Thịnh drilling engineering fundamentals, ch 1, 2, 3, 4, 5, 7, 8 10

People directly involved in drilling a well are employed either by the operatingcompany, the drilling contractor, or one of the service and supply companies.The operating company is the

Associate Professor Jorge H.B Sampaio Jr., PhD

Curtin University of Technology

Department of Petroleum Engineering

j.sampaio@curtin.edu.au

April 3, 2007

1 Introduction 1–1

1.1 Objectives 1–11.2 General 1–11.3 Drilling Rig Types 1–31.4 Personnel at Rig Site 1–51.5 Miscellaneous 1–7

2.1 Power System 2–52.1.1 Energy, Work, and Efficiency 2–62.2 Hoisting System 2–82.2.1 The Derrick 2–102.2.2 The Drawworks 2–112.2.3 The Block & Tackle 2–122.2.4 Load Applied to the Derrick 2–162.3 Drilling Fluid Circulation System 2–182.3.1 Mud Pumps 2–202.3.2 Solids Control Equipment 2–252.3.3 Treatment and Mixing Equipment 2–302.4 The Rotary System 2–332.4.1 Swivel 2–332.4.2 Kelly, Kelly Valves, and Kelly Saver Sub 2–332.4.3 Rotary Table and Components 2–362.5 Well Control System 2–382.6 Well Monitoring System 2–43

3.1 Drill Pipes 3–13.1.1 Drill Pipe Elevator 3–53.2 Drill Collars 3–53.3 Heavy Wall Drill Pipes 3–63.4 Special Tools 3–73.4.1 Stabilizers 3–73.4.2 Reamers 3–93.4.3 Hole–openers 3–93.5 Connections Make–up and Break–out 3–103.5.1 Maximum Height of Tool Joint Shoulders 3–113.5.2 Make–up Torque 3–133.6 Drill Bit 3–133.7 Other Drillstring Equipment 3–143.7.1 Top Drive 3–143.7.2 Bottom Hole Motors 3–15

4.1 Hydrostatic Pressure 4–14.1.1 Hydrostatic Pressure for Incompressible Fluids 4–24.1.2 Hydrostatic Pressure for Compressible Fluids 4–44.2 Buoyancy 4–7

5.1 Length of Drill Collars – Neutral Point Calculation 5–15.2 Design for Tensile Force, Torque, Burst, and Collapse 5–65.2.1 Maximum Tensile Force 5–65.2.2 Maximum Torque 5–95.2.3 Internal (Burst) and External (Collapse) Pressures 5–105.2.4 Drillstring Elongation 5–12

6.1 Mass and Energy Balance 6–16.1.1 Mass Conservation 6–26.1.2 Energy Conservation 6–36.2 Flow Through Bit Nozzles 6–6

6.2.1 Pressure Drop Across the Bit 6–66.2.2 Hydraulic Power Across the Bit 6–86.2.3 Impact Force of the Jets 6–86.3 Required Hydraulic Power 6–106.4 Bit Hydraulics Optimization 6–116.4.1 Nozzle Size Selection Criteria 6–136.4.2 Graphical Analysis 6–16

7.1 Functions of Drilling Fluids 7–17.2 Types of Drilling Fluid 7–27.2.1 Water–Base Fluids 7–37.2.2 Oil–Base Muds 7–67.2.3 Synthetic Fluids 7–77.2.4 Aerated Fluids 7–77.3 Laboratory Tests 7–77.3.1 Water–Base Mud Tests 7–77.3.2 Oil-Base Mud Testing 7–127.4 Fluid Density and Viscosity Calculations 7–137.4.1 Density Calculations 7–147.4.2 Density Treatment 7–157.4.3 Initial Viscosity Treatment 7–19

8.1 Rheological Classification of Fluids 8–18.2 Rheometry 8–48.2.1 Viscosity of Newtonian Fluids 8–58.2.2 Parameters of Bingham–Plastic Model Fluids 8–58.2.3 Parameters of Power–Law Model Fluids 8–58.2.4 Gel Strength 8–6

9.1 Laminar Flow in Pipes and Annuli 9–19.1.1 Equilibrium Equations 9–29.1.2 Continuity Equations 9–3

9.1.3 Newtonian Flow in Pipes – Poiseuille’s Equation 9–59.1.4 Newtonian Flow in Concentric Annuli – Lamb’s Equation 9–69.1.5 Slot Approximation for Newtonian Fluids 9–99.1.6 Pressure Drop Gradient for Non–Newtonian Fluids 9–109.2 Turbulent Flow in Pipes and Annuli 9–129.2.1 Turbulent Flow of Newtonian Fluids in Pipes 9–129.2.2 Criterion for Laminar – Transition – Turbulent Flow 9–199.2.3 Other Geometries – Turbulent Flow in Annuli (Newtonian) 9–209.2.4 Turbulent Flow for Non–Newtonian Fluids 9–22

10.1 Drill Bit Types 10–110.1.1 Roller Cone Bit 10–210.1.2 Air Drilling Bits 10–810.1.3 Fixed Cutter Bits (Drag Bits) 10–810.2 Bit Classification 10–1510.2.1 PDC Bit Classification System 10–1810.3 Drill Bit Selection and Evaluation 10–2010.3.1 Tooth Wear 10–2110.3.2 Bearing Wear 10–2110.3.3 Gage Wear 10–2210.4 Factors that Affect the Rate Of Penetration 10–2210.4.1 Bit Type 10–2210.4.2 Formation Characteristics 10–2210.4.3 Drilling Fluid Properties 10–2310.4.4 Operating Conditions 10–25

1.1 Rig Classification 1–32.1 Typical rig components 2–12.2 A simplified drillstring 2–32.3 Making a connection 2–42.4 Rig crew setting the slips 2–42.5 Removing one stand of drillstring 2–52.6 Typical hoisting system 2–92.7 Stand of doubles along the mast 2–102.8 Onshore rig drawworks 2–112.9 Brake belts and magnification linkage 2–112.10 Drawworks schematics 2–122.11 Forces acting in the block–tackle 2–132.12 Derrick floor plan 2–172.13 A swivel 2–192.14 Rig circulation system 2–202.15 Duplex pumps 2–222.16 Triplex pumps 2–222.17 Surge dampener 2–242.18 Solids control system 2–252.19 Shale shaker configurations 2–262.20 A two–screen shale shaker 2–262.21 A vacuum chamber degasser 2–272.22 Flow path in a hydrocyclone 2–282.23 Solid control equipment 2–282.24 Particle size classification 2–292.25 Internal view of a centrifuge 2–30

2.26 Mud cleaner 2–312.27 Mud agitator 2–312.28 Mud gun 2–322.29 Mud hopper 2–322.30 Cut views of a swivel 2–342.31 A square kelly and a hexagonal kelly 2–352.32 A kelly valve 2–352.33 Kelly bushings 2–362.34 Master bushings ([a] and [b]), and casing bushing (c) 2–362.35 Kelly bushing and master bushing 2–372.36 Drillpipe slip (detail when set in the master bushing) 2–372.37 DC slips, safety collar, and casing slips 2–382.38 A rotary table 2–382.39 BOP stacks 2–392.40 Annular BOP’s (a and b) and an inside BOP (c) 2–402.41 BOP: (a) blind and pipe rams, (b) shear rams 2–412.42 BOP accumulators and control panels 2–422.43 Choke manifold 2–422.44 Weight indicator (a) and a deadline anchor (b) 2–442.45 Drilling control console 2–443.1 Typical rotary drillstring 3–23.2 Typical tool joint designs (A) Internal upset DP with full–hole

shrink–grip TJ, (B) External upset DP with internal–flush shrink–

grip TJ, (C) External upset DP with flash–weld unitized TJ, (D)

External–internal upset DP with Hydrill™–pressure welded TJ 3–33.3 A DP elevator and the links to the hook body 3–53.4 A spiraled and a slick drill collars 3–63.5 Spiraled DC cross–section 3–63.6 A DC elevator 3–63.8 Heavy wall drill pipes 3–73.9 Some Stabilizers: (a) integral, (b) interchangeable, (c) non–rotating,(d) replaceable 3–83.10 A roller reamer 3–93.11 A fixed hole–opener 3–9

3.12 Manual tongs 3–103.13 Tongs in position to make–up a connection 3–113.14 A spinner 3–123.15 Tongs position during make–up 3–123.16 3–123.17 An electrical top drive 3–143.18 A bottom hole turbine 3–153.19 A bottom hole PDM 3–154.1 Stress state about a point in a fluid 4–14.2 Real gas deviation factor 4–54.3 Drillstring schematics for Example 12 4–95.1 Assumption 1 – pressure contributes to buckling 5–25.2 Assumption 2 – pressure does not contribute to buckling 5–46.1 Mass balance 6–26.2 Schematic of a circulation system 6–56.3 Longitudinal cut of bit nozzles (Courtesy SPE) 6–66.4 Pressure drop across the bit 6–76.5 Jet impact force 6–96.6 Line of maximum hydraulic power 6–166.7 Additional hydraulic constraints 6–176.8 Ideal surface operational parameters 6–186.9 Path of optimum hydraulics 6–196.10 Frictional pressure drop lines 6–206.11 Graph for Example 27 6–217.1 A mud balance 7–87.2 A Marsh funnel 7–87.3 A rotational viscometer (rheometer) 7–97.4 A API filter press 7–97.5 A HTHP filter press 7–97.6 Sand content sieve 7–107.7 Retort 7–107.8 Methyl blue capacity test kit 7–11

7.9 A pH meter 7–117.10 A titration kit 7–127.11 A permeameter kit 7–127.12 An aniline point kit 7–137.13 Electrical stability tester 7–137.14 Clay performance for viscosity 7–218.1 Typical graph of Newtonian fluids 8–28.2 Typical graph of Bingham-plastic fluids 8–38.3 Typical graphs of power–law fluids 8–38.4 Arrangement of a rotational viscometer 8–49.1 Velocity profiles of laminar flow 9–39.2 Velocity profile of laminar flow in a slot 9–49.3 Slot approximation of an annulus 9–99.4 Fluid particle flowing in a pipe 9–149.5 Stanton chart 9–159.6 Selection of the correct pressure drop value 9–1910.1 Typical roller cone bits 10–210.2 Cut view of a roller cone bits 10–310.3 Cut view of a non–sealed bearing bit 10–410.4 A sealed bearing bit 10–510.5 Cut view of a roller bearing cone 10–510.6 Cut view of a journal bearing cone 10–610.7 Geometry of bit cones 10–710.8 Cone offsets 10–810.9 Air drilling bits 10–910.10Steel blade drag bits 10–1010.11A diamond bit 10–1010.12Schematic and nomenclature of diamond bit 10–1110.13PDC bits 10–1310.14Schematic and nomenclature of a PDC bit 10–1410.15Nozzles in a PDC bit 10–1410.16Back rake and side rake angles in PDC bits 10–14

10.17IADC roller cone bit classification chart 10–1610.18Tooth wear diagram for milled tooth bits 10–2110.19Correlation between rock strength and threshold WOB 10–2310.20Variation of ROP with different fluid properties 10–2410.21Effect of differential pressure in the ROP 10–2510.22Exponential relationship between of differential pressure and ROP.10–2610.23Effect of WOB (a) and rotary speed (b) in the ROP 10–26

2.1 Heating values of fuels 2–62.2 Block–tackle efficiency ($\eta=0.96$) 2–1410.1 IADC codes for roller cone bits 10–1710.2 Range for IADC bit profile 10–1910.3 Range for IADC bit hydraulic design 10–1910.4 Range for IADC cutter size and density 10–20A.1 New Drill Pipe Dimensional Data A–2A.2 New Drill Pipe Torsional and Tensile Data Courtesy API A–3A.3 New Drill Pipe Collapse and Internal Pressure Data Courtesy APIA–4A.4 Premium Drill Pipe Torsional and Tensile Data Courtesy API A–5A.5 Premium Drill Pipe Collapse and Internal Pressure Data Cour-

tesy API A–6

Refer-1.2 General

When a drilling project is commenced, two goals govern its aspects The first

is to build the well according to its purpose and in a safe manner (i.e, avoidingpersonal injuries and avoiding technical problems) The second is to complete

it with minimum cost Thereto the overall costs of the well during its lifetime inconjunction with the field development aspects shall be minimized The overallcost minimization, or optimization, may influence the location from where thewell is drilled (e.g., an extended reach onshore or above reservoir offshore),the drilling technology applied (e.g., conventional or slim–hole drilling, over-balanced or underbalanced, vertical or horizontal, etc), and which evaluationprocedures are run to gather subsurface information to optimize future wells

On the other hand, the optimization is influenced by logistics, environmentalregulations, etc

To build a hole, different drilling technologies have been invented:

* Without mud → “Canadian drilling”

· Positive displacement motor drilling

· Electro motor drilling

– Annular drilling

* Diamond coring

* Shot drilling

• Special techniques

– Abrasive jet drilling

– Cavitating jet drilling

– Electric arc and plasma drilling

– Electric beam drilling

– Electric disintegration drilling

– Replaceable cutterhead drilling

– Rocket exhaust drilling

Figure 1.1: Rig Classification.

1.3 Drilling Rig Types

The diagram in Figure 1.1 shows a general classification of rotary drilling rigs.Several pictures of the different types of rigs are presented in Figures (a) to (l)below

(a) Jackknife rig (b) Portable mast.

(c) A cantilever rig on a barge (d) A self–contained

plat-form.

(e) A tender assisted platform (f) A submersible platform.

(g) A Jack–Up rig (h) Semi–submersible vessel.

(i) A drill–ship (j) A tension–leg platform.

(k) Caisson vessel (also called spar–

buoy).

(l) Diagram of a spar–buoy.

1.4 Personnel at Rig Site

This section describes the crew requirements and tasks of some individual crewmembers at the rig site

People directly involved in drilling a well are employed either by the operatingcompany, the drilling contractor, or one of the service and supply companies.The operating company is the owner of the lease/block and principal user of theservices provided by the drilling contractor and the different service companies

To drill an oil or gas well, the operating company (or simply called operator)acquires the right from the land owner under which the prospective reservoir

may exist, to drill and produce from it Usually, when a well has to be drilled,

an auction is run by the operator and various drilling contractors are invited

to place their bid Since drilling contractors are companies that perform theactual drilling of the well, their main job is to drill a hole to the depth/locationand specifications set by the operator Along with hiring a drilling contractor,the operator usually employs various service and supply companies to performlogging, cementing, or any other special operations, including maintaining thedrilling fluid in its planed condition

Most drilling crews consist of a tool pusher, a driller, a derrickman, a mudlogger, and two or three rotary helpers (also called floormen or roughnecks).Along with this basic crew configuration the operator sends usually a represen-tative, called company man to the rig For offshore operations the crews usuallyconsist of many more employees

Tool Pusher: The tool pusher supervises all drilling operations and is the

lead-ing man of the drilllead-ing contractor on location Along with this supervisionduties, he has to coordinate company and contractor affairs Two or threecrews operate 24/7, and it is a responsibility of the Tool Pusher to super-vise and coordinate these crews

Company Man: The company man is in direct charge of all company’s

activi-ties on the rig site He is responsible for the drilling strategy as well as thesupplies and services in need His decisions directly effect the progress

of the well

Driller: The driller operates the drilling machinery on the rig floor and is the

overall supervisor of all floormen He reports directly to the tool pusherand is the person who is most closely involved in the drilling process Heoperates, from his position at the control console, the rig floor brakes,switches, levers, and all other related controls that influence the drillingparameters In case of a kick he is the first person to take action bymoving the bit off bottom and closing the BOP

Derrick Man: The derrickman works on the so–called monkeyboard, a small

platform up in the derrick, usually about 90 ft above the rotary table When

a connection is made or during tripping operations he is handling andguiding the upper end of the pipe During drilling operations the derrick-man is responsible for maintaining and repairing the pumps and otherequipment as well as keeping tabs on the drilling fluid

Floormen: During tripping, the rotary helpers are responsible for handling the

lower end of the drill pipe as well as operating tongs and wrenches tomake or break up a connection During other times, they also maintainequipment, keep it clean, do painting and in general help where ever help

is needed

Mud Engineer, Mud Logger: The service company who provides the mud

al-most always sends a mud engineer and a mud logger to the rig site They

are constantly responsible for logging what is happening in the hole aswell as maintaining the proper mud conditions.

Ultra deep well: >5 000m

With the help of advanced technologies in MWD/LWD and extended reachdrilling techniques, horizontal departures of more than10000 m are possibletoday (e.g.,Wytch Farm)

Chapter 2

Rotary Drilling System

The most common drilling rigs in use today are rotary drilling rigs Their maintasks are to create rotation of the drillstring and facilities to advance and lift thedrillstring, casings, and special equipment into and out of the hole drilled Themain components of a rotary drilling rig can be seen in Figure 2.1

Figure 2.1: Typical rig components

Since the rig rate (rental cost of the rig) is one of the most influencing costfactors to the total cost of a well, careful selection of the proper type and ca-pacity is vital for a successful drilling project

For all rigs, the depth of the planned well determines basic rig requirementslike hoisting capacity, power system, circulation system (mud pressure, mudstream, mud cleaning), and the pressure control system The selection of themost cost–efficient rig involves both quantitative and qualitative considerations.The most important rig systems are:

1 Power system,

2 Hoisting system,

3 Drilling fluid circulation system,

4 Rotary system,

5 Derrick and substructure,

6 Well control system,

7 Well monitoring system

The proper way to calculate the various requirements is discussed below Thequalitative aspects involve technical design, appropriate expertise and training

of the drilling crew, contractors track record, and logistics handling

For offshore rigs, factors like water depth, expected sea, winds, and currentsconditions, and location (supply time) have to be considered

It should be understood that rig rates are not only influenced by the rigtype but they are also strongly dependent on by the current market situation(oil price, drilling activity, rig availability, location, etc) Therefore, for the rigselection, basic rig requirements are determined first Then drilling contractorsare contacted for offers of a proposed spud date (date at which drilling operationcommences) and alternative spud dates This flexibility to schedule the spuddate may reduce rig rates considerably

Before describe the various rig systems listed above, it is important to derstand the drilling process In rotary drilling, the rock is destroyed by theaction of rotation and axial force applied to a drilling bit The bit acts on the soildestroying the rock, whose cuttings must be removed from the bottom of theborehole in order to continue drilling

un-The drilling bit is located at the end of a drill string which is composed of drillpipes (also called joints or singles), drill collars, and other specialized drillingtools connected end to end by threads to the total length of the drill string, whichroughly corresponds to the current depth of the borehole Drill collars are thickwalled tubes responsible for applying the axial force at the bit Rotation at thebit is usually obtained by rotating the whole drill string from the surface (SeeFigure 2.2.)

The lower portion of the drill string, composed of drill collars and ized drilling tools, are called bottom hole assembly (BHA) A large variety ofbit models and designs are available in industry The choice of the right bit,

special-Figure 2.2: A simplified drillstring.

based on the characteristics of the formations to be drilled, and the right rameters (weight on bit and rotary speed) are the two most basic problems thedrilling engineer faces during drilling planning and drilling operation The cut-tings created by the bit action are lifted to the surface by the drilling fluid, which

pa-is continuously pumped from the surface to the bottom through inside of thehollow drill string At the bit, the drilling fluid is forced through nozzles in a fluidjet action which removes the cuttings from under the bit The fluid returns tothe surface carrying the cuttings, through the annular space between the drillstring and the borehole The carrying capacity of the drilling fluid is an impor-tant characteristics of the drilling fluid Other important characteristics are thecapacity to prevent formation fluids from entering in the borehole, and the ca-pacity to maintain the stability of the borehole wall At the surface, the cuttingsare separated from the drilling fluid by several solid removal equipment Thedrilling fluid accumulates in a series of tanks where it receives the necessarytreatment From the last tank in this series, the drilling mud is picked up by thesystem of pumps and pumped again down the hole

As drilling progresses, new joints are added to the top of the drill string creasing its length, in an operation called connection The diagram in Figure 2.3depicts the process of adding a new joint to the drill string

in-During the drilling of the length of the kelly, a new joint is picked from thepipe rack and stabbed into the mousehole using rig lift equipment At the kellydown, the kelly is pulled out of the hole A pipe slips (see figure 2.4) is used totransfer the weight of the drillstring from the hook to the master bushing The

Figure 2.3: Making a connection.

Figure 2.4: Rig crew setting the slips

connection at the first tool joint is broken and the kelly is swang and stabbedonto the joint in the “mousehole.” The new joint is stabbed on and connected tothe top of the drillstring The drillstring is picked up to remove the slips and thedrillstring is lowered until the kelly bushing fits the master bushing Then drilling

is re–initiated

As the bit gets dull, a round trip is performed to bring the dull bit to thesurface and replace it by a new one A round trip is performed also to changethe BHA The drillstring is also removed to run a casing string The operation

is done by removing stands of two (“doubles”), three (“thribbles”) or even four(“fourbles”) joints connected, and stacking them upright in the rig During trips,the kelly and swivel is stabbed into the “rathole".” The diagram in Figure 2.5depicts the process of removing a stand of the drillstring The process repeatsuntil the whole drillstring is out of the hole Then the drill string is run again into

Figure 2.5: Removing one stand of drillstring.

the hole and drilling continues The process to run the drillstring into the hole

is exactly the reverse of that shown in Figure 2.5

Sometimes the drillstring is not completely run out of the hole It is justlifted up to the top of the open-hole section and then lowered back again whilecontinuously circulating with drilling mud Such a trip, called wiper trip, is carriedout to clean the hole from remaining cuttings that may have settled along theopen–hole section

2.1 Power System

The power system of a rotary drilling rig has to supply power to items 2 to 7 inthe list above In addition, the system must provide power for pumps in general,rig light, air compressors, etc Since the largest power consumers on a rotarydrilling rig are the hoisting, the circulation system, and the rotary system, thesecomponents determine mainly the total power requirements During typicaldrilling operations, the hoisting and the rotary systems are not operated at thesame time Therefore the same engines can be used to perform both functions.Drilling rig power systems are classified as direct drive type and electrictype In both cases, the sources of energy are diesel fueled engines In thedirect drive type, internal combustion engines supply mechanical power to therig Most rigs use one to three engines to power the drawworks and rotary table.Power is usually transmitted to the elements by gears, chains, belts, clutches,and torque converters The engines are usually rated between 400 hp and

800 hp The power is used primarily to turn the drill string, pump the drillingfluid, and raise the drillstring Engines also power generators that supply theelectricity used on and around the rig Usually there are two generator sets

in the rig The rig can run with one of these units but it would run close tomaximum output at night The second provides for back–up and allows for otheroptions These engines are generally rated at 300 hp to 350 hp Rigs may alsoemploy one or two engines to power the drilling fluid pumps Total output variesfrom 300 hp to 800 hp In the electric type, several diesel engines are used togenerate electricity (DC and AC at various voltage levels) that are transmitted tothe various rig systems DC electric motors are compact and powerful, and canoperate in a wide range of power and torque There is considerable flexibility ofequipment placement, allowing better space utilization and weight distribution.This is extremely important in offshore rigs As guideline, power requirementsfor most onshore rigs are between 1,000 to 3,000 hp Offshore rigs in generaluse much more power

The performance of a rig power system is characterized by the output power, torque, and fuel consumption for various engine speeds These threeparameters are related by the efficiency of each system

horse-2.1.1 Energy, Work, and Efficiency

The energy consumed by the engines comes from burning fuels Table 2.1presents the heating values for some types of fuels used in internal combustionengines

The engine transforms the chemical energy of the fuel into work No enginecan transform totally the chemical energy into work Most of the energy thatenters the engine is lost as heat The thermal efficiency Et of a machine isdefined as the ratio of the work W generated to the chemical energy consumedQ:

Et = W

Q .Evidently, in order to perform this calculation, we must use the same unitsboth to the work and to the chemical energy Important conversion factors are:

1 BTU = 778.17 lbf/ft,

Table 2.1: Heating values of fuels

Fuel Type Heating Value Density

(BTU/lbm) (lbm/gal)

Gasoline 20000 6.6Butane (liquid) 21000 4.7Methane (gas) 24000 –

con-A system produces mechanical work when the sole result of the processcould be the raising of a weight (most time limited by its efficiency) In thiscase, the work W done by the system is given by

W = F h ,where F is the weight and h is the height Since power is the rate the work isproduced, if we take the time derivative of the work we obtain power:

P = dW

dt = F

dh

dt = F v ,where P is power, and v the velocity (assuming F constant) When a rotatingmachine is operating (an internal combustion engine or an electrical motor, forexample), we cannot measure its power, but we can measure its rotating speed(normally in RPM) and the torque at the shaft This is normally performed

in a machine called dynamometer The expression relating power to angularvelocity and torque is:

P = ω T ,where ω is the angular velocity (in radians per unit of time) and T is the torque

A common unit of power is the hp (horse power) One hp is the powerrequired to raise a weight of 33,000 lbf by one foot in one minute:

1 hp = 33, 000lbf ft

min = 550

lbf ft

s .For T in ft lbf and N in RPM we have:

When the rig is operated at environments with non–standard temperatures(85◦F) or at high altitudes, the mechanical horsepower requirements have to becorrected The correction should follow the American Petroleum Institute (API)standard 7B-llC:

1 Deduction of 3% of the standard brake horsepower for each 1000 ft ofaltitude above mean sea level

2 Deduction of 1% of the standard brake horsepower for each 10◦F rise orfall in temperature above or below 85◦F

Example 1: A diesel engine gives an output torque of 1740 ft lbf at an enginespeed of 1200 RPM If the fuel consumption rate was 31.5 gal/hr, what is theoutput power and the overall efficiency of the engine

Solution:

The power delivered at the given regime is:

P = 1200 RPM × 1740 ft lbf

5252 = 397.5 hpDiesel is consumed at 31.5 gal/hr From Table 2.1 we have:

Et= P

˙

Q =

397.51693.6 = 23.5%

2.2 Hoisting System

The hoisting system is used to raise, lower, and suspend equipment in the well(e.g., drillstring, casing, etc) The hoisting equipment itself consists of: (SeeFigure 2.6.)

• derrick (not shown),

Figure 2.6: Typical hoisting system.

The drilling line (wire rope) is usually braided steel cable varying from 1 inch

to 13/4 inches in diameter It is wound around a reel or drum in the drawworks.Power (torque and rotation) is transmitted to the drawworks, allowing the drillingline in or out The hoisting systems is composed by the derrick, the drawworks,and the block-tackle system

Figure 2.7: Stand of doubles along the mast.

2.2.1 The Derrick

The derrick or mast is a steel tower.1 The purpose of the derrick is to vide height to raise and lower the drillstring (and also casing) out and into theborehole

pro-Derricks are rated by the API according to their height and their ability towithstand wind and compressive loads API has published standards for theparticular specifications The higher the derrick is, the longer stands it canhandle, which in turn reduces the tripping time Derricks are designed to handletwo, three, or four joints

The derrick stands above the derrick floor The derrick floor is the stagewhere several surface drilling operations occur At the derrick floor are locatedthe drawworks, the driller’s console, the driller’s house (or “doghouse”), therotary table, the drilling fluid manifold, and several other tools to operate thedrillstring The space below the derrick floor is the substructure The height ofthe substructure should be enough to accommodate the well control equipment.(See Figure 2.1.) At about 3/4 of the height of the derrick is located a platformcalled “monkey board” This platform is used to operate the drillstring standsduring trip operations During drillstring trips, the stands are kept stood in in themast, held by “fingers” in the derrick rack near the monkey board, as shown inFigure 2.7

1 If the tower is jacked up, it is called mast If the tower is erected on the site, it is called derrick.

Figure 2.8: Onshore rig drawworks.

Figure 2.9: Brake belts and magnification linkage

2.2.2 The Drawworks

The drawworks provides hoisting and braking power required to handle theheavy equipments in the borehole It is is composed of a wire rope drum,mechanical and hydraulic brakes, the transmission, and the cathead (smallwinches operated by hand or remotely to provide hoisting and pulling power

to operate small loads and tools in the derrick area) Figure 2.8 shows a typicalonshore rig drawworks

The reeling–in of the drilling line is powered by an electric motor or Dieselengine, and the reeling–out is powered by gravity To control the reeling out,mechanical brakes and auxiliary hydraulic or magnetic brakes are used, whichdissipates the energy required to reduce the speed and/or stop the downwardmovement of the suspended equipment (See Figure 2.9.)

Figure 2.10: Drawworks schematics.

The drawworks take power from Diesel engines or electrical motors, and anassembly of gears and clutches reduces the rotary speed to power the drumand the various catheads A schematic of the internal mechanisms of a draw-works is shown in Figure 2.10 As shown in the schematics, the drum surfacehas a helical groove to accommodate the drilling line without causing excessivestress and stain This also helps the drilling line to lay neatly when reeled in

2.2.3 The Block & Tackle

The drawworks, although very powerful, cannot provide the pull required toraise the heavy drillstring The required pull is obtained with a system of pulleys.The drilling line coming from the drawworks, called fast line, goes over apulley system mounted at the top of the derrick, called the crown block, anddown to another pulley system called the traveling block The assembly ofcrown block, traveling block and drilling line is called block-tackle The number

of lines n of a tackle is twice the number of (active) pulleys in the traveling block.The last line of the tackle is called dead line and is anchored to the derrick floor,close to one of its legs Below and connected to the traveling block is a hook

to which drilling equipment can be hung As the drilling line is reeled in or out

of the drawworks, the traveling block rises and lowers along the derrick Thisraises and lowers the equipment in the well The block-tackle system provides

a mechanical advantage to the drawworks, and reduces the total load applied

to the derrick We will be interested in calculating the fast line force Ff (provided

by the drawworks) required to raise a weight W in the hook, and the total load

Figure 2.11: Forces acting in the block–tackle.

applied to the rig and its distribution on the derrick floor

2.2.3.1 Mechanical advantage and Efficiency

The mechanical advantage AM of the block–tackle is defined as the ratio of theload W in the hook to the tensile force on the fast line Ff:

AM = W

Ff .

For an ideal, frictionless system, the tension in the drilling line is the samethroughout the system, so that W = n Ff (See Figure 2.11.) Therefore, theideal mechanical advantage is equal to the number of lines strung through thetraveling block:

ef-F1 = ηFf

The force in the line over the second pulley (in the traveling block) is

W = η − η

n+1

1 − η Ff .Consequently, the real mechanical advantage is given by:

η − ηn+1

If the efficiency of the pulleys η is known, Block–tackle overall efficiency Ecan be calculated using Expression 2.1 A typical value for the efficiency ofball–bearing pulleys is η = 0.96 Table 2.2 shows the calculated and industryaverage overall efficiency for the usual number of lines

Table 2.2: Block–tackle efficiency ($\eta=0.96$)

2.2.3.2 Hook Power

For an ideal block–tackle system, the input power (provided by the drawworks)

is equal to the output or hook power (available to move the borehole ments) In this case, the power delivered by the drawworks is equal to the force

equip-in the fast lequip-ine Ff times the velocity of the fast line vf, and the power developed

at the hook is equal to the force in the hook W times the velocity of the travelingblock vb That is

Pd = Ff vf = W vb = Ph

Since for the ideal case n Ff = W, we have that

vb = vf

n ,that is, the velocity of the block is n times slower than the velocity of the fastline, and this is valid also for the real case Considering the Equation (2.2)

Example 2: A rig must hoist a load of 300,000 lbf The drawworks can vide a maximum input power to the block–tackle system of as 500 hp Eightlines are strung between the crown block and traveling block Calculate (1) thetension in the fast line when upward motion is impending, (2) the maximumhook horsepower, (3) the maximum hoisting speed

2.2.4 Load Applied to the Derrick

The total load applied to the derrick, FD is equal to the load in the hook plus theforce acting in the dead line plus the force acting in the fast line:

be anchored close to one of the remaining two legs.2

From this configuration the load in each leg is:

Leg B : W

4 ,Legs C and D : W

4 +

W2nE =

nE + 24nE W

2 The side of the derrick opposite to the drawworks is called V–gate This area must be kept free to allow pipe handling Therefore, the dead line cannot be anchored between legs A and B.

Figure 2.12: Derrick floor plan.

Evidently, the less loaded leg is leg B We can determine under which ditions the load in leg A is greater then the load in legs C and D:

con-n + 44n W >

nE + 24nE W → E > 0.5

Since the efficiency E is usually greater than 0.5, leg A will be the mostloaded leg, and very likely it will be the first to fail in the event of an excessiveload is applied to the hook If a derrick is designed to support a maximumnominal load Lmax, each leg can support L max

4 Therefore, the maximum hookload that the derrick can support for a given line arrangement is

Lmax

4 =

n + 44n Wmax → Wmax = n

n + 4Lmax .

The equivalent derrick load, FDE, is defined as four times the load in themost loaded leg For the derrick configuration above, the equivalent derrickload is

FDE = n + 4

n W The equivalent derrick load (which depends on the number of lines) must beless than the nominal capacity of the derrick

The derrick efficiency factor, ED is defined as the ratio of the total loadapplied to the derrick to the equivalent derrick load:

ED = FD

FDE =

(n+1)E+1

n E Wn+4

n W =

(n + 1)E + 1(n + 4)E .

Example 3: For the data of Example 2, calculate (1) the actual derrick load,(2) the equivalent derrick load, and (3) the derrick efficient factor.

FDE = n + 4

n W =

8 + 4

8 × 300, 000 = 450, 000 lbf(3) The derrick efficiency factor is

ED = FDFDE =

382, 000

450, 000 = 85%

2.3 Drilling Fluid Circulation System

The drilling fluid plays several functions in the drilling process The most tant are:

impor-1 clean the rock fragments from beneath the bit and carry them to surface,

2 exert sufficient hydrostatic pressure against the formation to prevent mation fluids from flowing into the well,

for-3 maintain stability of the borehole walls,

4 cool and lubricate the drillstring and bit

Drilling fluid is forced to circulate in the hole at various pressures and flow rates.Drilling fluid is stored in steel tanks located beside the rig Powerful pumpsforce the drilling fluid through surface high pressure connections to a set ofvalves called pump manifold, located at the derrick floor From the manifold,the fluid goes up the rig within a pipe called standpipe to approximately 1/3 ofthe height of the mast From there the drilling fluid flows through a flexible highpressure hose to the top of the drillstring The flexible hose allows the fluid toflow continuously as the drillstring moves up and down during normal drillingoperations

The fluid enters in the drillstring through a special piece of equipment calledswivel (Figure 2.13) located at the top of the kelly The swivel permits rotatingthe drillstring while the fluid is pumped through the drillstring.3 The drilling fluid

3 See Section 2.4.1 for details.

Figure 2.13: A swivel.

then flows down the rotating drillstring and jets out through nozzles in the drill bit

at the bottom of the hole The drilling fluid picks the rock cuttings generated bythe drill bit action on the formation The drilling fluid then flows up the boreholethrough the annular space between the rotating drillstring and borehole wall

At the top of the well (and above the tank level, the drilling fluid flows throughthe flow line to a series of screens called the shale shaker The shale shaker

is designed to separate the cuttings from the drilling mud Other devices arealso used to clean the drilling fluid before it flows back into the drilling fluid pits.Figure 2.14 depicts the process described above

The principal components of the mud circulation system are:

1 pits or tanks,

2 pumps,

3 flow line,

4 solids and contaminants removal equipment,

5 treatment and mixing equipment,

6 surface piping and valves,

7 the drillstring

The tanks (3 or 4 – settling tank, mixing tank(s), suction tank) are made ofsteel sheet They contain a safe excess (neither to big nor to small) of the