Drilling Engineering
Drilling Fluids
Dr. Imre FEDERER Associate Professor
Drilling Fluids
• Functions Of Mud• Drilling Mud Additives • Drilling Fluid Types • Drilling Mud Properties • Drilling Fluid Selection • Drilling Mud Problems • Solids Control
Drilling Fluids
• To remove the drilled cuttings from the hole. – Viscosity, Mud Weight.
• To suspend the cuttings when circulation is stopped – Gel strength, Yield Point, Mud Weight.
• To control BHP pressure greater than formation pressure. – Mud weight.
• To cool and lubricate the bit and drillpipe. • To prevent the walls of the hole from caving.
– Formation of a stable mud cake on the walls of wellbore. • To prevent or minimize the damaging effects to the formation.
– Clay stabilizer additives
Drilling Fluid Additives
Drilling Fluid Additives
Weighting Materials
Barite (BaSO4)• Barite (or barytes) is the most commonly used weighting material. • Barium sulphate has a specific gravity in the range of 4.20 - 4.60
• It is preferred because of its low cost and high purity.
• It is used when mud weights in excess of 10 ppg are required. • Barite can be used to achieve densities up to 2.28 s.g (22.0 ppg) in
both water- based and oil -based muds.
– At very high mud weights the rheological properties of the fluid become
difficult to control.
Drilling Fluid Additives
Weighting Materials
Calcium carbonate (CaCO3)• Advantage: its ability to react and dissolve in hydrochloric acid.
• Filter cake formed on productive zones can be easily removed. • CaCO3 is dispersed in oil muds more readily than is barite. • Its low specific gravity (2.60 - 2.80) limits the mud weight.
• The maximum density of mud to about 1.44 g/cm3 (12.0 ppg)
• Calcium carbonate is available as limestone or oyster shells.
Dolomite is a calcium - magnesium carbonate
• Dolomitre specific gravity of 2.80 - 2.90.
• The maximum mud density achieved is 1.60 s.g. (13.3 ppg).
Salt Brines
Fluid Practical Maximum Density kg/l (ppg) Caesium Formate 2.36 (19.7) Potassium Formate (KHCO2) 1.60 (13.3) Sodium Formate (NaHCO2) 1.33 (11.1)
Sea water 1.02 (8.5)
Brine-sodium chloride (NaCl) 1.18 (9.8) Brine-potassium chloride (KCl) 1.17 (9.7) Brine-calcium chloride (CaCl2) 1.38 (11.5) Brine-calcium bromide (CaBr2) 1.80 (15.0) Brine-zinc bromide (ZnBr2) 2.18 (18.1)
Crystallization Point of Brines
Weight Crystallization Point
kg/l ppg oC oF
Sodium Chloride (NaCl)
1,02 8.5 -2 29
1,08 9.0 -7 19
1,14 9.5 -16 6
1,2 10.0 -4 25
Calcium Chloride (CaCl2)
1,02 8.5 -1 30 1,14 9.5 -13 9 1,2 10.0 -22 -8 1,26 10.5 -37 -36 1,32 11.0 -30 -22 1,38 11.5 +2 35
Calcium Chloride/Bromide (CaCl2/Br2)
1,44 12.0 12 54
1,56 13.0 15 59
1,68 14.0 17,7 64
Drilling Fluid Additives
Materials used as viscosifiers Viscosifiers
• High viscosity provide the ability of cutting transport.
• Low viscosity provide low pressure loss in the circulation system. • Solids removal efficiency increase when the viscosity is decrease.
Relationship Between Function Of A Polymer In A
Drilling Fluid
Filtration Control Materials
• Filtration Control Materials
• Filtration control agents are compounds which reduce the amount of fluid that will be lost.
• from the drilling fluid into a subsurface formation due, essentially, to the differential between the hydrostatic pressure of the fluid and the formation pressure.
• Bentonite, polymers,
• starches and thinners or deflocculants all function as filtration control agents.
Filtration Control Materials
• Bentonite is the "backbone" of clay based mud systems. It imparts viscosity and suspension • as well as filtration control. The flat, "plate like" structure of bentonite packs tightly together • under pressure and forms a firm compressible filter cake, preventing fluid from entering the • formation
• Polymers such as Polyanionic cellulose (PAC) and Sodium Carboxymethylcellulose (CMC) • reduce filtrate mainly when the hydrated polymer chains absorb onto the clay solids and plug • the pore spaces of the filter cake p preventing fluid seeping through the filter cake and
• formation. Filtration is also reduced as the polymer viscosifies the mud thereby creating a • viscosified structure to the filtrate making it difficult for the filtrate to seep through.
• Starches function in a similar way to polymers. The free water is absorbed by the sponge like • material which aids in the reduction of fluid loss. They form very compressible particles that • plug the small openings in the filter cake.
• Thinners and deflocculants function as filtrate reducers by separating the clay flock‟s or • groups enabling them to pack tightly to form a thin, flat filter cake.
Rheology Control Materials
• Basic rheological control is achieved by controlling the concentration of the primary • viscosifiers used in the drilling fluid system. However, when efficient control of viscosity • and gel development cannot be achieved by control of viscosifier concentration, materials • called "thinners", "dispersants", and/or "deflocculants" are added. By definition, these are • materials that cause a change in the physical and chemical interactions between solids and/or • dissolved salts such that the viscous and structure forming properties of the drilling fluid are • reduced.
• Thinners are also used to reduce filtration and cake thickness, to counteract the effects of • salts, to minimize the effect of water on the formations drilled, to emulsify oil in water, and • to stabilize mud properties at elevated temperatures.
• Materials commonly used as thinners in water based clay containing drilling fluids can be • broadly classified as: (1) plant tannins, (2) lignitic materials, (3) lignosulfonates, and (4) low • molecular weight, synthetic, water soluble polymers.
Alkalinity and pH Control
Materials
• The pH affects several mud properties including:
• detection and treatment of contaminants such as cement
and soluble carbonates
• solubility of many thinners and divalent metal ions such
as calcium and magnesium
• Alkalinity and pH control additives include the alkali and
alkaline earth hydroxides; NaOH,
• KOH, Ca(OH)2, NaHCO3 and Mg(OH)2. These are
compounds used to attain a specific pH
• and to maintain optimum pH and alkalinity in water base
fluids Among the materials most
• Lubricating Material
• Lubricating materials are used mainly to reduce
friction between the wellbore and the
• drillstring. This will in turn reduce torque and
drag which is essential in highly deviate and
• horizontal wells.
• Lubricating materials include: oil (diesel, mineral,
animal, or vegetable oils), surfactants,
• fatty alcohol, graphite, asphalt, gilsonite, and
polymer or glass beads
Shale Stabilizing Materials
• There are many shale problems (see Chapter 14) which may be encountered while drilling sensitive highly hydratable shale sections.
• Shale stablisers include: high molecular weight natural or synthetic polymers • (polyacrylics/polyamines), asphaltic hydrocarbons, potassium and calcium salts,
glycols, and certain surfactants and lubricants.
• Essentially, shale stabilization is achieved by the prevention of water contacting the open shale section. This can occur when the additive encapsulates the shale or when a specific ion such as potassium actually enters the exposed shale section and
neutralise the charge on it.
• Field evidence indicates that polymers do not provide on their on complete shale • stabilisation and that soluble salts must also be present in the aqueous phase to
• .D r. i.l .l i.n . g. . F. .l u. .i d. . T. .y . p. e. .s
• A drilling fluid can be classified by the nature of
its continuous phase, i.e. what the fluid is
• based on, or built from. The three types of
drilling fluid are:
• 1. Water Based Muds
• 2. Oil Based Muds
Water Based Mud
• Water Based Mud
• These are fluids where water is the continuous
phase. The water may be fresh, brackish or
• seawater, whichever is most convenient and
suitable to the system.
• The following designations are normally used to
define the classifications of water base
• drilling fluids:
Water Based Mud
• 2. Non-dispersed - Inhibited
• 3. Dispersed - Non-inhibited
• 4. Dispersed - Inhibited
• “Dispersed” means that thinners have been
added to scatter chemically the bentonite (clay)
• and reactive drilled solids to prevent them from
building viscosity.
• “Non-Dispersed” means that the clay particles
are free to find their own dispersed
Water Based Mud
• Inhibited means that the fluid contains inhibiting ions such as chlorine, potassium or
• calcium or a polymer which suppresses the breakdown of the clays by charge association and • or encapsulation.
• Non-Inhibited means that the fluid contains no additives to inhibit hole problems.
• Non-inhibited - non-dispersed fluids do not contain inhibiting ions such as chloride (Cl-),
• calcium (Ca2+) or potassium (K+) in the continuous phase and do not utilize chemical • thinners or dispersants to effect control of rheological properties.
• Inhibited - non-dispersed fluids contain inhibiting ions in the continuous phase, however
• they do not utilize chemical thinners or dispersants.
• Non-inhibited dispersed fluids do not contain inhibiting ions in the continuous phase, but
• they do rely on thinners or dispersants such as phosphates, lignosulfonate or lignite to • achieve control of the fluids' rheological properties.
• Inhibited dispersed contain inhibiting ions such as calcium (Ca2+) or potassium (K+) in the
• continuous phase and rely on chemical thinners or dispersants, such as those listed above to • control the fluids rheological properties.
PRACTICAL RIG HYDRAULICS
Dr Federer Imre
Associate Professor
• Rheological models are mathematical equations used to predict fluid behaviour.
BINGHAM PLASTIC MODEL
The Bingham Plastic model describes laminar flow using the following equation:
τ= YP + PV * (γ)
• τ = measured shear stress in lb/100 ft2 • YP = yield point in lb/100 ft2
• PV = plastic viscosity in cP • γ = shear rate in sec ^(–1) PV = θ600 – θ300
YP = θ300 – PV
YP = (2 × θ300) – θ600
The Bingham Plastic model usually overpredicts yield stresses (shear stresses at zero shear rate) by 40 to 90 percent.
The following equation produces more realistic values of yield stress at low shear rates:
YP (Low Shear Rate)= (2 × θ3) - θ6
This equation assumes the fluid exhibits true plastic behaviour in the low shear rate range only.
POWER LAW MODEL
The Power Law model assumes that all fluids are pseudoplastic
in nature and are defined by the following equation: τ = K *(γ)^n
• τ = Shear stress (dynes / cm2) • K = Consistency Index • γ = Shear rate (sec-1) • n = Power Law Index
The constant “n” is called the POWER LAW INDEX and its value indicates the degree of non-Newtonian behaviour over a given shear rate range. The constant “n” has no units.
The Power Law model actually describes three types of fluids, based on the value of 'n':
• n = 1: The fluid is Newtonian • n < 1: The fluid is non-Newtonian • n > 1: The fluid is Dilatent
The “K” value is the CONSISTENCY INDEX and is a measure of the the thickness of the mud. An increase in the value of 'K'
indicates an increase in the overall hole cleaning effectiveness of the fluid. The units of 'K' are either lbs/100ft^2, dynes-sec or N/cm^2.
Hence the Power Law model is mathematically more complex than the Bingham Plastic model and produces greater accuracy in the determination of shear stresses at low shear rates.
HERSCHEL-BUCKLEY (YPL) MODEL
The Herschel-Bulkley model describes the rheological behaviour of drilling muds more accurately than any other model using the following equation:
τ = τo + K * (γ)^n
• τ = measured shear stress in lb/100 ft^2
• τo= fluid's yield stress (shear stress at zero shear rate) in lb/100 ft2
• K = fluid's consistency index in cP or lb/100 ft sec^2 • n = fluid's flow index
• γ= shear rate in sec^(-1)
The YPL model is very complex and requires a minimum of three shear-stress/shear-rate measurements for a solution.
PRACTICAL HIDRAULICS EQUATIONS
The procedure for calculating the various pressure losses in a circulating system is summarised below:
1. Calculate surface pressure losses using: P1 = E * ρ^0.8 * Q^1.8 * PV^0.2
2. Decide on which model to use: Bingham Plastic or Power Law.
3. Calculate pressure loses inside the drillpipe first then inside drillcollars.
4. Divide the annulus into an open and cased sections. 5. Calculate annular flow around drillcollars (or BHA). 6. Repeat step four for flow around drillpipe in the open
and cased hole sections.
7. Add the values from step 1 to 5, call this system losses. 8. Determine the pressure drop available for the bit = pump
pressure - system losses
9. Determine nozzle velocity, total flow area and nozzle sizes
For step 3. :
• Calculate critical velocity of flow
• Calculate actual average velocity of flow
• Determine whether flow is laminar or turbulent by comparing average velocity with critical velocity. If average velocity is less than critical velocity the flow is laminar.If average velocity is greater than critical velocity the flow is turbulent.
• Use appropriate equation to calculate pressure drop
For step 5. :
• Calculate critical velocity of annular flow
• Calculate actual average velocity of flow in the annulus
• Determine whether flow is laminar or turbulent by comparing average velocity with critical velocity. If average velocity is less than critical velocity the flow is laminar.If average velocity is greater than critical velocity the flow is turbulent.
BINGHAM PLASTIC MODEL
PIPE FLOW – ANNULAR FLOW
PIPE FLOW:
Determine average velocity and critical velocity:
If average velocity > critical velocity flow is turbulent, use:
If average velocity < critical velocity flow is laminar, use: ANNULAR FLOW:
Determine average velocity and critical velocity:
If average velocity > critical velocity flow is turbulent, use:
POWER LAW MODEL
PIPE FLOW - ANNULAR FLOW
Determine n and K from:
PIPE FLOW:
Determine average velocity and critical velocity:
If average velocity > critical velocity flow is turbulent, use:
POWER LAW MODEL
PIPE FLOW - ANNULAR FLOW
ANNULAR FLOW:
Determine average velocity and critical velocity:
If average velocity > critical velocity flow is turbulent, use:
PRESSURE LOSS ACROSS BIT
The object of any hydraulics programme is to optimise pressure drop across the bit such that maximum cleaning of bottom hole is achieved.
For a given length of drill string (drillpipe and drill collars) and given mud properties, pressure losses P1, P2, P3, P4 and P5 will remain constant. However, the pressure loss across the bit is greatly influenced by the sizes of nozzles used, and the latter determine the amount of hydraulic horsepower available at the bit.
To determine the pressure drop across the bit, add the total pressure drops across the system, i.e. P1 + P2 + P3 + P4 + P5, to give a total value of Pc (described as the system pressure loss). Then determine the pressure rating of the pump used. If this pump is to be operated at, say, 80-90% of its rated value, then the pressure drop across the bit is simply pump pressure minus Pc.
Procedure
1. From previous calculations, determine pressure drop across bit, using:
2. Determine nozzle velocity (ft/s):
3. Determine total area of nozzles (in^2):
OPTIMISATION OF BIT HYDRAULICS
All hydraulics programmes start by calculating pressure
drops in the various parts of the circulating system.
Pressure losses in surface connections, inside and around
the drillpipe, inside and around drill collars, are calculated,
and the total is taken as the pressure loss in the circulating
system, excluding the bit.
SURFACE PRESSURE
Once the system pressure losses, Pc, is determined, the questions is how much pressure drop can be tolerated at the bit (Pbit). The value of Pbit is controlled entirely by the maximum allowable surface pump pressure. Most rigs have limits on maximum surface pressure, especially when high volume rates – in excess of 1000 gpm are used. In this case, two or three pumps are used to provide this high quantity of flow. On land rigs typical limits on surface pressure are in the range 2,500 – 3000 psi for well depths of around 12,000 ft. For deep wells, heavy duty pumps are used which can have pressure ratings up to 5,000 psi.
Hence, for most drilling operations, there is a limit on surface pump pressure, and the criteria for optimising bit hydraulics must incorporate this limitation.
HYDRAULIC CRITERIA
There exist two criteria for optimising bit hydraulics: (1) maximum bit hydraulic horsepower (BHHP); and (2) maximum impact force (IF). Each criterion yields difference values of bitpressure drop and, in turn, different nozzle sizes. The engineer is faced with the task of deciding which criterion he is to choose. Moreover, in most drilling operations the flow rate for each hole section has already been fixed to provide optimum annular velocity and hole cleaning. This leaves only one variable to
optimise: the pressure drop across the bit, Pbit. We shall examine the two criteria in detail and offer a quick method for optimising bit hydraulics.
MAXIMUM BIT HYDRAULIC HORSEPOWER
The pressure loss across the bit is simply the difference between the standpipe pressure and Pc. However, for optimum hydraulics the bit pressure drop must be a certain fraction of the maximum available surface
pressure. For a given volume flow rate, optimum hydraulics is obtained when the bit hydraulic horsepower assumes a certain percentage of the available surface horsepower. In the case of limited surface pressure, the maximum pressure drop across the bit, as a function of available surface pressure, produces maximum
hydraulic horsepower at the bit for an optimum value of flow rate as shown below:
In the literature several values of n have been proposed, all of which fall in the range 1.8 - 1.86. Hence, when n = 1.86, the previous equation gives Pbit = 0.65 Ps. In other words, for optimum hydraulics, the pressure drop across the bit should be 65% of the total available surface pressure. The actual value of n can be determined in the field by running the mud pump at several speeds and reading the resulting pressures. A graph of Pc(=Ps - Pbit) against Q is then drawn. The slope of this graph is taken as the index n.
MAXIMUM IMPACT FORCE
In the case of limited surface pressure, it can be shown c that for
maximum impact force, the pressure drop across the bit (Pbit) is given by:
The bit impact force (IF) can be shown to be a function of Q and Pbit
according to the following equation.
NOZZLE SELECTION
Smaller nozzle sizes are always obtained when the maximum
BHHP method is used, as it gives larger values of Pbit than
those given by the maximum IF method. The following
equations may be used to determine total flow area and nozzle
sizes:
OPTIMUM FLOW RATE
The Optimum flow rate is obtained using the optimum value of Pc, n and
maximum surface pressure, Ps. For example, using the maximum BHHP
criterion, Pc is determined from:
The value of n is equal to the slope of the Pc - Q graph. The optimum
value of flow rate, Qopt is obtained from the intersection of the Pc value
and the Pc - Q graph.
MUD CARRYING CAPACITY
For effective drilling, cuttings generated by the drill bit must be removed immediately. The drilling mud carries the drill cuttings up the hole and to the surface, to be separated from the mud. The carrying (or lifting) capacity of mud is dependent on several
parameters including fluid density, viscosity, type of flow, annulus size, annular speed, particle density, particle shape and particle diameter. Other factors such as pipe
Rotation, pipe eccentricity also have some influence on the carrying capacity of mud. 1. Turbulent flow is most desirable for efficient removal of cuttings.
2.Low viscosity, low gel strength of mud are desirable properties for removal of cuttings. 3.High mud density helps to efficiently remove cuttings.
HOLE CLEANING
Efficient hole cleaning is directly dependent on the ability of mud to suspend and carry The drill cuttings to the surface. The problems associated with inefficient hole cleaning include:
1. Decreased bit life and slow penetration rate resulting from regrinding of drill cuttings.
2. Formation of hole fills near the bottom of the borehole during trips when the mud pump is off.
3. Formation of bridge in the annulus which can lead to pipe sticking.
4. Increase in annular density and, in turn, annular hydrostatic pressure of mud.
The increased hydrostatic pressure of mud may cause the fracture of an exposed weak Formation resulting in lost circulation. In practice, efficient hole cleaning is obtained by providing sufficient annular velocity to the drilling mud and by imparting desirable fluid properties.
SLIP VELOCITY
A rock particle falling through mud tends to settle out at constant velocity (zero acceleration) described as slip or terminal velocity and is given by:
For transitional flow:
TRANSPORT VELOCITY
Transport or lift velocity is defined as the difference between the annular velocity of mud and the slip velocity of particle:
It is obvious that for efficient hole cleaning, Va must be greater the Vs. Sample et al 10,11 observed that at annular velocities of less than 100 ft/min, particle slip velocity in both
Newtonian and non-Newtonian fluids is independent of the fluid annular velocity. Above an annular velocity of 100 ft/min, there appears to be a dependence of slip velocity on annular velocity.
DRILL CUTTINGS CONCENTRATION
To prevent hole problems, it is generally accepted that the volume fraction of cuttings (orconcentration) in the annulus should not exceed 5%. Therefore, the design programme for mud carrying capacity should also include a figure for the drill cuttings concentration in the annulus. The cuttings concentration is given by:
Drilling Engineering
CEMENTING OPERATIONS
Dr. Imre FEDERER Associate Professor
Cementing Operations
Functions of Cement
• Provide zonal isolation
– Primary barrier between formations
• Support axial load of casing strings and strings to be run later • Provide casing support and protection
• Support the borehole primary well control
Cement Slurry
Cement additives modify the behaviour of the cement slurry.
• Accelerators
– reduce the thickening time of a slurry and
– increase the rate of early strength development. • Retarders:
– chemicals which extend the thickening time of a slurry – to aid cement placement.
• Extenders:
– materials which lower the slurry density and increase the yield. • Weighting Agents:
Cement Slurry
Cement additives
• Dispersants:
– chemicals which lower the slurry viscosity and may also increase free water.
• Fluid-Loss Additives:
– materials which prevent slurry dehydration and reduce fluid loss to the formation.
• Lost Circulation Control Agents:
– materials which control the loss of cement slurry to weak or fractured formations.
• Miscellaneous Agents: – e.g. Anti-foam agents.
Type of additives Used Chemical composition Benefit accelerators Reducing WOC time Calcium chloride
Sodium chloride gypsum
Accelerated setting, high early strength
retarders Increasing thickening time for placement, reducing slurry viscosity Organic acids Lignosulfonates Increased pumping time Weight reducing additives
Reducing weight Bentonite gilsonite Lighter weight economy Heavy weight additives Increasing slurry weight Hematite dispersants Higher density Additives for controlling lost circulation
Bridging agent Walnut hulls Gypsum cement
Lighter fluid columns Squeezed fractured zone
Filtration-control additives
Squeeze cementing, setting long liners
•
Kútadatok p, T, h,
formáció
Slurry Testing
Reporting of Cement Tests
• Well Number • Well Depth
• Bottom Hole Static Temperature (BHST)
• Bottom Hole Circulating Temperature (BHCT)
• Source of cement samples, water samples and additive samples • Spacer recommendation and recipe
Slurry Testing
Lead and Tail Slurry results including:
• Cement type
• Water type, Water requirements • Additive requirements
• Slurry density, Slurry yield • Thickening time
• Heating schedule, Pressure schedule
• Rheology readings at BHCT (600-300-200-100-6-3 RPM)) • Compressive strength (8hrs-12hrs-16hrs-24hrs in psi)
Consistometer Thickening time
Compressive Strength
• Measurement of the uniaxial compressive strength of two-inch cubes of cement provides
• Indication of strength development of cement at downhole conditions.
• Slurry samples are cured for 8, 12, 16 and 24 hours at bottom-hole temperatures and pressures and the results reported in psi.
60
Compact Plug Container
Lifting Eye Cap Body Plug Release Plunger Plug Launch Indicator Detent Pin (Locks Quick-Latch in Open or Closed Position)
Quick Latch Coupler 1502 Unions
(Fluid Ports)
Plug Container Cement head
61 Top & Bottom Cementing Plug
Cementing Equipment
Float Shoe Guide Shoe Float Collar
Will rupture with pressure
9 5/8”
13 3/8” 18 5/8”
7”
63
Mechanical Aids Best
Practices
• Pipe Movement– Rotation
– Reciprocation
• Casing Attachments
– Scratchers scrape “wallcake” from borehole
– Centralizers provide stand-off from bore hole
– Specialized Float Equipment
Displacement Efficiency
• Stand Off (with centralisers)
• Flow Regime (Laminar or Turbulence) • Spacers (usually fresh water)
• Rotation (only if possible/practical) • Reciprocation (only if critical)
72
Mud Displacement Best Practices
Bad
Common types of Cementations
PRIMARY
• Single Stage Casing • Inner String (Stinger)
• Multiple Stage (rarely used) • Liner
• Balanced Plug
SECONDARY
• Remedial Circulation • Squeeze
Stinger (inner string) Cementation
WHEN :
• Relatively short & large diameter casing (surface)
• Hole size not accurately known or losses to the formation
WHY :
• Allows flexibility in cement quantity
• Keep pumping until good cement seen at surface,
Multiple Stage Cementation – When/Why
• To enable cementing of very long intervals w/ weak zones, thus reducing pressure on formation and equipment
• To enable to conduct selective cementing, e.g. placing cement above a loss zone
• To minimise channelling (mud/spacer/cement)
• Reduce risk of flash setting (long interval jobs with different pressures/temperature).
Cementing Accessories for Special Jobs
• Cementing with losses requires extra accessories
PURPOSE
• Enable to place cement above loss zones • Isolate hydrocarbon zones at various
Ten Steps to Optimise Cement Job
• Condition the drilling fluid• Optimise casing accessories • Maximise displacement rate
• Ensure pipe movement [if practical] • Spacers and flushes
• Temperature effects
• Selection/test of cement composition • Additional pre-job considerations
• Job execution
Condition the Drilling Fluid
• Viscosity of the mud should be reduced to the lowest practical
level before the drillpipe is removed from the hole.
• Not to reduce the mud rheology below the minimum level required to suspend the weighting agent.
• Once the casing has been run, the mud should be further
conditioned to remove gelled mud in areas of poor centralisation. • Min. two to three hole volumes are considered sufficient conditioning • After conditioning the hole, cementing should start without any break
Optimise Casing Accessories
• Best casing centralisation should be obtained by software. • A good rule-of-thumb is minimum 70% stand-off.
• Good centralisation can reduce casing running difficulties by helping to prevent differential sticking.
18 16 14 12 10 8 6 4 2 0 0 20 40 60 80 100 W W % Stand-off = w R H - R C X 100 API % STAND-OFF FLO W RA TE RA TIO R C R H
Casing Movement
• Whenever possible the casing should be reciprocated or rotated. • Pipe movement increases displacement efficiency by helping to
break-up gelled.
• Movement should be attempted - from hole conditioning to displacement.
• Rotation requires special equipment.
• For liners, rotation is recommended - due to concerns over setting the liner.
• Rules-of-thumb are suggested:
– reciprocate 20-40 ft over a period of 2-5 minutes – rotation rates of 10-40 rpm.
82
Spacers & Flushes Best Practices
• Used to:
– Separate Incompatible Fluids – Aid in Mud Displacement
– Leave All Downhole Surfaces Water-Wet • Volume Calculated By:
– 1000 ft Annular Fill or
– 10 min Contact Time
Displacement Rate
• Displacement rates should be maximised to obtain the most effective cement placement.
• Cement slurry washer and spacer fluid will achieve turbulence around the casing if it is possible
• Useful guideline is to ensure that the annular velocity (assuming concentric casing) is above 260 ft/min.
84
Fluid Velocity Best Practices
• Pump As Fast As PossibleDirection of flow
Plug Flow Laminar flow Turbulent flow
Laminar Sub-Layer Central Un-Sheared Core Laminar Sub-Layer
LOCAL FLUID VELOCITY
Pressures while Cementing
Balance the formation pressure Prevent the formation fracturing
Fracturing Gradient
Cement Bond Evaluation
Within 24 hours of the cement job
• Temperature log indicate the presence of cement and TOC.
More than 5 days after the cement job.
• Cement Bond Log (CBL) • Variable Density Log (VDL) • Cement Evaluation Tool (CET) • Ultrasonic Borehole Imaging (USI) • Segmented Bond Tool (SBT)
Cement Bond Evaluation
• Two major types of tools:
– Sonic tools (CBL/VDL)
• The attenuation rate depends on the cement compressive
strength, the casing diameter, and the percentage of bonded circumference.
• Variable density log
– Allows easy differentiation between casing and
formation arrivals
No Cement
Good Bond
Cement Bond Evaluation
Casing Bond Log [CBL]
• Bad Cementation
• High Attenuation/Ampl.
Casing Bond Log [CBL]
• Good Cementation • Low Attenuation/Ampl
Cement Proplems
Micro annular Mud Channel Mud Cake Poor Mudcake Removal Cement Integrity Insufficient HydrostaticLiner Cementing
Liner Cementing Guidelines
• Prior to the cementation the following calculations will be
conducted:
– Circulation volume
– Cement volume including excess – Volume of pre-flush
– Reduction in hydrostatic head due to pre-flush.
– For the pre-flush in open hole, assume gauge hole to calculate the height of the pre-flush.
– There should be sufficient overbalance at all times during
Liner Hanger Selection
Hanger Loading Forces
• Following cumulative forces should be taken into account. • (a) Liner hanging weight
• (b)The internal pressure required to initially set the
hanger and shear the ball seat • (c) Designated pressure to
bump the plug
• (d) Running string set down weight prior to cementing.
Liner Hanger Selection
Integral Packers
• To avoid sole reliance on the liner lap cement job.
Tie-back Packers
• If the integral packer is found to be leaking.
• In highly deviated wells rotating hangers are preferred.
• In deep or highly deviated wells, hydraulic set hangers are preferred. • If mechanically set liner hangers are
Liner Cementing
Liner Lap Length
• The optimum length of the liner lap will depend on the likelihood of obtaining a good cement bond over the liner lap.
• In vertical wells where the liner can be well centralised. – In this case a 250 - 500 ft liner lap should be used. • If use integral liner packers,
Cementing in Horizontal Section
Slurry used on horizontal sections:
• A settlement of more than 5 mm is unacceptable • A gradient of more than 1.0 lb/gal is unacceptable.
Displacement
• Circulate at least three times the hole volume
• Circulate until the properties of the mud returning are the same as those being pumped in.
Centralization
• Use rigid centralisers (or turbulators). • Use bowspring centralisers where.
97
Downhole Problems
Lost Circulation
Dr. Imre Federer
Associate Professor
99
LOST CIRCULATION MECHANISMS
• Measurable loss of whole mud (liquid phase and solid
phase) to the formation.
• Lost circulation can occur at any depth during any
operation.
PRESSURE INDUCED FRACTURE
• Wellbore pressure exceeds fracture pressure of the
formation causing the rock to crack open (fracture)
NATURALLY FRACTURES/ HIGH PERMEABILITY
• Overbalanced wellbore pressure is exposed a
formation with unsealed fractures or high permeability
ADVERSE EFFECTS ON DRILLING
OPERATIONS
IN ANY HOLE SECTIONS:
• Hole cleaning problems
• Hole bridge/ collapse
• Stuck pipe
• Well control event
SURFACE HOLE
• Loss of drive/ conductor shoe
• Loss of well
ADVERSE EFFECTS ON DRILLING
OPERATIONS
INTERMEDIATE and PRODUCTION
HOLE SECTIONS
• Loss of fluid level monitoring
• Loss of formation evaluation
• Extended wellbore exposure time
• Underground blowout
• Additional casing string
• Production zone damage
CAUSES OF LOST CIRCULATION
PRESSURE INDUCED FRACTURES
• Excessive mud weight
• Annulus friction pressure
• Wellbore pressure surges
• Imposed/ trapped pressure
• Shut-in pressure
• Low formation pressure
Cause:
- Wellbore pressure greater than fracturing pressure - Formation fractures allowes mud loss
Warning Sign: - Pronosed losses
- Excessive mud weight - Low fracture strength - Poor hole cleaning
- Wellbore pressure surge
Indications: - May begin with seepage loss
- Possible total loss - Pit volume loss
- Excessive hole fill-up
- In shut-in sudden loss of pressure
Firs Action: - Reduce pump speed to 1/2
(Total Loss) - Pull off bottom, stop pump
- Reset to zero stroke counter
- Fill annulus with water or light mud - Record strokes when annulus fill-up - Monitor well for flow
Preventiv Action: - Minimize mud weight
- Maximize solid removal - Control penetration rate
- Avoid imposed/ trapped pressure 104
CAUSES OF LOST CIRCULATION
NATURAL FRACTURES/ PERMEABILITY
• Unconsolidated formation
• Fissures/ fractures
• Unsealed fault boundary
• Vugular/ cavernous formation
106
Natural Fractures/High Permeability
Cause:
- Wellbore pressure is overbalanced to formation pressure - Mud is lost to natural fractures and/or high permeability
Warning: - Prodnosed loss zone
- Lost circulation can occure at any time during any openhole operation
Indications: - May begin with seepage loss
- Total loss possible
- Static losses during connections/survey - Pit volume loss
Firs Action: - Reduce pump speed to 1/2
(Total Loss) - Pull off bottom, stop pump
- Reset to zero stroke counter
- Fill annulus with water or light mud - Record strokes when annulus fill-up - Monitor well for flow
Preventiv Action: - Minimize mud weight
- Control penetration rate
- Minimize wellbore pressure surges - Pre-treat with LCM
LOSS SEVERITY CLASSIFICATIONS
SEEPAGE LOSS ( 20 BBLS/HR) PARTIAL LOSS ( 20 BBLS/HR) TOTAL LOSS (NO RETURNS) GRADUAL LOSSES OPERATION NOT INTERRUPTED POSSIBLE WARNING OF INCREASED LOSS SEVERITY IMMEDIATE DROP IN FLUID LEVEL WHEN PUMPING IS STOPPED SLOW TO REGAIN RETURNS AFTER STARTING CIRCUL. OPERATIONS USUALLY INTERRUPTED REMEDIAL ACTION REQUIRED RETURN FLOW STOPS IMMEDIATELY PUMP PRESSURE DECREASE STRING WEIGHT INCREASE OPERATION SUSPENDED REMEDIAL ACTION REQUIRED 107METHODS FOR LOCATING LOSS DEPTH
Successful treatment of lost circulation depends greatly on locating the depth of the loss zone
SURVEY METHODS PRACTICAL METHODS
TEMPERATURE SURVEY ACOUSTIC LOG
RADIOACTIVE TRACER SPINNER SURVEY
PRESSURE TRANSDUCER HOT WIRE SURVEY
OFFSET WELL DATA GEOLOGIST LOGGER
IDENTIFIES
POTENTIAL LOSS ZONE MONITORING FLUID LEVEL
TRENDS
WHILE DRILLING
GUIDELINES FOR LOST CIRCULATION SOLUTIONS
ACTION RESULTS CONSIDERATIONS
MINIMIZE MUD WT
Reduced wellbore pressure(driving force pushing mud into loss zone
More successful with pressure induced fractures
Possible well control event or hole instability problems
FORMATION “HEALING TIME”
Reactive clays of loss zone swell with water producing plugging effect
Soft shale deform with formation stress helping to “heal” the fracture
More successful with fresh water mud lost to shale formations
Better results with LCM
Normal 6-8 hours wait time with string in casing
LOSS CIRC. MATERIAL (LCM)
Effectively bridges, mats and seals small to
medium fractures/ permeability
Less effective with large fractures, faults
Ineffective cavernous zones
Increase LCM lbs/bbl with loss severity
GUIDELINES FOR LOST CIRCULATION SOLUTIONS (Cont′d)
ACTION RESULTS CONSIDERATIONS
SPECIALTY TECHNIQUES
A plug base is pumped into the loss zone
followed by a chemical activator
The two materials form a soft plug
Can be used in production zones
Increased risk of plugging equipment
Plug breaks down with time
CEMENT
Cement slurry is
squeezed into the loss zone under injection pressure
Provides a “fit-to-form” solid plug at or near the stress of the surrounding formation
DRILLING BLIND
In some cases, the only practical solution is to drill without returns
Not a consideration where well control potential exist
Set casing in the first competent formation
GUIDELINES FOR SUCCESSFUL LCM RESULTS
Locating the loss zone and accurate pill placement is vital. Position the string +/- 100 feet above loss zone, do not stop
pumping until the pill clears the bit.
Insure the base mud viscosity will suspend the LCM volume added.
Add fresh gel to a premixed LCM pill immediately before pumping, fresh gel continues to yield after spotting
An effective LCM pill bridges, matts and then seals the loss zone, particle size distribution and pill formulation must satisfy these requirements.
Consult the LCM product guide prior to applying the pill Use large nozzle sizes if the loss potential is high.
Keep the string moving during pill spotting operation to avoid stuck pipe
LOSS CIRCULATION MATERIAL (LCM)
MATERIAL DEFINITION
GRADES
FINE (F) A portion of material pass through the shaker.
MEDIUM (M) Majority of material will screen-out at shakers. COARSE (C) All material will screen-out at shaker. Will plug nozzles. Recommended open-ended pipe.
FIBROUS FLAKED
Non-rigid materials that form a mat on the hole wall to provide a foundation for normal filter cake development.
GRANULAR Rigid materials that plug the permeability of the loss zone
LCM BLEND Combination of fibrous, flaked and granular materials in sack
CELLULOSTIC Sized wood derived materials used to prevent seepage/partial loss
CALCIUM CARBONATE
Sized limestone or marble (acid soluble) used for seepage/partial loss in production zone
SIZED SALT Granulated salt (water soluble) developed for seepage/ partial loss
in production zone in salt-saturated systems
SEEPAGE LOSS SOLUTIONS (20 BBLS/HR)
FIRST ACTION RECOVERY
Reduce ROP to limit cuttings load Minimize mud
rheology
Add LCM pill in 5-10 PPB increments. Evaluate results over 2 circulations before increasing to next level of LCM concentration. Mix in 30 to 50 bbl batches dictated by hole size. Consider spotting LCM pill before POOH Minimize GPM NON-PRODUCTIVE INTERVALS
Minimize wellbore pressure surges Minimize mud wt WBM: LCM Blend (F) 5-15 PPB LCM Blend (M) 5-15 PPB Flaked (F/M) 10-20 PPB OBM/SBM: Cellulosic (F/M) 2-25 PPB
PRODUCTION ZONE EXPOSED
Consider pulling into casing and
waiting 6 to 8 hours WBM: Limestone (F/M) 5-30 PPB OBM/SBM: Cellulosic (F/M) 2-25 PPB Limestone (F/M) 5-15 PPB 113
PARTIAL LOSS SOLUTIONS (20 BBLS/HR)
FIRST ACTION RECOVERY
Reduce ROP to limit cuttings load Minimize mud
rheology
Add LCM pill in 5-10 PPB increments. Evaluate results over 2 circulations before increasing to next level of LCM concentration. Mix in 30 to 50 bbl batches dictated by hole size. Consider spotting LCM pill before POOH Minimize GPM NON-PRODUCTIVE INTERVALS
Minimize wellbore pressure surges Minimize mud wt WBM: LCM Blend (M) 15-25 PPB LCM Blend (C) 15-25 PPB Walnut (M/C) 10-20 PPB OBM/SBM: Cellulosic (F/M) 10-25 PPB Cellulosic (C) 10-25 PPB Walnut (M) 5-15 PPB
PRODUCTION ZONE EXPOSED
Consider pulling into casing and
waiting 6 to 8 hours WBM: LCM Blend (F) 5-15 PPB LCM Blend (M) 5-15 PPB Cellulosic (M) 5-15 PPB OBM/SBM: Cellulosic (F/M) 2-25 PPB Limestone (F) 5-15 PPB 114
TOTAL LOSS SOLUTIONS
FIRST ACTION RECOVERY
Pull off bottom, keep string moving Fill annulus with
water or light mud
Formulations for the specially pill and cement are dictated by conditions of each event
Minimize GPM NON-PRODUCTIVE INTERVALS
Record strokes if annulus fills up Minimize wellbore pressure surges WBM: 40 PPB LCM Pill Specialty Pill Cement Squeeze OBM/SBM: 30-40 PPB LCM Pill Specialty Pill Cement Squeeze
PRODUCTION ZONE EXPOSED
Consider pulling into the casing
WBM: 40 PPB LCM Pill Specialty Pill Cement Squeeze RESERVOIR NEEDS OBM/SBM: 30-40 PPB LCM Pill Specialty Pill Cement Squeeze RESERVOIR NEEDS 115
SEALING MATERIALS USED FOR LOST CIRCULATION
MATERIAL TYPE DESCRIPTION CONCENTR. LBS/BBL
LARGEST FRACTURE SEALED (INCHES)
0 4 8 12 16 20
Nutshell Granular 50%-3/16+ 10 mesh
50%-10+ 100 mesh 20 ______________ Plastic Granular 50%-3/16+ 10 mesh
50%-10+ 100 mesh 20 ______________ Limestone Granular 50%-3/16+10 mesh
50%-10+ 100 mesh 40 ________ Sulphur Granular 50%-3/16+ 10 mesh
50%-10+ 100 mesh 120 ________ Nutshell Granular 50%-10+ 16 mesh
50%-30+ 100 mesh 20 __________ Expanded Percite Granular 50%-3/16+10 mesh 50%-10+ 100 mesh 60 ________ 116
SEALING MATERIALS USED FOR LOST CIRCULATION
MATERIAL TYPE DESCRIPTION CONCENTR. LBS/BBL
LARGEST FRACTURE SEALED (INCHES)
0 4 8 12 16 20
Cellophane Laminated ¾” flakes 8 ________ Sawdust Fibrous ¼” particles 10 ________ Prairie Hay Fibrous ½” particles 10 ________ Bark Fibrous 3/8” particles 10 _____ Cottonseed
Hulls
Granular Fine 10 _____ Prairie Hay Fibrous 3/8” particles 12 ____
SPOTTING PROCEDURES FOR LOST CIRCULATION MATERIAL (LCM)
Locate the loss zone.
Mix 50 – 100 barrels of mud with 25 – 30 ppb bentonite and 30 – 40 ppb LCM
Position the drill string+/-100 feet above the loss zone
If open-ended, pump ½ of the pill into the loss zone. Stop the pump, wait 15 minutes and pump the remainder of the pill
If pumping through the bit, pump the entire pill and follow with 25 barrels of mud
If returns are not regained, repeat procedure. If returns are not regained, wait 2 hours and repeat procedure.
If returns are not regained after pumping 3 pills, consider other options to regain circulation
SPOTTING PROCEDURE FOR CEMENT
The cement slurry formulation should be tested by the cement company to determine the thickening time.
If possible, drill through the entire loss circulation interval Pull out of the hole and return with open-ended drill pipe
Position the open-ended drill pipe approximately 100 feet above the loss zone
Mix and pump 50 to 100 bbls of cement slurry
Follow the slurry with a sufficient volume of mud or water to balance the U-Tube
Wait 6 to 8 hours and attempt to fill the annulus Repeat the procedure if returns are not regained
It may be necessary to drill out the cement before repeating the procedure
LOST CIRCULATION PREVENTION GUIDELINES (1)
Prevention of lost circulation must be considered in the well planning, drilling and post analysis phases.
Design the casing program to case-off low pressure or suspected lot circulation zones.
Maintain mud weight to the minimum required to control known formation pressures.
Pre-treat the mud system with LCM when drilling through known lost circulation intervals.
Maintain low mud rheology values that are still sufficient to clean the hole.
Rotating the drill string when starting circulation helps to break the gels and minimize pump pressure surges.
Start circulation slowly after connections and periods of non-circulation.
LOST CIRCULATION PREVENTION GUIDELINES (2)
Prevention of lost circulation must be considered in the well planning, drilling and post analysis phases.
Use minimum GPM flow rate to clean the hole when drilling known lost circulation zone.
Control drill known lost circulation zone to avoid loading the annulus with cuttings.
Reduce pipe tripping speeds to minimize swab/surge pressure.
Plan to break circulation at 2 to 3 depths while tripping in the hole. Minimize annular restrictions.
Consider using jet sizes that will allow the use of LCM pills (12/32” jets+).
Be prepared for plugging pump suctions, pump discharge screen, drill string screens, etc.
Be prepared for mud losses due to shaker screen plugging.
PRECAUTIONS WHILE DRILLING WITHOUT RETURNS (1)
Circumstances may dictate drilling blind until 50 feet of the next
competent formation is drilled.
Casing is set to solve the lost circulation problem. A blind drilling
operation must have Drilling Manager approval.
Insure an adequate water supply is available.
Use one pump to drill and the other pump to continuously add water to the annulus. Assign a person to monitor the flow line at all times.
Monitor torque and drag to determine when to pump viscous sweeps. Closely monitor pump pressure while drilling for indications of pack-off. Control drill (if possible) at one joint per hour.
Pick up off bottom every 15 feet (3m) to ensure the hole is not packing off. Keep the pipe moving at all times.
Maintain a 400-500 bbl reserve of viscous mud ready to pump.
Consider spotting viscous mud on bottom prior to tripping or logging.
PRECAUTIONS WHILE DRILLING WITHOUT RETURNS (1)
Stop drilling and consider pulling to the shoe if pump repairs are required. Start and stop pipe slowly and minimize pipe speed.
Consider spotting a viscous pill above the BHA prior to each connection. Prior to each connection, circulate and wipe the hole thoroughly.
Do not run surveys when drilling blind. If circulation returns, stop drilling.
Raise the drill string to the shut-in position. Stop the pumps and check the well for flow.
If flow is observed, close the BOP and observe shut-in pressures.
No pressure – Slowly circulate bottoms up through 2 open chokes.
Pressure Observed –Slowly circulate the kick with present mud weight. At all times to pump cement to the well
Downhole Problems
Stuck Pipe
Dr. Imre Federer
Planning of Common
Activities
WELL PLANNING
• PLANNING
is probably the single most important
aspect of Stuck Pipe Prevention
• ACTIVITIES
which require daily attention are:-
– Selection and Change of BHA
– Drilling and Reaming close to Bottom
– Tripping in/out of the Hole
– Prepare for and running of Casing
WELL PLANNING
Selection of BHA
•
Design Simplicity
- Keep BHA
as short as
practically possible
- Eliminate and/or
lay down tools
which are not used or
have a low probability of being used
• Jar Optimisation
- Type of Jar, Placement of Jar, use of 1 or 2 Jar
• Dimensions
- Accurately
gauge Bit/Stabilisers (OD
), Tools (OD, ID)
-
Free access of wireline tools
(e.g. Free Point Indicator)
Make-up Size Drill Collars/HWDP Assy
• Compromise
between:
– WOB
(rigidity and annular clearance)
– Annular velocity
across the BHA
– Wall contact area
Contact Area – Sticking Tendency
- Casing, Liners, DC, OH, Completions sizes
Certification/Inspection/Operating Hours
• Lay down
or change out tools which are
uncertified
or
have reached
max. operating hours
WELL PLANNING
Selection of BHA
Hole Cleaning
• Mud rheology optimisation
• Effective Hole Cleaning/Cutting Transport
Trends
• Use of information on past and current wells
• Plotting and comparing drag and torque trends
Rathole for Casing String
• Keep as short as practically possible with the aim to
improve cement bond
WELL PLANNING
DRILLING
WELL PLANNING
DRILLING
Borehole Geometry
• Control the Dogleg Severity
• Build-up sections, horizontal departures and doglegs.
• Use software to assess expected (up/down) drag and
buckling
• Awareness about changes in BHA (PDC Bit Gauge
Length, Stabilisers, Rigidity, Clearance)
DRAG – OVERPULL - SETDOWN -
INCREMENTAL TORQUE
Mechanisms
Surface Forces when MOVING STRING
MAX UP ROTATING WEIGHT UP WEIGHT UP DRAG OVERPULL TRAVELING EQPT WT ROTATE MEASURED WEIGHT 132Surface Forces when MOVING STRING
MIN DOWN ROTATING WEIGHT UP WEIGHT DOWN WEIGHT DOWN DRAG SETDOWN TRAVELING EQPT WT ROTATE MEASURED WEIGHT 133Surface Forces when MOVING STRING
MIN MAX DOWN UP ROTATING WEIGHT UP WEIGHT DOWN WEIGHT UP DRAG OVERPULL DOWN DRAG SETDOWN TRAVELING EQPT WT ROTATE MEASURED WEIGHT 134Definitions
• Down Weight
and
Up Weight
is the Measured
Weight under Normal Conditions, when moving String
down or up,
without Rotation
and with
Pumps shut
off
• Rotating Weight
is measured
off bottom
and
keeping
string stationary
(with or without pumping)
• Restrictions, Up or Down, will result in
Overpull
and
Setdown respectively
Surface Forces when MOVING STRING
Surface Torque
MAX OFF BOTTOM DRILLING INCREMENTAL TORQUE MEASURED TORQUEOFF BOTTOM TORQUE
DRILLING TORQUE
Drag Charts
MAX MIN MARGIN OF OVERPULL DOWN WEIGHT LINE ROTATING WEIGHT LINE UP WEIGHT LINE MEASURED WEIGHT SURFACE DEPTH OF WELL 137
Drag Charts
MAX MIN MARGIN OF OVERPULL DOWN WEIGHT LINE ROTATING WEIGHT LINE UP WEIGHT LINE MEASURED WEIGHT SURFACE DEPTH OF WELL CUTTINGS BED DEVELOPS CIRCULATION, ROTATION & SWEEPS EFFECT 138
Drag Charts for RUNNING CASING
MARGIN OF OVERPULL MEASURED WEIGHT SURFACE DEPTH OF WELL MIN PREVIOUS CSG SHOE MAX WEIGHT in MUD CASING CANNOT BE PULLED BACK FROM THIS POINT ONWARDS
Friction Forces … DRAG WEIGHT NORMAL FORCE TENSION DOWN TENSION UP
Friction Force = Normal Force x Friction Factor
• Normal Force >> results from dogleg & tension
• Friction Factor >> results from mud type&formation
Friction Factor / Coefficient SHALE LIMESTONE SOFT SANDSTONE HARD SANDSTONE FRICTION FACTORS (PSEUDO) OIL BASED MUD WATER BASED MUD LOW MEDIUM HIGH MEDIUM
Its dependence on lithology and casing/open hole
CASING
WELLBORE STABILITY
Stuck Pipe MECHANISMS # 1
Wellbore Stability
Hydro-Pressured Shale
accounts for majority of
Stuck Pipe Incidents
• Influencing
factors are:-
– MUD
Mud type, Mud Density
– DRILL STRING
BHA Make-up, Dynamics
– FORMATION
Rock Stress, Sensitivity
– TIME
Deterioration Bore Hole Wall
– ”COMPLEX”
if all above factors combined
Mechanical WellBore Instability
in different formations
