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Questions and Answers
What primarily affects hydrostatic pressure in a well?
If the mud weight is 12.0 ppg and the True Vertical Depth (TVD) is 10,000 ft, what is the hydrostatic pressure (HP)?
What is classified as abnormal pressure in terms of pressure gradient?
Which factor does NOT improve cuttings transport efficiency?
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What contributes to the formation pressure within the pore spaces of rock formations?
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What is one of the major functions of drilling fluid?
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What is the formula for calculating hydrostatic pressure in drilling fluids?
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Which of the following is NOT a minor function of drilling fluid?
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What aspect of drilling mud contributes to controlling subsurface pressure?
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Why is it important to maintain good drilling mud properties?
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Study Notes
Introduction
- Drilling fluid, also known as drilling mud, plays a key role in the rotary drilling process.
- Its primary functions include removing drilled cuttings from the borehole and preventing fluid flow from formations into the borehole.
- The cost of drilling mud can represent a significant portion of overall well expenses, ranging from 10% to 15%.
- Maintaining proper mud properties is crucial as neglecting them can lead to drilling issues that require significant time and cost to resolve.
- To ensure optimal mud properties, operating companies typically employ a service company to provide a drilling fluid specialist (mud engineer) on the rig.
- The mud engineer's responsibilities include formulating, continuously monitoring, and treating the mud as needed.
Why is Drilling Fluids so important?
- Drilling fluid circulating within the well acts similarly to blood circulating within a body.
Functions of a Drilling Fluid
Major Functions
- Drilling fluids are designed to perform three main functions:
- Control Subsurface Pressure: This is achieved through the fluid's hydrostatic pressure, influenced by the mud density and well's true vertical depth.
- Transport Cuttings: The fluid's flow from bit nozzles creates a jet action, dislodging cuttings from the bottom of the hole and carrying them to the surface.
- Support and Stabilize the Wellbore: This is primarily accomplished by controlling the loss of filtrate to permeable formations and managing the chemical composition of the drilling fluid.
Minor Functions
- Drilling fluids perform additional, less critical functions:
- Support the weight of tubulars
- Cool and lubricate the bit and drill string
- Transmit hydraulic horsepower to the bit
- Provide a medium for wireline logging
- Assist in gathering subsurface geological data and formation evaluation
- Cool and lubricate the bit
Control Subsurface Pressure
- The fluid must maintain control of formation pressure through its hydrostatic pressure.
- Hydrostatic pressure (HSP) is calculated as: -HSP = 0.052 X Mw X TVD - HSP = Hydrostatic pressure (psi) - Mw = Mud weight (ppg - pound per gallon) - TVD = True vertical depth (ft)
- Hydrostatic Pressure is not influenced by hole geometry. Only mud weight and true vertical depth (TVD) affect it.
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Example
- Mud Weight = 12.0 ppg, True Vertical Depth (TVD) = 10,000 ft
- Hydrostatic Pressure (HP) = 0.052 × 12.0 × 10,000 = 6,240 psi
- Hydrostatic pressure can also be calculated using pressure gradient:
- Hydrostatic Pressure (HP) = Pressure gradient in psi/ft × True Vertical Depth (TVD)
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Example
- Pressure Gradient = 0.5 psi/ft
- True Vertical Depth (TVD) = 10,000 ft
- Hydrostatic Pressure (HP) = 0.5 psi/ft × 10,000 ft = 5,000 psi
Formation Pressure
- Formations consist of solids with various porosity and permeability.
- They contain liquids such as water, gas, or oil, which can be under pressure due to overburden pressure and tectonic forces.
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Formation Pressure is classified into three categories:
- Subnormal pressure: Gradient < 0.433 psi/ft
- Normal Pressure: 0.433 < Gradient < 0.465 psi/ft
- Abnormal pressure: 0.465 < Gradient < 1 psi/ft
Overburden Pressure
- Overburden Pressure is the pressure exerted by the weight of overlying formations above a specific point.
Transport Cuttings
- The fluid flowing from bit nozzles creates a jetting action, removing cuttings from the bottom of the hole and carrying them to the surface.
- Several factors influence the efficiency of cuttings transport:
- Velocity: Higher annular velocity generally improves cuttings transport, influenced by pump output, borehole size, and drill string size.
- Density: Increasing mud density enhances carrying capacity due to the buoyant effect on cuttings.
- Viscosity: Increased viscosity often improves cuttings removal.
- Pipe Rotation: Rotation aids in moving cuttings into areas of higher fluid velocity from low velocity areas near the borehole wall and drill string.
- Inadequate cuttings removal can lead to problems such as:
- "Fill on bottom" after a trip
- Hole pack-off
- Lost returns
- Differentially stuck pipe
Support and Stabilize Wellbore
- Most permeable formations have pore spaces too small for whole mud to enter; however, fluid filtrate can penetrate these spaces.
- The rate of filtrate entry depends on the pressure differential between the formation and the drilling fluid column, and the quality of the filter cake deposited on the formation face.
- Borehole stability is maintained by controlling filtrate loss to permeable formations and carefully adjusting the chemical composition of the drilling fluid.
- Excessive filtrate loss and incompatible filtrates can destabilize the formation through shale hydration or chemical reactions between drilling fluid components and the wellbore.
Drilling Fluid Classifications
- Drilling fluids are categorized into:
- Water-Based Fluids
- Oil-Based Muds
Water-Based Fluids
- Water-based drilling fluids can be further classified into specific types, each suited for different situations:
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Non-Inhibitive Fluids: Designed for simple applications and are generally inexpensive. Their exact composition varies depending on the geology of the formations being drilled.
- Clear Water: A nearly ideal drilling fluid, used in various salinity levels depending on the formation. Viscous sweeps are used to clear cuttings as needed.
- Native Muds: These muds are based on clays found in the surrounding area. They are often used in areas with abundant clay sources.
- Bentonite-Water Muds: Composed of bentonite clay, these muds are widely used due to their cost-effectiveness and ability to control filtration and viscosity.
- Lignite/Lignosulfonate (Deflocculated) Muds: Contain lignite or lignosulfonate to reduce viscosity and improve filtration properties. These muds are often used in areas with high clay concentrations.
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Inhibitive Fluids: These fluids are designed to control shale swelling and prevent clay dispersion. They are commonly used when drilling formations that tend to destabilize due to their high clay content.
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Potassium Chloride (KCl) Muds: These muds contain Potassium chloride to inhibit shale swelling. They are effective in formations that are sensitive to water-based fluids.
- KCl-Polymer (KCl-PHPA) Muds: A combination of Potassium chloride and polymers such as PHPA (partially hydrolyzed polyacrylamide) to improve wellbore stability and minimize cutting dispersion.
- KOH-Lignite Muds: Contain potassium hydroxide and lignite to inhibit shale swelling and improve mud properties.
- KOH-Lime Muds: Contain potassium hydroxide and lime for similar purposes as KOH-Lignite muds.
- KCl-Cationic Polymer Muds: Combine Potassium chloride and cationic polymers for enhanced wellbore stability and shale control.
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Potassium Chloride (KCl) Muds: These muds contain Potassium chloride to inhibit shale swelling. They are effective in formations that are sensitive to water-based fluids.
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Polymer Fluids: These contain polymers for specific purposes, such as:
- Viscosification: Providing viscosity through high molecular weight polymers like PHPA, PAC, and XC polymer.
- Filtration Control: Managing filtrate loss by using polymers.
- Deflocculation: Reducing viscosity and improving filtration by using polymers.
- High-Temperature Stabilization: Stabilizing mud properties at high temperatures.
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Salt-Based Fluids: Formulated to minimize shale hydration or swelling. They are suitable for drilling formations prone to instability due to their clay content.
- Calcium Chloride (CaCl2) Muds: These muds contain Calcium chloride to control shale swelling and provide inhibition.
- Sodium Chloride (NaCl) Muds: Contain Sodium chloride for similar purposes as CaCl2 muds.
- Zinc Chloride (ZnCl2) Muds: Utilize Zinc chloride to inhibit clay hydration.
- Magnesium Chloride (MgCl2) Muds: Commonly used in formations sensitive to water-based fluids.
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Non-Inhibitive Fluids: Designed for simple applications and are generally inexpensive. Their exact composition varies depending on the geology of the formations being drilled.
Oil-Based Muds
- Oil-based fluids contain oil as their continuous phase, with water acting as the dispersed phase, if present.
- Solids in oil-based muds are oil-wet, meaning they have a preference for oil over water.
Oil Mud Applications
- Oil-based muds offer several advantages in specific drilling scenarios:
- Shale Stability: They prevent water movement from the mud into the shale, preventing shale swelling and instability.
- Penetration Rates: Often lead to faster drilling speeds compared to water-based muds, while maintaining good shale stability.
- High Temperatures: Effective at high temperatures, up to 550°F.
- Drilling Salts: They are used in formations with high salt content, as they do not leach out salt.
- Coring Fluids: Highly oil-wetting, which prevents water from entering cores during coring operations.
- Packer Fluids: Provide long-term stability as packer fluids under high temperatures, due to their high temperature stability.
- Lubricity: Exceptional lubricity, suitable for highly deviated and horizontal wells.
- Low Pore Pressure Formations: Easily used in low pore pressure formations, as mud weight can be maintained below water weight.
- Corrosion Control: Good corrosion protection for pipe due to the oil being the external phase and coating the pipe.
Disadvantages of Oil Muds
- Oil-based muds also have several drawbacks:
- High Initial Cost: They are more expensive than water-based muds.
- Reduced Kick Detection: Difficult to detect kicks (fluid flow from the formation into the well) when using oil-based muds.
- Environmental Concerns: Considerations regarding discharge of cuttings, loss of whole mud, and disposal of oil-based mud.
- Fire Hazards: Potential fire hazards due to the low flash points of vapors from the oil mud.
- Rig Modifications: Requires additional rig equipment and modifications to minimize loss of oil mud.
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