Influence of wear on casing strength


The burst, collapse and axial strengths of casing are directly related to wall thickness, and hence are reduced by wear. The casing must be designed so that wear will not reduce the strength of the casing below that which will enable the well to be drilled and operated safely and efficiently.

1 Introduction

Unless there is well documented evidence that wear is not a problem, the amount of wear should be monitored closely during the drilling of the well, so that if it becomes excessive appropriate action can be taken.

Wear should not be confused with friction. Friction is partially determined by surface roughness. Since surface conditions are strongly affected by the wear process, wear and friction will influence each other. However there is no general, unambiguous relationship between the two. This means that wear and friction have to be evaluated separately.

1.1 Site and timing of casing wear

The major cause of casing wear is by a rotating drillstring which is pulled against the casing in the curved parts of the wellbore as a result of the tension in the drillstring. Wear due to drillpipe tripping has been calculated to represent approximately 1% of total wear. Wear due to wireline is somewhat greater than that of drillpipe tripping but still of the same order of magnitude. As a result of these observations, casing wear is almost exclusively on the result of contact between the rotating drillstring and the casing.

In deviated wells this will occur over the build-up, drop-off and tangent sections, and also where casing buckling may have occurred i.e. at the top of cement.

In vertical wells, wear points could also develop at the top of cement if casing buckling occurs. Otherwise, wear is likely to be small and uniformly distributed unless there are severe local doglegs.

Deep wells are of particular concern. Firstly, drilling time increases, increasing the time for wear. Secondly, the longer drillstrings will cause greater tension and thus generate higher contact forces.

Wear is often found in the casing joints just below the hanger. This is caused by misalignment of the rotary table relative to the wellhead and casing aggrevated by the high tension in the drillpipe resulting in high contact loads. If the conductor casing and BOP are inclined with respect to the (rig-) vertical the wellhead can be seen as a severe dogleg.

The casing wear is also aggravated by tong marks on the drillpipe. These tong marks will wear off, but mainly in the top part of the casing string they cause more than average wear to the casing, casing hanger and wear bushing in the wellhead. A larger wear design margin for 5-10 casing joints just below the hanger may be considered to counter act the reduction in wall thickness. It is also important to ensure that the casing housing, wear bushing, casing hanger, and the first few joints below the hanger have a common internal diameter. Achieving the same throughbore for these components eliminates high localised contact loads.

Most improvement in casing wear are related to tool joint hardfacing materials. e.g. some hardfacing material form a very hard, thin, glass-like layer. When the surface is worn away a new layer is formed. Non-rotating drillpipe/casing protectors, further assist in the reduction of casing wear.

2 Effect of wear on different types of casing strength

2.1 Collapse strength

The collapse capacity of worn casing is directly related to the remaining wall thickness. The collapse capacity should be calculated by using the minimum remaining wall thickness in the appropriate collapse formula from API Bull. 5C3. Since the wall thickness is not usually reduced in a uniform manner, use of the minimum value will give a conservative estimate of the remaining capacity.

The stress concentration that may arise from wireline wear does not affect collapse resistance.

2.2 Burst strength

The burst capacity of worn casing is proportional to the remaining wall thickness and should be calculated from the burst formula in API Bull. 5C3 using the minimum wall thickness. This typically applies to drillpipe generated wear.

For wireline wear, the reduction in burst pressure is the result of two factors. The first is the reduction due to the reduced wall thickness and the second is due to the stress concentration resulting from the sudden change in geometry.

For a groove created by 15/32 in (11.91 mm) open hole logging cable, the stress concentration factor ranges from ca. 1.2 to 1.4. The burst capacity of casing worn by such wireline is thus the burst strength as determined from reduced wall thickness divided by 1.4. Wireline wear in the vertical part of well is normally negligible, and the reduction in burst resistance due to logging is, in such cases, trivial. In the build-up, drop-off and tangent sections of the well, wireline wear could be greater, but still small compared to that caused by drillpipe rotation.

Note that the burst capacity formula for casing is based on yield of the pipe. In fact, failure will not occur until the pipe material reaches its ultimate strength. As a result, the capacity calculated from minimum remaining wall thickness (and any stress concentration factor) can be regarded as conservative.

2.3 Axial strength

Since the resistance of casing to axial loading is the product of the material yield strength and the cross-sectional area of the steel, any uniform (i.e. covering the entire circumference) or localised (i.e. only part of the circumference) reduction in wall thickness will affect this resistance. However, the effect of a given localised reduction in wall thickness on collapse and burst capacity will be much more severe than on the axial load capacity.

2.4 Strength of connections

Connection axial strengths are also calculated based on cross-sectional areas. The axial strength of an internally worn connection should be calculated using the formulas given in API Bull. 5C3 for round thread, buttress thread, and extreme line connections based on the maximum internal diameter of the pin.

For premium connections, the calculation of remaining strength will vary with connection type and the manufacturer should be consulted.

Little analysis has been performed on the internal leak resistance of internally worn casing connections. Early work on this topic (based on the contact stress in API connections) concluded that the internal leak pressure will be independent of casing wall reduction due to wear as long as the wear has not cut through the first sealing point of the connection.

In general it is recommended to contact the manufacturer to establish the remaining connection strength for a worn connection.

3 Wear mechanisms

Wear is the result of a complex tribological process taking place in the contact area between the drillstring and the casing, with mud generally present as the intermediate medium.

Contact between drillstring and casing can occur at the drillpipe tool joint and along the drillpipe body.

At moderate drillpipe tension, using Range 2 drillpipe, and dogleg severities less than 6°/100 ft (2.0°/10 m), pipe body contact with the casing is minimal. In most cases, therefore, wear due to pipe body rotation will be negligible. The main point of contact between the drillstring and the casing will be the drillpipe tool joints. Most research into casing wear, therefore, is based on contact between casing material and tool joint material.

Parameters such as contact load, surface roughness, hardness, geometry and chemical composition of both the tool joint and the casing, and the mud composition will determine what kind of wear mechanism occurs.

The three types of wear mechanism are:

  • two-body adhesive wear;
  • two-body abrasive wear;
  • three-body abrasive wear

The rate of wear depends upon the wear mechanism. Laboratory tests using smooth steel tool joints to examine the variation in wear rate, volume of steel per unit of time, with increasing contact pressure show a distinct change in wear rate at a contact pressure around 200 psi (1,379 kPa).

Contact pressure is the contact load divided by the contact area. It is used, instead of contact force, to eliminate the effect of changing contact area during the wear process. For a constant contact load, the volumetric wear rate decreases with time. This is due to the fact that as the casing wears, the resulting groove causes an increase in contact area, and thus a decrease in contact pressure. The wear rate, however, is proportional to contact pressure.

At low pressures, three-body abrasive wear dominates with the use of smooth steel tool joints while at higher pressures two-body adhesive wear is the primary mechanism. Within the range 150-250 psi (1,034-1,724 kPa), either mechanism may occur.

3.1 Two-body adhesive wear

Adhesive wear is the dominant wear mechanism for smooth steel tool joints at high contact pressures. It is also termed "galling". It is a mechanism characterised by local solid phase welding which occurs when the two bodies are in intimate contact. The welds are sheared off by the relative motion of the mating surfaces and metal is transferred from the low strength body (casing) to the high strength body (tool joint). The bond of the material to the tool joint is however temporary and ultimately results in the production of flake-like wear debris.

3.2 Two-body abrasive wear

This type of wear, also known as "chipping", occurs when sharp particles on a tool joint (e.g. exposed hardfacing material) cut into the casing material as a result of high local contact stress between the sharp particle and the casing. This type of wear produces fine cuttings or chips similar to machining on a lathe.

3.3 Three-body abrasive wear

In the case when the smooth tool joint and casing surfaces are separated by solid particles contained in the drilling fluid, e.g. barites, a three-body abrasive wear mechanism occurs. It is also referred to as "grinding". The casing surface is cyclically loaded by the solid particles due to the drillpipe rotation. This causes fatigue and embrittlement of the metal which ultimately leads to microfractures at the surface. The rate at which these fatigue cracks develop depends on the peak loads and is thus related to the hardness of the solid particles. The microfracturing process produces a powder-type wear debris.

An extreme case of three-body abrasive wear known as "polishing" occurs when the hard particles contained in the drilling fluid can be embedded in one of the contacting surfaces i.e. when a rubber drillpipe protector is used. Now the peakloads are governed and limited by the forces required to push the hard particles into the rubber surface rather than by the particle strength. Consequently a very fine powder-type debris is produced.

Three-body abrasive wear represents mild wear conditions and will not usually result in excessive casing wear.

The above mechanisms can be characterised by wear factors. The wear factor represents the amount of wear that takes place with each mechanism for a given set of operating conditions - the larger the wear factor, the greater the amount of wear.

Typical wear factor values for the various wear mechanisms are given below. These factors are normalised such that polishing has a maximum wear factor of 1.

Wear mechanism         Debris            Wear Factor

Two-body abrasive       Cuttings         400-1800

Two-body adhesive      Flakes            20-50

Three-body abrasive    Powder          0.1-10

In a new casing the initial contact area between smooth tool joints and casing is very small, i.e. line contact, resulting in high contact pressures. In addition, mill scale and irregularities of the tool joint surfaces, e.g. tongmarks, contribute to severe initial wear conditions. Consequently a high wear rate occurs (two-body adhesive) which results in a rapid increase of the contact area, and thus a reduction of the contact pressure to a level that enables mild wear conditions to occur (three body abrasive).

This implies that during the first bit run through a new casing, large volumes of steel filings, i.e. flakes, may be produced initially, after which the wear process stabilises at mild wear conditions. During successive bit runs the wearing down of tongmarks may cause accelerated casing wear as well at the start of the runs.

Note that the wear rate has so far been expressed in terms of volume casing material removed per unit of time. A more usable and understandable form is to refer to wear depth per unit of time, since this enables the calculation of the remaining collapse, burst or axial capacity of the worn casing. Wear volume and wear depth are related by the geometry of the contacting surfaces.

Thus, for the first bit run through a new casing as described above, wear depth will initially increase rapidly due to the high contact pressures. As the wear depth and contact area increase, mild wear results. It results that the rate of increase of wear depth drops dramatically.

4 Modelling the wear process

The aim of wear modelling is to be able to predict in advance where casing wear will occur and how severe it will be. The technique most commonly adopted is to modify theoretical models, usually by the use of wear factors, so that they match field and laboratory observations.

A considerable amount of the early laboratory casing wear modelling produced conflicting results and conclusions, with differing solutions proposed.

These variations are a result of the testing equipment and methods used, and that those results should be used with caution.

There is general agreement, however, that casing wear models have to take into account the following:

  • the magnitude of the tool joint - casing contact pressure;
  • the geometry of the contacting surfaces;
  • the relative roughness of the contacting surfaces;
  • the material of the contacting surfaces;
  • the magnitude of the relative velocity and the time the mating surfaces are in contact, i.e. the wear track length;
  • the drilling fluid composition.

The affect of each of these variables on the wear depth rate is now discussed individually in qualitative terms, and then the computer model for quantification of these effects will be introduced.

4.1 Contact pressure

As described earlier, the wear mechanism and therefore the wear rate for smooth tool joints is determined by the contact pressure. During the initial "breaking-in", the wear mechanism is adhesive due to the small contact area and resulting high pressure. As the casing rapidly wears, the contact area increases and the reduced contact pressure means that the wear mechanism returns to a mild three-body abrasive wear.

If the contact loads are very high, a significant wear depth may be experienced before the contact area is large enough to reduce contact pressure to a level where mild wear occurs.

For two body abrasive wear, due to exposed rough tool joint hardfacing material, severe wear results from the extremely high localised contact pressure. Mild wear conditions are never achieved.

For smooth tool joints in weighted mud systems it has been experimentally determined that the contact load must remain below 2,200 lbs (10,000 N) for the mild three body abrasive wear mechanism to be prevalent. Above this contact load, the protective mud solids film fails and adhesive wear occurs.

High contact loads can also cause uncemented casing to deflect elastically against the hole wall. For casing with non-flush connections, this causes bending to be concentrated near the connection.

Since the drillstring follows the gradual curvature of the borehole, the tool joints will be parallel to the casing for the majority of the casing joint length. However, in the vicinity of the casing connection the drillpipe tool joints become tilted with respect to the casing and wear increases dramatically. Rough edges on the tool joint further increase the wear rate at these points.

4.2 Contact surfaces

a. Geometry

Studies on casing wear generally concentrate on the volume of steel removed from the casing wall. As discussed earlier, this volume must be converted to a loss of wall thickness so that the remaining casing capacity can be determined.

The depth of wear is related to the volume of wear by means of the curvature of the contacting surfaces. For a tool joint of a given size, the initial wear depth will be greater for large casing sizes than small casing sizes. This results from the fact that for the larger casing sizes, a greater wear depth has to be achieved to increase the contact area sufficiently such that mild wear conditions occur.

Furthermore, the relationship between wear depth rate and casing sizes is very non-linearly dependant on the current depth of wear. If the current wear depth is low, the contact area is small (almost line contact) and the influence which casing size has on the subsequent wear rate is negligible. If the wear depth is high, the casing size becomes more significant in determining contact area, and thus contact pressure and wear rate.

Uncemented casing will bend under drillpipe contact loads. Because casing size determines its bending stiffness, the wear in the vicinity of casing connections will be lower for large diameter uncemented casing and higher for small diameter uncemented casing.

b. Roughness

Casing wear depends strongly on the type of tool joint used. Plain steel tool joints, or tool joints with smooth hardfacing, give rise to severe wear in brines or unweighted muds, but only mild wear in oilbase muds or weighted waterbase muds. Tool joints with exposed rough hardfacing lead to severe wear irrespective of the drilling fluid.

The following types of tool joint can be distinguished:

Plain steel The tool joint surface is not protected which results in relatively low wear rates of the casing in weighted muds (except for that caused by tong marks). In unweighted mud systems however the smooth tool joints are prone to two body adhesive wear.

Tungsten-carbide hardfacing Protection is provided by tungsten-carbide particles which may be deposited on the tool joint surface in an alloy matrix. This type of hardfacing is characterised by a rough and eccentric surface which leads to two body abrasive wear and has to be worn smooth in the open hole before the tool joints can be run in casing. Alternately, the surface can be machined smooth prior to use.

Two-phase hardfacing To avoid wear of casing caused by rough tungsten-carbide hardfaced tool joints, an overlay can be applied to give it wear characteristics similar to that of smooth steel tool joints. However proper inspection and maintenance is required to prevent tungsten-carbide from contacting the casing as the overlay wears down.

Alloy hardfacing An alloy hardfacing is a one-layer application without tungsten carbide.

To prevent rapid wear, it is essential that only smooth hardfacing is used and that this hardfacing is flush with the body of the tool joint. If the hardfacing stands proud, the contact area is reduced and the contact pressure increases leading to higher rates of wear.

Acceptable hardfacing materials are

Hardfacing                  Supplier                               Type

SMFI pro-casing        SMFI, France                         Alloy hardfacing

Vetco ACW                 Vetco, West Germany         Two-phase hardfacing

Vetco ACE                  Vetco, West Germany         Two-phase hardfacing

Vetco WOKA-600      Vetco, West Germany          Alloy hardfacing

Vetco WOKA-300      Vetco, West Germany        Two-phase hardfacing

Reed/Baker overlay  Reed/Baker, USA                Two-phase hardfacing

Bakermite                   Reed/Baker, USA               Alloy hardfacing

Reed CP flush           Reed/Baker, USA               Two-phase hardfacing

Drilco SAV-CAS         Drilco, USA                           Two-phase hardfacing

Supersmooth X         Hughes, France                   Machined tungsten-carbide hardfacing

All other hardfacing materials must be machined in order to meet the specification.

Laboratory tests revealed that in a barite weighted waterbase mud the wear rate is negligible provided the smooth tool joints have a total circumferential load-carrying area of at least 46 in2 (300 cm2). Only drillpipes of which the tool joints meet this criterion are acceptable for use in cased hole sections.

Figure 360:Effect of load-carrying area of tool joint on casing wear

The load-carrying area of tool joints can be measured using the contact print technique. This technique is available as a service from Vetco. In addition to the above, the edges of the hardfaced area on the tool joints must also be inspected for smoothness.

c. Material

Laboratory wear tests examined the role of wear as function of the casing grade and metallurgy. Carbon content of the steel was the only metallurgical property that correlated with wear i.e. the rate or amount of wear decreases as the carbon content (and grade) increases. As the casing strength, and therefore hardness, increases towards that of the tool joint then abrasive wear will decrease. Adhesive wear, however, will increase as the hardness of the contacting surfaces becomes similar.

Although the rate of wear was found to vary with grade it was concluded that grade is not a dependable measure of wear resistance. Care should be exercised when taking wear data corresponding to one grade, e.g. P110, and applying it to a different grade, e.g. N80. This should not be done unless there is no other data available.

It can be said, however, that when plain steel tool joints are in use, the difference in strength (hardness) between the tool joint and the casing material is important in avoiding adhesive wear. As a result, when designing the casing for burst and collapse, an increase in wall thickness is preferable to an increase in grade.

Studies have also shown that casing wear is reduced by internally coating the casing with chrome. Chrome tool joint coatings also reduce casing wear. Hardening or nitriding of the inside of the casing surface has proven ineffective in reducing casing wear.

4.3 Relative velocity and contact time of mating surfaces

The volume of wear "cuttings" is proportional to the rotary cutting distance (p´rpm´contact time´tool joint OD). As a result, for a given tool joint, casing wear is proportional to the drillstring rotation speed and the number of rotating hours. The rate of penetration is also an important factor in that it determines the length of time that a tool joint is in contact with any particular point in the casing. One of the failings of earlier laboratory studies was the omission of axial movement in the testing equipment.

To simulate an actual number of field drilling hours, the Wear Track Length (WTL) was introduced. The WTL is defined as the length of tool joint surface passing along a certain point of the casing due to rotation and translation. The WTL should be identical in the field and in the test facility for a representative simulation of casing wear.

4.4 Drilling fluid composition

Generally rough tool joints, which result in locally very high contact pressures, cause local ruptures in protective mud layers and films. As a result, wear rates will remain high and the drilling fluid composition will have little influence. Only when smooth tool joints are used will the fluid type, and its weighting material, be important.

For smooth tool joints in both unweighted and barite-weighted oil base muds (OBM), wear is very low in all cases. The combination of oilwetting agents and emulsifiers present in unweighted oilbase muds is already sufficient to create a film with a protective action similar to that of barite. Barite addition does not increase the degree of protection.

Smooth tool joints in unweighted waterbase muds (WBM) cause severe adhesive wear. In barite-weighted waterbase muds however, a protective barite layer is formed that prevents metal-to-metal contact and casing wear is low and identical for all mud weights.

Barite is the most effective mud weighting material for reducing casing wear. Tests using various weighting materials have been performed. Three-body abrasive wear increases with particle hardness in the sequence barite, iron oxide and quartz. Chalk and drilled solids (clays) have particle sizes significantly smaller than those of the other three materials and do little to reduce casing wear.

Figure 363:Effect of weighting material on casing wear (contact force 8 kN, 115 rpm, 5 m/hr ROP, smooth tooljoint)

Tests have been carried out to examine the effect on casing wear of muds containing additives (such as lignosulphonate, starch, sulphonated lignite and salts) and various types of lubricants. For weighted muds, no additional effect of additives or lubricants on wear was found. For unweighted muds the following observations can be made:

·Few of the additives tested significantly improved the lubricity of the seawater/lignosulfonate muds and as a result reduced the casing wear. However, all really effective lubricants identified sofar are more toxic than could be tolerated for use.

·The addition of diesel oil (10%v) has no effect on wear. Diesel oil is unable to create a chemically bound lubricant film, since it does not contain any reactive components.

·1 mm diameter glass beads (up to 6%w) has no effect on wear at all. The glass beads were simply unable even to reach the contact area, because of their size.

·The addition of salt reduces casing wear. Possibly, salts aid in the formation of a corroded layer that (partially) prevents adhesive wear. The addition of 10%w sodium chloride to a bentonite base mud has a similar effect on casing wear as the addition of 2%v lubricant.

·The addition of mud additives, such as lignosulphonates, starches and other polymers to a bentonite suspension causes a reduction of wear. The effects, however, are difficult to reproduce with any accuracy and are less pronounced than those obtained with lubricants and high salt concentrations. A different case is the addition of Resinex or gilsonite-type materials. When added in sufficient concentration (1.0-2.0%w), these small insoluble asphaltic particles give a protection similar to that of barite.

With respect to drilled solids it is observed that small quantities of drilled solids i.e. sand and/or silt (2-4%v) have no, or hardly any, effect on wear. In unweighted simple waterbase muds, adhesive wear is so severe that no abrasive contribution of the sand (silt) can be observed. In unweighted, film-forming muds (salts, lubricants, oilbase muds) an occasional increase in friction coefficient was observed when sand reached the contact area. No effect of small sand additions on the overall wear rate as observed, however. In weighted waterbase muds, the sand is so much "diluted" by weighting material that again no effect was observed. However, optimal operation of the solids-removal equipment is required to keep the sand/silt content at these acceptably low levels.

The table below illustrates the relationship between wear, tool joint hardfacing, and fluid content.

Tool joint hard facing                         Fluid content                                                               Wear factor range

Fully smooth                                       OBM                                                                              0.5-1

Fully smooth                                       WBM + barite or dolomite                                           0.5-1

Fully smoothunweighted                  WBM or brine, 2.0 vol% lubricant                              1-10

Fully smooth                                      WBM + drilled solids only                                             5-10

Fully smooth                                       unweighted WBM or brine, 0.5 vol% lubricant         10-20

Fully smooth                                      WBM + bentonite                                                            10-30

Fully smooth                                      unweighted WBM or brine, no lubricant                     30-100

50% smooth                                      fluid content has no effect                                            20-50

Rough                                                fluid content has no effect                                             50-150

Very rough                                        fluid content has no effect                                              200-400

Summarising for smooth tool joints, mud types and additives can make a significant difference to wear rates. For rough tool joints however, they have no influence as the tool joint surface roughness dominates the wear process.

5 Controlling casing wear

From the previous sections, it is apparent that casing wear is primarily affected by contact load, tool joint hardfacing condition, mud properties, and wear track length. Elimination or reduction of casing wear therefore must concentrate on these four factors.

5.1 Contact load

Wear will be proportional to contact load - although not linearly. It has been determined that the protective layer provided by the mud starts to fail when the contact forces exceed 2,200 lbs (10,000 N), and the wear rate increases significantly at that load. Therefore contact load should be kept below this value. Contact loads, and their influence on casing wear, can be minimised in a number of ways.

a. Well path selection

High contact loads occur when the tool joints are pulled firmly against the casing over a dogleg zone, i.e. build-up or drop-off section, or a localised drilled dogleg. Thus contact loads can be minimised by ensuring that dogleg severity in the build and drop sections of deviated wells is as low as possible, and that localised drilled doglegs in vertical or straight sections are avoided. Minimising casing wear should be one of the considerations when designing the wellpath, and this can be achieved by using a software to analyse the contact loads and resulting wear for the proposed well path [239]. While the well is being drilled, the actual wellpath can be similarly analysed and the hole plugged back if the actual doglegs will lead to excessive contact loads and hence unacceptable wear during drilling of the next section.

b. Rubber drillpipe protectors

Drillpipe protectors can be used to distribute the contact load over a larger area. By mounting one protector per single (at midjoint) the contact load at the tool joint is reduced by 50%. Two protectors per single triple the load carrying capacity which implies that the maximum acceptable dogleg is three times the maximum obtained when protectors are not used. The wear caused by rubber drillpipe protectors is approximately 5% of that due to plain steel tool joints under the same conditions. Rubber drillpipe protectors are also used (particularly in the USA) to prevent contact between tool joint and casing surfaces. This is achieved by placing a protector, having an OD at least 0.4 inches greater than that of the tool joint, approximately 1 foot above the pin tool joint. However, it is the view that such a practice does not prevent casing wear and should not be adopted. If applied, the drillpipe protectors should be mounted in the middle of the drillpipe, where their deformation underloading does not negate their purpose, because of the increased allowable compression compared to a position close to a tooljoint.

There are significant disadvantages associated with the use of drillpipe protectors, even for load distribution purposes. As the surface of the protector becomes impregnated with sand it will start to add to casing wear. In addition, there is concern about operational problems caused by the presence of protectors i.e. the danger of closing the pipe rams on a protector which has slipped, and the extra time required for stripping operations. Slippage of protectors can however be prevented by rotating the drillpipe through doglegs when running-in and pulling-out since this will reduce the drag.

In general, it is recommended that casing wear is minimised by use of smooth tool joint hardfacing, optimum well path design, and film-forming muds, rather than by using drillpipe protectors. However, for special conditions, after a thorough evaluation and with extra attention for the operational aspects, special types of drillpipe protector can be used. The drilling industry in developing non-rotating protectors, which could assist in the reduction of casing wear.

c. Bending of casing under high contact loads

Wear associated with bending of casing in the vicinity of casing collars can be eliminated in a number of ways:

1.Cement the casing over the interval where high contact loads will be experienced.

2.Install steel rings on both sides of the collars - the thickness of the rings should be slightly less than that of the collar in order to create a gradual transition. These rings should be located at a distance of 6 ft (2 m) from the collars. Rigid centralisers may also be used for this purpose.

3.Use internally/externally flush casing.

4.Ensure that the tapered sections of tool joints are ground smooth.

5.2 Hardfacing of tool joints

Rough tool joint hardfacing is the most dominant cause of catastrophic casing wear, and hence it must not be used inside casing. Only smooth (machined or field worn) hardfacing is acceptable and the drilling contract must specify quantitatively the smoothness of the hardfacing. This document is also applicable for used drillpipe and can be referred to in the drilling contract. It includes the description of inspection techniques for tool joint hardfacing.

In the past, common practice has been to run drillpipe with new rough hardfacing exclusively in open hole to wear-in the hardfacing. However, besides the complicated pipe handling, a judgement must still be made as to when the hardfacing is smooth enough. Such practices are therefore not recommended.

5.3 Drilling fluids

Wear is small, with the application of smooth hardfacing when using oilbase drilling muds and weighted waterbase drilling muds due to the development of a protective film. The absence of this protective film causes rapid casing wear. Drillstring rotating hours in unweighted waterbase muds and also in brine should therefore be limited unless effective lubricants are used.

Lubricants can significantly reduce wear in the low solids muds. Wear decreases with increasing lubricant concentration up to 2% by volume. Concentrations of over 2% by volume may cause oil wetting and clogging up of mud solids.

5.4 Wear-track length (WTL)

As described earlier, the volume of wear is proportional to the rotary cutting distance or wear track length. This length is a function of the tool joint dimensions, the drillstring rotation speed, the number of rotating hours, and the rate of penetration. Given that the rate of penetration is, for the sake of argument, fixed, then the casing wear can only be minimised by reducing the rotation speed or by reducing the number of rotating hours. This is best achieved by use of a downhole motor so that it is not necessary to rotate the drillstring.

Consideration should also be given to possible severe casing wear while drilling out cement plugs. Plugs which have a tendency to rotate should be avoided wherever possible because this can lead to a significant amount of time rotating the drillpipe at the same depth.

6 Designing for wear

Casing wear should be allowed for in the casing design process.

In the event that the casing wear is significant but not sufficient to justify increased casing wall thickness or immediate use of alternative drilling methods (e.g a downhole motor to avoid drillstring rotation), a wear monitoring programme should be implemented while drilling.

7 Wear monitoring programme

Ongoing wear monitoring is best performed by use of a casing wear prediction model that can be used at the casing design stage by input of a wear factor. It can also be used to calculate the amount and distribution of casing wear based on the amount of steel recovered at surface. The main input parameters for the model when used for monitoring are the wellbore survey and the weight of recovered steel.

The steel removed from the casing has to be collected. For this purpose a number of bar-shaped magnets may be used which are positioned diagonally in the flowline. The ditch magnets should be stacked so that the mud passes more than one magnet. A plastic sheet or bag placed over the magnet enables the steel to be more easily removed.

Recording of the weight of steel filings taken from each individual magnet enables the efficiency of the steel collection and possible saturation of the magnets to be assessed. The weight measurements for each individual magnet can also be used to determine the minimum measuring frequency to avoid magnet saturation. Such services can often be obtained as part of a mud-logging contract.

The shape of the recovered filings should also be recorded since this can give an indication of the wear mechanism.

A plot of the amount of metal recovered versus rotating hours should be used to estimate the final amount of worn steel by extrapolation towards the planned drilling time. This extrapolated value is then input in the wear model.

If the anticipated wear reduces the strength capacity of the casing below that required to allow safe drilling and operation of the well, appropriate measures, such as the use of a mud motor, should be taken.

Wear can also be evaluated by the use of wireline logging tools. These services can give an accurate measure of remaining wall thickness. It is strongly recommended that a base log is run prior to commencing drilling operations. This is especially the case for drilling operations conducted inside the production casing.

It is evident that measurement of actual wear should be performed with wireline logging tools in order to calibrate the results of estimations. Such logging runs should be performed at regular intervals during drilling of the section and the final wear predictions based on simulations adjusted accordingly. If it is found that the output closely matches the log results, then it may be possible to rely solely on the computer model.



#1 Vilma 2017-08-10 09:40
The following, while journalists attemptedto glean a bit through Players Sky’s restriction media gain access to for the support period, Brailsford
accused a writer, Barry Ryan, regarding
“recording shit around [him]” and also conveyed him he
was real eliminated through listening closely to Froome because the race leader
conversed to television retailers. That took place after having a identical occurrence while using the website’s
editor Daniel Benson earlier from the run. -
fmtrustonline.c om: