Video summary

Drilling Rig Components, Dr. Salah Elkatatny

Main summary

Key takeaways

Educational

Main ideas / lessons conveyed

Purpose of the session

The session explains drilling engineering rig basics, focusing on:

  • Common rig types and how they’re classified (e.g., land vs. offshore; depth/water depth; capacity)
  • The rig system/component architecture, showing how major subsystems work together for safe drilling

Rig types (overview)

Land (onshore) rigs

Classified by:

  • Portability (how the rig can be moved)
  • Maximum operating depth
  • Capacity/load limits (linked to derrick height and power)

Marine (offshore) rigs

Classified by:

  • Portability
  • Maximum water depth
  • Support method
    • Floating rigs: drill ship, semi-submersible
    • Bottom-supported rigs: jackup platform, barge

Key design difference

  • Land rig: design driven mainly by depth to drill
  • Offshore rig: design driven mainly by water depth

How derricks/masts relate to capacity

  • The derrick/mast is limited by the maximum load it can carry, which depends on the depth/height of the carried equipment.
  • A rule-of-thumb mentioned: ~10 horsepower per 100 ft of drilling.

Example capacity classes (land rigs)

  • Light: drills to about 2,000 m, ~650 hp
  • Medium: up to 4,000 m
  • Heavy: up to 6,000 m, ~2,000 hp
  • Ultra heavy: more, ~3,000 hp and more

Derrick/mast portability options

  • Cantilever/conventional derrick
    • Assembled in place
    • Raised by a hoisting system
  • Mast system
    • Portable mast moved as one piece by truck
    • Telescopic raising

Rig component / system breakdown (six operating systems)

The presenter frames nearly all rigs (onshore or offshore) around ~six operating systems:

  1. Hoisting system
  2. Rotating system
  3. Circulating system
  4. Controlling (well control) system
  5. Power system
  6. Monitoring system (newer emphasis: real-time sensing and data-driven optimization)

Detailed methodology / instruction-style content

A) Hoisting system: key components and what they do

Main goal: Lift/lower and run drill string and casing strings safely.

Major equipment mentioned

  • Derrick / mast
    • Provides:
      • Load capacity (can carry the maximum string load; heaviest typically casing)
      • Height for running in/out (height discussed as > 90 ft, about one stand length)
  • Substructure / floor
    • Supports loads of derrick + heavy equipment
    • Provides space/height for well control equipment and wellhead equipment across casing stages
  • Drawworks (described as the heart of hoisting)
    • Contains:
      • Drum
      • Braking systems (manual and auxiliary)
    • Controls movement of drilling line
  • Crown block + traveling block + hook
    • Crown block: fixed upper part of derrick, includes sheaves/achieves guiding rope
    • Traveling block + hook: moving load-handling assembly
    • Example hook mass noted: ~23,000 lb, so rope integrity is critical
  • Drilling line / hoisting line routing
    • From storage reel → deadline anchor → around crown block → to traveling block → back to crown block → finally to drum
    • “Fast line”: the segment associated with small travel movements; moving the traveling block by 1 ft multiplies line movement by the number of line segments between crown and traveling blocks.
  • Catheads (right and left of the drum)
    • Connected via lines to tongues to supply torque for pipe connections (tool joint makeup)
  • Air winches / air hoses
    • Used to move heavy items on the rig floor where humans cannot lift/transport manually

B) Hoisting system calculations & safety procedure concepts (rope wear and safe design)

1) Determine derrick/mast load using number of lines

If hook load is supported by n lines, use load distribution to compute:

  • Static fast line load
  • Static dead line load
  • Static derrick load (rule-of-thumb form):
    • Static derrick load = ((n + 2) / n) × hook load

If friction matters:

  • Introduce efficiency to adjust line loads and obtain:
    • Fast line load
    • Dead line load
    • Dynamic crown block load (summation concept)

2) Compute “design factor” for drilling line

  • Design factor = (normal strength of wire rope) / (fast line load)
  • Used to select safe line with an appropriate safety margin.

3) Compute cumulative rope work as “ton-miles”

Operating phases described conceptually:

  • Round trip #1: running from surface/floor to target depth without drilling
  • Drilling/coring phase
  • Second round trip: returning to floor/upper position after drilling/coring section

Ton-mile relationships (conceptual):

  • During drilling:
    • ton-miles = 3 × (round trip 2 − round trip 1)
  • During coring:
    • coring = 2 × (round trip 2 − round trip 1)
  • During casing:
    • Depends on casing weight, depths, and forces (as stated in the session)

4) Determine when to perform “slip and cut”

Guideline mentioned:

  • After reaching about 100 ton-miles (example threshold),
    • Perform “slip and cut”
    • Reposition rope so worn sections move off critical sheave points
    • Remove worn rope and replace/cut accordingly

Rope cut length method:

  • Slip-and-cut length = (# of laps to cut) × (drum circumference)
  • Drum circumference = π × diameter × number (as described; includes π and drum diameter)

5) Determine required laps to cut using API specification

Required laps depend on:

  • Derrick height
  • Drum diameter
  • Design factor
  • Total ton-miles accumulated

Example:

  • If derrick height ≈ 187 and diameter ≈ 30, then laps to cut ≈ 14.5 laps

Safety takeaway: A key objective of the hoisting system study is ensuring safe rope operation through executing slip-and-cut.

C) Rotating system: purpose, equipment, and limitations

Main goal: Provide:

  • Rotation to the bit
  • Plus weight on bit (WOB concept)

1) Kelly system (older method)

  • Kelly connected to:
    • Kelly bushing
    • Master bushing
    • Rotary table

Key limitation:

  • Drilling depth limited to kelly length (about 40–54 ft)
  • After each joint (about 30 ft mentioned), need to:
    • Disconnect kelly
    • Store it in rat hole
    • Retrieve next joint from mouse hole

Kelly must be stronger because it carries total string weight, especially during trip-out.

2) Top drive system (modern alternative)

  • Motor moved from rotary table area to above the drill string

Components described:

  • Connects to rig structure via crown block + hook
  • Includes swivel
  • Moves up/down like an elevator

Pipe handling:

  • Pulls stands from monkey board
  • Example stand length: about three joints (~90 ft)

Advantages given:

  • Drill multiple stands (not only one kelly length)
  • Reduce time for connections
  • Reduce non-circulation time, supporting better drilling fluid temperature control and hole cleaning

3) Swivel function

  • Connects rotary hose to the drill string
  • Provides pathway for drilling fluid into the drill string
  • Prevents drill pipe rotation from damaging the hoisting line system:
    • Drill string rotates
    • Crown/traveling blocks move up/down without rotation
    • If crown/traveling blocks rotate, it could damage lines/process

4) Drilling weight distribution (mechanical emphasis)

  • Rotation comes from rotary table or top drive.
  • WOB is applied by drill collars (heavy components).
  • Avoid using drill pipe under tension as the primary WOB source.
  • Transition detail:
    • Use heavy-wall drill pipe as transition between drill collar and drill pipe
    • Not recommended to jump directly from thick to thin mechanically
    • Heavy-wall section helps position the neutral point and supports safer WOB distribution (example concept: using a lower percentage of collar weight to be in a “safe mode”).

D) Circulating system: components, flow path, and pressure-loss logic

Main goal: Clean the hole and maintain wellbore stability by circulating drilling fluid.

“Blood” analogy

  • Pump acts like the heart:
    • Injects drilling fluid down the hole
    • Returns it to surface

Flow path (as described)

  • Pump → drill string → bit → cuttings return up → flow line → shale shaker → waste/solids handling → degasser/solids control → active tank → back to pump

Key solid control steps

  • Shale shaker
    • First solid control device
    • Removes largest cuttings (~80% stated)
  • Degasser / vacuum separator
    • Removes gas cut from mud using vacuum
    • Not recommended during kick scenarios when gas is high; then use choke manifold approach
  • Vertical separator
    • Separates larger quantities (positioned after degassing, contextually)
  • Desander
    • Removes sand particles larger than ~40 microns
    • Uses centrifugal force
  • Desilter
    • Removes silt particles ~20–25 microns
  • Mud cleaner
    • Combination of shale shaker + desander + desilter when shale shaker alone is insufficient
  • Centrifuge
    • Removes very fine particles (including weighting material)
    • Used to recover weighting material to re-increase mud density

Pressure-loss and pump selection methodology

Pressure losses determine:

  • Required pump selection/specification
  • Effects of downhole formation

Example pressures mentioned:

  • In injection line: up to ~2,500–3,000 psi
  • At shale shaker return side: back to roughly ~1 atmosphere

Warning principle:

  • Excessive pressure can fracture formation and cause losses of fluid.

Pump types and output/loss reasoning

  • Pump configurations: duplex and triplex (as described)
  • Single-acting vs double-acting mechanism explained

Pump output matters for:

  1. Loss estimation (seepage / partial loss / severe loss / total loss)
  2. Well control & kill operations
    • During kick circulation response, pump rate reduced to slow pump rate
    • Knowing slow pump pressure supports well control calculations

Rig uptime/business lesson

Because rig time is expensive:

  • Use two/three pumps: one active, others standby
  • Maintain inventory for connections and backup capability to avoid non-productive time

E) Controlling / well control system: hydrostatic control + equipment roles

Main concept: Primary well control is hydrostatic pressure of drilling fluid. Equipment is secondary control.

The mud engineer designs drilling fluid to provide sufficient formation pressure control.

1) Diverter

Used when drilling a surface hole where there is no surface casing yet.

Purpose:

  • Divert fluid away from rig during kick/emergency

Mechanism described:

  • Open one wing based on wind direction
  • Close annular preventer afterward (annular preventer can close around various shapes, including open hole)

Note:

  • Unlike BOP, diverter does not apply back pressure to formation.

2) Blowout Preventer (BOP) system

  • Installed above surface casing using a casing head (casing head welded to surface casing and fixed in cellar/floor)
  • BOP stack includes:
    • Drilling spool (connection for choke line and kill line)
    • Annular preventer / rams

BOP purpose:

  • Provides back pressure control; closes to stop movement and waits until pressure stabilizes.

RAM types and when used

  • Pipe rams: seal around a specific drill pipe size (e.g., 5-inch ram example)
  • Annular preventer: first step in kick scenarios; can close around anything, including open hole when string is at bottom
  • Blind ram: closes against open hole when there is no drill string
  • Shear ram: emergency action that can cut pipe and isolate the lower section
  • Blind shear ram: combination of blind + shear capability
  • Variable ram: designed to handle varying sizes with less mismatch

Control hardware

  • Accumulator unit/control system
    • Stores hydraulic pressure (example: ~300–3000 psi)
    • Hydraulic lines connect accumulator to BOP actuators
  • Monitoring gauges:
    • Manifold pressure, accumulator pressure, annular pressure
  • Four-way valves
    • Move valves to required positions

Presenter emphasis:

  • Continuously monitor each subsystem pressure.

F) Power system

Main goal: Provide electrical power for fluid/rotation/hoisting systems.

  • Uses diesel generators
  • Generators are needed where grid power is absent (e.g., offshore/desert)

G) Monitoring system (data + AI/ML)

Modern add-on (since ~2013–2014 emphasized)

  • Real-time sensors record many drilling parameters every ~1–2 seconds or per depth increment as needed
  • Parameters listed include:
    • Well depth
    • Weight on bit
    • Rotary speed and rotary torque
    • Pump pressure, pump rate/flow return rate
    • Rate of penetration
    • Hook load
    • Fluid property
    • Bit level

Automated vs non-automated measurement

  • Some properties automated
  • Fluid property measured only about twice a day (or four times a day in emergencies)

AI/ML methodology to improve mud-property monitoring

Problem described:

  • Missed intervals without frequent measurements (e.g., 12 hours)
  • Dependence on intermittent mud density and marsh funnel time readings

Proposed solution:

  • Automated/continuous measurement for:
    • Mud density
    • Marsh funnel time
  • Continuous sampling described: about every 5 minutes

AI can predict:

  • Plastic viscosity
  • Yield point
  • Flow behavior index
  • Flow consistency index

Barite sagging monitoring concept

Concern:

  • Barite settling in high-pressure/high-temperature wells

Monitoring approach:

  • Sample measurements from:
    • Top of tank
    • Middle of tank
    • Bottom of tank
  • Detect density/marsh funnel deviations to infer barite sagging

Speakers / sources featured (as identified in the subtitles)

  • Dina Atta — session moderator; petroleum engineer at “Khaleda Petroleum Company” (as stated)
  • Dr. Salah Elkatatny (also referred to as Dr. Salah Katatney / Dr. Salah Najar due to subtitle variation) — presenter; associate professor at King Fahd University of Petroleum and Minerals; also associated with Cairo University (on leave per subtitles)
  • API — cited as the source for drilling line specifications (used to determine slip-and-cut laps)

Original video