4 - Water Base Mud System_PTM_Handout

5/21/2010

Global Research & Technology Centre/ GRTC Training Department

WATER-BASED WATERMUD SYSTEM

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What is mud

LIQUID WATER OIL

SOLIDS

MUD

BENTONITE/GEL

WATER-BASE MUD

BARITE CHEMICALS SALT

OIL-BASE MUD

DRILL SOLIDS SCOMI OILTOOLS

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What is mud

LIQUID PRODUCTS WATER OIL

SOLIDS PRODUCTS

MUD MUD SYSTEM

BENTONITE/GEL

WATER-BASE MUD

BARITE CHEMICALS SALT

OIL-BASE MUD

DRILL SOLIDS SCOMI OILTOOLS

Up to 80% of the rocks we drill are shales, ie clay-rich rocks

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Shale Inhibition

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Definition

Inhibition is the process of minimising the inherent potential for clays, shales & mudstones to hydrate and/or collapse and disperse

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What is an Inhibitive Drilling Fluid?

● An inhibitive mud system is one that tends to retard or even prevent (inhibit) appreciable hydration (swelling) or dispersion of formation clays and shales by chemical or physical means

● Inhibition

also applies to salt and gypsum formations which may re-dissolve.

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What Are We Inhibiting ? ● Up to 80% of the worlds sedimentary rocks that we drill are Shales - most require some degree of inhibition to prevent: • Hydration • Dispersion • Wellbore stability problems

● The hydration of clay and shale particles in the reservoir rock. • These can block the pore space, and in the worst case can completely block a producing reservoir. SCOMI OILTOOLS

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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

WBM

5. Reducing the fluid loss 6. Reducing the pH 7. Increasing the Chloride content 8. Oil wetting the surface rocks

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1 – Cation Exchange (KCL)

The smaller potassium ion base exchanges with the larger sodium and calcium ion. As a consequence of its smaller dimensions the potassium ions forms a more effective bridge between the clay sheets, ie the clay sheets take on their least expanded form and therefore their lowest potential for hydration.

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1 – Cation Exchange (KCL)

K+

Potassium ion to stabilize the clay

K+

formation

wellbore

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1 – Cation Exchange (KCL)

• 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. SCOMI OILTOOLS

2 – Coating Mechanism with Encapsulating Polymer PHPA encapsulating polymer chemistry • 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. SCOMI OILTOOLS

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2 – Coating Mechanism with Encapsulating Polymer PHPA encapsulating polymer chemistry • 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

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2 – Coating Mechanism with Encapsulating Polymer 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. SCOMI OILTOOLS

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2 – Coating Mechanism with Encapsulating Polymer Potassium ion to stabilize the clay K+

PHPA encapsulates drill cutting to protect it from mud filtrate invasion K+

formation

wellbore

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3 – Coating Mechanism with Glycol

The inhibition mechanism of glycols is understood and there are several theories:

not

fully

• Soluble glycols i.e. non-clouding glycols increase the viscosity of the filtrate which in turn slows down water penetration into the shales. • Glycols are generally mildly anionic and will therefore attach to positive sites on the clay surface thereby retarding hydration.

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3 – Coating Mechanism with Glycol Thermally activated glycols • At bottom hole temperature a correctly formulated thermally activated glycol/KCL combination will cause the glycol to “cloud out” i.e. come out of solution and plug pore spaces/fissures in the clay, thereby minimising further ingress of water. • The “clouded out” glycol goes back into solution as the temperature of the mud drops near surface.

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3 – Coating Mechanism with Glycol Thermally activated glycols

Clouded glycol 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

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4 – Sealing the micro fissures/fractures with Silicates A gel/precipitate barrier is thought to be formed by a dual action as follows: • Filtrate containing silicate oligomers small enough to enter the shale pore throats / microfissures comes into contact with shale pore fluid. The near neutral pH of the shale pore fluid will cause a fall in the pH of the filtrate containing silicate. This in turn allows the growth and development of silica hydrogels that block the shale pore throats. • Divalent ions, such as calcium, associated with shale pore fluid will react instantaneously with silicate oligomers to form insoluble precipitates. SCOMI OILTOOLS

4 – Sealing the micro fissures/fractures with Silicates Fracture propagation

Mp

FLUID INGRESS

Fp

Mp

Fp

Non-inhibitive Non inhibitive Fluid

Mp = Fp = Mechanical Failure

Mp > F p

Silicate gel/precipitate

Mp

FLUID INGRESS

Mp > Fp

Fp

Mp HYDROHYDRO-FOIL S8 Fluid

Fp

Mp > Fp = Mechanical Stability

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4 – Sealing the micro fissures/fractures with Silicates H2O May Penetrate But Ions Are Excluded

Ca Ca

H2O

Ca

Ca

SHALE PORE

Ca Ca

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~ GELLED/PRECIPITATED SILICATES

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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Mechanisms of Shale Inhibition Bit balling and accretion - WBM • Various mixtures and formulations of filming agents, eg amines, 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. SCOMI OILTOOLS

Mechanisms of Shale Inhibition 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.

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Impact of salinity on Kaolinite dispersion rates • Very low salinity levels promote dispersion. • Very high salinity levels promote dispersion. • Moderately high salinity results in less propensity to disperse.

Lower salinity

Moderate salinity

Higher salinity

High dispersion rate

Moderate dispersion rate

High dispersion rate

< 10%

KCL

> 12%

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Water-Base Mud Inhibition

Potassium ion to stabilize the clay K+

PHPA encapsulates drill cutting to protect it from mud filtrate invasion K+ 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). Appropriate WBM inhibition / encapsulation levels can be established by closely monitoring the drill cuttings at the shale shakers.

• Very fine mushy cuttings indicate shale dispersion and the need to increase the concentration of encapsulating polymer(s).

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WATER-BASE MUD SYSTEMS ● Many types of water-base systems. ● Basic systems are usually converted to complex systems as a well is deepened, as wellbore temperatures and/or pressures increase and formations dictate. ● More than one system is typically used when drilling the same well.

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WATER-BASE MUD SYSTEMS ● Many types of water-base systems. ● Basic systems are usually converted to complex systems as a well is deepened, as wellbore temperatures and/or pressures increase and formations dictate. ● More than one system is typically used when drilling the same well.

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Classification of Water-Base Mud

WATER BASE MUD

HIGH SOLIDS, DISPERSED

LOW SOLIDS, NON-NON DISPERSED

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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 Quantitative analysis (weight %) of bulk sample Quartz

K Feldspar

Plagioclase

Kaolinite

Illite

Illite/ Smectite

Total

21.7%

5.4%

5.3%

23.3%

20.8%

21.6%

98.1%

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Mineralogy by XR Diffraction/XRD 60%

Less than 2 micron clay size fraction

50% 40% 30% 20% 10% 0% Illite / smectite

Illite

Kaolinite

Chlorite

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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

10 – 40 meq/100g

1 – 10 meq/100g

Increasingly reactive Reactivity = the potential for a clay type to hydrate

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Shale cation identification – MBI (CEC) Types of Formation

Range of M.B.I. Values

Sandstones, marls Little to zero sensitivity to water

0-5

Low kaolin-illite shales Little sensitivity to water

5 - 10

High illite or low levels of smectite Moderate sensitivity

10 - 15

High smectite High sensitivity to water

15 - 25

Sensitivity to water clearly indicates potential for hydration SCOMI OILTOOLS

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Capillary suction time (CST) – reactivity quantification ● indicates a shale’s dispersion potential ● CST method employs the capillary suction pressure of a porous filter paper to effect a filtration ● The rate at which filtrate spreads away from the sample is controlled predominantly by the filtrate rate of the sample

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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/deflocculation of clays decreases viscosity and decreases the 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 water base fluids and mineral sample containing reactive clays under simulated conditions while fluid is in motion. ● The observed swelling characteristic are utilised to anticipate and/or correct the oftentimes unpredictable problems that are frequently encountered while drilling shale formations.

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Swellmeter ● It is a very useful tool when designing drilling fluids or when testing the behavior of existing muds because it shows the changes in the clay/fluid interaction for short periods 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 fluid and 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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SCOMI Water Base Mud System

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Low Solid Polymer Mud Systems ● HYDRO-FOIL Classic KCL/PHPA

● HYDRO-FOIL GEN 1 KCL/PHPA/Glycol

● HYDRO-FOIL S8 Silicate mud system

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Low Solid Polymer Mud Systems ● HyPR-FOIL S8 High Performance silicate system – Sodium chloride free drilling fluid for sensitive environ ments.

● HyPR-DRILL High Performance WBM (HPWBM), which provides wellbore stability, enhanced inhibition and rapid penetration rates.

● HyPR-TAR Inhibitive anti accretion drilling fluid for tar sand drilling SCOMI OILTOOLS

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Specialised Water Base Mud Systems ● RHEO-PLEX Mixed Metal Oxide/MMO system

● HYDRO-THERM High temperature condition up to 400 oF

● OPTA-FLO Custom designed Reservoir Drill – In Fluids

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Contamination Definition: ● Any external addition of unwanted material or substances to the drilling fluid while drilling as a result of chemical 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 SCOMI OILTOOLS

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Contamination - Solid 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

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Contamination - Solid Calcium Contamination: Treatment : Treat with sodium carbonate (soda ash) Ca++ + Na2CO3 --> CaCO3 + 2Na+

Or break over to a gypsum mud

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Contamination - Solid Carbonates, Bicarbonates Contamination ● Sources: • Carbonate formations • Overtreatment • Carbon Dioxide • Thermal degradation of organics • Contaminated barite • Make up water ● Treatment: • Lime • Gypsum 61

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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

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