psi (0.34 MPa). These are thought to indicate temporary blocking of the annulus by sloughing formation. Sometimes the pulses correlate with spikes on the torque log indicating simultaneous grabbing of the BHA. Later analysis using signal processing techniques has shown that the torque and standpipe pressure indicators can be combined into a diagnostic to warn of worsening borehole condition, as shown in Figure 5c.

Conclusions A technique based on the use of depth indexed "profiles" of data logged during previous trips and when drilling has been described. These profiles act as a template against which current measurements can be compared to warn of changing borehole conditions. The monitoring system is used in conjunction with modem display techniques and has two key functions : (1) To warn the driller and other rig personnel of possible problem zones when tripping. (2) To alert them to increased likelihood of pipe-sticking while drilling and while tripping.

Practical Method To Minimize Stuck PipeIntroduction An integrated sticking pipe monitor which automatically calculates friction forces and factors, anytime the drillstring is moving, builds normal profiles with depth for comparison and issues alarms to the field crew and driller when sticking is occurring at the BHA. A new comprehensive approach which tracks friction factors anytime the drillstring is moving. Starting from measurements of hookload, surface torque, down hole weight on bit and torque, the technique eliminates the effects of hole size, geometry and BHA, and leads to effects of hole size, geometry and BHA, and leads to computed values of sliding and rotating friction factors, which are then monitored during all drilling phases. Theory A friction factor is defined as the ratio of the force required to move an object, divided by the side force between the object and the surface on which it is resting. The forces on a drillstring section in a deviated wellbore are the buoyant weight of the element and the tension or compression forces on either end of the element. (Drillstring stiffness forces are not taken into account making the model inaccurate in build rates above 20 0/100 ft.) These forces can be used to compute a side force acting perpendicular to the wellbore path. If it were possible to measure the weight and torque loss across a single element, the friction factors could be calculated between the element and the formation using the following equations: DRAG = Weight Loss /Side Force FRIC = Torgue Loss or Pipe Radius/Side Force where DRAG is defined as the axial friction factor and FRIC is defined as the rotary friction factor.

Figure 1 shows the situation for all off bottom conditions including drilling connections, reaming and tripping.

Figure 2 shows the situation for all on bottom drilling conditions.

There are three distinct friction factors which should be tracked in time. they are: a) The axial friction factor (DRAG) while drillstring is moving axially without rotation (sliding) b) The axial friction factor (DRAG) while drillstring is moving axially while rotating (reaming) c) The rotary friction factor (FRle) while drillstring is rotating (whether moving axially or not) While moving the drillstring in the wellbore, the integrated drilling monitor automatically builds up profiles of friction factors versus measured depth for the above three categories. This is done by maintaining a running average of the real-time friction factors for each 500 foot depth interval for the entire well. It is reasonable to project the profiles ahead of the bit since friction factors do not change appreciably with depth.

DATA PRESENTATION AND INTERPRETATION Figure 4 shows a sample of the real-time display screen without data for explanation purposes. The data are plotted versus bit depth and up to 3 hours of information can be displayed. Traditional API gamma ray is plotted as a log in the first bottom track, sliding DRAG in the second track, reaming DRAG in the third track and rotating FRIC in the fourth top track. The gamma ray log is measured and transmitted by the MWD tool while drilling. However, the friction factor tracks show information while drilling, reaming, tripping and at connections. Therefore, multiple data points can exist at any given bit depth. In order to make this information easily interpretable, the data are shown as a series of points, i.e. a scatter plot, rather than a log which can increase and decrease in depth. Because data from many different drilling operations are shown on each track, the data points are color coded with operation. For example, drilling points are green, connections are blue and tripping is brown. In this way the engineer can immediately identify from which operation the data were measured.

CONCLUSIONS a) Friction factors measured while drilling, at connections and during trips will be identical for a given depth and drilling operation in the absence of sticking. Profiles of the average friction factors for a given operation (rotating, sliding, reaming) can automatically be constructed in real~ time versus depth for a given well. b) Profile friction factor values change very little with depth and are extended beyond the bit to allow evaluation of the drilling of new hole.

c) Smart Alarms are used to automatically warn the well site crew and the driller that a sticking situation is happening and that action is needed to prevent stuck pipe. d) An integrated, automatic friction monitor requiring minimal interaction by the field crew has been developed for real-time sticking pipe detection, evaluation and prevention.

Improved Method for Use of Chelation to Free Stuck Pipe and Enhance Treatment of Lost Returns

IntroductionNon aqueous fluids are well known for their deposition of low permeability filter cake. But still we found problem of differential sticking and techniques to free the pipe have largely been ineffective. In addition, lost returns in NAF continue to be one of the industrys most difficult and expensive problems to solve. The technique which is most commonly used to free the pipe is locally soaking the cake using a combination treatment that first conditions the cake and then removes a significant amount of the weighting material. Laboratory experiments have shown the technique can increase cake permeability by more than 850 fold. Mainly two processes are done in this technique. First we release barite dissolvers near the stuck point so it will increase the permeability of the filter cake. By increasing the cake permeability, pressure is allowed to penetrate the cake underneath the pipe, allowing it to more easily become free. Dissolving barite also reduces the shear strength of the filter cake, which may also facilitate freeing stuck pipe. In second process they try to reduce the lost circulation generated by the barite dissolvers. This is done by formation integrity technique. This technique mainly involves rock mechanics based technique.

Barite dissolversBarite dissolvers have long been used in the industry to combat scale in downhole tubulars. Additionally, barite dissolvers have gained use as a means to treat formation damage from mud invasion since the primary weighting agent for drilling fluids is barite. Barite is extremely insoluble in most acids and typically requires specialized chelation agents to remove. EDTA and DTPA are the most common chelation agents. Similar compounds, variations, mixtures, and new dissolving compounds are also being developed.

Differentially Stuck PipeDifferential pressure sticking (DPS) is a common worldwide drilling problem that results in significant increases in non- productive time and overall well cost. Additionally, a Differentially Stuck Pipe event may result in abandonment of the current hole and force a sidetrack. To mitigate DPS events, operators often minimize the overbalance (by decreasing mud weight), minimize stationary time, minimize drilled length through low pressure formations, increase drill collar and drill string stabilization, and optimize fluid properties in attempts to minimize the risk of sticking. However, despite the best efforts of operators a Differentially Stuck Pipe event may still occur. A common practice to free differentially stuck pipe is to pump a chemical spotting fluid. The purpose of the fluid is to dissolve or break down the filter cake so the pipe can be freed. Most service companies provide multiple spotting fluid options. Water-based drilling fluids have engendered numerous spotting fluids that have been used successfully in the field. These spotting fluids are typically composed of NAF. These fluids function by reducing the area of contact and may penetrate the cake and relieve pressure differential. Often, operators may choose to use a NAF while drilling if the risk of a DPS event is high. This minimizes the filter cake permeability and causes the pressure differential to develop more slowly upon embedment. Additionally, the filter cake is much slicker, thinner, and easier to shear all factors

that minimize the risk of a DPS event. While the use of a NAF is often sufficient to avoid DPS events, it is still known to occur. This is especially the case when the fluid incorporates bit-generated coarse solids that result in leaky and thick filter cakes exposed to unsupported drill collars. However, the industry currently has minimal available options to free differentially stuck pipe when drilling with a NAF. Regardless of the believed mechanism of DPS, it can be agreed that by removing barite (a significant portion of the filter cake), the sticking force will be reduced. This occurs either by decreasing the shear strength of the cake (by decreasing the pressure differential and by creating voids within the filter cake) or simply by relieving some or all of the pressure differential. This paper presents a method to free differentially stuck pipe in a NAF by removing barite from the filter cake, thereby increasing filter cake permeability. Additionally, the method would be applicable to water-based drilling fluids.

Lost ReturnsLost returns is a common worldwide drilling problem that has significant costs due to lost drilling fluids, lost time, potential wellbore influx, and induced wellbore instability. Losses through propagated fractures constitute the overwhelming majority of lost returns in the industry (as opposed to vugular losses or seepage losses). The operator has developed Fracture Closure Stress (FCS) practices to combat losses by utilizing a rock mechanics approach. In brief, integrity can be built in a formation by increasing the width of a fracture. This can be done with multiple approaches as varied as traditional LCM, cement, polymers, or adhesive solids. The process of building integrity requires (1) the fracture tip be isolated from the wellbore so pressure can be applied to widen the fracture to increase its closing stress, and (2) that the width be built to a level that achieves a stress exceeding the wellbore pressure required to drill ahead. Isolation of the tip from wellbore pressure occurs when the LCM and barite lose sufficient carrier fluid to become immobile. One potential issue with these stress building operations, especially in NAF, is that very high fluid loss is needed to form the immobile mass in the fracture faces. If fluid loss is inadequate, the solids remain mobile, pressure continues to be transmitted to grow the tip and it is not possible to build pressure within the fracture to increase closing stress. Lost returns are often difficult to treat in NAF due to the very low fluid losses achieved with most NAF filter cakes and the inability to dehydrate the solids. While the native permeability of the formation might allow rapid leadoff of the FCS fluid, a tight NAF filter cake on the fracture face prevents this from occurring. This paper presents a method to increase the permeability of the filter cake prior to the FCS treatment. By increasing the permeability of the filter cake on the fracture faces, greater leadoff would occur and an immobile mass would be deposited.

Differential Pressure Sticking TestsSmall scale differential pressure sticking tests were conducted in a unique differential pressure sticking apparatus (stickometer). The test apparatus consists of a chamber that accommodates a cylindrical core (4-inch diameter with 2-inchhole made of sandstone or ceramic) of known permeability. Fig. 1 schematically illustrates the apparatus. Drilling fluid is circulated throughout the system and a pressure differential of 500 psi is allowed to occur on the core between the wellbore and the formation. A dynamic filter cake is then deposited on the walls of the core. Situated within the core is an aluminium rod that creates an annulus through which the fluid can flow Fig. 2 is a photo of the rod situated in the core in a disassembled state for illustrative purposes. Once filter cake deposition is completed, the rod can be embedded into the filter cake. The rod also has pressure transducers in it to measure the pressure inside the filter cake. After remaining stationary for a set amount of time, load to free the pipe in an axial direction is applied and the freeing force recorded. In the tests conducted for these experiments, a generic water-based drilling fluid (WBM) was used rather than the NAF from previous tests. The WBM was used to ensure a thick filter cake would be formed which is needed to get the most meaningful pressure data from the transducers. The use of a WBM should have no effect on the viability of the test. In fact, it may be possible to skip the

solvent (pre-flush) phase when using a WBM. This option was not explored in these tests in order to be consistent with the filtration tests. After filter cake build up, the pipe was embedded and the pressure recorded as a function of time. The solvent was then spotted into the chamber and allowed to filter in the chamber for approximately 10 minutes. Finally, the agent was spotted into the chamber. The transducer records pressure at all times. All tests were conducted at approximately 75F. A control test using only Fluid was also conducted to determine if the solvent had a significant contribution on the pressure response and sticking force.

Figure 1: Schematic laboratory apparatus to simulate differential pressure sticking

Figure 2: Core arrangement in equipment

Conclusion & SummaryThe operator has developed an improved technique to increase the permeability of a NAF filter cake. The technique involves locally soaking the cake using a combination treatment that first conditions the cake and then removes a significant amount of the weighting material.

The Evaluation of Surface-Active Agents for use in the prevention of Differential-Pressure Sticking of Drill Pipe.Introduction The authors discuss the use of surface-active agents (Surfactants) in mitigating the problem of differential sticking, by analyzing the efficiency of various surfactants in their abilities to release differential-pressure stuck pipe. Definition of the Problem: The solution to various differential sticking problems through proper mudcontrol. Explanation of the Problem: Drill stem differential-pressure sticking is the result of drill collars laying against the mud filter cake on the wall of the drilled hole where the existing pressure differential acting against the isolated area of the drill collars in contact with the mud cake and the friction between the pipe and the cake are too large for a direct pull to effect a release. The problem of stuck drill pipe increases as deeper wells are drilled. This is due to the use of longer lengths of drill collars, oversize drill collars, high density drilling fluids, and abnormal formation pressures which are sometimes encountered. A highly permeable low-pressure zone is more susceptible for this type of phenomenon due to the mud cake deposition and pressure differential being greater in these areas. Normally, the hydrostatic pressure exerted by the drilling fluid column is uniformly distributed over the entire surface area of the drill pipe. Any restriction of uniform pressure distribution, such as that caused when the drill pipe movement ceases and the drill collars rest against the wall, creates an unbalanced hydrostatic pressure or a pressure differential, which results in a force that retains the collars against the wall of the hole and restricts pipe movement.

The author discusses that, if a uniform lubricating pressure-transmitting film can be created that will surround the pipe at all times, differential pressure sticking can be eliminated or, at least, its severity reduced. This film will also aid in reducing the friction between the pipe and the mud cake. The author also mentions that when added to an emulsion drilling fluid or to oil used to spot around stuck drill pipe, certain surface-active agents help to create such a film by making the drill pipe become preferentially oil wet.

The surfactants which proved best suited for preventing and reducing the severity of pressure differential sticking gave the following characteristics to the base mud: 1) Low water loss, 2) Low mud filtrate surface tension, 3) Thin filter cakes, 4) Stable emulsions.

18: Concentration v/s Breakaway Force Plot, the straight line above the upper inflection point can be used to determine the concentration of the surfactant.

CONCLUSIONSFrom the results of this study a number of conclusions can be made, these are as follows: 1) Proper surfactant concentration to provide low breakaway forces can be determined by using a concentration opposite the straight line portion above the upper inflection point of the breakaway or surface tension versus concentration curves. 2) Drilling fluids used in differential pressure sticking areas must be maintained in good condition and have the properties of low water loss, mud filtrate, and surface tension, thin filter cakes, and stable emulsions. 3) If drill pipe becomes wall stuck in a mud cake in which surfactant drilling fluids were used, release by oil spotting using similar surface active agents will result in a faster and more efficient release of stuck pipe. 4) Surfactants with a good ability to prevent and release differential pressure stuck pipe should be used in the mud programs of wells where pressure differential sticking is a problem.

Fishing MWD Tools in Horizontal Wells without Fluid CirculationThe boom in horizontal drilling presents new problems that require innovative solutions. Typical drilling problems such as stuck drill pipe have only become more acute with the emergence of horizontal drilling. Formation instability, improper hole cleaning and break-out debris in the hole wedged beside the drill string can cause drill pipe to become stuck resulting in costly pipe recovery operations. A new application of the electric wire-line Well Tractor has made possible the efficient recovery of MWD (Measurement While Drilling) tools and other stuck assemblies in horizontal and highly deviated wells. Operators face challenges in the conveyance of pipe recovery tools in the lateral section of a well if circulation is lost during the drilling process. This leaves the operator with few options, all of which are time consuming and expensive. In some cases, abandoning the hole and side tracking is required. In addition to drill pipe recovery services such as free point and back-off operations, MWD tools can be fished in highly deviated and horizontal wells, reducing overall operational and replacement costs of these exceptionally high priced MWD tools. With rising rig costs, it is crucial that fishing operations are conducted in the most efficient manner possible. The Well Tractor has fished MWD tools successfully at various well depths, inclinations, mud weights and different drilling assemblies. The Well Tractor design is well suited for operation inside drill pipe and completion strings with varying Internal Diameter (ID) such as joint connections, or when going through cross-overs and landing nipples. An overview of the Well Tractor technology, used in these fishing operations, is presented. A summary of operational benefits related to this application is included along with case studies showing how the Well Tractor technology has become a new solution for conveyance of fishing technology to retrieve MWD and other systems in deviated or horizontal pipe recovery operations.

IntroductionThe boom in the oil and gas drilling sector worldwide has greatly increased the volume of horizontal wells drilled over the last few years, especially in development areas. As this horizontal completion technique gains more acceptances, it also presents added problems and challenges that require original solutions. One such problem; stuck drill pipe, has become more and more prevalent a problem with the growth of horizontal drilling projects. Formation cave-in, improper hole cleaning techniques and unwanted debris in the borehole can lodge drill pipe, resulting in costly pipe recovery operations. Since drilling in highly deviated and horizontal trajectories requires precise placement of the hole within a productive zone, the operator must utilize the services of the MWD companies. Probe based internal directional and gamma detectors with associated electronics are deployed to allow for precision measurements to be transmitted to surface during the drilling process to ensure the drill string is positioned properly in the lateral section. When this bottom hole assembly and drill string become stuck, it requires operators and directional drillers to seek new and innovative solutions for fishing applications that greatly surpass traditional methods resulting in cost savings to the operator.

The Well Tractor technology is a proven tool as a conveyer of fishing services in horizontal and deviated wells. In such operations it provides the means for deploying retrieval hardware inside the drill pipe to the MWD probe allowing for an efficient fishing operation. Seeing as the Well Tractor is powered by an electric motor and hydraulic pump, no fluid circulation is needed as a transport mechanism. Only a powered wireline cable on surface is required. Well Tractor technology takes less time to initiate and recover the tools downhole. Today, this alternative is available. The necessary mechanism to push a wireline tool string through drill pipe and into the horizontal section of a well can be provided by using the Well Tractor Operators are now given the ability to convey pipe recovery and fishing services through drill pipe with an I.D. as small as 2.25 when gravity techniques and pump down are not feasible or successful. The conventional pump down method for fishing usually results in failure due to loss of mud circulation and insufficient hole cleaning and mud properties breakdown. Heavy settling of mud solids can prevail. All of the above mentioned difficulties contribute to an inefficient drilling operation and hence, an unstable wellbore resulting in stuck pipe probabilities. Operators are able to fish MWD tools with wireline or slick line in holes with less than 60 degrees inclination. Over this deviation, pump down tools can be utilized, but only if circulation is achievable. Pumping tools downhole without circulation can, at times, be achieved, but is not always recommended. Bull heading fluids into the formation can cause various problems such as: fluid damage to a zone of Interest, lost circulation, breaking down of the formation or loosing shoe integrity. Pumping into the formation without returns can agitate bottom hole pressures, causing serious well control issues. Another conventional method for fishing utilizes coiled tubing services, however, this strategy is expensive, requires heavy lifts and headcount is high. The availability of coiled tubing on short notice is also not always feasible. Furthermore, coiled tubing can leave a rather large footprint on location and requires rigging down or manipulation of the drilling equipment. In addition, subsequent operational runs such as free point tools or stuck pipe logs cannot be conveyed with coil.

Summary of Benefits When performing fishing operations off a drilling rig using an electric line Well Tractor the following benefits are realized: Faster Mob/De-mob of equipment Faster rig up Rig down Smaller footprint on location Increased job efficiency Start to finish Overall savings in operating time No lost in hole charges Minimal interface with other operations

The use of electric line conveyance systems for fishing with minimal HSE impact minimizes downtime allowing the operator to move ahead with the scheduled drilling. Besides the stated benefits to the operator, fishing out of the MWD string also allows the directional drilling company, who maintains and operates the MWD tool, to retain their assets and place them into service soon after.

ConclusionsThis new fishing application using the Well Tractor will, without a doubt, replace conventional methods of fishing in drill pipe. Well Tractor technology on wireline takes less time to mobilize and deploy onto a drilling rig than other conventional methods. It also recovers tools and conveys pipe recovery services through horizontal drill pipe sections more efficiently using electric wireline depth control and does not require any need for pumping services, even in extended reach applications. Finally, this technology requires less people and therefore provides a more positive HSE impact to operations. The above solutions provide the operator a high probability of success in retrieving most fished items and a notable overall reduction in cost compared to conventional fishing operations.

Economics of FishingIntroduction

Fishing usually is needed when least expected and brings a sudden halt to operations, especially if the drill string becomes stuck. Reaction planning begins at this time unless the drilling project was planned properly from the outset. That reaction planning is not good and should not be done is not the question. What is important is to establish the facts. What caused the drill string to become stuck? What should be done to free the drill string? What will the cost be? This addresses these questions. It also emphasizes the importance of routine, continuous, but often unrewarded, effort by operation personnel. This presents one viewpoint for evaluating alternatives to fishing, for retrieving a fish compared with sidetracking, and for using economics and risk factors in the decision-making process. These alternatives are compared in Fig.1. The discussion includes factors that can prevent fishing, such as drill string inspection, and that can cause fishing, such as poor mud programs and differential-pressure sticking. Here it illustrates decision-making processes involved in recovering or sidetracking the fish when the drill string is stuck by differential pressure. Even though this is only one of many causes for fishing, the process used to evaluate the economics may be applied .to many other operations. The goal is to provide a usable wellbore at the lowest ultimate cost.

Economics of Fishing or SidetrackingThe decision to fish or to sidetrack often involves feelings about the ability of operations personnel to perform fishing operations successfully. Instead, risk factors based on past performance should be the most important part of the decision to attempt a fishing job compared with the cost to sidetrack to eliminate the fishing job. Such factors as hole and casing sizes, tool availability, availability of knowledgeable fishing operators, the area of drilling activity, and hole conditions will affect the potential success of a fishing job. Despite the many parameters affecting fishing, assessing the basic costs and economics should follow the basic guidelines for estimating cost: estimate costs of the various alternatives, apply the best estimate of risk factors, and make the best decision possible with due consideration for all known variables. Evaluate for Completion "As Is." The drilling group should review the objectives outlined in the drilling program and consult the geologist and reservoir engineer responsible for the well before deciding whether fishing is necessary. In some situations, reserves above the fish may be sufficient to justify completing the well after the section of hole containing the fish has been abandoned. Perhaps objectives below the fish top may be recoverable with an offset well. Cost To Fish. The economic calculations are relatively easy; but the success ratio (risk factor) for fishing is not easy to ascertain. Past performance for similar jobs should be reviewed to determine the success ratio. The estimated fishing cost should include the days anticipated at the average total daily operating cost, plus fishing tools and operator, plus the cost of damage to the recovered fish. The sum of these costs, including consideration of the success ratio (risk factor), should be used in an economic comparison. If fishing is unsuccessful, then the remaining fish will need to be sidetracked.

Cost To Sidetrack. The estimated cost to sidetrack and red rill should include the rig days anticipated to reach the original depth times the average total daily operating cost, plus cement and tools to randomly sidetrack the well around the fish. Days to reach original total depth (TD) will include estimates of time for setting the cement plug, kicking off, and red riling to original depth. Sidetracking is not risk-free but is about 90% successful. Cost Comparison. The data for cost comparisons in Table 1 assume that the TD is 15,000 ft, with the top of fish at 14,000 ft, and that the fish is differentially stuck. The ROP averaged 150 ftlD below 14,000 ft, and the total daily operating cost was $12,000/day (including all mud treating, rentals, supervision, etc.). Fishing Cost Calculations. The estimated daily fishing cost is the sum of the daily operating cost ($12,000) and fishing services ($3,000), or $15,000/day. The fishing services include operator, tools, and back off wire line. The estimated rate of recovery is 150 ftlD, which includes washing over, tripping, screwing into the fish, backing off free pipe, and tripping to wash over additional fish. Fishing operations can be routine until cuttings and/or barite settle, or small pieces of junk fall to plug the inside of the drill string. This plugging will hamper further wireline work and necessitate less efficient operations if fishing is to continue. This possibility reduces the success ratio to about 25% (certainly no greater than 50%). For purposes of this paper, the success ratio is assumed to be 33 %. Sidetracking Cost Calculations. The estimated cost to sidetrack assumes the same daily operating cost ($12,000) plus the cost of directional operator and tools plus the cost of fish left in the hole. The first step is to set a cement plug, dress it off, and then use directional tools to kick off. (Sometimes, kicking off can be done in a favorable direction to penetrate the objective formation in an optimum structural position.) The estimated time required to set the cement plug and to start kickoff is 3 days, and directional drilling past the top of the fish is estimated to take 2 days. The chances of completing a sidetrack within the original cost estimate are usually as high as 90 % . Decision Plan. The decision plan should include all factors that may be involved .In the operation. For this reason, spotting fluids are covered to show the general case for this economics of fishing. Once drill string is stuck, the time required to get a spotting fluid in place is critical. The ability for spotting fluids to free stuck strings decreases rapidly (exponentially) with time. One major operator states that a fish stuck for 96 hours cannot be freed with a spotting fluid. Therefore, spotting fluids should be pumped as quickly as possible, preferably in less than 6 to 8 hours. While the spotting fluid is working, the fishing job should be planned and fishing tools and the wire line unit taken to location. The wire line is used to determine the free point (stuck point) and to back off. If the decision is to sidetrack, then cement and tools to sidetrack should be taken to location. The concept is to allow 24 to 36 hours for the spotting fluid to free the stuck string. Then the operator should locate the free point, back off one or two joints above it, and be ready to begin fishing operations or to sidetrack. An economic analysis to fish or to sidetrack should have been made before this time and updated as existing conditions change. The assumption is that, should fishing operations become difficult, sidetracking can begin immediately. Operations that usually cause fishing to be stopped are (1) loss of wire line tools

inside the fish, (2) plugging of the inside of the stuck string with barite or debris from fishing, or (3) loss of a rotary shoe and/or wash pipe on the outside of the fish. Note that the usual procedure is to back off and recover all free drill string and then compare the cost of fishing (washing over) the stuck portion of the drill string against the cost to sidetrack around the stuck drill string . Economics-Fish or Sidetrack. The economics involved in the decision analysis for immediate sidetrack or fishing under the conditions described in Table I are described below. 1. Fish 7 days, and sidetrack if unsuccessful. Assumptions included in the first scenario in Table 2 are 7 rig days, fishing costs, and repairs to fish recovered with a 33 % risk factor. Included in the second scenario is the added cost to sidetrack after failure of fishing operations with a 67% risk factor. 2. Immediate sidetrack. Assumptions included in the first scenario in Table 3 are 12 days to reach original TD, all directional costs, and a 90% risk factor. Included in the second is a 100% increase in cost resulting from trouble with a 10% risk factor. 3. The savings per job for sidetracking immediately. These savings are calculated by subtracting the cost of each job assuming risk for immediate sidetrack from the similar cost for fishing. This difference, $28,200, indicates that about 10% savings can be accrued by starting to sidetrack immediately rather than beginning fishing operations. This statement assumes that the success/ failure ratios are valid. These ratios should be evaluated for each job on the basis of past experience and the conditions causing the fishing job. Sidetracking is considered to involve less risk than fishing, except in very deep wells, in formations not conducive to sidetracking, or if the value of the fish is exceptionally high. In these cases, the risk factors should be revised accordingly. Again, past records should provide an adequate appraisal of the risk for evaluating the economics for the specific job. Table :-1 Well condition and economics of fishing Drilling Data TD,ft ROP, ft Daily operating cost, $/day Fishing Data Top of fish, ft Estimated recovery rate, ftlD Cost (wirellne truck, fishing tools, and operator), $/day Values of fish, $/ft Repairs to recovered fish, $ Success ratio (risk factor), % Sidetrack Data Time to set cement plug, days Cement plug cost (300 ft in 83/4-in. hole), $ Time to kickoff, days Mud motor cost (one run), $ Directional tools and operator, $Iday Time to drill around fish, days 15,000 150 12,000 14,000 150 3,000 50 10,000 33 3 6,000 2 5,000 2,000 7

Success ratio (risk factor), % Table 2:-Risk Analysis for fishing

90

Routine Fishing (33% risk factor) 7 days of rig operation at $12,000/day 84,000 Fishing costs 21,000 Repair damage to fish 10,000 Total cost 115,000 Risk cost 38,300 Troublesome Fishing (67% risk factor) 7 days of rig operation at $12,000/day 84,000 Fishing costs 21,000 Repair damage to fish 0 Sidetrack cost (risk cost from below) 240,300 Total cost 345,300 Risk cost 230,200 Cost of Each Job Assuming Risks Estimated cost of each of 10 jobs using risk factors outlined above, $ 268,500 Table 3:-Risk Analysis for side tracking Routine Sidetrack (90% risk factor) 12 days of rig operation at $12,000/day 144,000 Directional costs 29,000 Purchase fish to be sidetracked 50,000 Total cost 223,000 Risk cost 200,700 Troublesome Sidetrack (10% risk factor) 24 days of rig operation at $12,Ooo/day 288,000 Directionaf costs 58,000 Purchase fish to be sidetracked 50,000 Total cost 396,000 Risk cost 39,600 Cost of Each Job Assuming Risk Estimated cost of each of 10 jobs using risk factors outlined above, $ 240,300

Review Steps taken to reduce the potential for a fishing job and the effort spent planning and executing fishing operations often are met with skepticism. People with little or no operating expertise question the wisdom of making these plans. Those personnel who attempt to explain this planning and at the same time supervise one of the most troublesome problems in drilling (fishing) are the unsung heroes of the oil field.

General Rules to be Considered in a Fishing Job Plan When an operator expects or faces a fishing problem while drilling, he should consider the following two points: while drilling, before problem occurs, he has to do his best to stay out oftrouble after problem occurs, he should try to minimize as much as possible cost of handling the problem These two points could be achieved by adopting the following: The well drilling programme has to show all possible problem zones, their depths, and the right procedure to deal with each. If a fishing job is expected to occur, a fishing programme containing general guidelines to handle the problem should be attached to the well drilling programme, taking into consideration that all necessary equipment are available in the area. When a fishing problem occurs, prepare a plan of action after proper investigation with all available possible techniques to recover fish. Techniques should be organized in priority order, the most efficient and economic one being first. Estimate a budget and time required for the fishing job after the first bakeoff/cutoff the drill string. Prepare other alternative plans and develop them as necessary while fishing job in progress.

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Although each fish has various techniques to recover it yet it is not necessary to attempt them all before deciding on abandonment. Sometimes, at the time of deciding to terminate a fishing job, there will be several approaches still unattempted to recover the fish. But unless the fishing job has been progressing satisfactorily and is near completion, these last-minute efforts are frequently unsuccessful. In special cases, if time permits, try reasonable and practical methods. A decision to quit a fishing job in favour of other alternatives is based on: - Progress of fishing - Casing


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