Drilling EngineeringDrilling FluidsDr. Imre FEDERERAssociate Professor

Drilling FluidsFunctions Of MudDrilling Mud AdditivesDrilling Fluid TypesDrilling Mud PropertiesDrilling Fluid SelectionDrilling Mud ProblemsSolids Control

Drilling FluidsTo remove the drilled cuttings from the hole. Viscosity, Mud Weight. To suspend the cuttings when circulation is stoppedGel 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 additivesTo assist in the gathering of the information from the formations.

Drilling Fluid AdditivesWeighting Materials

Drilling Fluid Additives Weighting MaterialsBarite (BaSO4)Barite (or barytes) is the most commonly used weighting material. Barium sulphate has a specific gravity in the range of 4.20 - 4.60It 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.Disadvantage: Not soluble in acid cause formation damage.

Drilling Fluid Additives Weighting MaterialsCalcium 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 carbonateDolomitre specific gravity of 2.80 - 2.90. The maximum mud density achieved is 1.60 s.g. (13.3 ppg).Its ability to react and dissolve in hydrochloric acid

Salt Brines

FluidPractical Maximum Density kg/l (ppg)Caesium Formate2.36 (19.7)Potassium Formate (KHCO2)1.60 (13.3)Sodium Formate (NaHCO2)1.33 (11.1)Sea water1.02 (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 Pointkg/lppgoCoFSodium Chloride (NaCl)1,028.5-2291,089.0-7191,149.5-1661,210.0-425Calcium Chloride (CaCl2)1,028.5-1301,149.5-1391,210.0-22-81,2610.5-37-361,3211.0-30-221,3811.5+235Calcium Chloride/Bromide (CaCl2/Br2)1,4412.012541,5613.015591,6814.017,7641,815.019,467

Drilling Fluid AdditivesMaterials used as viscosifiersViscosifiersHigh 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 MaterialsFiltration Control MaterialsFiltration 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 MaterialsBentonite is the "backbone" of clay based mud systems. It imparts viscosity and suspensionas well as filtration control. The flat, "plate like" structure of bentonite packs tightly togetherunder pressure and forms a firm compressible filter cake, preventing fluid from entering theformationPolymers such as Polyanionic cellulose (PAC) and Sodium Carboxymethylcellulose (CMC)reduce filtrate mainly when the hydrated polymer chains absorb onto the clay solids and plugthe pore spaces of the filter cake p preventing fluid seeping through the filter cake andformation. Filtration is also reduced as the polymer viscosifies the mud thereby creating aviscosified 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 likematerial which aids in the reduction of fluid loss. They form very compressible particles thatplug the small openings in the filter cake.Thinners and deflocculants function as filtrate reducers by separating the clay flocks orgroups 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 primaryviscosifiers used in the drilling fluid system. However, when efficient control of viscosityand gel development cannot be achieved by control of viscosifier concentration, materialscalled "thinners", "dispersants", and/or "deflocculants" are added. By definition, these arematerials that cause a change in the physical and chemical interactions between solids and/ordissolved salts such that the viscous and structure forming properties of the drilling fluid arereduced.Thinners are also used to reduce filtration and cake thickness, to counteract the effects ofsalts, to minimize the effect of water on the formations drilled, to emulsify oil in water, andto stabilize mud properties at elevated temperatures.Materials commonly used as thinners in water based clay containing drilling fluids can bebroadly classified as: (1) plant tannins, (2) lignitic materials, (3) lignosulfonates, and (4) lowmolecular 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 carbonatessolubility of many thinners and divalent metal ions such as calcium and magnesiumAlkalinity 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 pHand to maintain optimum pH and alkalinity in water base fluids Among the materials mostcommonly used to control pH are

Lubricating MaterialLubricating materials are used mainly to reduce friction between the wellbore and thedrillstring. This will in turn reduce torque and drag which is essential in highly deviate andhorizontal wells.Lubricating materials include: oil (diesel, mineral, animal, or vegetable oils), surfactants,fatty alcohol, graphite, asphalt, gilsonite, and polymer or glass beads

Shale Stabilizing MaterialsThere 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 shalestabilisation and that soluble salts must also be present in the aqueous phase to stabilize hydratable shales.

.D r. i.l .l i.n . g. . F. .l u. .i d. . T. .y . p. e. .sA drilling fluid can be classified by the nature of its continuous phase, i.e. what the fluid isbased on, or built from. The three types of drilling fluid are:1. Water Based Muds2. Oil Based Muds3. Gas Based Muds

Water Based MudWater Based MudThese are fluids where water is the continuous phase. The water may be fresh, brackish orseawater, whichever is most convenient and suitable to the system.The following designations are normally used to define the classifications of water basedrilling fluids:1. Non-dispersed-Non - inhibited

Water Based Mud2. Non-dispersed - Inhibited3. Dispersed - Non-inhibited4. Dispersed - InhibitedDispersed 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 dispersedequilibrium in the water phase.

Water Based MudInhibited means that the fluid contains inhibiting ions such as chlorine, potassium orcalcium or a polymer which suppresses the breakdown of the clays by charge association andor 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 chemicalthinners or dispersants to effect control of rheological properties.Inhibited - non-dispersed fluids contain inhibiting ions in the continuous phase, howeverthey do not utilize chemical thinners or dispersants.Non-inhibited dispersed fluids do not contain inhibiting ions in the continuous phase, butthey do rely on thinners or dispersants such as phosphates, lignosulfonate or lignite toachieve control of the fluids' rheological properties.Inhibited dispersed contain inhibiting ions such as calcium (Ca2+) or potassium (K+) in thecontinuous phase and rely on chemical thinners or dispersants, such as those listed above tocontrol the fluids rheological properties.

PRACTICAL RIG HYDRAULICSDr Federer Imre Associate Professor

Rheological models are mathematical equations used to predict fluid behaviour. Most drilling fluids are non-Newtonian and pseudoplastic .

BINGHAM PLASTIC MODELThe Bingham Plastic model describes laminar flow using the following equation: = YP + PV * ()

= measured shear stress in lb/100 ft2YP = yield point in lb/100 ft2PV = plastic viscosity in cP = shear rate in sec ^(1)

PV = 600 300YP = 300 PVYP = (2 300) 600

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 3) - 6

This equation assumes the fluid exhibits true plastic behaviour in the low shear rate range only.

POWER LAW MODELThe Power Law model assumes that all fluids are pseudoplastic in nature and are defined by the following equation:

= K *()^n

= Shear stress (dynes / cm2)K = Consistency Index = 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 Newtoniann < 1: The fluid is non-Newtoniann > 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 effectivenessof 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.

The effect of n value

HERSCHEL-BUCKLEY (YPL) MODELThe Herschel-Bulkley model describes the rheological behaviour of drilling muds more accurately than any other model using the following equation:

= o + K * ()^n

= measured shear stress in lb/100 ft^2o= fluid's yield stress (shear stress at zero shear rate) in lb/100 ft2K = fluid's consistency index in cP or lb/100 ft sec^2n = fluid's flow index= 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 EQUATIONSThe procedure for calculating the various pressure losses in a circulating system is summarised below:Calculate surface pressure losses using:P1 = E * ^0.8 * Q^1.8 * PV^0.2Decide on which model to use: Bingham Plastic or Power Law.Calculate pressure loses inside the drillpipe first then inside drillcollars.Divide the annulus into an open and cased sections.Calculate annular flow around drillcollars (or BHA).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.Determine the pressure drop available for the bit = pump pressure - system lossesDetermine 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 dropFor 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. Use appropriate equation to calculate annular pressure drop

BINGHAM PLASTIC MODEL PIPE FLOW ANNULAR FLOWPIPE 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:

If average velocity < critical velocity flow is laminar, use:

POWER LAW MODELPIPE FLOW - ANNULAR FLOWDetermine n and K from:

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:

POWER LAW MODELPIPE FLOW - ANNULAR FLOWANNULAR 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:

PRESSURE LOSS ACROSS BITThe 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.ProcedureFrom previous calculations, determine pressure drop across bit, using:

Determine nozzle velocity (ft/s):

Determine total area of nozzles (in^2):

Determine nozzle sizes in multiples of 32 seconds

OPTIMISATION OF BIT HYDRAULICSAll 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. This pressure loss is normally given the symbol Pc.

SURFACE PRESSUREOnce 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 CRITERIAThere 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 HORSEPOWERThe 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 FORCEIn 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 SELECTIONSmaller 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 RATEThe 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 CAPACITYFor 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.

4.Pipe rotation aids the removal of cuttings.

HOLE CLEANINGEfficient 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 VELOCITYA 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:

For turbulent flow, the equation becomes:

TRANSPORT VELOCITYTransport 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 10,11observed 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 anannular velocity of 100 ft/min, there appears to be a dependence of slip velocity on annular velocity.

DRILL CUTTINGS CONCENTRATIONTo 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 EngineeringCEMENTING OPERATIONSDr. Imre FEDERERAssociate Professor

Cementing OperationsFunctions of CementProvide zonal isolationPrimary barrier between formationsSupport axial load of casing strings and strings to be run laterProvide casing support and protectionSupport the borehole primary well control Hydrostatic pressure > Formation pressure

Cement SlurryCement additives modify the behaviour of the cement slurry. Acceleratorsreduce the thickening time of a slurry and increase the rate of early strength development.Retarders: chemicals which extend the thickening time of a slurryto aid cement placement.Extenders: materials which lower the slurry density and increase the yield.Weighting Agents: materials which increase slurry density.

Cement SlurryCement 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 UsedChemical compositionBenefitacceleratorsReducing WOC timeCalcium chlorideSodium chloridegypsumAccelerated setting, high early strengthretardersIncreasing thickening time for placement, reducing slurry viscosityOrganic acidsLignosulfonatesIncreased pumping timeWeight reducing additives Reducing weightBentonitegilsoniteLighter weight economyHeavy weight additivesIncreasing slurry weightHematitedispersantsHigher densityAdditives for controlling lost circulationBridging agentWalnut hullsGypsum cementLighter fluid columnsSqueezed fractured zoneFiltration-control additives Squeeze cementing, setting long linerspolymersReduced dehydration

Ktadatok p, T, h, formci tulajdonsgai,

Cement Excess

Slurry TestingReporting of Cement TestsWell NumberWell DepthBottom Hole Static Temperature (BHST)Bottom Hole Circulating Temperature (BHCT)Source of cement samples, water samples and additive samplesSpacer recommendation and recipe

Slurry TestingLead and Tail Slurry results including:Cement typeWater type, Water requirementsAdditive requirementsSlurry density, Slurry yieldThickening timeHeating schedule, Pressure scheduleRheology readings at BHCT (600-300-200-100-6-3 RPM))Compressive strength (8hrs-12hrs-16hrs-24hrs in psi)Estimated job time - to include mixing, pumping and displacement

Slurry MixerRheometer

ConsistometerThickening time

Ultrasonic Cement Analyser

Filterpress

Compressive StrengthMeasurement 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.

*Plug ContainerCement headCementing Equipment

*Top & Bottom Cementing PlugCementing EquipmentFloat ShoeGuide ShoeFloat CollarWill rupturewith pressure

9 5/813 3/818 5/872 7/8

*Mechanical Aids Best PracticesPipe MovementRotationReciprocationCasing AttachmentsScratchers scrape wallcake from boreholeCentralizers provide stand-off from bore holeSpecialized Float EquipmentCENTRALISERS

*

Cement Transporter/ Container

Slurry Mixing System

Control Consol

Displacement EfficiencyStand Off (with centralisers)Flow Regime (Laminar or Turbulence)Spacers (usually fresh water)Rotation (only if possible/practical)Reciprocation (only if critical)

*Mud Displacement Best Practices

Annular Flow Profile with Eccentric Casing

Common types of CementationsPRIMARYSingle Stage CasingInner String (Stinger)Multiple Stage (rarely used)LinerBalanced PlugSECONDARYRemedial CirculationSqueezeBailer (usually with coiled tubing)

Stinger (inner string) CementationWHEN :Relatively short & large diameter casing (surface)Hole size not accurately known or losses to the formationWHY :Allows flexibility in cement quantityKeep pumping until good cement seen at surface, thereafter only small volume of cement still to be displaced

Multiple Stage Cementation When/WhyTo enable cementing of very long intervals w/ weak zones, thus reducing pressure on formation and equipmentTo enable to conduct selective cementing, e.g. placing cement above a loss zoneTo minimise channelling (mud/spacer/cement)Reduce risk of flash setting (long interval jobs with different pressures/temperature).

Cementing Accessories for Special JobsCementing with losses requires extra accessories

PURPOSEEnable to place cement above loss zonesIsolate hydrocarbon zones at various depths in the well

Ten Steps to Optimise Cement JobCondition the drilling fluidOptimise casing accessoriesMaximise displacement rateEnsure pipe movement [if practical]Spacers and flushesTemperature effectsSelection/test of cement compositionAdditional pre-job considerationsJob executionEvaluation [logging to assess bond]

Condition the Drilling FluidViscosity 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 conditioningAfter conditioning the hole, cementing should start without any break in circulation.

Optimise Casing AccessoriesBest 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.

Casing MovementWhenever 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 minutesrotation rates of 10-40 rpm.

*Spacers & Flushes Best PracticesUsed to:Separate Incompatible FluidsAid in Mud DisplacementLeave All Downhole Surfaces Water-Wet

Volume Calculated By:1000 ft Annular Fill or10 min Contact Time WHICH ONE IS GREATER

Displacement RateDisplacement 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 possibleUseful guideline is to ensure that the annular velocity (assuming concentric casing) is above 260 ft/min.

*Fluid Velocity Best PracticesPump As Fast As PossibleDirection of flowPlug FlowLaminar flowTurbulent flowLaminar Sub-LayerCentral Un-Sheared CoreLaminar Sub-LayerLOCAL FLUID VELOCITY

Pressures while Cementing Balance the formation pressure

Prevent the formation fracturing

Fracturing GradientIncreased formation strength

Cement Bond EvaluationWithin 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 EvaluationTwo 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 logAllows easy differentiation between casing and formation arrivalsNoCementGoodBond

Cement Bond EvaluationCasing Bond Log [CBL]Bad CementationHigh Attenuation/Ampl.

Casing Bond Log [CBL]Good CementationLow Attenuation/Ampl

Cement Proplems

Liner CementingLiner Cementing GuidelinesPrior to the cementation the following calculations will be conducted:Circulation volumeCement volume including excessVolume of pre-flushReduction 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 the cement job.

Liner Hanger SelectionHanger Loading ForcesFollowing 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 SelectionIntegral PackersTo 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 used they should be resetable.

Liner CementingLiner Lap LengthThe 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, the liner lap need only be of the order of 100 ft in length.

Cementing in Horizontal SectionSlurry used on horizontal sections:A settlement of more than 5 mm is unacceptableA gradient of more than 1.0 lb/gal is unacceptable.DisplacementCirculate at least three times the hole volumeCirculate until the properties of the mud returning are the same as those being pumped in.CentralizationUse rigid centralisers (or turbulators).Use bowspring centralisers where.

*QUESTIONS?

Downhole ProblemsLost CirculationDr. Imre FedererAssociate Professor*

*Lost Circulation

LOST CIRCULATION MECHANISMSMeasurable loss of whole mud (liquid phase and solid phase) to the formation. Lost circulation can occur at any depth during any operation.PRESSURE INDUCED FRACTUREWellbore pressure exceeds fracture pressure of the formation causing the rock to crack open (fracture)NATURALLY FRACTURES/ HIGH PERMEABILITYOverbalanced wellbore pressure is exposed a formation with unsealed fractures or high permeability*

ADVERSE EFFECTS ON DRILLING OPERATIONSIN ANY HOLE SECTIONS:Hole cleaning problemsHole bridge/ collapseStuck pipeWell control eventSURFACE HOLELoss of drive/ conductor shoeLoss of well*

ADVERSE EFFECTS ON DRILLING OPERATIONSINTERMEDIATE and PRODUCTION HOLE SECTIONSLoss of fluid level monitoringLoss of formation evaluationExtended wellbore exposure timeUnderground blowoutAdditional casing stringProduction zone damage*

CAUSES OF LOST CIRCULATIONPRESSURE INDUCED FRACTURESExcessive mud weightAnnulus friction pressureWellbore pressure surgesImposed/ trapped pressureShut-in pressureLow 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 surgeIndications:- May begin with seepage loss- Possible total loss- Pit volume loss- Excessive hole fill-up- In shut-in sudden loss of pressureFirs 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 flowPreventiv Action:- Minimize mud weight - Maximize solid removal- Control penetration rate- Avoid imposed/ trapped pressure*Pressure Induced Fractures

CAUSES OF LOST CIRCULATIONNATURAL FRACTURES/ PERMEABILITYUnconsolidated formationFissures/ fracturesUnsealed fault boundaryVugular/ cavernous formation*

*Natural Fractures/High PermeabilityCause:- 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 flowPreventiv Action:- Minimize mud weight - Control penetration rate- Minimize wellbore pressure surges- Pre-treat with LCM

*

LOSS SEVERITY CLASSIFICATIONSSEEPAGE LOSS( 20 BBLS/HR)PARTIAL LOSS( 20 BBLS/HR)TOTAL LOSS(NO RETURNS)GRADUAL LOSSESOPERATION NOT INTERRUPTEDPOSSIBLE WARNING OF INCREASED LOSS SEVERITYIMMEDIATE DROP IN FLUID LEVEL WHEN PUMPING IS STOPPEDSLOW TO REGAIN RETURNS AFTER STARTING CIRCUL.OPERATIONS USUALLY INTERRUPTEDREMEDIAL ACTION REQUIREDRETURN FLOW STOPS IMMEDIATELYPUMP PRESSURE DECREASESTRING WEIGHT INCREASEOPERATION SUSPENDEDREMEDIAL ACTION REQUIRED

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METHODS FOR LOCATING LOSS DEPTHSuccessful treatment of lost circulation depends greatly on locating the depth of the loss zone

SURVEY METHODSPRACTICAL METHODSTEMPERATURE SURVEYACOUSTIC LOGRADIOACTIVE TRACERSPINNER SURVEYPRESSURE TRANSDUCERHOT WIRE SURVEYOFFSET WELL DATAGEOLOGIST LOGGER IDENTIFIESPOTENTIAL LOSS ZONEMONITORING FLUID LEVEL TRENDSWHILE DRILLING

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GUIDELINES FOR LOST CIRCULATION SOLUTIONSACTIONRESULTSCONSIDERATIONSMINIMIZE MUD WTReduced wellbore pressure(driving force pushing mud into loss zoneMore successful with pressure induced fracturesPossible well control event or hole instability problemsFORMATIONHEALINGTIMEReactive clays of loss zone swell with water producing plugging effectSoft shale deform with formation stress helping to heal the fractureMore successful with fresh water mud lost to shale formationsBetter results with LCMNormal 6-8 hours wait time with string in casingLOSS CIRC.MATERIAL(LCM)Effectively bridges, mats and seals small to medium fractures/ permeabilityLess effective with large fractures, faultsIneffective cavernous zonesIncrease LCM lbs/bbl with loss severity

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GUIDELINES FOR LOST CIRCULATION SOLUTIONS (Contd)ACTIONRESULTSCONSIDERATIONSSPECIALTYTECHNIQUESA plug base is pumped into the loss zone followed by a chemical activatorThe two materials form a soft plugCan be used in production zonesIncreased risk of plugging equipmentPlug breaks down with timeCEMENTCement slurry is squeezed into the loss zone under injection pressureProvides a fit-to-form solid plug at or near the stress of the surrounding formationDRILLINGBLINDIn some cases, the only practical solution is to drill without returnsNot a consideration where well control potential existSet casing in the first competent formation

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GUIDELINES FOR SUCCESSFUL LCM RESULTSLocating 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 spottingAn 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 pillUse large nozzle sizes if the loss potential is high. Keep the string moving during pill spotting operation to avoid stuck pipe

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LOSS CIRCULATION MATERIAL (LCM)MATERIALDEFINITIONGRADESFINE (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 FLAKEDNon-rigid materials that form a mat on the hole wall to provide a foundation for normal filter cake development.GRANULARRigid materials that plug the permeability of the loss zoneLCM BLENDCombination of fibrous, flaked and granular materials in sackCELLULOSTICSized wood derived materials used to prevent seepage/partial lossCALCIUM CARBONATESized limestone or marble (acid soluble) used for seepage/partial loss in production zoneSIZED SALTGranulated salt (water soluble) developed for seepage/ partial loss in production zone in salt-saturated systems

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SEEPAGE LOSS SOLUTIONS (20 BBLS/HR)FIRST ACTIONRECOVERYReduce ROP to limit cuttings loadMinimize mud rheologyAdd 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 POOHMinimize GPMNON-PRODUCTIVE INTERVALSMinimize wellbore pressure surgesMinimize mud wtWBM:LCM Blend (F) 5-15 PPBLCM Blend (M) 5-15 PPBFlaked (F/M) 10-20 PPBOBM/SBM:Cellulosic (F/M) 2-25 PPBPRODUCTION ZONE EXPOSEDConsider pulling into casing and waiting 6 to 8 hoursWBM:Limestone (F/M) 5-30 PPBOBM/SBM:Cellulosic (F/M) 2-25 PPBLimestone (F/M) 5-15 PPB

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PARTIAL LOSS SOLUTIONS (20 BBLS/HR)FIRST ACTIONRECOVERYReduce ROP to limit cuttings loadMinimize mud rheologyAdd 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 POOHMinimize GPMNON-PRODUCTIVE INTERVALSMinimize wellbore pressure surgesMinimize mud wtWBM:LCM Blend (M) 15-25 PPBLCM Blend (C) 15-25 PPBWalnut (M/C) 10-20 PPBOBM/SBM:Cellulosic (F/M) 10-25 PPBCellulosic (C) 10-25 PPBWalnut (M) 5-15 PPBPRODUCTION ZONE EXPOSEDConsider pulling into casing and waiting 6 to 8 hoursWBM:LCM Blend (F) 5-15 PPBLCM Blend (M) 5-15 PPBCellulosic (M) 5-15 PPBOBM/SBM:Cellulosic (F/M) 2-25 PPBLimestone (F) 5-15 PPB

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TOTAL LOSS SOLUTIONSFIRST ACTIONRECOVERYPull off bottom, keep string movingFill annulus with water or light mudFormulations for the specially pill and cement are dictated by conditions of each eventMinimize GPMNON-PRODUCTIVE INTERVALSRecord strokes if annulus fills upMinimize wellbore pressure surgesWBM:40 PPB LCM PillSpecialty PillCement SqueezeOBM/SBM:30-40 PPB LCM PillSpecialty PillCement SqueezePRODUCTION ZONE EXPOSEDConsider pulling into the casingWBM:40 PPB LCM PillSpecialty PillCement SqueezeRESERVOIR NEEDSOBM/SBM:30-40 PPB LCM PillSpecialty PillCement SqueezeRESERVOIR NEEDS

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SEALING MATERIALS USED FOR LOST CIRCULATIONMATERIALTYPEDESCRIPTIONCONCENTR.LBS/BBLLARGEST FRACTURESEALED (INCHES)0 4 8 12 16 20NutshellGranular50%-3/16+ 10 mesh50%-10+ 100 mesh20______________PlasticGranular50%-3/16+ 10 mesh50%-10+ 100 mesh20______________LimestoneGranular50%-3/16+10 mesh50%-10+ 100 mesh40________SulphurGranular50%-3/16+ 10 mesh50%-10+ 100 mesh120________NutshellGranular50%-10+ 16 mesh50%-30+ 100 mesh20__________ExpandedPerciteGranular50%-3/16+10 mesh50%-10+ 100 mesh60________

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SEALING MATERIALS USED FOR LOST CIRCULATIONMATERIALTYPEDESCRIPTIONCONCENTR.LBS/BBLLARGEST FRACTURESEALED (INCHES)0 4 8 12 16 20CellophaneLaminated flakes8________SawdustFibrous particles10________Prairie HayFibrous particles10________BarkFibrous3/8 particles10_____Cottonseed HullsGranularFine10_____Prairie HayFibrous3/8 particles12____

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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 zoneIf open-ended, pump of the pill into the loss zone. Stop the pump, wait 15 minutes and pump the remainder of the pillIf pumping through the bit, pump the entire pill and follow with 25 barrels of mudIf 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

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SPOTTING PROCEDURE FOR CEMENTThe cement slurry formulation should be tested by the cement company to determine the thickening time. If possible, drill through the entire loss circulation intervalPull out of the hole and return with open-ended drill pipePosition the open-ended drill pipe approximately 100 feet above the loss zone Mix and pump 50 to 100 bbls of cement slurryFollow the slurry with a sufficient volume of mud or water to balance the U-TubeWait 6 to 8 hours and attempt to fill the annulus Repeat the procedure if returns are not regainedIt may be necessary to drill out the cement before repeating the procedure

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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.

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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.

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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.

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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 ProblemsStuck PipeDr. Imre FedererAssociate Professor

Planning of Common Activities*

WELL PLANNINGPLANNING is probably the single most important aspect of Stuck Pipe Prevention

ACTIVITIES which require daily attention are:-Selection and Change of BHADrilling and Reaming close to Bottom Tripping in/out of the Hole Prepare for and running of Casing

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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 usedJar Optimisation- Type of Jar, Placement of Jar, use of 1 or 2 JarDimensions- 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 BHAWall contact areaContact Area Sticking Tendency - Casing, Liners, DC, OH, Completions sizesCertification/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 optimisationEffective Hole Cleaning/Cutting TransportTrendsUse of information on past and current wellsPlotting and comparing drag and torque trendsRathole for Casing StringKeep as short as practically possible with the aim toimprove cement bondWELL PLANNINGDRILLING*

WELL PLANNINGDRILLINGBorehole GeometryControl the Dogleg SeverityBuild-up sections, horizontal departures and doglegs.Use software to assess expected (up/down) drag and bucklingAwareness about changes in BHA (PDC Bit Gauge Length, Stabilisers, Rigidity, Clearance)

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DRAG OVERPULL - SETDOWN - INCREMENTAL TORQUEMechanisms *

Surface Forces when MOVING STRING MAXUPROTATING WEIGHTUP WEIGHTUP DRAGOVERPULLTRAVELING EQPT WTROTATEMEASURED WEIGHT*

Surface Forces when MOVING STRING MINDOWNROTATING WEIGHTUP WEIGHTDOWN WEIGHTDOWN DRAGSETDOWNTRAVELING EQPT WTROTATEMEASURED WEIGHT*

Surface Forces when MOVING STRING MINMAXDOWNUPROTATING WEIGHTUP WEIGHTDOWN WEIGHTUP DRAGOVERPULLDOWN DRAGSETDOWNTRAVELING EQPT WTROTATEMEASURED WEIGHT*

DefinitionsDown Weight and Up Weight is the Measured Weight under Normal Conditions, when moving String down or up, without Rotation and with Pumps shut offRotating Weight is measured off bottom and keeping string stationary (with or without pumping)Restrictions, Up or Down, will result in Overpull and Setdown respectivelySurface Forces when MOVING STRING *

Surface Torque MAXOFF BOTTOMDRILLINGINCREMENTAL

TORQUEMEASURED TORQUEOFF BOTTOM TORQUEDRILLING TORQUE*

Drag Charts MAXMINMARGIN OF OVERPULLMARGIN OF SETDOWNDOWN WEIGHT LINEROTATING WEIGHT LINEUP WEIGHT LINEMEASURED WEIGHTMEASURED DEPTHSURFACEDEPTH OF WELL*

Drag Charts MAXMINMARGIN OF OVERPULLMARGIN OF SETDOWNDOWN WEIGHT LINEROTATING WEIGHT LINEUP WEIGHT LINEMEASURED WEIGHTMEASURED DEPTHSURFACEDEPTH OF WELLCUTTINGS BED DEVELOPSCIRCULATION, ROTATION & SWEEPS EFFECT*

Drag Charts for RUNNING CASING MARGIN OF OVERPULLMEASURED WEIGHTMEASURED DEPTHSURFACEDEPTH OF WELLMINPREVIOUSCSG SHOEMAXWEIGHT in MUDCASING CANNOT BE PULLED BACK FROM THIS POINT ONWARDS*

Friction Forces DRAGWEIGHTNORMAL FORCETENSION DOWNTENSION UPFriction Force = Normal Force x Friction FactorNormal Force >> results from dogleg & tensionFriction Factor >> results from mud type&formation*

Friction Factor / Coefficient SHALELIMESTONESOFT SANDSTONEHARD SANDSTONEFRICTION FACTORS(PSEUDO) OIL BASED MUDWATER BASED MUDLOWMEDIUMHIGHMEDIUMIts dependence on lithology and casing/open holeCASING*

WELLBORE STABILITY Stuck Pipe MECHANISMS # 1 *

Wellbore StabilityHydro-Pressured Shale accounts for majority of Stuck Pipe IncidentsInfluencing factors are:- MUDMud type, Mud Density DRILL STRINGBHA Make-up, Dynamics FORMATIONRock Stress, Sensitivity TIMEDeterioration Bore Hole WallCOMPLEXif all above factors combined

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Mechanical WellBore Instabilityin different formations*

Shale Borehole InstabilityPRIMARY CAUSES:Mud WT is either too HIGH or too LOWRelatively HIGH Shale Pore Pressure close to the well boreHydration Stress (swelling shales)OTHER (supplementary) CAUSES:Natural fracturesDrill string vibration resulting in hole enlargement

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Rock Mechanical Factors*

Mud Weight OUTSIDE acceptable RANGERock Mechanical Influencing factors:When MUDWEIGHT TOO LOWWe will exceed COMPRESSIVE STRENGTH, resulting in COLLAPSEWhen MUDWEIGHT TOO HIGHWe will exceed TEN-SILE STRENGTH, resulting in FRACTURES and possibly LOSSESTools to calculate min/max mud weight:BOREOLE STABILITY CHARTS using area specific data

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Mudweight INSIDE acceptable RANGEWHEN DRILLING SHALE3,0004,5006,0007,5009,00010,5000.42511.512.513.5Depth TV [ft]14.5Mud Gradient [psi/ft]0.4650.6850.7300.7750.815Estimated Fracture GradientEstimated Pore Pressure Gradient654585255Estimated Borehole Collapse Gradient*

Rock Mechanical Borehole FailureShThe resultant Radial Stress Sr should be sufficient to prevent collapse of the hole by compression and shearing PoWELLBOREDrilling FluidSr = Radial Stress = Pw - PoPwSh = Rock (Hoop) Stress (created by drilling the hole)This shearing force is trying to collapse the holePw = WellBore Pressure (created by drilling fluid)This force is supporting the holePo = Pore Pressure (this force opposes the force exerted by the mud column)*

Rock Mechanical Borehole FailureWhen Radial Stress is small, the shear strength of the formation (such as SHALE) will be exceeded

RESULT CAVINGS

Increase mud weight*

High Pore Pressure Effect*

Distance from borehole wall [r/R] r = Distance from Hole Centre and R = Borehole radius15211917SandstoneOVERBALANCE (Wellbore - Pore Press) = 5300 kPa Pressure Differential creates Filter Cake Filter Cake prevents further penetration of fluid Pore Pressure is constant even after many days, except for a few inches close to Well BorePore PressureMud PressureOverbalance Pressure [kPa]300015004500High Pore Pressure in vicinity of Well Bore - SANDSTONE*

Distance from borehole wall [r/R]r = Distance from Hole Centre and R = Borehole radius152119171 Day45 Days7 DaysSandstoneShalePore PressureMud PressureOverbalance Pressure [kPa]OVERBALANCE (Wellbore - Pore Press) = 5300 kPa (Continuous) flow due to pressure differential over Shale Pore Pressure will quickly increase with time when overbalance is high. Compare the inflated Pore Pressures between 1 day and 45 days exposure Fluid penetration depends on medium (water/oil) and permeability of shale450030001500High Pore Pressure in vicinity of Well Bore - SHALE*

Distance from borehole wall [r/R] r = Distance from Hole Centre and R = Borehole radius152119171 DayIf we would use 1/2 the overbalance 7 DaysShalePore PressureMud PressureOverbalance Pressure [kPa]OVERBALANCE (Wellbore - Pore Press) = 2650 kPa Pore Pressure will increase less rapidly with time when overbalance is reduced to 1/2 the original value Fluid penetration still depends on medium water/oil) and permeability of shaleSandstone45 Days450030001500High Pore Pressure in vicinity of Well Bore - SHALE*

High Pore Pressure in vicinity of Well BoreWhen Drilling Shale, Filter Cake almost non-existent:Results in FLUID INVASION and DEEP PENETRATIONResults in PORE PRESSURE INCREASE with TIMEPreventive and Reducing Measures:Minimise Overbalance, increase density in small steps if rock stress increase as a result of inclinationSelect appropriate Drilling Fluid to reduce invasionAvoid high swab and surge pressuresAvoid well bore disturbances, i.e. (back-) reaming.

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Borehole Collapse in time*

Shale Instability vs. TimeHardening ZoneSoftening Zone

Borehole collapse vs. mud weight

Washed out and in gauge HOLESand in gauge holeShale washed out hole*

Mud Selection*

High Pore Pressure in vicinity of Well BoreMud Selection:Any mud which is effective in creating a threshold pressure within the shale capillaries:FIRST CHOICEnon-water based (oil based) even silicate or formate brinesSECOND CHOICEwater-basedwith KCl, Polymers, etc.Alternative and/or viscous mud filter cake (bad choice)A minimum overbalance is still essential

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Dynamic Bottomhole Pressure*

Drilling Fluids for ShaleNon-Water Based Fluids:Oil Based (aromatics)Pseudo Oil Based (ester/ether)Water Based Fluids:PolyglycolsKCl PolymersFerroChrome LignosulphonateSaturated CaCl2 & High Density FormatesSilicates (w/ gel forming - plugging pores)

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Difference Water Based & Oil Based MUDWELLBOREWELLBORECAPILLARY ACTIONREPULSIONSURFACE TENSIONFREE FLOW IN (SLOW)WBMOBMSHALESHALE*

Permeability of Shale:A filtercake cannot existOil Base reduces penetration of fluids (water phase) by capillary actionInstability:Can still occur with OBM if lack of mud weightOnset of fractures makes it easier for the situation to get worse or more difficult to restore.Difference Water Based & Oil Based MUD*

Effects of MUD on Bore Hole StabilityOil Base MudBore Hole Wallsmoothno interactionKCl WB Mudbalanced activityWB Mudunbalanced activityBore Hole Wallrelatively smoothreduced interactionBore Hole Wallroughhydration*

Operational - When Drilling ShalesMinimise Open Hole Time (golden rule)Adhere to planned/optimal Mud PropertiesKeep the Hole Clean (measure/check/confirm)Increase Mud Weight in small stepsAvoid decrease of Mud Weight if at all possibleMinimise backreaming if at all possible*

Mechanism # 2 DIFFERENTIAL STICKING *

DIFFERENTIAL STICKINGInfluencing factors are:- PERMEABILITYFormation Type and Zones WALL CONTACT BHA, DC Type, Size, Stabs, Deviation OVERBALANCEPore Pressure Depleted Zones MUD PROPERTIES Density, Filter Loss/Cake, Low Gravity Solids TIMEPipe MovementWhat can stick ?: BHA DCs, Casing, HWDP, DP

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StringExcess mud pressureFiltercakeGelled, stagnant mudPermeable FormationDeviationbuild-up of Low Gravity SolidsDIFFERENTIAL STICKING *

StringExcess mud pressureFiltercakeGelled, stagnant mudPermeable FormationDeviationbuild-up of Low Gravity SolidsStringContact Area will increase with timeStringString will sag and fully penetrate FCDIFFERENTIAL STICKING *

DIFFERENTIAL STICKING If NO Pipe Movement :With time, pipe/wire will penetrate into filtercakeContact area will increase, overbalance (mud density vs pore pressure) directly across pipe/wireSticking force will increase exponentially

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Why does it happen so OFTEN :Long duration Surveys, Connections, Minor RepairsPore Pressure information not known/measuredInadequate optimisation of BHA or W/L Tool StringInadequate optimisation of Mud PropertiesResponse of Rig Team to first signs; Immediate response to permanently stuck situation.DIFFERENTIAL STICKING *

Drilling FluidTorquePressureFilter CakeFiltrate

Filter Cake builds up Torque required to rotate ball and to break bond with cake increases if left stationary for longer period

Torque will increase exponentially with time

STICKANCE TESTER *

1. Overpull on connections will be:a. erraticc. increasingb. unaffectedd. smooth 2. Torque trend is likely to be:a. smoothc. erraticb. unaffectedd. increasing (connections) 3. Circulating Pressure will be:a. fluctuatingc. restrictedb. unaffectedd. impossible 4. The problem is ___unlikely______ to stabilise with time !a. most likelyc. likelyb. unlikelyd. expected 5. The warning signs begin to appear during:a. drillingc. reamingb. trippingd. connections

Differencial Sticking - Warning Signs

FREEING DIFFERENTIALLY STUCK PIPEImmediate action upon 1st indication:Apply maximum allowable slack down/pull and torque into stringJar down with substantial weight slacked offIf this is unsuccessful the following actions are necessary:Reduce the pressure differential to reduce density of the drilling fluid.Remove the wall cake by "dissolving" it through spotting pipe-lax pills dissolved in diesel oil. This can often take more than a day.*

Mechanism # 3 HOLE CLEANING *

HOLE CLEANING Influencing factors are:MUDRheology, Suspension when circulation low/stopped, Shear Thinning when circulation resumedCIRCULATION Rate to be as fast as Hole and Surface Equipment allowsROTATIONAs fast as BHA and Trajectoryallows. Caution during backreamingDEVIATIONProblematic between 50 65 degMEASURING Shale Shakers, Lag Time, Pressurewhile Drilling Tool (ECD)

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Hole CleaningIn combination with hole instability, the main cause of Stuck Pipe.*

Problematic between 50 and 65 degreesPotential cuttings beds between 40 and 75 degRelatively less problematic in horizontal section of holes

Hole Cleaning*

SIGNS are:How do we know the Hole is CLEAN? Cuttings or Cavings Volume Size Shape Overpull & Resistance High fluctuating Torque Swabbing Pump Pressure increase Past well experience*

LAMINAR versus TURBULENT*

LAMINAR FLOW VELOCITY PROFILEFLOW REGIME in Annulus *

LAMINAR Flow VelocitiesMinimum Flow Velocity considered to be: 50 m/min (150 ft/min)*

FLOW VELOCITY HIGHEST VALUESVELOCITY WITH POOR MUD RHEOLOGYDRILL STRINGFLOW REGIME in Annulus *

FLOW VELOCITY HIGHEST VALUESVELOCITY WITH POOR MUD RHEOLOGYWHEN OPTIMISING MUD RHEOLOGYDRILL STRINGTRYING TO REACH IMMOBILE MUD AND CUTTINGS BED(FAST) ROTATION OF DRILL STRING TO MOVE CUTTINGSFLOW REGIME in Annulus *

DefinitionTo optimise Hole Cleaning Efficiency in highly-deviated wellbores (40-80 from vertical), a balance must be struck betweenminimising particle settling velocity andpromotion of fluid velocity under eccentric drill pipe Adjustments in fluid properties made with only settling velocity or velocity under the drill pipe in mind will not promote efficient hole cleaning

Hole Cleaning Efficiency*

Shale Shakers where we SHOULD observe !!where we SHOULD observe !where we SHOULD measure !*

LOOK FORShale Shaker Volume Size TypeCUTTINGSCAVINGSSamplesHow do we know what we are LOOKING for ?*

What could be your contribution to HOLE CLEANING ? Observe Volume Cuttings Observe Volume Cavings Observe Type of Cavings Measure all of the above Report Observations Discuss Observationsand operationally... Pump Faster if possible Rotate Faster if possible Optimise Mud Rheologyat the Shale Shaker*

Hole Cleaning Guidelines - Drilling(critical for hole angles 40 - 65 deg)Drilling Practice:Drill with controlled ROP, if indications of loading the annulus with cuttingsCirculate at max. allowable pump rate, provided we have no losses or create washoutsDo not assume that the hole is clean:-Use drag/torque trends of previous wells; monitor and communicate trends current wellMeasure/record trends at the shale shaker

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Hole Cleaning Guidelines - Drilling(critical for hole angles 40 - 65 deg)Mud:Aim for mud properties with a shear thinning effect, which will ensure that we get:high annular velocities at low side of hole and over washouts when circulating at high rateMax suspension, when NOT circulating or trippingUse lo/hi vis tandem sweeps as required. The use of sweeps usually indicates mud rheology is not optimalReaming / Wiping Practice:Ream/wipe after drilling a long section in sliding mode. If high RPM can be used, hole cleaning is more efficient

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Hole Cleaning Guidelines - Connection(critical for hole angles 40 - 65 deg)Preparation and Practice:Ream/backream each single or stand; if cuttings bed has developedEnsure to use full rate circulation when reaming/wiping before connection and/or surveyAfter connection, rotate string first, before bringing pumps up to full rateMonitor, record, plot and communicate:Up/down/rot string weightOff and on bottom torqueCirculation pressure trends

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Hole Cleaning Guidelines - TRIPPING(critical for hole angles 40 - 65 deg)Immediate action: Overpull when Tripping:Determine overpull and setdown limits before the trip; discuss and agree with all staffIf overpull/setdown limit is reached, run back at least 1 stand; if the problem is thought to be solids, then clean hole with lo-hi vis sweepsIf cuttings/cavings bed is difficult to dislodge, backream with extreme caution, this might take time..! Most stuck pipe incidents when tripping occur as a result of impatience and shortcuts !*

MEASURING Hole Cleaning EFFECTIVENESSCUTTINGS FLOW METER (CFM)Collection Tray & Discharge SystemTray will dump after pre-set periodCorrelation in real time includes lag time, flow rate, hole volume etc. INFORMATION COLLECTED:- Cumulative Cuttings Weight & Volume Cuttings Flow Rate in volume against time and against lagged depth interval Ratio between measured cuttings flow rate and increase in hole volumeComparison of theoretical weight of rock drilled and cuttings weight showing cuttings left in hole

*

1. Up and down Drag Trends will be:a. smooth and highc. lowb. erratic and highd. unaffected 2. Torque trend will be:a. smooth & highc. high & erraticb. unaffectedd. impossible 3. Drag Trend will improve when:a. drillingc. calling the officeb. circulatingd. tripping 4. _a, b and/or c _ will increase if corrective action is NOT taken !a. hole fillc. pump pressureb. mud weightd. ROP 5. The warning signs are most likely to appear:a. after connectionsc. tripping outb. reaming downd. tripping in

Settling of Solids - Warning Signs

*Mechanism # 4 WELLBORE STABILITY

Other common causes for INSTABILITY (not Hydro-Pressured Shale related)Unconsolidated FormationsMobile FormationsFractured or Faulted FormationsGeo-pressured FormationsReactive FormationsTectonically Stressed Formations

*WELLBORE STABILITY

*Unconsolidated Formations

UNCONSOLIDATED Formations*Indications:Drilling shallow unconsolidated formation, sand, gravel in Top HoleAbundance of loose sand/ gravel over shale shaker, desander/-silterShakers blindingErratic DragSeepage or partial lossesPack-off possible. Regaining circulation difficult.

UNCONSOLIDATED Formations*Preventive Action:Ensure to have some fluid loss controlEnsure adequate hole cleaning. Accept controlled ROP to reduce annular density. Regularly sweep hole with hi-vis pillBe alert when making connections. Formation can slough in unexpectedly. Break circulation gently, avoids surgesInclude Jar in BHASpot hi-vis pill or gel mud before roundtrips and prior running casing

*Mobile Formations

MOBILE Formations*Indications:When drilling Salts or Plastic ShalesSalts known to deform plastically and/or creep into the wellbore over timeHigh overpull/setdown during wipertrips or roundtripsRepeated reaming required to continue making holeRestriction in circulation possible

MOBILE Formations*Preventive Action:Use of eccentric PDC Bits and/or use of roller reamerUse low WOB and high RPM. Accept controlled ROP and (re)-reaming intervalsExtensive precautionary reaming during wipertrips or roundtripsIncrease mud density, before entering mobile zone, if proven successful

MOBILE Formations*FreeingSpot a fresh water pill if in a salt formation. (Consider the effect on well control and on other open hole formations ). If moving up, apply torque and jar down with maximum trip load. If moving down, jar up with maximum trip load. Torque should not be applied while jarring up.

*Fractured or Faulted Formations

FRACTURED/FAULTED Formations*Indications:Drilling limestone, chalk or shale sequence with known history of fractures/faults, Formations to be brittle (e.g. coal)Large cuttings over shale shakerTorque during drilling/reaming fluctuating. Vibration possible.Partial or total lossesReaming required to pass interval during or after wipertrip/roundtrip

FRACTURED/FAULTED Formations*Preventive Action:Constantly check hole condition. Ream intervals precautionaryAvoid losses. Keep hole clean. Limit annular density (ECD). Restrict tripping speedsIf losses, pull out immediately above fractured/faulted zoneEnsure to have inhibited HCl acid at rigStability will return, provided rig team caution and known techniques

FRACTURED/FAULTED Formations*Freeing:If packed off while off bottom then follow First Actions. Otherwise JAR UP in an effort to break up formation debris. Use every effort to maintain circulation. Circulate high density viscous sweeps to clean debris. Spot acid if stuck in limestone.

*Geo-pressured Formations

GEO-PRESSURED Formations*Indications:Exploration/appraisal wells. Usually shale high pressure transition zoneFast ROP. Possibly some drag when moving string and making connectionsDistinctive splintery cavings. Usually accompanied by high levels of background gas and/or tripgasPack-off tendency during roundtrips when cavings have not been observed or when quantity has increasedSPALLING OF SPLINTERY CAVINGSPORE PRESSURE HIGHER THAN HYDR. HEAD

GEO-PRESSURED Formations*Preventive Action:Monitor and plot pore pressureCross check origin of cavings.Increase density in small incrementsTake time to circulate hole clean when fast ROPs are experienced. Be cautious when formation gas to surfaceAvoid excessive swabs and surges during roundtrips and connectionsExercise all practices related to hole cleaning and instability problems

GEO-PRESSURED Formations*Immediate action:Apply maximum allowable pull and torque into stringJar up/ jar down with substantial weight slacked offUse every effort to maintain circulation.

*Reactive Formations

REACTIVE Formations*Indications:Drilling shallow young shales Absorption of drilled shales into mudIncrease of plastic viscosity and yieldClayballs at surface, bit and stabiliser balling in the holeMushy, soft cuttingsOverpull on wipertrips/roundtripsIncrease of pump pressure and torque depending on annular clearance

REACTIV Formations*Preventive Action:Ensure adequate mud inhibition, e.g KCL, to minimise hydration processDilute mud if increase of bentonite content in mud cannot be controlledWipe the hole as required. Wash/ream if overpull/setdown becomes excessiveAvoid BHA with tight clearances Circulate clean at possible high rate, but caution when breaking circulationDrill quickly, minimise open hole time

Effects of MUD on Bore Hole StabilityOil Base MudBore Hole Wallsmoothno interactionKCl WB Mudbalanced activityWB Mudunbalanced activityBore Hole Wallrelatively smoothreduced interactionBore Hole Wallroughhydration*

REACTIV Formations*Immediate action:Apply maximum allowable pull and torque into stringJar down with substantial weight slacked offUse every effort to maintain circulation.

*Tectonically Stressed Formations

Indications:Wide variation in rock stress orientationMultiple faulting, e.g. in mountainous or active areasExtensive (back-) reaming during roundtrips. High fluctuating torque during hard reaming to bottom. Excessive quantities of cavings to surfaceDifficult to stop/limit instability with any mud or mud weight

*Tectonically Stressed Formations

TectonicStressTectonicStresscontinuoussqueezed holesand cavingsMountainous AreaMultiple FaultingStress Orientation*Tectonically Stressed Formations

Preventive Action:Make use of local experience, stability studiesCareful selection of optimum (low) inclination and direction through tectonically stressed formation(s)Drill tangent section through interval, if at all possible, to minimise open hole exposure timeIf instability is known to be difficult to stop, consider use of:oil based mudmaximum allowable densityextra casing contingency in programme

*Tectonically Stressed Formations

Freeing:If packed off while off bottom then follow First Actions. JAR UP/DOWN in an effort to break up formation debris. Use every effort to maintain circulation. Circulate high density viscous sweeps to clean debris.

*Tectonically Stressed Formations

*Borehole Geometry

Indications:At abrupt changes in angle or direction in medium-soft.Where high side wall forces and string rotation exist.Occurs only while POOH.Sudden overpull as BHA reaches dogleg depth.Unrestricted circulation.Free string movement below key seat depth possible.Cyclic overpull at tool joint intervals on trips.*Key Seating Borehole Geometry

Preventive Action:Minimise dogleg severity. Perform reaming and/or wiper trips if a dogleg is present.Consider running string reamers or a key seat wiper if a key seat is likely to be a problem.

*Key Seating Borehole Geometry

*Key Seating Borehole GeometryFreeingIf possible, apply torque and jar down with maximum trip load. Back ream out of the hole. If present use key seat wiper.

1. Up and down Drag Trends will begin to:a. stabilisec. increaseb. decreased. become erratic 2. Torque trend will be:a. smooth & highc. high & erraticb. constantd. low3. If borehole is smaller than Bit/BHA Circ. Pressure may:a. fluctuatec. washout the formationb. increased. stay about the same4. If water base mud is not salt saturated, you can expect:a. hole collapsec. anything, depends on formb. hole washoutd. excess filtercake5. The warning signs are most likely to develop during:a. drilling (occasionally)c. reaming downb. circulatingd. tripping

Borehole Geometry - Warning Signs

*Cement Related

Cement Related - Stuck Pipe Causes Indications:Poor CementationsLong ratholesPreventive Action:Minimise the length of rathole.Perform reaming and/or wiper trips.FreeingIf possible, apply torque and jar down with maximum trip load.

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*Undergauge Hole

Undergauged Hole*Undergauge HoleIndications:Dull bit evaulationCoringPreventive Action:Bit gauge protection.Perform reaming after coring.FreeingJAR UP with maximum trip load.

Junk in Hole*Indications:Something is missing at rigfloorHand tools, parts of tongs, slips..Preventive Action:Keep order at rigfloor.Good maintenance of toolsCareful workFreeingJAR DOWN with maximum trip load.

Drill String Vibration*Not a direct cause, but STABLE formations become to UNSTABLEIndications:High drill string vibrationPreventive Action:Appropriate BHA and weight on bitAppropriate transition zone between DC and DP

DRILLING FLUID When we select mud, you have to considerType of MudFormation StabilityHole CleaningDifferential StickingDrag and Torque

MUD plays the biggest role in avoiding of STUCK PIPE!

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