Untitled Quiz

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.
• 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)
  • 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.
• 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:
  • 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.
  • 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.
    • 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.
  • 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.
  • 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.

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.