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 • To assist in the gathering of the information from the formations.
Drilling Fluid Additives Weighting Materials
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.
• Disadvantage: Not soluble in acid cause formation damage.
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). • Its ability to react and dissolve in hydrochloric acid
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
kg/l 1,02 1,08 1,14 1,2
1,02 1,14 1,2 1,26 1,32 1,38 1,44 1,56 1,68 1,8
Crystallization Point oC oF ppg Sodium Chloride (NaCl) 8.5 -2 29 9.0 -7 19 9.5 -16 6 10.0 -4 25 Calcium Chloride (CaCl2) 8.5 -1 30 9.5 -13 9 10.0 -22 -8 10.5 -37 -36 11.0 -30 -22 11.5 +2 35 Calcium Chloride/Bromide (CaCl2/Br2) 12.0 12 54 13.0 15 59 14.0 17,7 64 15.0 19,4 67
Drilling Fluid Additives 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.
Materials used as viscosifiers
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 • commonly used to control pH are
• 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 stabilize hydratable shales.
• .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 • 3. Gas 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: • 1. Non-dispersed-Non - inhibited
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 • equilibrium in the water phase.
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. Most drilling fluids are non-Newtonian and pseudoplastic .
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.
The effect of „n” value
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. Use appropriate equation to calculate annular pressure drop
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:
If average velocity < critical velocity flow is laminar, 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:
If average velocity < critical velocity flow is laminar, 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:
If average velocity < critical velocity flow is laminar, 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):
4.
Determine nozzle sizes in multiples of 32 seconds
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. This pressure loss is normally given the symbol Pc.
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. 4.Pipe rotation aids the removal of 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:
For turbulent flow, the equation becomes:
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 (or concentration) 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 – Hydrostatic pressure > Formation pressure
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: – materials which increase slurry density.
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
polymers
Reduced dehydration
•
Kútadatok p, T, h, formáció tulajdonságai,
Cement Excess
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) • Estimated job time - to include mixing, pumping and displacement
Slurry Mixer
Rheometer
Consistometer
Thickening time
Ultrasonic Cement Analyser
Filterpress
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.
Cementing Equipment Lifting Eye
Plug Container
Cement head
Cap
Body
1502 Unions (Fluid Ports)
Plug Release Plunger
Plug Launch Indicator
Detent Pin (Locks Quick-Latch in Open or Closed Position)
Quick Latch Coupler
60
Cementing Equipment
Float Shoe
Guide Shoe
Float Collar Will rupture with pressure
61
Top & Bottom Cementing Plug
13 3/8”
18 5/8” 7”
9 5/8” 2 7/8”
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
CENTRALISERS
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Cement Transporter/ Container
Slurry Mixing System
Control Consol
Displacement Efficiency • Stand 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
Bad
Good
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Annular Flow Profile with Eccentric Casing
Common types of Cementations PRIMARY • Single Stage Casing • Inner String (Stinger)
• Multiple Stage (rarely used) • Liner • Balanced Plug SECONDARY • Remedial Circulation • Squeeze • Bailer (usually with coiled tubing)
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, • thereafter only small volume of cement still to be displaced
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 depths in the well
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 • Evaluation [logging to assess „bond‟]
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 in circulation.
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.
FLOW RATE RATIO
18
RH
16 14
RC
12 10
W
8
w
6
% Stand-off = - R X 100 RH C
4 2 0
0
20
40 API % STAND-OFF
60
80
100
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.
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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 “WHICH ONE IS GREATER”
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.
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Fluid Velocity Best Practices • Pump As Fast As Possible
Direction of flow
LOCAL FLUID VELOCITY
Plug Flow
Laminar Sub-Layer
Laminar flow Central Un-Sheared Core
Turbulent flow Laminar Sub-Layer
Pressures while Cementing
Balance the formation pressure Prevent the formation fracturing
Fracturing Gradient
Increased formation strength
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.
No Cement
• Variable density log – Allows easy differentiation between casing and formation arrivals
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 Insufficient Hydrostatic Pressure
Micro annular
Cement Integrity
Fluid Loss
Poor Mudcake Removal
Mud Channel
Mud Cake
Liner 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 the cement job.
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 used they should be resetable.
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, – the liner lap need only be of the order of 100 ft in length.
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.
QUESTIONS? 97
Downhole Problems
Lost Circulation Dr. Imre Federer Associate Professor
98
Lost Circulation
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 100
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 101
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
102
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
103
Pressure Induced Fractures
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: (Total Loss)
- Reduce pump speed to 1/2 - 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
105
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: (Total Loss)
- Reduce pump speed to 1/2 - 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
Natural Fractures/High Permeability
106
LOSS SEVERITY CLASSIFICATIONS SEEPAGE LOSS
PARTIAL LOSS
TOTAL LOSS
( 20 BBLS/HR)
( 20 BBLS/HR)
(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.
RETURN FLOW STOPS IMMEDIATELY
PUMP PRESSURE DECREASE
STRING WEIGHT INCREASE
OPERATIONS USUALLY INTERRUPTED REMEDIAL ACTION REQUIRED
OPERATION SUSPENDED REMEDIAL ACTION REQUIRED
107
METHODS 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
OFFSET WELL DATA
ACOUSTIC LOG
GEOLOGIST LOGGER IDENTIFIES
RADIOACTIVE TRACER
POTENTIAL LOSS ZONE SPINNER SURVEY
PRESSURE TRANSDUCER
HOT WIRE SURVEY
MONITORING FLUID LEVEL TRENDS WHILE DRILLING
108
GUIDELINES FOR LOST CIRCULATION SOLUTIONS ACTION
RESULTS
MINIMIZE MUD WT FORMATION “HEALING TIME”
LOSS CIRC. MATERIAL (LCM)
Reduced wellbore pressure(driving force pushing mud into loss zone
CONSIDERATIONS
More successful with pressure induced fractures
Possible well control event or hole instability problems
Reactive clays of loss zone swell with water producing plugging effect Soft shale deform with formation stress helping to “heal” the fracture
Effectively bridges, mats and seals small to medium fractures/ permeability
More successful with fresh water mud lost to shale formations Better results with LCM Normal 6-8 hours wait time with string in casing Less effective with large fractures, faults Ineffective cavernous zones Increase LCM lbs/bbl with loss severity 109
GUIDELINES FOR LOST CIRCULATION SOLUTIONS (Cont′d) ACTION
RESULTS
SPECIALTY TECHNIQUES
BLIND
Can be used in production zones
Increased risk of plugging equipment
The two materials form a soft plug
Cement slurry is squeezed into the loss zone under injection pressure
CEMENT
DRILLING
A plug base is pumped into the loss zone followed by a chemical activator
CONSIDERATIONS
In some cases, the only practical solution is to drill without returns
Plug breaks down with time Provides a “fit-to-form” solid plug at or near the stress of the surrounding formation Not a consideration where well control potential exist Set casing in the first competent formation 110
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 111
LOSS CIRCULATION MATERIAL (LCM) MATERIAL
DEFINITION FINE (F) A portion of material pass through the shaker.
GRADES
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 112
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
OBM/SBM: Consider pulling WBM: Cellulosic (F/M) 2-25 PPB into casing and Limestone (F/M) 5-30 PPB Limestone (F/M) 5-15 PPB waiting 6 to 8 hours 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
WBM: OBM/SBM: Consider pulling LCM Blend (F) 5-15 PPB Cellulosic (F/M) 2-25 PPB into casing and LCM Blend (M) 5-15 PPB Limestone (F) 5-15 PPB waiting 6 to 8 hours Cellulosic (M) 5-15 PPB 114
TOTAL LOSS SOLUTIONS FIRST ACTION
Pull off bottom, keep string moving
Fill annulus with water or light mud
Minimize GPM
Record strokes if annulus fills up
Minimize wellbore pressure surges
RECOVERY Formulations for the specially pill and cement are dictated by conditions of each event NON-PRODUCTIVE INTERVALS 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
Plastic
Granular
Limestone
Granular
Sulphur
Granular
Nutshell
Granular
Expanded
Percite
Granular
50%-3/16+ 10 mesh 50%-10+ 100 mesh 50%-3/16+ 10 mesh 50%-10+ 100 mesh 50%-3/16+10 mesh 50%-10+ 100 mesh 50%-3/16+ 10 mesh 50%-10+ 100 mesh 50%-10+ 16 mesh 50%-30+ 100 mesh 50%-3/16+10 mesh
50%-10+ 100 mesh
20
______________
20
______________
40
________
120
________
20
__________
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
3/8” particles
10
_____
Fine
10
_____
3/8” particles
12
____
Fibrous
Cottonseed Granular Hulls Prairie Hay Fibrous
117
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 118
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 119
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 noncirculation. 120
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. 121
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. 122
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 123
Downhole Problems Stuck Pipe Dr. Imre Federer Associate Professor
Planning of Common Activities
125
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
126
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)
127
WELL PLANNING
Selection of BHA
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
128
WELL PLANNING
DRILLING 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 129
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)
130
Mechanisms DRAG – OVERPULL - SETDOWN INCREMENTAL TORQUE
131
Surface Forces when MOVING STRING
MEASURED WEIGHT
MAX ROTATING WEIGHT
ROTATE
UP WEIGHT
UP
UP DRAG OVERPULL TRAVELING EQPT WT 132
Surface Forces when MOVING STRING MIN MEASURED WEIGHT SETDOWN DOWN DRAG
DOWN DOWN WEIGHT
ROTATING WEIGHT
ROTATE
UP WEIGHT
TRAVELING EQPT WT 133
Surface Forces when MOVING STRING MIN MEASURED WEIGHT SETDOWN DOWN DRAG
DOWN DOWN WEIGHT
MAX ROTATING WEIGHT
ROTATE
UP WEIGHT
UP
UP DRAG OVERPULL TRAVELING EQPT WT 134
Surface Forces when MOVING STRING Definitions • 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
135
Surface Torque
MEASURED TORQUE
OFF BOTTOM
DRILLING
OFF BOTTOM TORQUE
DRILLING TORQUE INCREMENTAL
TORQUE
MAX 136
Drag Charts MEASURED WEIGHT
SURFACE
MAX MARGIN OF OVERPULL
DOWN WEIGHT LINE
ROTATING WEIGHT LINE UP WEIGHT LINE
MIN DEPTH OF WELL 137
Drag Charts MEASURED WEIGHT
SURFACE
MAX
UP WEIGHT LINE
MARGIN OF OVERPULL
DOWN WEIGHT LINE
ROTATING WEIGHT LINE CUTTINGS BED DEVELOPS
MIN DEPTH OF WELL
CIRCULATION, ROTATION & SWEEPS EFFECT 138
Drag Charts for RUNNING CASING MEASURED WEIGHT
SURFACE
MARGIN OF OVERPULL
PREVIOUS CSG SHOE
MAX
CASING CANNOT BE PULLED BACK FROM THIS POINT ONWARDS
MIN DEPTH OF WELL
WEIGHT in MUD 139
Friction Forces … DRAG
TENSION UP
Friction Force = Normal Force x Friction Factor • Normal Force >> results from dogleg & tension • Friction Factor >> results from mud type&formation
NORMAL FORCE
WEIGHT
TENSION DOWN 140
Friction Factor / Coefficient
FRICTION FACTORS (PSEUDO) OIL BASED MUD
LOW
WATER BASED MUD
MEDIUM
CASING
SHALE
LIMESTONE
SOFT SANDSTONE
HARD SANDSTONE
MEDIUM
HIGH
Its dependence on lithology and casing/open hole 141
Stuck Pipe MECHANISMS # 1
WELLBORE STABILITY
142
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
143
Mechanical WellBore Instability in different formations
144
Shale Borehole Instability PRIMARY CAUSES: • Mud WT is either too HIGH or too LOW • Relatively HIGH Shale Pore Pressure close to the well bore • Hydration Stress (swelling shales) OTHER (supplementary) CAUSES:
• Natural fractures • Drill string vibration resulting in hole enlargement
145
Rock Mechanical Factors
146
Mud Weight OUTSIDE acceptable RANGE Rock Mechanical Influencing factors: • When MUDWEIGHT TOO LOW – We will exceed COMPRESSIVE STRENGTH, resulting in COLLAPSE • When MUDWEIGHT TOO HIGH – We will exceed TEN-SILE STRENGTH, resulting in FRACTURES and possibly LOSSES Tools to calculate min/max mud weight: • BOREOLE STABILITY CHARTS using area specific data 147
Mudweight INSIDE acceptable RANGE WHEN DRILLING SHALE 3,000
5º Estimated Pore
4,500
Estimated Borehole Collapse Gradient
Pressure Gradient
Depth TV [ft]
25º
6,000
Estimated Fracture Gradient
45º
65º
7,500
85º 9,000
10,500
0.425
0.465
11.5
12.5
13.5
14.5
0.685
0.730
Mud Gradient [psi/ft]
0.775
0.815
148
Rock Mechanical Borehole Failure
Sh
WELLBORE Drilling Fluid
Pw Po Sr = Radial Stress = Pw - Po
Sh = Rock (Hoop) Stress (created by drilling the hole) This shearing force is trying to collapse the hole
Pw = WellBore Pressure (created by drilling fluid) This force is supporting the hole Po = Pore Pressure (this force opposes the force exerted by the mud column) The resultant Radial Stress Sr should be sufficient to prevent collapse of the hole by compression and shearing 149
Rock Mechanical Borehole Failure • When Radial Stress is small, the shear strength of the formation (such as SHALE) will be exceeded
RESULT »
» CAVINGS
Increase mud weight
150
High Pore Pressure Effect
151
High Pore Pressure in vicinity of Well Bore - SANDSTONE
OVERBALANCE (Wellbore - Pore Press) = 5300 kPa
Overbalance Pressure [kPa]
Mud Pressure 4500
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 Bore 3000
1500
Pore Pressure
Sandstone 15
17
Distance from borehole wall [r/R] r = Distance from Hole Centre and R = Borehole radius
19
21 152
High Pore Pressure in vicinity of Well Bore - SHALE OVERBALANCE (Wellbore - Pore Press) = 5300 kPa (Continuous) flow due to pressure differential over Shale
Overbalance Pressure [kPa]
Mud Pressure 4500
3000
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 shale Shale 45 Days 7 Days
1500 1 Day
Sandstone Pore Pressure
15
17
Distance from borehole wall [r/R] r = Distance from Hole Centre and R = Borehole radius
19
21 153
High Pore Pressure in vicinity of Well Bore - SHALE
OVERBALANCE (Wellbore - Pore Press) = 2650 kPa Pore Pressure will increase less rapidly with time
Overbalance Pressure [kPa]
Mud Pressure
Pore Pressure
when overbalance is reduced to 1/2 the original value Fluid penetration still depends on medium water/oil) 4500
and permeability of shale Shale
3000
45 Days 7 Days 1 Day
1500
If we would use 1/2 the overbalance
Sandstone 15
17
Distance from borehole wall [r/R] r = Distance from Hole Centre and R = Borehole radius
19
21
154
High Pore Pressure in vicinity of Well Bore • When Drilling Shale, Filter Cake almost non-existent: – Results in FLUID INVASION and DEEP PENETRATION – Results in PORE PRESSURE INCREASE with TIME
• Preventive and Reducing Measures: – Minimise Overbalance, increase density in small steps if rock stress increase as a result of inclination
– Select appropriate Drilling Fluid to reduce invasion – Avoid high swab and surge pressures – Avoid well bore disturbances, i.e. (back-) reaming. 155
Borehole Collapse in time
156
Shale Instability vs. Time
Hardening Zone Softening Zone
Borehole collapse vs. mud weight
‘Washed out’ and ‘in gauge’ HOLE
Shale ‘washed out’ hole
Sand ‘in gauge’ hole
159
Mud Selection
160
High Pore Pressure in vicinity of Well Bore Mud Selection:
• Any mud which is effective in creating a threshold pressure within the shale capillaries: – FIRST CHOICE
non-water based (oil based) even silicate or formate brines
– SECOND CHOICE
water-based with KCl, Polymers, etc.
– Alternative and/or viscous mud filter cake (bad choice) • A minimum overbalance is still essential
161
Dynamic Bottomhole Pressure
162
Drilling Fluids for Shale • Non-Water Based Fluids: – Oil Based (aromatics) – Pseudo Oil Based (ester/ether)
• Water Based Fluids: – Polyglycols – KCl Polymers – FerroChrome Lignosulphonate – Saturated CaCl2 & High Density Formates – Silicates (w/ gel forming - plugging pores) 163
Difference Water Based & Oil Based MUD
OBM WELLBORE
WBM WELLBORE
REPULSION SHALE
FREE FLOW IN (SLOW)
SHALE
SURFACE TENSION
CAPILLARY ACTION 164
Difference Water Based & Oil Based MUD • Permeability of Shale:
– A filtercake cannot exist – Oil Base reduces penetration of fluids (water phase) by capillary action
• Instability: – Can still occur with OBM if lack of mud weight – Onset of fractures makes it easier for the situation to get worse or more difficult to restore.
165
Effects of MUD on Bore Hole Stability Oil Base Mud
Bore Hole Wall smooth no interaction
KCl WB Mud balanced activity
Bore Hole Wall relatively smooth reduced interaction
WB Mud unbalanced activity
Bore Hole Wall rough hydration 166
Operational - When Drilling Shales • Minimise Open Hole Time (golden rule) • Adhere to planned/optimal Mud Properties • Keep the Hole Clean (measure/check/confirm)
• Increase Mud Weight in small steps • Avoid decrease of Mud Weight if at all possible • Minimise backreaming if at all possible
167
Mechanism # 2
DIFFERENTIAL STICKING
168
DIFFERENTIAL STICKING Influencing factors are:•
PERMEABILITY
Formation Type and Zones
•
WALL CONTACT
BHA, DC Type, Size, Stabs, Deviation
•
OVERBALANCE
Pore Pressure Depleted Zones
•
MUD PROPERTIES
Density, Filter Loss/Cake, Low Gravity Solids
•
TIME
Pipe Movement
What can ‘stick’ ?:
BHA DC‟s, Casing, HWDP, DP 169
DIFFERENTIAL STICKING build-up of Low Gravity Solids
Filtercake
Excess mud pressure
String Permeable Formation
Gelled, stagnant mud
170
DIFFERENTIAL STICKING build-up of Low Gravity Solids
Filtercake
Contact Area will increase with time
Excess mud pressure
String
String Permeable Formation
Gelled, stagnant mud
String will sag and fully penetrate FC
171
DIFFERENTIAL STICKING If NO Pipe Movement : • With time, pipe/wire will „penetrate’ into filtercake • Contact area will increase, overbalance (mud density vs pore pressure) directly across pipe/wire • Sticking force will increase exponentially
172
DIFFERENTIAL STICKING Why does it happen so OFTEN :
• Long duration Surveys, Connections, Minor Repairs • Pore Pressure information not known/measured • Inadequate optimisation of BHA or W/L Tool String
• Inadequate optimisation of Mud Properties • Response of Rig Team to first signs; Immediate response to permanently stuck situation.
173
STICKANCE TESTER
Torque Pressure Drilling Fluid
- 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 Filter Cake Filtrate 174
Differencial Sticking - Warning Signs 1. Overpull on connections will be: a. erratic c. increasing b. unaffected d. smooth 2. Torque trend is likely to be: a. smooth c. erratic b. unaffected d. increasing (connections) 3. Circulating Pressure will be: a. fluctuating c. restricted b. unaffected d. impossible 4. The problem is ___unlikely______ to stabilise with time ! a. most likely c. likely b. unlikely d. expected 5. The warning signs begin to appear during: a. drilling c. reaming b. tripping d. connections
FREEING DIFFERENTIALLY STUCK PIPE Immediate action upon 1st indication:
• Apply maximum allowable slack down/pull and torque into string • Jar down with „substantial‟ weight slacked off • If 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. 176
Mechanism # 3
HOLE CLEANING
177
HOLE CLEANING Influencing factors are: • MUD
Rheology, Suspension when circulation low/stopped, Shear Thinning when circulation resumed
• CIRCULATION Rate to be as fast as Hole and Surface Equipment allows • ROTATION
As fast as BHA and Trajectory allows. Caution during backreaming
• DEVIATION
Problematic between 50 – 65 deg
• MEASURING
Shale Shakers, Lag Time, Pressure while Drilling Tool (ECD) 178
Hole Cleaning In combination with hole instability, the main cause of Stuck Pipe.
179
Hole Cleaning
• Problematic between 50 and 65 degrees • Potential cuttings beds between 40 and 75 deg • Relatively less problematic in horizontal section of holes 180
How do we know the Hole is CLEAN? SIGNS are:
n Cuttings or Cavings - Volume - Size - Shape
n Overpull & Resistance n High fluctuating Torque n Swabbing
n Pump Pressure increase n Past well experience 181
LAMINAR versus TURBULENT
182
FLOW REGIME in Annulus
LAMINAR FLOW VELOCITY PROFILE
183
LAMINAR Flow Velocities
Minimum Flow Velocity considered to be: 50 m/min (150 ft/min)
184
FLOW REGIME in Annulus FLOW VELOCITY HIGHEST VALUES
VELOCITY WITH POOR MUD RHEOLOGY DRILL STRING
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FLOW REGIME in Annulus FLOW VELOCITY HIGHEST VALUES VELOCITY WITH POOR MUD RHEOLOGY
WHEN OPTIMISING MUD RHEOLOGY DRILL STRING
TRYING TO REACH IMMOBILE MUD AND CUTTINGS BED (FAST) ROTATION OF DRILL STRING TO MOVE CUTTINGS 186
Hole Cleaning Efficiency Definition • To optimise Hole Cleaning Efficiency in highlydeviated wellbores (40-80 º from vertical), a balance must be struck between – minimising particle settling velocity and – promotion 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
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where we we SHOULD observe ! Shale Shakers – where SHOULD observe !! where we SHOULD measure !
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How do we know what we are LOOKING for ?
Samples
LOOK FOR
CUTTINGS
Shale Shaker • Volume • Size • Type
CAVINGS
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What could be your contribution to HOLE CLEANING ? at the Shale Shaker n Observe Volume Cuttings n Observe Volume Cavings n Observe Type of Cavings n Measure all of the above n Report Observations n Discuss Observations and operationally... n Pump Faster if possible
Shakers
n Rotate Faster if possible n Optimise Mud Rheology
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Hole Cleaning Guidelines - Drilling (critical for hole angles 40 - 65 deg) Drilling Practice:
• Drill with controlled ROP, if „indications‟ of loading the annulus with cuttings • Circulate at max. allowable pump rate, provided we have no losses or create washouts • Do not assume that the hole is clean:– Use drag/torque trends of previous wells; monitor and communicate trends current well – Measure/record trends at the shale shaker 191
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 rate – Max suspension, when NOT circulating or tripping • Use lo/hi vis tandem sweeps as required. The use of sweeps usually indicates mud rheology is not optimal Reaming / Wiping Practice: • Ream/wipe after drilling a long section in sliding mode. If high RPM can be used, hole cleaning is more efficient 192
Hole Cleaning Guidelines - Connection (critical for hole angles 40 - 65 deg) Preparation and Practice:
• Ream/backream each single or stand; if cuttings bed has developed • Ensure to use full rate circulation when reaming/wiping before connection and/or survey • After connection, rotate string first, before bringing pumps up to full rate • Monitor, record, plot and communicate: • Up/down/rot string weight • Off and on bottom torque
• Circulation pressure trends 193
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 staff • If 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 sweeps • If 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 ! 194
CUTTINGS FLOW METER (CFM) • Collection Tray & Discharge System • Tray will dump after pre-set period
MEASURING Hole Cleaning EFFECTIVENESS
• Correlation 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 volume
• Comparison of theoretical weight of rock drilled and cuttings weight showing cuttings left in hole 195
Settling of Solids - Warning Signs 1. Up and down Drag Trends will be: a. smooth and high c. low b. erratic and high d. unaffected 2. Torque trend will be: a. smooth & high c. high & erratic b. unaffected d. impossible 3. Drag Trend will improve when: a. drilling c. calling the office b. circulating d. tripping 4. _a, b and/or c _ will increase if corrective action is NOT taken ! a. hole fill c. pump pressure b. mud weight d. ROP 5. The warning signs are most likely to appear: a. after connections c. tripping out b. reaming down d. tripping in
Mechanism # 4 WELLBORE STABILITY
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WELLBORE STABILITY Other common causes for ‘INSTABILITY’
(not Hydro-Pressured Shale related) • Unconsolidated Formations • Mobile Formations
• Fractured or Faulted Formations • Geo-pressured Formations • Reactive Formations • Tectonically Stressed Formations
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Unconsolidated Formations
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UNCONSOLIDATED Formations Indications: • Drilling shallow unconsolidated formation, sand, gravel in Top Hole • Abundance of loose sand/ gravel over shale shaker, desander/-silter • Shakers blinding • Erratic Drag • Seepage or partial losses
• Pack-off possible. Regaining circulation difficult.
200
UNCONSOLIDATED Formations Preventive Action: • Ensure to have some fluid loss control • Ensure adequate hole cleaning. Accept controlled ROP to reduce annular density. Regularly sweep hole with hivis pill • Be alert when making connections. Formation can slough in unexpectedly. Break circulation gently, avoids surges
• Include Jar in BHA • Spot hi-vis pill or gel mud before roundtrips and prior running casing
201
Mobile Formations
202
MOBILE Formations Indications: • When drilling Salts or Plastic Shales • Salts known to deform plastically and/or creep into the wellbore over time • High overpull/setdown during wipertrips or roundtrips • Repeated reaming required to continue making hole • Restriction in circulation possible
203
MOBILE Formations Preventive Action: • Use of eccentric PDC Bits and/or use of roller reamer • Use low WOB and high RPM. Accept controlled ROP and (re)-reaming intervals • Extensive precautionary reaming during wipertrips or roundtrips • Increase mud density, before entering mobile zone, if proven successful
204
MOBILE Formations Freeing •
Spot 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.
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Fractured or Faulted Formations
206
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 shaker • Torque during drilling/reaming fluctuating. Vibration possible. • Partial or total losses
• Reaming required to pass interval during or after wipertrip/roundtrip
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FRACTURED/FAULTED Formations Preventive Action:
• Constantly check hole condition. Ream intervals precautionary • Avoid losses. Keep hole clean. Limit annular density (ECD). Restrict tripping speeds
• If losses, pull out immediately above fractured/faulted zone • Ensure to have inhibited HCl acid at rig • Stability will return, provided rig team caution and known techniques
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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.
209
Geo-pressured Formations
210
GEO-PRESSURED Formations SPALLING OF SPLINTERY CAVINGS
Indications:
• Exploration/appraisal wells. Usually shale high pressure transition zone • Fast ROP. Possibly some drag when moving string and making connections • Distinctive splintery cavings.
PORE PRESSURE HIGHER THAN HYDR. HEAD
• Usually accompanied by high levels of background gas and/or tripgas • Pack-off tendency during roundtrips when cavings have not been observed or when quantity has increased
211
GEO-PRESSURED Formations Preventive Action:
• Monitor and plot pore pressure • Cross check origin of cavings. • Increase density in small increments • Take time to circulate hole clean when fast ROPs are experienced. Be cautious when formation gas to surface • Avoid excessive swabs and surges during roundtrips and connections • Exercise all practices related to hole cleaning and instability problems
212
GEO-PRESSURED Formations
Immediate action: •
Apply maximum allowable pull and torque into string
•
Jar up/ jar down with „substantial‟ weight slacked off
•
Use every effort to maintain circulation.
213
Reactive Formations
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REACTIVE Formations Indications:
• Drilling shallow young shales • Absorption of drilled shales into mud • Increase of plastic viscosity and yield • Clayballs at surface, bit and stabiliser balling in the hole • Mushy, soft cuttings • Overpull on wipertrips/roundtrips
• Increase of pump pressure and torque depending on annular clearance
215
REACTIV Formations Preventive Action:
• Ensure adequate mud inhibition, e.g KCL, to minimise hydration process • Dilute mud if increase of bentonite content in mud cannot be controlled
• Wipe the hole as required. Wash/ream if overpull/setdown becomes excessive • Avoid BHA with „tight‟ clearances • Circulate clean at possible high rate, but caution when breaking circulation • Drill quickly, minimise open hole time
216
Effects of MUD on Bore Hole Stability Oil Base Mud
Bore Hole Wall smooth no interaction
KCl WB Mud balanced activity
Bore Hole Wall relatively smooth reduced interaction
WB Mud unbalanced activity
Bore Hole Wall rough hydration 217
REACTIV Formations
Immediate action: •
Apply maximum allowable pull and torque into string
•
Jar down with „substantial‟ weight slacked off
•
Use every effort to maintain circulation.
218
Tectonically Stressed Formations
219
Tectonically Stressed Formations Indications: • Wide variation in rock stress orientation • Multiple faulting, e.g. in mountainous or active areas • Extensive (back-) reaming during roundtrips. High fluctuating torque during „hard‟ reaming to bottom. • Excessive quantities of cavings to surface • Difficult to stop/limit instability with any mud or mud weight 220
Tectonically Stressed Formations
Mountainous Area Multiple Faulting Stress Orientation
221
Tectonically Stressed Formations Preventive Action: • Make use of local experience, stability studies
• Careful 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 time • If instability is known to be difficult to stop, consider use of: • oil based mud • maximum allowable density • extra casing contingency in programme 222
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. 223
Borehole Geometry
224
Key Seating – 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.
225
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.
226
Key Seating – Borehole Geometry
Freeing •
If possible, apply torque and jar down with maximum trip load.
•
Back ream out of the hole.
•
If present use key seat wiper.
227
Borehole Geometry - Warning Signs 1. Up and down Drag Trends will begin to: a. stabilise c. increase b. decrease d. become erratic 2. Torque trend will be: a. smooth & high c. high & erratic b. constant d. low 3. If borehole is smaller than Bit/BHA Circ. Pressure may: a. fluctuate c. washout the formation b. increase d. stay about the same 4. If water base mud is not salt saturated, you can expect: a. hole collapse c. anything, depends on form b. hole washout d. excess filtercake 5. The warning signs are most likely to develop during: a. drilling (occasionally) c. reaming down b. circulating d. tripping
Cement Related
229
Cement Related - Stuck Pipe Causes Indications: •
Poor Cementations
•
Long ratholes
Preventive Action:
•
Minimise the length of rathole.
•
Perform reaming and/or wiper trips.
Freeing •
If possible, apply torque and jar down with maximum trip load.
230
Undergauge Hole
231
Undergauge Hole Indications: •
Dull bit evaulation
•
Coring
Preventive Action: •
Bit gauge protection.
•
Perform reaming after coring.
Freeing •
JAR UP with maximum trip load.
Undergauged Hole 232
Junk in Hole Indications: •
Something is missing at rigfloor
•
Hand tools, parts of tongs, slips..
Preventive Action: •
Keep order at rigfloor.
•
Good maintenance of tools
•
Careful work
Freeing •
JAR DOWN with maximum trip load.
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Drill String Vibration
•
Not a direct ‘cause‟, but… STABLE formations become to UNSTABLE
Indications: •
High drill string vibration
Preventive Action: •
Appropriate BHA and weight on bit
•
Appropriate transition zone between DC and DP
234
DRILLING FLUID When we select mud, you have to consider Type of Mud Formation Stability
Hole Cleaning Differential Sticking Drag and Torque
„MUD plays the biggest role in avoiding of STUCK PIPE!”
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