4 - water base mud system_ptm_handout
DESCRIPTION
Water Base Mud SystemTRANSCRIPT
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Global Research & Technology Centre/ GRTC
Training Department
WATERWATER--BASED BASED MUD MUD SYSTEMSYSTEMWATERWATER--BASED BASED MUD MUD SYSTEMSYSTEM
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What is mud
LIQUID MUDSOLIDS
WATER
OIL
SALT
CHEMICALS
BARITE
BENTONITE/GEL
DRILL SOLIDS
WATER-BASE MUD
OIL-BASE MUD
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What is mud
LIQUID MUDSOLIDS
WATER
OIL
SALT
CHEMICALS
BARITE
BENTONITE/GEL
DRILL SOLIDS
WATER-BASE MUD
OIL-BASE MUD
PRODUCTS PRODUCTS MUD SYSTEM
WATER
OIL
SALT
CHEMICALS
BARITE
BENTONITE/GEL WATER-BASE MUD
OIL-BASE MUD
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Up to 80% of the rocks we drill are shales, ie clay-rich rocks
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Shale Inhibition
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Inhibition is the process of minimising the inherentpotential for clays, shales & mudstones to hydrateand/or collapse and disperse
Definition
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What is an Inhibitive Drilling Fluid?
● An inhibitive mud system is one that tends to retard oreven prevent (inhibit) appreciable hydration (swelling) ordispersion of formation clays and shales by chemical orphysical means
● Inhibition also applies to salt and gypsum formationswhich may re-dissolve.
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What Are We Inhibiting ?
● Up to 80% of the worlds sedimentary rocks that wedrill are Shales - most require some degree ofinhibition to prevent:
• Hydration
• Dispersion
• Wellbore stability problems
● The hydration of clay and shale particles in thereservoir rock.
• These can block the pore space, and in the worstcase can completely block a producing reservoir.
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Insufficient Inhibition
• Clay swelling• Increases torque and drag• Increased tripping time• Mud rings - Gumbo attacks• Stuck pipe or casing
• Clay disintegration• Washouts - poor hole cleaning• Increased viscosity• Poor solids removal efficiency• Increased mud costs
Clay disintegration typically follows clay swelling
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Hydration Followed by dispersion
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Mechanism for shale inhibition
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Mechanisms of Inhibition
1. Cation Exchange
2. Encapsulating polymers
3. Glycol/Polyol Chemistry
4. Silicate Precipitation
5. Reducing the fluid loss
6. Reducing the pH
7. Increasing the Chloride content
8. Oil wetting the surface rocks
WBM
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The smaller potassium ion base exchanges with thelarger sodium and calcium ion. As a consequence of itssmaller dimensions the potassium ions forms a moreeffective bridge between the clay sheets, ie the claysheets take on their least expanded form and thereforetheir lowest potential for hydration.
1 – Cation Exchange (KCL)
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K+
K+
Potassium ion to
stabilize the clay
formation wellbore
1 – Cation Exchange (KCL)
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• The more reactive the shale the greater will be the depletion of the KCL concentration in the mud. KCL concentration must be maintained at optimum levels at ALL times.
• % KCL concentration must be based on the inherent reactivity of the shale. This must be determined by DCM and / or CEC analysis of cuttings at 5 to 10 meter intervals in order to identify the most reactive shale.
• Formulate mud with KCL +/- 2% higher than the required level of KCL inhibition as a buffer to ensure that KCL levels keep up with the rate of depletion.
• Increase KCL levels prior to trips, logging and running casing to allow for continuing depletion.
1 – Cation Exchange (KCL)
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• Anionic i.e. negatively charged (-) high molecular weight PHPA polymers adsorb onto the positively charged sites on the broken edges of the clay platelet.
• This results in the formation of a jelly like protective coating which plugs and seals shale pores and fissures and so retards the movement of water into the shale.
• The protective coating of PHPA plays a significant role in strengthening the surface of the shale so that is better withstands the effects of mechanical abrasion / attrition leading to dispersion.
PHPA encapsulating polymer chemistry
2 – Coating Mechanism with Encapsulating Polymer
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• PHPA provides a very viscous filtrate which serves to reduce water ingress into the shale pores.
• PHPA polymers slow down the dispersion rate of highly dispersive shales such as Kaolinite i.e. sufficient to allow cuttings to be transported to surface before significant dispersion takes place. PHPA solution
PHPA encapsulating polymer chemistry
2 – Coating Mechanism with Encapsulating Polymer
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Encapsulating polymers, eg PHPA
• Optimum PHPA concentrations must be maintained at all times. This can lead to high mud viscosities which can become operationally problematic especially at higher mud weights.
• Lower molecular weight encapsulating polymers offer a compromise. Higher concentrations are required which must at all times be maintained at optimum levels.
2 – Coating Mechanism with Encapsulating Polymer
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K+
K+
Potassium ion to
stabilize the clay
PHPA encapsulates
drill cutting to protect
it from mud filtrate
invasion
formation wellbore
2 – Coating Mechanism with Encapsulating Polymer
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The inhibition mechanism of glycols is not fullyunderstood and there are several theories:
• Soluble glycols i.e. non-clouding glycols increase theviscosity of the filtrate which in turn slows down waterpenetration into the shales.
• Glycols are generally mildly anionic and will thereforeattach to positive sites on the clay surface therebyretarding hydration.
3 – Coating Mechanism with Glycol
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• At bottom hole temperature a correctly formulatedthermally activated glycol/KCL combination will causethe glycol to “cloud out” i.e. come out of solution andplug pore spaces/fissures in the clay, therebyminimising further ingress of water.
• The “clouded out” glycol goes back into solution as thetemperature of the mud drops near surface.
Thermally activated glycols
3 – Coating Mechanism with Glycol
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Thermally activated glycols
Mud pits and solids control:Glycol in solution
Downhole Glycol forms droplets or micelles
which coat out on well bore and cuttings
Temperature reduction lowers the Glycol back below its cloud point
Unclouded glycol
Clouded glycol
3 – Coating Mechanism with Glycol
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A gel/precipitate barrier is thought to be formed by a dualaction as follows:
• Filtrate containing silicate oligomers small enough toenter the shale pore throats / microfissures comes intocontact with shale pore fluid. The near neutral pH of theshale pore fluid will cause a fall in the pH of the filtratecontaining silicate. This in turn allows the growth anddevelopment of silica hydrogels that block the shalepore throats.
• Divalent ions, such as calcium, associated with shalepore fluid will react instantaneously with silicateoligomers to form insoluble precipitates.
4 – Sealing the micro fissures/fractures with Silicates
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4 – Sealing the micro fissures/fractures with Silicates
NonNon-inhibitive Fluidinhibitive Fluid
HYDROHYDRO--FOIL S8 FluidFOIL S8 Fluid
Fracture propagation
FLUIDINGRESS
MMpp FFpp
FLUIDINGRESS
MMpp FFpp
MMp > p > FFpp
FFpp
MMp = p = FFpp = = Mechanical FailureMechanical Failure
MMp > p > FFpp MMp > p > FFpp = = Mechanical StabilityMechanical Stability
Silicate gel/precipitate
MMpp
MMpp
FFpp
NonNon-inhibitive Fluidinhibitive Fluid
HYDROHYDRO--FOIL S8 FluidFOIL S8 Fluid
Fracture propagation
FLUIDINGRESS
MMpp FLUIDINGRESS
MMpp FFpp
FLUIDINGRESS
MMpp FLUIDINGRESS
MMpp FFpp
MMp > p > FFpp
FFpp
MMp = p = FFpp = = Mechanical FailureMechanical Failure
MMp > p > FFpp MMp > p > FFpp = = Mechanical StabilityMechanical Stability
Silicate gel/precipitateSilicate gel/precipitate
MMpp
MMpp
FFpp
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4 – Sealing the micro fissures/fractures with Silicates
~ GELLED/PRECIPITATED SILICATES
SHALE PORECa
Ca
Ca
Ca
Ca
Ca
H2O
H2O May Penetrate But Ions Are Excluded
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Mechanisms of Shale Inhibition
Long chain high molecular weight polymer vs. short chain low molecular weight polymer?
Low molecular weight polymer High molecular weight polymer (PHPA)
Low viscosity impact on mud properties High viscosity impact on mud properties
Absorption of low molecular weight polymer creates an overall negative charge resulting in deflocculation
High molecular weight polymers act as a bridge between particles to form larger aggregates
Deflocculated Aggregated
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• Various mixtures and formulations of filming agents, egamines, are generally mixed with a base oil or ester “carrier fluid” containing de-emusifying agents. These formulations are generally marketed as ROP enhancing agents.
• These additives, whilst providing exceptional to minimal ROP enhancement depending upon a range of factors, have also proved useful for minimising bit balling and accretion by creating an “oil wet” barrier on the surfaces of the pipe and drill bit. This in turn prevents the hydrogen bonding of the shale cuttings onto the steel surfaces.
Bit balling and accretion - WBM
Mechanisms of Shale Inhibition
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Micro fractured shales - WBM & SBM
• Appropriately sized bridging agents, e.g. calcium carbonate and cellulose, will minimise filtrate invasion and therefore reduce the potential for hydration and dispersion.
• The deformable properties of products such as lignite, gilsonite and blown asphalt have proved to be extremely efficient at sealing micro fractures thereby minimising filtrate invasion and delaying the otherwise earlier onset of hole stability problems in micro fractured shales.
Mechanisms of Shale Inhibition
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• Very low salinity levels promote dispersion.
• Very high salinity levels promote dispersion.
• Moderately high salinity results in less propensity to disperse.
Lower salinity
High dispersion rate
Moderate salinity
Moderate dispersion rate
Higher salinity
High dispersion rate
< 10% KCL > 12%
Impact of salinity on Kaolinite dispersion rates
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K+
K+
Water-Base Mud Inhibition
Potassium ion to
stabilize the clay
PHPA encapsulates
drill cutting to protect
it from mud filtrate
invasion
Glycol cloud-out
create a thin film
to protect forma
tion from mud
filtrate invasion
formation wellbore
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Inhibition Monitoring
The only “hands on” and immediate way to successfully monitor shale inhibition in the field is to examine the condition of the cuttings coming off the shale shaker screens.
• Cuttings should be firm / discrete & travel smoothly across the shale shaker screens.
• Soft, sticky cuttings indicate that immediate action should be taken to increase the inhibition level(s).
• Very fine mushy cuttings indicate shale dispersion and the need to increase the concentration of encapsulating polymer(s).
Appropriate WBM inhibition / encapsulation levels can be established by closely monitoring the drill cuttings at the shale shakers.
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WATER-BASE MUD SYSTEMS
● Many types of water-base systems.
● Basic systems are usually converted to complexsystems as a well is deepened, as wellboretemperatures and/or pressures increase andformations dictate.
● More than one system is typically used whendrilling the same well.
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WATER-BASE MUD SYSTEMS
● Many types of water-base systems.
● Basic systems are usually converted to complexsystems as a well is deepened, as wellboretemperatures and/or pressures increase andformations dictate.
● More than one system is typically used whendrilling the same well.
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Classification of Water-Base Mud
WATER BASE WATER BASE MUDMUD
LOW SOLIDS,LOW SOLIDS,NONNON--
DISPERSEDDISPERSED
HIGH SOLIDS,HIGH SOLIDS,DISPERSEDDISPERSED
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High Solids Dispersed Mud Systems
• Spud Mud
• Seawater Muds
• Lignite/Lignosulfonate
• Gyp-Lignosulfonate
• Lime Muds
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Low Solids Non Dispersed Mud Systems
• Polymer Base
• Potassium Base
• KCl/Polymer
• KCl/PHPA
• KCl/Polymer/Glycol
• Silicate mud
• Formate Base Mud
• MMO/MMH mud
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Low Solids Non Dispersed Mud Systems
Advantages
• Greater degrees of inhibition than a dispersed mud
• Flexibility• Logistics• Less Damaging to
formation• Increased ROP• Optimum rheological
characteristics• Resistant to contaminating
ions
Disadvantages• Temperature limitations
of polymers • Some polymers are
attacked by bacteria • Polymers are more
expensive per sack • Requires care in mixing
procedures
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Make-Up Water
●Type of water
●Chloride concentration
●Hardness (Calcium / Magnesium) concentration
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Shale analysis & testing
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Mineralogy by XR Diffraction/XRD
● XRD is used to classify & quantify the different clay minerals present in a shale sample.
● XRD analysis of cuttings from example well
Quartz K
FeldsparPlagioclase Kaolinite Illite
Illite/Smectite
Total
21.7% 5.4% 5.3% 23.3% 20.8% 21.6% 98.1%
Quantitative analysis (weight %) of bulk sample
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Mineralogy by XR Diffraction/XRD
0%
10%
20%
30%
40%
50%
60%
Illite /smectite
Illite Kaolinite Chlorite
Less than 2 micronclay size fraction
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Shale cation identification – (CEC)
● Determination of total cation exchange capacity
● Determines the capacity of a clay to absorb cations from a solution
● Measures the potential reactivity of a shale using the methylene blue index
● Cuttings are carefully prepared and gradually “saturated” in a methylene blue solution to a titration end point
● Result gives the shale reactivity potential in milliequivalents/100g
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Shale cation identification – MBI (CEC)
Typical MBI values for the principal sample clay types
Smectites Illites Kaolinite
80 - 150 meq/100g
1 – 10meq/100g
10 – 40meq/100g
Increasinglyreactive
Reactivity = the potential for a clay type to hydra te
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Shale cation identification – MBI (CEC)
Types of Formation Range of M.B.I. Values
Sandstones, marlsLittle to zero sensitivity to water
Low kaolin-illite shalesLittle sensitivity to water
High illite or low levels of smectiteModerate sensitivity
High smectiteHigh sensitivity to water
0 - 5
5 - 10
10 - 15
15 - 25
Sensitivity to water clearly indicates potential fo r hydration
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Capillary suction time (CST) – reactivity quantification
● indicates a shale’s dispersion potential
● CST method employs the capillary suction pressure of aporous filter paper to effect a filtration
● The rate at which filtrate spreads away from the sampleis controlled predominantly by the filtrate rate of thesample
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Capillary suction time (CST) – reactivity quantification
CST Filtration Unit.
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Capillary suction time (CST) – reactivity quantification
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Capillary suction time (CST) – reactivity quantification
Dispersion/deflocculationof clays decreases
viscosity and decreasesthe filtration rate –CST is increased
Aggregated but deflocculated clays
decreases viscosity and increases filtration rate –
CST is decreased
Flocculation of clays increases viscosity and
increases filtration rate –CST is decreased
Aggregated and flocculated clays increases viscosity
and increases filtration rate – CST is decreased
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Swellmeter
● Is a method of examining the interaction between waterbase fluids and mineral sample containing reactive claysunder simulated conditions while fluid is in motion.
● The observed swelling characteristic are utilised toanticipate and/or correct the oftentimes unpredictableproblems that are frequently encountered while drillingshale formations.
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Swellmeter
● It is a very useful tool when designing drilling fluids orwhen testing the behavior of existing muds because itshows the changes in the clay/fluid interaction for shortperiods of times (0-5 minutes) as well as longer periods(>350 minutes).
● Bit balling, pipe drag, hole sloughing and other “gumbo”related shale problems may be predicted in advance,enabling the operator to select the proper drilling fluidand therefore achieve a stable wellbore environment.
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Swellmeter
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Swellmeter
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Swellmeter
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SCOMIWater Base Mud System
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Low Solid Polymer Mud Systems
● HYDRO-FOILClassic KCL/PHPA
● HYDRO-FOIL GEN 1KCL/PHPA/Glycol
● HYDRO-FOIL S8Silicate mud system
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Low Solid Polymer Mud Systems
● HyPR-FOIL S8High Performance silicate system – Sodium
chloride free drilling fluid for sensitive environments.
● HyPR-DRILLHigh Performance WBM (HPWBM), which
provides wellbore stability, enhancedinhibition and rapid penetration rates.
● HyPR-TARInhibitive anti accretion drilling fluid for tar sand
drilling
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Specialised Water Base Mud Systems
● RHEO-PLEXMixed Metal Oxide/MMO system
● HYDRO-THERMHigh temperature condition up to 400 oF
● OPTA-FLOCustom designed Reservoir Drill – In Fluids
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Contamination
Definition:
● Any external addition of unwanted material orsubstances to the drilling fluid while drilling as a result ofchemical reaction and/or changes of concentration.
Depends on:
● Type of mud system
● Chemistry of the mud
● Amount of solids
● Type of solids
● Concentration of the contaminant
● Temperature
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Cement Contamination
Treatment :
● Pretreat mud with sodium bicarbonate
Ca(OH)2 + NaHCO3 --> CaCO3 + H2O + NaOH
● Or pretreat mud with S.A.P.P
Na2H2P2O7 + 3Ca(OH)2 --> Ca3(PO4)2 + 2NaOH + 3H2O
● Citric acid or any acidic product can be used to reduce pH
Contamination - Solid
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Calcium Contamination:
Treatment :
Treat with sodium carbonate (soda ash)
Ca++ + Na2CO3 --> CaCO3 + 2Na+
Or break over to a gypsum mud
Contamination - Solid
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Carbonates, Bicarbonates Contamination
● Sources:
• Carbonate formations
• Overtreatment
• Carbon Dioxide
• Thermal degradation of organics
• Contaminated barite
• Make up water
● Treatment:
• Lime
• Gypsum
•
Contamination - Solid
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Contamination
Chemical Treatment in U.S Units
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Contamination
Chemical Treatment in Metric Units
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Contamination