Rig Components

Drilling Engineering

Drilling Rigs

 Nearly all of today’s rigs are of the rotary type (other type is percussion or “cable tool” type – used only for shallow wells)

 Rigs may be marine or land (offshore or onshore)

 Marine (swamp)/offshore/deepwater rigs

 Bottom supported - for water depth (WD) of ~350 ft

 Platform, barge (20 - 40 ft WD), and jackup up to 350 ft WD)

 Platform rigs may be self contained or tendered, water depth limited by platform design, may be >1500 ft WD

 Floating - semi-submersible (up to ~6000+ ft WD) and drillship (up to 13,000+ ft WD)

Classification of Rigs Based on Location

In general, there are three locations: onshore, swamp

(inland) or offshore

 Onshore: mast or mobile (generally of the cantilever type)

 Swamp: tender barge or jack-up (they are bottom-supported)

Land Rigs (light land rig)

 Capable of drilling up to 10,000’

 Typical derrick load < 750,000 lbf

 BOP rating 5,000 psi

Land Rig : Mast Type (light land rig)

 Description:

 Portable Truck Mounted, Telescopic Mast.

 Lower Lift Capacity

 Quick mobilization and rig up/ rig down

 Used for:

 Shallower onshore wells (<3650 m).

 Mobilization time is crucial.

 Location or road capacity size is limited

Land Rig : Mast Type

 Description:

 Transported by dismantling / Reassembling in several parts.

 When greater lift capacity is needed.

 Longer moving time.

 Used for:

 Deeper wells (>2500 m) on land.

 Transporting time is not a concern.

Some Rig Requirements

 Determine derrick load from heaviest casing string plus overpull requirement (with floating rig this may be riser weight)

 Determine substructure requirements from drillstring stand back load plus heaviest casing load

 Determine pump requirement from annular velocity requirements (look at all hole sizes) and horsepower requirements (motors, bit hydraulics, cuttings removal)

 Determine drill string requirements (drill pipe strength, drill collar size)

 Determine mud system requirements from hole volume and other factors (e.g. lost circulation reserves, mud change out, mud cleaning requirements)

Some Rig Requirements

 Determine total rig power requirements – drawworks, pumps, electrical generation

 Power type – SCR, direct drive, diesel electric

 Determine storage and work area requirements – fuel, water, supplies, pipe storage, well testing, etc.

 Determine drilling fluid treatment requirements

Some Rig Requirements Special Requirements

 Onland

Road load limits

Noise and illumination pollution

Cuttings and mud disposal requirements

Location size constraints

Marine Rigs Selection

 Many designs criteria are used in selecting the proper marine rig. Major criteria are as follows:

Water depth rating (first evaluation tool)

Derrick and substructure capacity

Physical rig size and weight

Deck load capacity

Stability in rough weather (wind)

Duration of drilling program

Rig rating features such as horsepower, pipe handling and mud mixing capabilities

Exploratory versus development drilling

Offshore/Bottom Supported: Submersible /Barge

 Description:



Transported by floating, submerged on location for drilling.

 Used for:

 Shallow Waters ( < 30 m) – rivers, swamps, coastal regions, and inland bays.

Marine rigs – floating – drilling barge

 Floating rectangular barge with self contained rig on board

 Sheltered inland waters

Offshore/Supported : Jack-Ups

 Description:



Mobile offshore drilling structure

with tubular or derrick legs that

can be ‘jacked up’ and positioned

on location to support the deck

and hull.

 Used for:



Offshore drilling with water

depths 100-130 mts

Marine rigs – bottom supported - jack up

 Usually 3 legs which stand on the seabed

 Hull is lowered and legs raised for rig moves

 Can drill in shallow waters (to ~450 ft)

 Can cost between $45,000-90,000+/day

 BOP’s are below the derrick cantilever

Offshore/Supported : Platform

 Description:



Self-contained rigid, immobile

structure from which

development wells are drilled and

produced.

 Used for:



Offshore drilling on existing

platforms essentially unlimited

water depths, limited by platform

design which may be floating and

Offshore/Supported : Tender

 Description:

 Drilling mast and drawworks and a limited amount of

drilling support equipment is placed on the platform.

 The rest of the drilling equipment (pumps,

generators, storage, and living accommodations, etc.) are on a barge like vessel moored adjacent to the platform.

 Used for:

 Platforms with limited size of weight bearing capacity or working area.

Marine rigs (floating – semi-submersible)

 Rig towed on to location, then either anchors or uses dynamic positioning

 Can move off location fast if problems arise.

 Usually uses BOPs located at the seabed.

 Accommodation for up to 100+ persons. High cost;

Marine Rigs – (Floating – Drill Ship)

 Ship shaped hull, usually

self-propelled for rig moves

 Often uses dynamic positioning but may be anchored

 High storage

capacity; 1 or 2 wells without re-supply

 High cost, can be well over

Let’s Take a Break

At the end of this module, YOU should be able to;

1. Name or describe the rig components.

2. Explain the functions of the major components of a rig. 3. Understand fundamental rig operations.

4. Understand the well control systems especially BOP functions and arrangements.

5. Know well monitoring systems.

Basic Rig Components and Operations



Whether offshore or land based all rotary rigs have the same

basic drilling equipment, with the following major components

or systems:

 Power system

 Hoisting system

 Fluid-circulating system

 Rotary system

 Well control system

Rig Power Systems

 Most rig power is consumed by the hoisting and fluid circulation systems.

 Usually both systems are not used at the same time

 Power requirements: 500 - 3,000+ HP (horse power)

 Types of power prime movers

 Steam engine (obsolete)

 Internal combustion diesel engine

 Diesel-electric

 Direct-drive – (uses gears, chains, belts etc.)

 Mechanical HP requirement for prime movers must be modified for harsh temperature environment & altitude

Comparison of Rig Power Systems



Comparison is based on transmission methods



Mechanical drive - uses gears, chains, and belts



Direct-current (DC) generators and motors: use power cords

instead of chains; decreased rig noise level; can be positioned

away from the rig, and increase efficiency



Alternating current (AC)-silicon controlled rectifier (SCR)

combined with motors: most widely used; offers longer life,

lighter weight; and less maintenance, and lower cost than DC

systems

Hoisting System



Function: To provide a means of lowering and raising

equipment into or out of the hole



Principal components

 Derrick & substructure

 Block & tackle pulley arrangements and drill line

 Major routine operations  Making connection

 Making a trip

Major Rig Components - Drawworks

The drawworks controls the

movement of the travelling

block up and down the derrick.

Drawworks unit showing sand line sheave on top, eddy current brake, main brake, gear handles

View across drill floor to the drawworks

Driller’s console with weight indicator and main brake

Drawworks

 The drawworks is the control center of the rig and it houses the drum which spools the drilling line

 Principal parts are: drum, brakes, the transmission, and the catheads

 Its design depends on prime mover type and power transmission type

 Rated by horse power & depth

 Drawworks HP = (W x Vh)/(33000 x E); W is lbf and Vh is in ft/min, E is traveling assembly (block and tackle) efficiency

Major Rig Components – Mast or Derrick

The mast provides the range of movement of the travelling block. It allows pipe “stands” to be

racked or stood back during trips.

Derrickman on monkey board adding stands to the string

Derrick showing monkey board, crown block, block guides

Major Rig Components – Drill Line and Travelling Blocks

Deadline anchor with sensator shown

Rig Fluid Circulating System

 Function is to remove rock cuttings out of the hole as drilling progresses

 Principal components are  Pumps

 Pits and or tanks  Mixing devices

 Contaminants removal equipment, and  Flow conduits

Conventional Fluid Flow Conduits

 These are components through which the fluid moves from the pump to the rig floor

 Surge chamber - located in the high pressure discharge line from the pump to reduce vibration

 4 - 6” heavy-walled pipe from pump to base of rig substructure

 Stand pipe, attached to one of the legs

 Flexible rotary hose

 Swivel - rotates and allows fluid circulation under pressure

Mud Pumps



The function of the mud pump is to circulate fluid at desired

pressures and flow rates.

 Mud pumps are generally reciprocating types: two general types - double-acting (duplex) and single-acting (triplex)

 Pumps are denoted by the stroke, bore and rod diameters (for duplex only)

 Commonly rated by horse power (HP), maximum pressure and

maximum stroke rate (which controls the maximum output volume rate)

 Two or three pumps are generally installed on a rig

 One pump may be used as a standby; two or three may be used when drilling surface holes; one often is all that is needed at deeper depth

Major Rig Components – Mud Pumps

Mud pumps provide fluids at desired pressures and flow rates to the drill string for circulation into and out of the well.

Mud Pumps

Discharge Pulsation Damper

Pump Suction Line (from mud tank)

Flexible High Pressure Discharge Hose Pressure Relief Valve

Drilling Rig Substructure Well with BOPS

Advantages and Disadvantages of Reciprocating Pumps

 Advantages

 Ability to move fluids with high solids content

 Ability to pump large particles, for example, lost circulation materials, (LCM)

 Ability to operate over a wide range of pressures and volumes by using different liners and pistons

 Ease of operations and maintenance; and very reliable

 Disadvantages

 Discharge flow is pulsating and hence causes vibration on discharge lines

Mud Pump Exercises:



Use the formula:



HHP= DF x [(



P)(Q)/1714]/efficiency



To calculate the horsepower needed for the following

situations:



Surface hole drilling: 1200 gpm at 2500 psi



Intermediate hole drilling: 400 gpm at 3000 psi

Single-Acting Triplex Pump

 Has three pistons and it sucks and discharges on every two strokes  Pump factor, Fp = pump

displacement per complete cycle (or stroke)

 Fp = (/4)(3)(Ls)(DL2_)Ev

 DL = liner diameter

 Ls = stroke length

 Ev = pump volumetric efficiency

 Note: there is no Dr = rod diameter

 This pump is light, more compact, cheaper to operate and very useful offshore where space is limited  Parts are smaller and easier to

Mud Pits or Mud Tanks

 Mud pits may be pits in the ground lined with an impermeable liner or may be steel tanks. Offshore they of course are steel tanks.

 Three basic types of mud tanks: settling, suction, and reserve

 Settling: allows time for setting of cuttings and release of entrained gas

 Suction: the pump sucks cleaned fluid from it

 Reserve: to contain contaminated fluid, cuttings, and any sometimes produced formation fluid

Contaminants (Solids) Removal Equipment

 Shale shaker - a vibrating screen that removes coarse rock cuttings/caving such as shales

 Desander - removes sand or larger particles not caught by the shale shaker screen

 Desilter - removes very fine particles and silt

 Hydrocyclone/decanting centrifuge - removes finely grounded solids

 Mud cleaner - a combination of a hydrocyclone and a shaker screen, and use only for moderately high-density fluid

 Degasser - removes entrained gas from the fluid

 Except for the shale shaker all devices separate fluids by density differences or settling

Solids Control



Solids control equipment will be covered in detail when we

discuss drilling fluids.

Conventional Rig Rotary System

 Rig rotary system includes all the equipment used to

achieve bit rotation. Can be conventional or top drive type

 Conventional rotary system is made up of - swivel, kelly,

kelly bushing, rotary drive,

rotary table, and the drill string (i.e. drill pipe and drill collars)

 More common offshore and on large land rigs is a top drive system, which may also be called a power swivel

Swivel

 First connection to the hoisting system

 Mud entry point under high pressure 2000 – 7500 psi

 Top does not rotate

 Bottom free to rotate

 Top connects to a flexible hose which in turn connects to a fixed steel high pressure standpipe

Kelly, Rotary Kelly Bushing and Rotary Table

 Square or Hexagonal drive shaft

 Passes through Kelly Bushings

 Bushings have drive pins to locate into the master

Top Drive

 Top drive, also may be

called a power swivel. In this system the

regular swivel, kelly, and

kelly bushing are eliminated.

Rig Rotary System Top Drive

 Top drive

 Has built-in tongs to make and breakout pipes.

 Uses a hydraulic or electric motor to achieve rotation.

 Safer and easier for crew members to handle the drill pipe.

 Saves time as connections are made very fast and safer. The crew uses the unit’s built-in tongs.

 Connections only need to be made every ~90 feet or every 3 joints of pipe improving drilling efficiency.

 Provides other operational advantages.

Well Control System

 One of the most important systems on the rig. Its functions are:

 To detect a kick and to close the well on surface

 To circulate well under pressure and permit increasing the fluid density at the same time

 To move pipe under pressure

 To divert flow from the rig

 “Kick” is the uncontrolled flow of formation fluid into the well and occurs when hydrostatic pressure (P_h) is less than the formation pressure (P_f)

 If the well control system fails, a BLOWOUT occurs - this is perhaps the worst disaster while drilling.

 A blowout is an uncontrolled flow of fluid from a well

 Effects of blowouts may cause: loss of life, loss of equipment, loss of the well, loss of natural resources, and damage to the environment.

Kick Detection During Drilling Operation

 Kick detection while drilling usually achieved by use of a pit volume indicator or mud flow indicator.

 Both devices can detect an increase in the flow of mud

returning from the well over that which is being circulated by the pump.

 Mud flow indicator can detect a kick more quickly. Used in

Blowout Preventer Accessories

 These are accumulators, casing head, control panel, kelly cock, inside BOP, and high pressure circulation device

 Accumulator

 Used to close hydraulically the BOP and located away from the rig

 Its characteristics: most be able to close all the BOP units at least once; has its own power source; it’s oil must be compatible with elastomers used in the BOP.

 Casing head - connects BOP stack to top of casing.

 Control panel - on the rig floor and easily accessible to the driller.  Kelly cock/inside BOP - stop flows from inside the drill pipe.

 High pressure circulating device (pump) - used to circulate the kick out of the hole.  Back pressure device – used to maintain additional pressure on the well while

Blowout Preventers

 These are special pack-off devices used to stop fluid flow from a well. A multiple of the pack-of devices is called BOP stack. Stack arrangement is dependent on many factors including formation pressure & operator policies

 Purpose of BOP

 Stops flow from the annulus with or without the drill string in the hole  To determine if flow from the well may occur

 To allow pipe movement under pressure  To allow fluid circulation

Typical Arrangements of Blowout Preventers

 The arrangement of the BOP stack varies considerably. The arrangement used depends on the magnitude of formation pressure in a particular area and on the type of well control

procedures used by the operating company.

 API suggests several arrangements of BOP stacks. This figure shows typical arrangements for 10K and 15Kpsi working pressure service.

A = annular preventer, R = ram preventer, S = drilling spool G = rotating head

Remote Control Panel for Operating Blowout Preventers

 The control panel for operating the BOP stack usually is placed on the derrick floor for easy access by the driller.

 The controls are marked (and should be marked) clearly and identifiably with the BOP stack arrangement used.

 In general, the control panel is located away from the rotary area.

 Another remote panel may be located on the ground or at a remote location for use if the primary operating panel

Well Monitoring Systems

 A well must be monitored for safety, operational efficiency, and to detect drilling problems

 Different devices are used to achieve these objectives



Parameter Measured

Device Used

 Depth Geolograph

 Rate of Penetration (ROP) Geolograph (by deduction)

Well Monitoring Systems



Parameter Measured

Device Used

 Rotary speed Tachometer on weight indicator

 Torque Torque indicator

 Pump pressure Pressure gauge on stand pipe

 Flow rate Stroke counter

 Fluid density Mud balance

 Mud temperature Flow line thermometer

Major Rig Components – Marine BOP’s

BOPs allow the top of the well to be sealed against very high pressures and allow fluid to be pumped into the well.

Marine Rigs – Specialist Equipment – Slip Joint and

Riser Tensioners

 Slip joint allows relative movement between the rig and the well (heave, tide).

 Tensioners supports the weight of the riser and keep the riser top in tension.

Marine Rigs – Specialist Equipment – Riser Joints And

Flex Joint

1. Riser joints contain buoyancy chambers (reduce load), kill & choke lines and boost line.

2. Flex joint at seabed allows lateral movement of rig.

Marine Rigs – Specialist Equipment – Subsea BOP

 Subsea BOP is positioned on the wellhead at the seabed.

 Remote controls from the surface.

 Accumulator bottles on the stack allow operation, even if disconnected from the rig, by sonic signals

Tubular Specifications

 All tubular (drill pipe, drill collar, casing, and tubing) are specified by the

following:

 Range (length): 3 ranges - R1 (18 – 22 ft, uncommon), R2 (27 - 30 ft), R3 (>38-45 ft)

 Nominal weight per foot

 Outside diameter, OD

 Steel grade (drill pipe is E75, X95, G105, S135, and Z140)

 Essentials of drill string design

 Tally - each joint must be measured carefully and recorded

 Capacity and displacement volumes must be known

 Pipe capacity = (xd_id2_)/4

 Displacement capacity = ( x(d_od2 _-

d_id2_)/4

 API/ISO documents dictate pipe and connection specifications

Drill Pipes and Drill Collars

 Drill pipes

 Transmit rotational power to the bit.

 Transmit drilling fluid to the bit.

 Drill collars

 Provide weight on bit.

 Prevent buckling of the drill string.

 Provide pendulum effects to cause the bit to drill a more nearly vertical hole.

 Support and stabilize the bit to drill new hole aligned with the already drilled hole.

 Drill collars can be round (most), spiral, or square

 Spiral used in small diameter holes or deviated wells to prevent or reduce differential pipe sticking.

Safety Provisions on the Rig

 Rig equipment is designed to prevent accidents  Handrails on walkways and stairways

 Guards on all moving machinery

 Pressure relief devices on mud lines and pumps

 Personal Protective Equipment (PPE)  No loose or floppy clothing

 Hard hat must be worn to protect the head

 Steel-toe shoes must be worn to protect the feet  Safety goggles to prevent eye injuries

Safety Provisions on the Rig



Safety meetings

 Must be conducted often to discuss procedures

 Must provide manuals for new employees

 Must conduct regular drills



Special conditions

Review

Rig Selection: Major COMPONENTS to be Selected /

Sized:

 Hoisting System

 Rotary System

 Circulating System

 Well Control System

 Power Generator System

 Tubular Goods

Rig Specification: Hoisting System

 Specify Hook Load Capacity

 Specify Drawworks

 Power Delivery (loose guidelines)

 Lightweight Rigs : 650 HP  Intermediate Rigs : 1300 HP  Heavyweight Rigs : 2000 HP

 Ultraheavy Rigs : 3000 HP or above

 Drum Diameter, Groove Sizes etc.

 Braking Systems (Operational, Emergency)

 Crown Block

Rig Specification: Rotary System

 Specify Type of Rotary System  Rotary Table-Kelly System

 Top-Drive System

 Specify Max. Working Torque

 Specify Max. Working RPM

Rig Specification: Circulating System

 Specify The Pumps

Types (Duplex, Triplex; Single Acting, Double Acting etc)

Capacities (HP, Max Pressure, Max SPM, Max GPM etc)

Stroke Lengths, Liner Sizes etc.

 Specify Tanks

Numbers, Purposes, Volumes, Number of Tank Agitators.

 Specify The Mud Cleaning Equipment

Shale Shakers, Gas Separators, Degasser, Desanders, Desilters, Centrifuges, Gas Burners, etc.

 Specify The Additive Mixing Equipment Hoppers, pneumatic equipment, etc.

Rig Specification: Well Control System

 Specify the BOP stack

 Individual Components (pipe rams, pipe rams, shear rams, annular preventer and their pressure ratings)

 Stack Configuration

 Other Components

 Chokes, Choke Manifolds, Valves

 Kill Line, Choke Line, Secondary Lines

 Control System

 Reaction Time

 Capacity (accumulator capacity, number of bottles or pressure tanks, etc.)

 Reliability

Rig Specification: Power Generation System

 Number of generator sets

 Engine specification (fuel used, type of engine, horsepower)

 Generator specification (Kilowatts, AC/DC)

 SCR specifications

 Distribution system

 Flexibility to redistribute power

Rig Specification: Tubular Goods Inventory

 Drill Collars, HWDP, Drill-Pipe, Cross-Overs, Various Subs, Mills, Jars, etc.

 Sizes

 Thread types  Grades

 Quantities

Rig Specification: Derrick/Mast Capacity & Sub-Structure

 Derrick/Mast Capacities  Load Capacities

 Floor Space  Height

 V-door clearance, etc  Rig floor auxiliary hoists

 Elevating/Assembling/Transportation Mechanism

 Sub-Structure  Load Capacities  Dimensions

 KB to Ground Clearance

Rig Specification: Miscellaneous

 Floor Equipment – power tongs, hydraulic slips, etc.

 Automation and instrumentation

 Communication systems

 Operational water depth, riser specification, etc.

 Operating conditions (wind, water currents, temperature, altitude etc.)

 Mooring system

 Stationing/positioning system

 Transportation/propulsion system

 Cranes

 Cementing unit

 Logging unit, etc.

Minimum Calculations

1. Derrick Load Calculations

2. Power Requirement Calculations

Now, YOU should be able to;

1. Name or describe the rig components

2. Explain the functions of the major components of a rig 3. Understand fundamental rig operations

4. Understand fundamental rig calculations such as rig power, derrick load, derrick efficiency, mud pump volume, tubular volumes.

5. Understand the well control systems especially BOP functions and arrangements

6. Know well monitoring systems

Appendix to Rigs and Rig Operations

The following slides are relevant to

sections covered in this lecture but

are left out for brevity, they may be

used as deemed appropriate by the

instructor

Land Rigs (Heavy Land Rig)

 Capable of drilling deeper than 10,000’

 Typical derrick load > 1,000,000 lbs

 BOP rating  10,000 psi

Land Rigs – Helicopter Portable

 Breaks down into small packages for moving (~8000 lb for medium lift choppers to 20,000 lb for military type choppers)

 Can deploy in locations not otherwise useable without very high cost (jungle, mountain tops, inaccessible locations)

Marine Rigs – Bottom Supported – Platform



Self contained rig installed

on platform



Once drilling is finished, rig

can be removed or

replaced with smaller

completion or workover

rig.

Marine Rigs – (Semi-Submersible)

Heating Values of Various Fuels

Fuel

Type

Density

(lbm/gal)

Heating Value

(Btu/lbm)

Diesel

7.2

19,000

Gasoline

6.6

20,000

Butane

4.7

21,000

Methane

---

24,000

Example: A diesel engine delivers an output torque of 1,740 ft-lbf at 1,200 rpm. If the fuel consumption rate is 31.5 gal/hr, what is the output power and overall engine efficiency?

Solution:

The angular velocity, ω, is given by  21,2007,539.8rad /min

The power output can be computed using the equation P = T   _hp

hp lbf ft lbf ft P T P 5 . 397 min/ / 000 , 33 min / 740 , 1 8 . 539 , 7 _    

From the previous table, the density, ρ, for diesel is 7.2 lbm/gal and the heating value, H, is 19,000 Btu/lbm. Thus, the fuel consumption rate w_f is:

  3.78 /min 60 1 / 2 . 7 / 5 . 31 lbm minutes hour gal lbm hr gal w_{f }      

The total heat energy consumed by the engine is given as:

 Btu lbm ft lbf Btu lbm Q H w Q i f i / 779 / 000 , 19 min / 78 . 3    

Rig Power System-Example Problem

 Example: A drilling rig is working in an arid climate (85°F) at an elevation of 3,600 ft. During the day, the peak temp. is 105oF. The min. temperature (prior to dawn) is 45°F. The rig has three 1,000 HP prime movers. Determine the min. and max. HP available during the 24-hr period.

 Solution

 The total available HP from the prime movers is 3 x 1000 HP = 3,000 HP  The loss in HP due to altitude =3% loss/1000 ft x 3600 ft x3000 HP= 324 HP  Hence, available HP at an altitude of 3,600 ft = 3,000 HP-324 HP = 2676 HP

 Minimum HP will occur at the max. temp. = 2676 HP - loss to increase in temp.= 2676 HP - 1% loss/10oF x (105-85) °F x 2676

 = 2676 HP - 53.5 HP = 2622 HP

 Maximum horsepower will occur at the minimum temp.  = 2676 HP + increase due to decrease in temp.

 = 2676 HP + 1% gain/10°F x (85-45)°F x 2676 =2676 HP+107 HP

Example: A rig must hoist a load of 300,000 lbf. The drawworks can provide an input power to the block and tackle system of 500 hp. Eight lines are strung between the crown block and traveling block. Calculate (1) the static tension in the fast line when upward motion is impending, (2) the maximum hook horsepower available, (3) the maximum hoisting speed, (4) the actual derrick load, (5) the maximum equivalent derrick load, and (6) the derrick efficiency factor. Assume that the rig floor is arranged as shown previously.

(1) The power efficiency for n = 8 is given as 0.841.

The tension in the fast line is calculated as follows: En   lbf W F_f 44,590 8 841 . 0 000 , 300 _  

(2) The maximum hook horsepower available is P_h  E p_i  0.481

 

(3) The maximum hoisting speed is given by

min / 3 . 46 000 , 300 min / 000 , 33 5 . 420 ft lbf hp lbf ft hp W P_h  _        

Example: A rig must hoist a load of 300,000 lbf. The drawworks can provide an input power to the block and tackle system of 500 hp. Eight lines are strung between the crown block and traveling block. Calculate (1) the static tension in the fast line when upward motion is impending, (2) the maximum hook horsepower available, (3) the maximum hoisting speed, (4) the actual derrick load, (5) the maximum equivalent derrick load, and (6) the derrick efficiency factor. Assume that the rig floor is arranged as shown previously.

Solution:

(4) The actual derrick load is calculated as follows:

(5) The maximum equivalent load is calculated as follows:

(6) The derrick efficiency factor is

      lbf W n E n E E F_d 300,000 382,090 8 841 . 0 8 841 . 0 841 . 0 1 1 _                     lbf W n n F_de 300,000 450,000 8 4 8 4 _                 % 9 . 84 849 . 0 000 , 450 090 , 382 or F F E_d  d   continued

Projection of Drilling Lines on Rig Floor

 The drilling lines usually are arranged as in the plan view of the rig floor shown.

 For this arrangement:  All legs equally support

the load on the traveling block – each having one fourth of the “hook load.”  Derrick legs C and D

share the load imposed by the tension in the fast line.

 Leg A assumes the full load imposed by the tension in the dead line.

Double-Acting Duplex Pump

 Has two pistons and it both sucks and discharges on every stroke

 Pump factor, Fp = pump displacement per complete cycle (or stroke)

 Fp = (/4)(2)(Ls)[(2(DL2_{)) - Dr}2_)]Ev  DL = liner diameter

 Dr = rod diameter  Ls = stroke length

 Ev = pump volumetric efficiency  Hydraulic pump horse power

HHP= (P)(Q)/1714

 P = differential pressure, psi (P_out - P_inlet)

The following slides may be used to illustrate drill line

capacity and contains an exercise

Schematic of Block and Tackle

1. Comprised of crown block, traveling block, and drilling line.

2. Provides a mechanical advantage, which

permits easier handling of large loads.

3. Generally mechanical advantage is less than n (i.e. less than 100%) due to friction.

4. As n increases, the mechanical advantage increases.

Drilling Line

 The drilling line is subjected to fatigue and wear when in service during normal tripping operation.

 Failure of the line may result in injury to personnel, damage to the rig, and loss of the drilling string.

 Hence, drilling line tension is always maintained less than the yield strength of the line.

 The greatest wear occurs at pickup points on the traveling and crown blocks and the drawworks.

 These wear locations must be changed regularly by following a

preventative maintenance program called a SLIP and CUT Program (similar to oil change for your car).

Drilling Line

 Steel construction 6x19

 6 pieces or strands

 19 wires in each piece

 Rope lays

 The lay of a wire rope is the way the wires and strands are placed during manufacture.

 Right and Left lay refers to the

direction in which the strands of the rope are wound around the core.  Regular and Langs lay refers to the

way the wires in the strand are wound in relation to the strands

Refer to API Spec 9A (ISO 10425) for details as well as API RP9B for recommended practices

Slip and Cut Program

 Slip and Cut involve:

 Suspend the traveling block.

 Loosen the dead line at the wire line anchor.

 Slip in a few feet of new line into service from the storage reel.  Disconnect the drill line from the drawworks drum.

 Cut off a section of the line from the drawworks end, pull through an amount equal to the amount cut off and reconnect the drill line to the drawworks spool.

 A Slip and cut program is conducted based on a unit of service called the “ton-mile” method.

 Based on the assumption that a line will safely perform so much work (ton-mile).  A line has rendered 1 ton-mile when the traveling block has moved 2,000 lbf a

Exercise: Calculate Desired Drawworks Horsepower



Using this equation:

Drawworks HP = (W x Vh)/(33000 x E); W is lbf and Vh is in ft/min, E is traveling assembly (block and tackle) efficiency



Calculate the needed horsepower to move a drillstring weighing

225,000 pounds at a rate of 150 feet per minute, use an

Exercise: Calculate wire rope capacity



Using the previous 2 slides and a design factor of 3.5.

Determine the maximum load that may be supported if a 1-1/2

inch EIP wire rope is used as a drilling line. Use load case A

strung up with 10 lines.



Consider that the tension in the fast line is calculated as follows:



FL Tension = Fast Line Factor x Load



The Fast Line Factor for 10 lines is 0.123



What is the maximum load that can be lifted with this drilling

line?

Example: Compute the pump factor in units of barrels per stroke for a duplex pump having 6.5-in. liners, 2.5-in. rods, 18-in. strokes, and a volumetric efficiency of 90%.

Solution:

The pump factor for a duplex pump can be determined as follows using the equation for duplex-double-acting pump









Recall that there are 231 in3 _{in a U.S. gallon and 42 U.S. gallons in a U.S.}

barrel. Thus, converting to the desired field units yields

stroke bbl gal bbl in gal stroke in / 2052 . 0 42 3 231 3 2 . 991 , 1   



The following slides discuss solids control equipment, this is

covered in detail later in the course, however these slides may

be used to illustrate or respond to questions at this time.

Realize though that these same slides will be shown later in the

course.

Example Solids Processing Layout

Degasser

Centrifuge

To Trip Tank

Gumbo Slide (optional)

Gas Buster Removal Section Hopper Additions Section S uction & T e s ting Se c tion

Treated Fluid to Well

Returns from Well Choke From Trip Tank

Scalping Shaker (optional)

Desilter or Mud Cleaner Desander Sand Trap Main Shaker Hopper Mud Pump(s) Well

Desander

Inside diameter larger

than six inches.

Desilter

Centrifuges

 In weighted drilling fluid systems, decanting centrifuges recover as much as 95% of barite, which is returned to the active system, while also discarding finer, lower-gravity solids. In chemically enhanced dewatering systems, centrifuges significantly reduce liquid

discharge volumes and appreciably enhance total solids control system efficiency.

Example Solids Processing Layout - Review

Degasser

Centrifuge

To Trip Tank

Gumbo Slide (optional)

Gas Buster Removal Section Hopper Additions Section S uction & T e s ting Se c tion

Treated Fluid to Well

Returns from Well Choke From Trip Tank

Scalping Shaker (optional)

Desilter or Mud Cleaner Desander Sand Trap Main Shaker Hopper Mud Pump(s) Well



The following slides may be useful to support your lecture or

respond to questions related to well control topics, well control

is covered in more detail later in this course.

Two alternative trip-tank arrangements for kick detection

during tripping operations

 While making a trip, circulation is stopped and a significant volume of pipe is

removed from the hole. Hence, to keep the hole full, mud must be pumped into the hole to replace the volume of pipe removed.

 Hole-fill up indicator is used during trip operations. Used to measure accurately the mud volume required to fill hole.

 Trip tanks - small tanks holds 10 - 15

gauge makers - provide the best means of monitoring hole fill - up volume.

 Pump stroke counters - use if no trip tanks on the rig to determine hole fill - up

volume.

 Never use active pits as hole fill-up

volume indicators because it is too large to provide sufficient accuracy.

Components of a Kick Detection System

 Mud flow indicator - detects a kick more quickly, sees the kick first

 Pit volume indicator - indicates the active pit volume and presets at high & low levels; an alarm turns a light or a horn on when the levels are below or above set levels

 Gain in pit volume = kick volume !!!

 Hole fill-up indicator - used while tripping to measure accurately the fluid required to fill the hole

 Trip tanks - usually very small (10 - 15 bbl capacity) and provide the best way to monitor hole fill-up volumes

Blowout Preventers



Types of BOP - ram and annular preventers



Three types of ram: pipe; blind; and shear

Pipe closes against the drill pipe.

Blind closes the well when there is no drill pipe in hole.

Shear, is a special blind ram as it shears the drill pipe.

 Usually only used when all pipe ram and annular preventers have failed.



Annular preventer, also called a “bag” preventer uses an

elastomer ring to close against the drill string.



BOP working pressures

Typical Arrangements of Blowout Preventers

 The arrangement is defined starting at the casing head and proceeding up to the bell

nipple.

 Thus, arrangement RSRRA

denotes the use of a BOP stack with a ram preventer, attached to the casing head, a drilling spool above the ram preventer, two ram preventers in series above the drilling spool and annular preventer above the ram preventer