Drilling Eng Fundamentals

Curtin University of TechnologyDepartment of Petroleum Engineering

Master of Petroleum Well EngineeringDrilling Engineering Fundamentals

Chapter 1

Introduction

1.1 Objectives

The purpose of this text is to give students an introduction to the principles andsome recommended procedures practiced in drilling engineering. All chaptersin general contain a theoretical introduction, examples, and exercises. Refer-ences for further readings are given at the end of the text. Necessary equationsand procedures to solve the exercises are presented throughout the text.

1.2 General

When a drilling project is commenced, two goals govern its aspects. The firstis 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 completeit 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:

• Percussion drilling

– Cable drilling → “Pennsylvanian drilling”

– Drillstring

* With mud → Quick percussion drilling

CHAPTER 1Introduction to Drilling

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* Without mud → “Canadian drilling”

• Rotating drilling

– Full cross-section drilling

* Surface driven· Rotary bit· Rotary nozzle

* Subsurface driven· Turbine 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

– Explosive drilling

– Flame jet drilling

– Implosion drilling

– Laser drilling

– REAM drilling

– Replaceable cutterhead drilling

– Rocket exhaust drilling

– Spark drilling

– Subterrene drilling

– Terra drilling

– Thermal-mechanical drilling

– Thermocorer drilling

Throughout this text, rotary drilling technology is discussed exclusively.


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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.


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(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.


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(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


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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 invitedto 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 drilling 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 progressof the well.

Driller: The driller operates the drilling machinery on the rig floor and is theoverall 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 smallplatform up in the derrick, usually about 90 ft above the rotary table. Whena 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 thelower 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 helpis 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


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

1.5 Miscellaneous

According to a wells final depth, it can be classified into:

Shallow well: < 2000 mConventional well: 2 000 m – 3500 mDeep well: 3500 m – 5000 mUltra 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).


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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.

CHAPTER 2Rotary Drilling Systems

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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 trainingof 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 un-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.

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 special-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,


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Figure 2.2: A simplified drillstring.

based on the characteristics of the formations to be drilled, and the right pa-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, whichis 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 in-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.

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


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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 drillingis 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 operationis 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


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Figure 2.5: Removing one stand of drillstring.

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


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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 setsin 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 horse-power, torque, and fuel consumption for various engine speeds. These threeparameters are related by the efficiency of each system.

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)Diesel 19000 7.2

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


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1 cal = 4.1868 Joule = 4.1868 N m,

1 BTU = 252 cal.

Engines are normally rated by the power P they can deliver at a given work-ing regime. Power if defined as the rate work is performed, that is work per unitof time. If Q̇ is the rate of chemical energy consumed by the machine (chemicalenergy per unit of time), we can rewrite the expression for the thermal efficiencyas:

Et =P

Q̇.

To calculate Q̇ we need to know the type of fuel and the rate of fuel con-sumption in mass per unit time. (Consumption of gaseous fuels is normallygiven in mass per unit time, but consumption for liquid fuels is normally given involume per unit time. In the latter, we need to know the density of the fluid.)

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 performedin 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:

N [RPM]

(π rad/s

30 RPM

)T [ft lbf]

(1 hp

550 lbf ft/s

)= P [hp] .

that isP [hp] =

N [RPM] T [ft lbf]

5252.


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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 hp

Diesel is consumed at 31.5 gal/hr. From Table 2.1 we have:

Q̇ = 31.5gal

hr× 7.2

lbm

gal× 19000

BTU

lbm= 4, 309, 200 BTU/hr

Converting to hp, results in:

Q̇ = 4, 309, 200BTU

hr× 778.17 lbf ft

BTU× 1 hr

3600 s× 1 hp

550 lbf ft/s= 1693.6 hp

The thermal efficiency is:

Et =P

Q̇=

397.5

1693.6= 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),


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Figure 2.6: Typical hoisting system.

• draw works,

• fast line,

• crown block,

• traveling block,

• dead line,

• deal line anchor,

• storage reel,

• hook.

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


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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 pro-vide height to raise and lower the drillstring (and also casing) out and into theborehole.

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.

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


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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 powerto 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.)


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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 numberof 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 hookto which drilling equipment can be hung. As the drilling line is reeled in or outof the drawworks, the traveling block rises and lowers along the derrick. Thisraises and lowers the equipment in the well. The block-tackle system providesa mechanical advantage to the drawworks, and reduces the total load appliedto the derrick. We will be interested in calculating the fast line force Ff (providedby the drawworks) required to raise a weight W in the hook, and the total load


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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:

(AM)ideal = n .

In a real pulley, however, the tensile forces in the cable or rope in a pulleyare not identical. If Fi and Fo are the input and output tensile forces of the ropein the pulley, the efficiency η of a real pulley is given by the following ratio:

η =Fo

Fi

.

We will assume that all pulleys in the hoisting system have the same ef-ficiency, and we want to calculate the mechanical advantage of a real pulleysystem. If Ff is the force in the fast line, the force F1 in the line over the firstpulley (in the crown block) is given by

F1 = ηFf .


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

F2 = ηF1 = η2Ff .

Using the same reasoning over and over, the force in the ith line is

Fi = ηiFf .

The total load W acting in the hook is equal to the sum of the forces in eachline of the traveling block. This means that the load W is given by

W = F1 + F2 + · · ·+ Fn = (η + η2 + · · ·+ ηn)Ff .

It can be easily shown that the expression between parenthesis can be writ-ten as

η − ηn+1

1− η.

Therefore we have:

W =η − ηn+1

1− ηFf .

Consequently, the real mechanical advantage is given by:

AM =W

Ff

=η − ηn+1

1− η.

The overall efficiency E of the system of pulleys is defined as the ratio ofthe real mechanical advantage to the ideal mechanical advantage:

E =AM

(AM)ideal

=η − ηn+1

n(1− η). (2.1)

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 ($\eta=0.96$).n E Eave

6 0.869 0.8748 0.836 0.84110 0.804 0.81012 0.775 0.77016 0.746 0.740

Therefore, if E is known, the fast line force Ff required to rise a load W isgiven by

Ff =W

nE(2.2)


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232310B

Rectangle



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 equip-ments). In this case, the power delivered by the drawworks is equal to the forcein the fast line Ff times the velocity of the fast line vf , and the power developedat 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)

Ff =W

n E(2.3)

2.2

which represents the real relationship between the force in the fast line andthe weight in the hook, and multiplying both sides by vf we obtain:

Ff vf = Pd =W vf

n E=

W vb

E=

Ph

E,

Pd =Ph

E,

which represents the real relationship between the power delivered by the draw-works and the power available in the hook, where E is the overall efficiency ofthe block–tackle system.

Example 2: A rig must hoist a load of 300,000 lbf. The drawworks can pro-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.

Solution:

Using E = 0.841 (average efficiency for n = 8) we have:

(1) Ff =W

n E=

300, 000 lbf

8× 0.841→ Ff = 44, 590 lbf

(2) Pd = 500 hp =Ph

E=

Ph

0.841→ Ph = 421 hp


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(3) Ph = 421 hp

(550 lbf ft/s

1 hp

)= 231, 550 lbf ft/s = W vb = 300, 000 lbf × vb

vb =231, 550 lbf ft/s

300, 000 lbf→ vb = 0.772 ft/s = 46.3 ft/min

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:

FD = W + Ff + Fd .

The worst scenario for the force in the fast line is that for the real case. FromSection 2.2.3.1 the force in the fast line is:

Ff =W

n E(2.4)

2.2

For the dead line, however, the worst scenario (largest force) is that of idealcase. In this case, the force in the dead line is:

Fd =W

n.

Therefore, the total load applied to the derrick is:

FD = W +W

n E+

W

n=

(n + 1)E + 1

n EW .

The total load FD, however, is not evenly distributed over all legs of thederrick. In a conventional derrick, the drawworks is usually located betweentwo of the legs of the derrick. (See Figure 2.12.) The dead line, however mustbe anchored close to one of the remaining two legs.2

From this configuration the load in each leg is:

Leg A :W

4+

W

n=

n + 4

4nW ,

Leg B :W

4,

Legs C and D :W

4+

W

2nE=

nE + 2

4nEW .

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


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Figure 2.12: Derrick floor plan.

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

n + 4

4nW >

nE + 2

4nEW → 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 Lmax

4. Therefore, the maximum hook

load that the derrick can support for a given line arrangement is

Lmax

4=

n + 4

4nWmax → 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

nW .

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 EW

n+4n

W=

(n + 1)E + 1

(n + 4)E.


Page 2–17



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.

Solution:

(1) The actual derrick load is given by

FD =(n + 1)E + 1

n EW =

(8 + 1)× 0.841 + 1

8× 0.841× 300, 000 = 382, 000 lbf

(2) The equivalent derrick load is given by

FDE =n + 4

nW =

8 + 4

8× 300, 000 = 450, 000 lbf

(3) The derrick efficiency factor is

ED =FD

FDE

=382, 000

450, 000= 85%

2.3 Drilling Fluid Circulation System

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

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

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

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

3See Section 2.4.1 for details.


Page 2–18



Figure 2.13: A swivel.

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


Page 2–19



Figure 2.14: Rig circulation system.

total volume of the borehole. In the case of loss of circulation, this excess willprovide the well with drilling fluid while the corrective measures are taken. Thenumber of active tanks depends on the current depth of the hole (bypassesallow to isolate one or more tanks.) The tanks will allow enough retaining timeso that much of the solids brought from the hole can be removed from the fluid.

2.3.1 Mud Pumps

The great majority of the pumps used in drilling operations are reciprocat-ing positive displacement pumps (PDP). Advantages of the reciprocating PDPwhen compared to centrifugal pumps are:

• ability to pump fluids with high abrasive solids contents and with largesolid particles,

• easy to operate and maintain,

• sturdy and reliable,

• ability to operate in a wide range of pressure and flow rate.


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Centrifugal pumps are very sensitive to abrasive solid contents mud, and donot offer a wide range of operation compared to PDP.

PDP are composed of two major parts, namely:

Power end: receives power from engines and transform the rotating movementinto reciprocating movement.

Fluid end: converts the reciprocating power into pressure and flow rate.

The efficiency Em of the power end, that is the efficiency with which rotating me-chanical power is transformed in reciprocating mechanical power is of the orderof 90%. The efficiency Ev of the fluid end (also called volumetric efficiency),that is, the efficiency that the reciprocating mechanical power is transformedinto hydraulic power, can be as high as 100%.

Rigs normally have two or three PDPs. During drilling of shallow portions ofthe hole, when the diameter is large, the two PDPs are connected in parallel toprovide the highest flow rate necessary to clean the borehole. As the boreholedeepens, less flow rate and higher pressure are required. In this case, normallyonly one PDP is used while the other is in standby or in preventive maintenance.The great flexibility in the pressure and flow rate is obtained with the possibilityof changing the diameters of the pair piston–liner. The flow rate depends onthe following parameters:

• stroke length LS (normally fixed),

• liner diameter dL,

• rod diameter dR (for duplex PDP only),

• pump speed N (normally given in strokes/minute),

• volumetric efficiency EV of the pump.

In addition, the pump factor Fp is defined as the total volume displaced by thepump in one stroke.

There are two types of PDP: double-action duplex pump, and single-actiontriplex pump. Triplex PDPs, due to several advantages, (less bulky, less pres-sure fluctuation, cheaper to buy and to maintain, etc,) has taking place of theduplex PDPs in both onshore and offshore rigs.

2.3.1.1 Duplex PDP

The duplex mud pump consists of two double–action cylinders (see Figure 2.16-a). This means that drilling mud is pumped with the forward and backwardmovement of the barrel.


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(a) Piston scheme (double action). (b) A duplex unit.

Figure 2.15: Duplex pumps.

(a) Piston scheme (single action). (b) A Triplex unit.

Figure 2.16: Triplex pumps.

For a duplex pump (2 double–action cylinders) the pump factor is given by:

Fp =π

2

(2d2

L − d2R

)LS EV .

A typical duplex pump is shown in Figure 2.16-b.

2.3.1.2 Triplex PDP

The triplex mud pump consists of three single–action cylinders (see Figure ??-a). This means that drilling mud is pumped only in the forward movement of thebarrel.

For a triplex pump the pump factor is given by:

Fp =3π

4d2

L LS EV .

A typical triplex pump is shown in Figure ??-b.

2.3.1.3 Pump Flow Rate

For both types of PDP, the flow rate is calculated from:

q = N Fp .


Page 2–22



For N in strokes per minute (spm), dL, dR, and LS in inches, Fp in in3, and qin gallons per minute (gpm) we have:

q =1

231N Fp .

Note that in this particular formulation, the volumetric efficiency of the pump isincluded in the pump factor.

2.3.1.4 Pump Power

Pumps convert mechanical power into hydraulic power. From the definition ofpower we can write:

P = F v .

In its motion, the piston exerts a force on the fluid that is equal to the pressuredifferential in the piston ∆p times the area A of the piston, and the velocity v isequal to the flow rate q divided by the area A, that is

PH = (∆p A)q

A= ∆p q . (2.5)

For PH in hp, ∆p in psi, and q in gpm we have:

PH =∆p q

1714.29. (2.6)

Example 4: Compute the pump factor in gallons per stroke and in barrels perstroke for a triplex pump having 5.5 in liners and 16 in stroke length, with avolumetric efficiency of 90%. At N = 76spm, the pressure differential betweenthe input and the output of the pump is 2400 psi. Calculate the hydraulic powertransferred to the fluid, and the required mechanical power of the pump if Em is78%.

Solution:

The pump factor (triplex pump) in in3 per stroke is:

Fp =3π

4× 5.52 × 16× 90% = 1026 in3

Converting to gallons per stroke and to barrels per stroke gives:

Fp = 1026× 1

231= 4.44gps = 4.44× 1

42= 0.1058bps

The flow rate at N = 76spm is:

q = N Fp = 78spm× 4.44gps = 337.44gpm


Page 2–23



The hydraulic power transferred to the fluid is:

PH =2400psi× 334.44gpm

1714.29= 468hp

To calculate the mechanical power required by the pump we must considerthe efficiencies:

P = 468hp× 1

90%× 1

78%= 667hp

2.3.1.5 Surge Dampeners

Due to the reciprocating action of the PDPs, the output flow rate of the pumppresents a “pulsation” (caused by the changing speed of the pistons as theymove along the liners). This pulsation is detrimental to the surface and down-hole equipment (particularly with MWD pulse telemetry system). To decreasethe pulsation, surge dampeners are used at the output of each pump. A flexiblediaphragm creates a chamber filled with nitrogen at high pressure. The fluctu-ation of pressure is compensated by a change in the volume of the chamber.The schematic of a typical surge dampener is shown in Figure 2.17.

A relief valve located in the pump discharge line prevents line rupture incase the pump is started against a closed valve.

Figure 2.17: Surge dampener.


Page 2–24



2.3.2 Solids Control Equipment

The purpose of the solids control equipment is to reduce to a minimum theamount of inert solids and gases in the drilling fluid. They are:

1. Shale shakers,

2. Degassers,

3. Desanders (hydrocyclones),

4. Desilters (hydrocyclones),

5. Centrifuges,

6. Mud cleaners.

Figure 2.18 shows a sketch of a typical solids control system (for unweightedfluid). Fine particles of inactive solids are continuously added to the fluid dur-ing drilling. These solids increase the density of the fluid and also the frictionpressure drop, but do not contribute to the carrying capacity of the fluid. Theamount of inert solids must be kept as low as possible.

Figure 2.18: Solids control system.


Page 2–25



Figure 2.19: Shale shaker configurations.

Figure 2.20: A two–screen shale shaker.

2.3.2.1 Shale Shakers

The shale shaker removes the coarse solids (cuttings) generated during drilling.It is located at the end of the flow line. It constitutes of one or more vibratingscreens in the range of 10 to 150 mesh over which the mud passes before it isfed to the mud pits. (See Figure 2.19.)

The screens are vibrated by eccentric heavy cylinders connected to electricmotors. The vibration promotes an efficient separation without loss of fluid.Figure 2.20 shows a typical two–screen shale shaker.

2.3.2.2 Degassers

Gases that might enter the fluid must also be removed. Even when the fluid isoverbalanced, the gas contained in the rock cut by the bit will enter the fluid andmust be removed. The degasser removes gas from the gas cut fluid by creatinga vacuum in a vacuum chamber. The fluid flows down an inclined flat surfaceas a thin layer. The vacuum enlarges and coalesce the bubbles. Degassed


Page 2–26



Figure 2.21: A vacuum chamber degasser.

fluid is draw from chamber by a fluid jet located at the discharge line. A typicaldegasser diagram is shown in Figure 2.21.

2.3.2.3 Hydrocyclones (Desanders and Desilters)

Hydrocyclones are simple devices with no internal moving parts. The drillingfluid enters the device through a tangential opening in the cylindrical section,impelled by a centrifugal pump. The centrifugal force generated by the whirlingmotion pushes the solid particles towards the internal wall of the inverted cone.As the whirling flux moves downwards the rotating speed increased and thediameters decreases. The fluid free of solid particles is “squeezed” out of theflow and swirls upwards in a vortex motion, leaving the hydrocyclone from theupper exit. The solids leave the hydrocyclone from the apex of the cone (under-flow). For maximum efficiency, the discharge from the apex exit of hydrocycloneshould be in a spray in the shape of a hollow cone rather than a rope shape.Figure 2.22 shows the fluid/solids paths in a hydrocyclone.

Hydrocyclones are classified according to the size of the particles removedas desanders (cut point in the 40–45µm size range) or desilters (cut point inthe 10–20µm size range). At the cut point of a hydrocyclone 50% of the parti-cles of that size is discarded. The desander is a set of two or three 8in or 10inhydrocyclones, and are positioned after the shale shaker and the degasser (ifused). The desilter is a set of eight to twelve 4in or 5in hydrocyclones. It re-moves particles that can not be removed by the desander. Figures 2.23 showsa desander (a), and a desilter (b). Note the size and number of hydrocyclonesin each case.

A typical drilling solid particle distribution and particle size range classifica-tion are shown in the diagram in Figure 2.24.


Page 2–27



Figure 2.22: Flow path in a hydrocyclone.

(a) Desander. (b) Desilter.

Figure 2.23: Solid control equipment.


Page 2–28



Figure 2.24: Particle size classification.

2.3.2.4 Centrifuges

The centrifuge is a solids control equipment which separates particles evensmaller, which can not be removed by the hydrocyclones. It consists of a rotat-ing cone–shape drum, with a screw conveyor. (See Figure 2.25.) Drilling fluid isfed through the hollow conveyor. The drum rotates at a high speed and createsa centrifugal force that causes the heavier solids to decant. The screw rotatesin the same direction of the drum but at a slight slower speed, pushing the solidstoward the discharge line. The colloidal suspension exits the drum through theoverflow ports. The drums are enclosed in an external, non–rotating casing notshown in the figure.

2.3.2.5 Mud Cleaners

Inert solids in weighted fluid (drilling fluid with weight material like barite, ironoxide, etc) can not be treated with hydrocyclones alone because the particlesizes of the weighting material are within the operational range of desandersand desilters. 4 This is shown in the diagram in Figure 2.24, which includes theparticle size distribution of typical industrial barite used in drilling fluids.

A mud cleaner is a desilter unit in which the underflow is further processedby a fine vibrating screen, mounted directly under the cones. The mud cleanerseparates the low density inert solids (undesirable) from the high density weight-

4Weighting material are relatively expensive additives, which must be saved.


Page 2–29



Figure 2.25: Internal view of a centrifuge.

ing particles. (See Figure 2.26-a.)

Hydrocyclones discriminate light particles from heavy particles. Bentoniteare lighter than formation solids because they are of colloidal size (although ofthe same density). Barite particles are smaller than formation solids becausethey are denser.

The desilter removes the barite and the formation solids particles in the un-derflow, leaving only a clean mud with bentonite particles in a colloidal suspen-sion in the overflow. The thick slurry in the underflow goes to the fine screen,which separate the large (low density) particles (formation solids) from the small(high density) barite particles, thus conserving weighting agent and the liquidphase but at the same time returning many fine solids to the active system.The thick barite rich slurry is treated with dilution and mixed with the clean mud(colloidal bentonite). The resulting mud is treated to the right density and vis-cosity and re–circulates in the hole. A diagram of a mud cleaner is shown inFigure 2.26-b.

Mud cleaners are used mainly with oil– and synthetic–base fluids where theliquid discharge from the cone cannot be discharged, either for environmentalor economic reasons. It may also be used with weighted water–base fluids toconserve barite and the liquid phase.

2.3.3 Treatment and Mixing Equipment

Drilling fluid is usually a suspension of clay (sodium bentonite) in water. Higherdensity fluids can be obtained by adding finely granulated (fine sand to silt size– see Figure 2.24) barite (BaSO4). Various chemicals or additives are alsoused in different situations. The drilling fluid continuous phase is usually water(freshwater or brine) called water–base fluids. When the continuous phase isoil (emulsion of water in oil) it is called oil–base fluid. The basic drilling fluids


Page 2–30



(a) Unit of a mud cleaner (b) Principle of the mud cleaner.

Figure 2.26: Mud cleaner.

(a)

Figure 2.27: Mud agitator.

physical properties are density, viscosity, and filtrate. Fresh water density is8.37 pounds per gallon (ppg). Bentonite adds viscosity to the fluids and alsoincreases the density to about 9 to 10 ppg. Higher density (15 to 20 ppg) isobtained with barite, iron oxide, or any other dense fine ground material.

Water base fluids are normally made at the rig site (oil base mud and syn-thetic fluids are normally manufactured in a drilling fluid plant). Special treat-ment and mixing equipment exists for this purpose. Tank agitators, mud guns,mixing hoppers, and other equipment are used for these purposes.

Tank agitators or blenders (Figure 2.27-a) are located in the mud tanks tohomogenize the fluid in the tank. They help to keep the various suspendedmaterial homogeneously distributed in the tank by forcing toroidal and whirlmotions of the fluid in the tank. (See Figure 2.27-b.)

Mud guns are mounted in gimbals at the side of the tanks, which allow aim-


Page 2–31



Figure 2.28: Mud gun.

(a) (b)

Figure 2.29: Mud hopper.

ing a mud jet to any point in the tank. They help to homogenize the propertiesof two tanks, and spread liquid additives in a large area of the tank (from apre-mixed tank). (See Figure 2.28.) Centrifugal pumps power the mud guns.

The mixing hopper (see Figure 2.29) allows adding powder substances andadditives in the mud system. The hopper is connected to a Venturi pipe. Mudis circulated by centrifugal pumps and passes in the Venturi at high speed,sucking the substance into the system.


Page 2–32



2.4 The Rotary System

The rotary system is the set of equipments necessary to promote the rotationof the bit. The bit must be mechanically and hydraulically connected to the rig.This connection is made by the drillstring. The purpose of the drillstring is totransmit axial force, torque, and drilling fluid (hydraulic power) to the bit. Thebasic drillstring is composed of the following components:

• Swivel,

• Kelly and accessories,

• Rotary table and components,

• Drillstring tubulars (drill pipe, drill collars, etc.),

• Drill bit.

Several other components and equipment can be connected to the drillstring toperform several tasks and to lend to the drillstring special features.

2.4.1 Swivel

The swivel is suspended by the hook of the traveling block and allows the drill-string to rotate as drilling fluid is pumped to within the drillstring. Without theswivel, drilling fluid could not be pumped downhole, or the drillstring could notrotate. The swivel also supports the axial load of the drillstring. See Figure 2.30for cuts of a swivel showing the internal parts.

A flexible hose connects to the gooseneck which is hydraulically coupled tothe top of the swivel stem by a stuffing box. The stem shoulder rest on a largethrust tapered roller bearing, which transmits the drillstring weight to the swivelbody, and then to the bail. The thread connector of the swivel is cut left–handso that it will not tend to disconnect when the drillstring is rotated by the kelly orby the top drive.

2.4.2 Kelly, Kelly Valves, and Kelly Saver Sub

Below and connected to the swivel is a long four-sided (square) or six-sided(hexagon) steel bar with a hole drilled through the middle for a fluid path calledkelly. The purpose of the kelly is to transmit rotary motion and torque to thedrillstring (and consequently to the drill bit), while allowing the drillstring to belowered or raised during rotation. The square or hexagonal section of the kellyallows it to be gripped and turned by the kelly bushing and rotary table (seeSection 2.4.3). The kelly bushing has an inside profile matching the kelly’soutside profile (either square or hexagonal), but with slightly larger dimensions


Page 2–33



(a) Lateral cut. (b) Front cut.

Figure 2.30: Cut views of a swivel.

so that the kelly can freely move up and down inside it. The overall length ofthe kelly varies from 40 ft to 54 ft.

It is common (and advisable) to include two special valves at both ends ofthe kelly, called kelly valves. (The upper kelly valve has left–hand threads.) Thekelly valve consists of a ball valve which allows free passage of drilling fluidswithout pressure loss. This is a safety device that can be closed to preventflow from inside the drillstring during critical operations like kick control. It alsoisolates the drillstring from the surface equipment and allows disconnecting thekelly during critical operations.

A kelly saver sub is simply a short length pipe with has male threads onone end and female on the other. It is screwed onto the bottom of the lowerkelly valve or topdrive and onto the rest of the drillstring. When the hole mustbe deepened, and pipe added to the drillstring, the threads are unscrewed be-tween the kelly saver sub and the rest of the drillstring, as opposed to betweenthe kelly valve or topdrive and the saver sub. This means that the connectionbetween the kelly or topdrive and the saver sub rarely is used, and suffers min-imal wear and tear, whereas the lower connection is used in almost all casesand suffers the most wear and tear. The saver sub is expendable and doesnot represent a major investment. However, the kelly or topdrive componentthreads are spared by use of a saver sub, and those components represent asignificant capital cost and considerable downtime when replaced. It is impor-tant that both lower kelly valve and kelly saver sub be of the same diameter of


Page 2–34



Figure 2.31: A square kelly and a hexagonal kelly.

Figure 2.32: A kelly valve.


Page 2–35



the drill pipe tool-joints to allow stripping into the hole during control operations.

2.4.3 Rotary Table and Components

Torque and is transmitted to the kelly by the kelly bushing. The kelly bushinghas an inside profile matching the kelly’s outside profile (either square or hexag-onal), but with slightly larger dimensions so that the kelly can freely move upand down inside it (see Figure 2.33).

Figure 2.33: Kelly bushings.

Figure 2.34: Master bushings ([a] and [b]), and casing bushing (c).

The kelly bushing fits in the master bushing, which, in turn, attach to therotary table. It connects to the master bushing either by pins of by a squared


Page 2–36



Figure 2.35: Kelly bushing and master bushing.

link. A master casing bushing is used to handle casings. Figure 2.34 shows twomaster bushing and one master casing bushing. The master bushing transmittorque and rotation from the rotary table to the kelly bushing. Figure 2.35 showsa kelly bushing, master bushing, and rotary table assembly.

The master bushing (and also the master casing bushing) has a taperedinternal hole as shown in the schematics in Figure 2.36-a. The purpose ofthe tapered hole is to receive the pipe slips (see Figure 2.36-b). During pipeconnection or drillstring trip operations, this tapered hole receives either the drillpipe slips, or the drill collar slips, or the casing slips, which grips the tubular andfrees the hook from its weight.

Because of the slick shape of most drill collars, a safety clamp is always

(a) (b)

Figure 2.36: Drillpipe slip (detail when set in the master bushing).


Page 2–37



(a) (b) (c)

Figure 2.37: DC slips, safety collar, and casing slips.

Figure 2.38: A rotary table.

used above the drill collar slips (mandatory!) If the drill collars slides in theslips, the safety clamp works as a stop to force the slips to grip the drill collar.A drill collar slips, a safety collar, and a casing slips are shown in Figure 2.37.

The rotary table (Figure 2.38) receives power from the power system (eithermechanical or electric.) A gearbox allows several combinations of torque andspeed.

2.5 Well Control System

The functions of the well control system are to detect, stop, and remove anyundesired entrance of formation fluids into the borehole. An undesired entranceof formation fluid into the borehole is called kick and may occur due to several


Page 2–38



(a) A fixed rig BOP. (b) A floating rig BOP.

Figure 2.39: BOP stacks.

reasons (high pressure formations, insufficient drilling fluid density, drillstringswab, loss of circulation, formation fracture, etc). If the undesired entranceof fluid feedbacks and the fluid continuously enters the borehole reaching thesurface, it is called blowout. Blowouts (in particular gas blowouts) are extremelydangerous and put the crew, the rig, the drilling operation, and the reservoir atrisk.

The well control system must detect, control, and remove the undesiredentrance of fluids into the borehole. The system is composed of sensors (flowrate, surface volume, annular and drillstring pressure etc,) capable to detect anincrease of flow or volume in the fluid system, the blowout preventer (BOP), thecirculating pressure control manifold (choke manifold), and the kill and chokelines.

The BOP is a set of pack–offs capable of shutting the annular space be-tween the surface casing and the drillstring. Because of the diversity in shapeof the annular, several different device types exist and they are normally assem-bled together (and in various configurations) called BOP stack (see Figure 2.39.The BOP stack is located under the rotary table in land and fixed marine rigs,and on the bottom of the sea in mobile and floating rigs.

The various types of BOP devices are:

Annular BOP: The purpose of the annular BOP is to shut the annular in front ofany kind of drillstring equipment (except stabilizers) or even without drill-string. The active element is an elastomeric ribbed donut that is squeezedaround the drillstring by an hydraulic ram (see Figure 2.40-a and -b). It islocated at the top of the BOP stack. Controlling the pressure applied tothe ram, it is possible to strip the drillstring in and out while keeping the


Page 2–39



(a)

(b) (c)

Figure 2.40: Annular BOP’s (a and b) and an inside BOP (c)

annular closed (requires the use of an inside-BOP, shown in Figure 2.40-c, which should be connected immediately to the drillstring when a kick isidentified). The inside bop acts as a check valve, allowing fluid be pumpeddown the drillstring, but blocking back flow.

Blind ram: The blind rams (normally one at the top of all other rams) allowsshutting the borehole with no drillstring element in front of it. (See Fig-ure 2.41-a, upper ram.) If the blind ram is applied to a drillpipe, the pipewill but no seal is obtained.

Pipe rams: The pipe rams allows shutting the annular in front a compatibledrill pipe (not in front of tool joints.) Normally two rams are used (a special


Page 2–40



spool between the two is used where the kill and choke line is connected.(See Figure 2.41-a, lower ram.) The use of two pipe rams also permit tosnub the drillstring during the well control operation.

Shear rams: The shear ram (normally one below the blind ram or below allother rams) can shear a drill pipe and provide seal. (See Figure 2.41-b.) This is a last resource when all other rams and annular had failed.Circulation through the drillstring is lost and, if the shear ram is the lowerone, the drillstring falls into the borehole.

(a) (b)

Figure 2.41: BOP: (a) blind and pipe rams, (b) shear rams.

All these safety devices are hydraulically actuated by a pneumatic–hydraulicsystem (actuators and accumulators), which can operate completely indepen-dent of the power system of the rig. Two control panels are normally used, oneat the rig floor, and a remote one away from the risky area.

The accumulators are steel bottles lined with a elastomeric bladers formingtwo separated compartments. One compartment is filled with oil, which powersthe BOP. The other compartment is filled with air or nitrogen at high pressure.The pressure of the gas pressurizes the oil across the elastomeric liner. Rigpower, during ordinary operation, keeps the gas in the accumulators underpressure. The accumulators should be able to provide hydraulic power to closeand open all elements of the BOP stack a number of times without externalpower.

Choke Manifold

During a kick control operation, some of the BOP stack devices are actuated toclose the annulus and divert the the returning fluid to the choke line. The chokeline directs the returning fluid to a manifold of valves and chokes called chokemanifold, which allows to control the flow pressure at the top of the annularadjusting the flow area open to flow. The choke manifold also direct the flow toa flare (in case of a gas kick), or to the pits (if mud) or to special tanks (if oil).


Page 2–41



Figure 2.42: BOP accumulators and control panels.

Figure 2.43: Choke manifold.


Page 2–42



2.6 Well Monitoring System

Several sensors, gauges, meters, indicators, alarms, and recorders exist in therig to provide all data required to control (safely, efficiently, and reliably) of alloperations under way in the rig. Among the most important parameters are:

• weight on bit (WOB) and hook load,

• rate of penetration (ROP),

• rotary speed,

• torque,

• circulating (pump) pressure,

• flow rate (in and out),

• drilling fluid gain/loss,

• mud temperature,

• mud density,

• total hydrocarbon gas in the drilling fluid.

Accurate and reliable indication of hook load and weight on bit are essentialfor the efficient control of rate of penetration, bit life, borehole cleaning, andborehole direction.

The weight indicator works in conjunction with the deadline anchor usingeither tension or compression hydraulic load cells. The deadline anchor sensesthe tension in the deadline and hydraulically actuates the weight indicator. Mostweight indicators have two hands and two scales. The inner scale shows thehook load and the outer one shows the weight-on–bit.

To obtain the weight–on–bit, the driller perform the following steps: withthe bit out of the bottom, the drillstring is put to rotate and the weight of thedrillstring is observed in the central scale; using the knob at the rim of the weightindicator, the outer scale is adjusted so that the zero of the outer scale alignswith the longer hand. The driller lowers the drillstring slowly observing the longhand. When the bit touches the bottom, part of the weight of the drillstring istransferred from the hook to the bit (the weight–on–bit.) The amount of weighttransferred corresponds to the decrease of hook load, indicated by the longpointer (turning counterclockwise).

All modern rigs have control consoles that shows all pertinent parameters inanalog and or digital displays. All parameters and operations may be recordedin physical (paper) or magnetic media for post analysis. Some automated op-erations like constant weight–on–bit and constant torque are possible in mostrigs.


Page 2–43



(a) (b)

Figure 2.44: Weight indicator (a) and a deadline anchor (b).

Figure 2.45: Drilling control console.


Page 2–44



Chapter 3

Drillstring Tubulars and Equipment

The purpose of the drillstring is to transmit mechanical power (torque and rota-tion), hydraulic power (pressure and flow rate), and weight to the bit.

The drillstring is composed mainly of the following elements:

• Drill pipes,

• Heavy wall drill pipes,

• Drill collars,

• Several special elements and tools.

Figure 3.1 shows an schematic of a typical rotary drillstring.

3.1 Drill Pipes

Below the kelly assembly (upper kelly valve + kelly +lower kelly valve + kellysaver sub) is a length of drill pipes (DP). Drill Pipe is a primary and importantdrillstring member.

Since the drill pipes are generally compose the upper and longest portionof the drillstring, they must be light and strong.

The drill pipe body is a seamless pipe with outside diameter (OD) varyingfrom 23/8in to 65/8in. The outside diameter and the wall thickness t determinethe linear weight of the drill pipe. The inside diameter (ID) is equal to OD minus2t.

Drill pipes are made of high grade steel (there are also drill pipes made ofaluminum, carbon fiber, etc). API has standardized four steel grades: E–75,X–95, G–105, and S–135. The figures represent the minimum yield strengthYs (in ksi) of the the steel. Drill pipes are specified with the following basicparameters:

CHAPTER 3Drillstring Tubulars and Equipment

Page 3–1



Figure 3.1: Typical rotary drillstring.

1. Length range:

Range I: 18ft to 22ft,

Range II: 27ft to 30ft (most common),

Range III: 38ft to 45 ft,

2. Nominal linear weight: in general 2 or 3 linear weight or wall thickness foreach standard OD

3. Wall upset: EU (external upset), IU (internal upset), and IEU (internal &external upset). The wall upset is a length of extra thickness at both endsof the drill pipe body to provide a smooth transition between the pipe bodyand the tool joint, in order to reduce the stress concentration,

4. Tool joint OD, ID, and tong length,

5. Steel grade: (D-55), E-75, X-95, G-105, S-135,

6. Connection size and type: from 23/8in to 51/2in, type IF (internal flush), EF(external flush), FH (full hole), XH (extra hole), SH (slim hole), DS (doublestreamline), and NC (numbered connection),

The API RP-7G contains the specification of all API standard drill pipes ap-proved for oil and gas drilling use. The tool joints are heavy coupling elements


Page 3–2



having coarse, tapered threads and sealing shoulders designed to sustain theweight and to transmit torque along the drillstring. The threads of the tool jointsare specially designed to offer strength (axial and torsional), easy handling, fastconnections (number of turns to make the connection), and leak-proof sealing(metal to metal). Tool joints might be welded or screwed to the ends of the drillpipe body.

Figure 3.2: Typical tool joint designs. (A) Internal upset DP with full–holeshrink–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 DPwith Hydrill™–pressure welded TJ.

Two other common properties of drill pipes are capacity and displacement.

Pipe Capacity: The capacity Ap of a drill pipe is a measure of its internal area,expressed as volume/length, usually gal/ft or bbl/ft.1 If Di is the insidediameter (ID) of a drill pipe in inches, then

Ap =π

4D2

i [in2] =D2

i

24.51[gal/ft] =

D2i

1029.41[bbl/ft] .

Pipe Displacement: The displacement As of the drill pipe is the measure ofits cross-section area, expressed as volume/length, normally bbl/ft. If Do

1Sometimes the capacity is expressed as the reversal of the area, usually in ft/bbl. Thereader should be attended to the units.


Page 3–3



is the outside diameter (OD) of a drill pipe in inches, then

As =π

4

(D2

o −D2i

)[in2] =

D2o −D2

i

24.51[gal/ft] =

D2o −D2

i

1029.41[bbl/ft] .

Annulus Capacity: The annulus capacity Aa is not a property of the pipe be-cause it depends on the diameter of the hole opposite to the pipe. If DW

is the diameter of the well, the annulus capacity Aa in bbl/ft is given by:

Aa =π

4

(D2

W −D2o

)[in2] =

D2W −D2

o

24.51[gal/ft] =

D2W −D2

o

1029.41[bbl/ft] .

The capacity and displacement formulas above do not take into account thetool joints, and manufacturer tables must be consulted when more accuratevalues are required. In particular, the nominal weight that specify a given drillpipe represents neither the pipe body linear weight, nor the the average linearweight (body plus tool joint divided by its length). It is just a nominal value. Forexample, a typical 5in DP with 19.5 lb/ft has an internal diameter of 4.276in.The density of steel is 489.5 lb/ft3. Therefore, one foot op pipe body weights

π

4

(52 − 4.2762

)×(

1ft3

144in3

)× 489.5 lb/ft3 = 17.93 lb/ft .

Considering a 30 ft long DP (Range II), the tool joints (pin and box) compriseabout 21/2 ft of its length. Outside and inside diameters of the tool joints are 6inand 31/2 in respectively. Therefore, the linear weight of the tool joint is

π

4

(62 − 3.52

)×(

1 ft3

144 in3

)× 489.5 lb/ft3 = 63.41 lb/ft .

The weight of the drill pipe (body plus TJ) is

27.5 ft× 17.93 lb/ft + 2.5 ft× 63.41 lb/ft = 651.6 lbm .

Consequently, the adjusted linear weight of the drill pipe is

651.6 lb

30 ft= 21.72 lb/ft .

Drill pipes are subjected to wear during operation. In particular, reductionof tool joints OD and wall thickness reduce tensile and torsion capacity of theelement. Used drill pipes are classified as Premium or Class I if the minimumwall thickness is at least 80% of the wall thickness of a new pipe, and Class IIwhen at least 70%. A new pipe that for the first time is connected to a drillstringis immediately re–classified to premium DP. Table A.1 presents dimensionaldata for new drill pipes.


Page 3–4



Figure 3.3: A DP elevator and the links to the hook body.

3.1.1 Drill Pipe Elevator

Drill pipes are handled during tripping using a drill pipe elevator. (The swiveland kelly are set aside in the rat hole.) It is connected by two links to thehook body (See Figures 3.3 and 2.4) . A hinge and latch allows opening andclosing the bi–parted collar around the drill pipe. The elevator is operated bythe roughnecks at the rotary table level, and by the derrick man at the monkeyboard.

Drill pipes extend across almost the whole length of the drillstring and, al-though relatively light, they contribute with a significant part of the drillstringweight (50% or more). However, drill pipes are, in general, used only undertension. They should not be subjected to compression due to its low resistanceto buckling. Therefore, they cannot be used to apply weight on the bit. 2

3.2 Drill Collars

Since drill pipes cannot be used to apply weight on bit, this role is played bethe drill collars (and also by heavy weight drill pipes as shown next). Drill col-

2In horizontal wells, drill pipes can be put under compression if located in a suitably curvedsection of the hole; in addition, compression service drill pipes (CSDP, S-135 grade DP with 2 or3 wear knots) are specially designed to work under compression to drill short radius horizontalwells.


Page 3–5



lars (DC) are thick walled steel pipes located normally right above the bit, andtheir purpose is to provide weight (axial force) to the bit. Drill collars are man-ufactured with carbon steel (AISI 4115), or some non-magnetic alloy (stainlesssteel, monel metal). The outside of drill collars may be slick (small diameters)or spiral grooved (any size.). Figure 3.4 shows a spiraled and a slick drill col-lars. The purpose of the groves is to reduce or avoid the risk of differentialsticking opposite to permeable formations . The depth of the grooves is madelarger than the average thickness of a flocculated mud cake (see Figure 3.5).Average length of drill collars is 34 ft, but re–threading normally makes themshorter.

Figure 3.4: A spiraled and a slick drill collars.

Figure 3.5: Spiraled DC cross–section. Figure 3.6: A DC elevator.

The elevators for drill collars are very similar to the elevators for drill pipes.They differ in the shape of the internal hole that clamps on the pipe. Most drillcollars are recessed so as to be handled with the elevator. If the drill collar isnot recessed (sometimes even if it is!), a special sub called lift sub is used. Liftsubs have the shape of the upper end of a drill pipe, and connects to the top ofsections of drill collars during trips. Then the drill pipe elevator can be used tolift or lower the drillstring.

3.3 Heavy Wall Drill Pipes

In addition to drill pipes and drill collars, there are special pipes called heavywall drill pipes (HWDP). They are intermediary pipes between drill pipes anddrill collars, being strong enough to be put under compression (they contribute


Page 3–6



to the available weight to apply to the bit), and they are flexible enough to beused in directional drilling (less torque and drag than drill collars.) The useof HWDP also allow a gradual transition between the flexible drill pipes andthe stiff drill collars (less stress concentration, and therefore, less mechanicalfatigue on the threads.)

HWDPs look very similar to regular drill pipes, being of the same length ofRange II DP (27 to 30 ft), but with longer tool joints (to permit re–threading).HWDPs have a central external upset as shown in Figure 3.8. This centralupset provides an additional third point of contact, increasing the overall stiff-ness and protecting the pipe sections from excessive wearing in high inclinationwells (normally the tool joints and central upset have a band of hard material toprevent/reduce wear).

Figure 3.8: Heavy wall drill pipes.

3.4 Special Tools

Several drilling equipment are used in the drillstring. The most important are:

• stabilizers,

• reamers,

• hole–openers.

3.4.1 Stabilizers

Stabilizers provide localized additional support points (localized larger diame-ter) in one or more positions along the drillstring. For vertical wells, the stabilizerprevents low frequency vibration in the drillstring during rotation. The advan-tages are:

• reduce wear (of both drillstring and casing),

• reduce mechanical fatigue,

• reduce mechanical instability of formation (caving),

• reduce tortuous hole.


Page 3–7



Stabilizers are essential equipment for directional drilling. Suitable choice ofnumber and position of stabilizers in the drillstring lend to the bottom hole as-sembly (BHA, the lower part of the drillstring composed of drill collars, stabiliz-ers and HWDP) special characteristics in terms of inclination control:

• angle build–up,

• angle drop–off,

• angle hold.

Stabilizer may be of the following types:

• integral blade,

• interchangeable blade,

• non–rotating blades,

• replaceable blades,

• clamp–on

• near-bit,

The diameter of stabilizers can be in gauge or under gauge. More recently,remote adjustable blade stabilizers were introduced. Changing suitably the di-ameter of the stabilizers provide a level of control in the directional behavior ofBHAs.

(a) (b) (c) (d)

Figure 3.9: Some Stabilizers: (a) integral, (b) interchangeable, (c) non–rotating,(d) replaceable.


Page 3–8



3.4.2 Reamers

The purpose of the reamer is to keep the diameter of the open hole in gauge,that is, with the expected original diameter of the bit. Two reasons may causea decrease in the original diameter:

1. formation swelling (hydrated shales, moving salt),

2. bit diameter reduction (hard and abrasive formations).

The reamer also functions as a stabilizer since the rollers touch the boreholewall. Different types of rollers can be selected to suit the formations beingreamed. (See Figure 3.10.)

Figure 3.10: A roller reamer. Figure 3.11: A fixed hole–opener.

3.4.3 Hole–openers

The hole–opener is a tool designed to enlarge the diameter of a previously (orsimultaneously drilled smaller borehole. Three situations (at least) are possible:(See Figure 3.11.)

1. to drill the borehole section with a smaller bit, and later to enlarge to thefinal diameter (a special tool called bull nose is connected in the place ofthe bit, to guide the hole opener along the pre-drilled hole),

2. to drill the borehole section with a smaller bit and simultaneously enlargeto the final diameter,


Page 3–9



3. to enlarge a section below a casing with a diameter larger than the internaldiameter of the casing. In this case, a special hole opener (also callerunderreamer) with hinged arms actuated hydraulically is used (the drillingfluid pressure actuates in rams that open the arms forcing the cuttersagainst the borehole wall).

3.5 Connections Make–up and Break–out

To make–up and break–out the pipe connections (during normal operationsand drillstring trips), big self–locking wrenches called manual tongs are usedto grip the drillstring and apply torque. The tongs are kept suspended at suit-able height above the rotary table (3 to 5ft) balanced by counter–weights. Theywork in pairs, one turns to left (counterclockwise) and the other to right (clock-wise). They are mechanically or pneimatically actuated by the cathead (specialrotating spools connected to the drawworks). (See Figure 3.12).

(a) Left tongue (break-out). (b) Right tong (make–up).

Figure 3.12: Manual tongs.

To make–up a connection, the left tong grips the upper tool joint joint (box)of the lower pipe, and the right tong grips the lower tool joint (pin) of the upperpipe. The left tong is connected by a steel rope to a fixed point in the derrick,and the right tong is connected to the cathead (turns the upper pipe). To breaka connection, the left tong grips the lower tool joint (pin) of the upper pipe, andthe right tong grips the upper tool joint (box) of the lower pipe. The right tongis connected by a steel rope to a fixed point in the derrick, and the left tong isconnected to the cathead (also turns the upper pipe). Figure 3.13 shows thetongs ready to make–up a connection.


Page 3–10



Figure 3.13: Tongs in position to make–up a connection.

When set and ready to apply torque, the angle between the arms of thetongs should be either 90◦ or 180◦ (the ideal is zero degrees but operationaldifficulties make this position not practical). It is important to leave the rotarytable unlocked, to avoid damage to the pipe caused by the slips.

Compressed air tongs or spinners (see Figure 3.14) are also used to speed–up the operation, but the torque to make–up or to break–out the connection isalways done using the manual tongs.

3.5.1 Maximum Height of Tool Joint Shoulders

To make–up or break–out a connection, the drillstring must be resting on themaster bushing using the slips (DP and HWDP) or slips+safety clamp (DC andany other slick equipment.) The angle between the arms of the tongs are either90◦ or 180◦ as shown in Figure 3.16.

The maximum height of the tool joint shoulder with respect to the masterbushing is given by the following formulas:

Case 1: 90◦

Hmax[ft] = 0.053YminLT S

Tmu


Page 3–11



Figure 3.14: A spinner.

Figure 3.15: Tongs position during make–up.

Figure 3.16:

Case 1: 180◦

Hmax[ft] = 0.038YminLT S

Tmu

where: Ymin = minimum yield stress of the pipe [psi]LT = tong’s arm length [ft]

S = Ic

=π(D4

o−D4i )

32Do= section modulus [in3]

Tmu = make up torque [ft lbf]


Page 3–12



Example 5: Calculate maximum height of the tool joint shoulder for a 5 in ODDP, 19.5 lb/ft, X-95, with NC50 65/8 in – 31

2 in new tool joint, using tongs with31/2 ft positioned at 90◦ and 180◦.

Solution:Ymin = 95 kpsi = 95, 000psi

LT = 3.5 ft

S =π (54 − 4.2764)

32× 5= 5.71 in3

Tmu = 27, 076 ft · lbf

a) 90◦:

Hmax = 0.05395, 000× 3.5× 5.71

27, 076= 3.72 ft

b) 180◦:

Hmax = 0.03895, 000× 3.5× 5.71

27, 076= 2.76 ft

3.5.2 Make–up Torque

It is very important to apply the right torque during the make–up of a connec-tion. Too little torque will not provide a suitable seal between the pin and boxshoulders, and leakage might wash out the threads causing failure of the con-nection. Too much torque may cause mechanical failure of the threads, eitherin the box or in the pin. The API RP7G tables present the maximum (tb.9) andminimum (tb.10) torques for each standard connection.

3.6 Drill Bit

The bit is connected to the lower end of the drill collars. Bits are manufacturedwith a pin, so that to connect to the lower pin of the drillstring, a bit sub is used.The bit sub is a short sub (11/2 to 2 ft) with two box connections.

There are a large variety of bits. Each type is designed to drill rocks ofdifferent hardness, composition, abrasiveness, etc, encountered during drillingoperations. It is a duty of the drilling engineer to select the most appropriatebit and the drilling parameters (nozzle sizes, weight-on-bit, rotation speed, andflow rate) to optimize the performance of the operation. A more detailed studyof drill bits is covered in Chapter 10.


Page 3–13



3.7 Other Drillstring Equipment

In addition to the kelly–rotary table assembly, two other methods can be usedto promote rotation to the bit:

• Top drive,

• Bottom hole motors (positive displacement motors and turbines).

3.7.1 Top Drive

The top drive, also called power swivel, takes the place of the kelly, and thetorque is applied to the top of the drill pipe section by mean of hydraulic orelectric motors. The assembly slides along tracks (most models incorporatea swivel in the design,) and is suspended by the hook. The reactive torque istransmitted to the rig structure directly through the tracks or by a torque reactionbeam.

Figure 3.17: An electrical top drive.

A great advantage of using a top drive is the possibility to drill a full stand(3 or 4 drill pipes) without interruption, saving time in connections. Anotheradvantage is the possibility of rotating the drillstring during the trips reducingthe drag to pull–out or slack–off the drillstring in the hole for high inclinationdrilling.


Page 3–14



3.7.2 Bottom Hole Motors

Bottom hole motors are special engines located above the bit to promote bitrotation. Bottom hole motors convert hydraulic power of the drilling fluid (P =q ∆p) into mechanical (rotational) power.

Turbines use fluid momentum conversion on the blades of stator/rotor togenerate rotation and torque. Turbines operates in high speed and has a narrowrange of operation. The torque decreases steadily from the maximum at 0 rpm(stalled) to zero at the maximum speed.

Figure 3.18: A bottom hole turbine.

Positive displacement motors (PDM) use continuous displacement of con-stant volume compartments created between an elastomer stator and a steelrotor to generate rotation and torque. The rotation speed of a PDM is functionof the flow rate, and the torque is directed related to the pressure differentialacross the motor (easily monitored from the surface). The use of bottom holemotors is essential for directional drilling. The use of bent sub or bent housingprovides a good deal of control of the inclination and the azimuth, allowing todrill complex trajectories.

Figure 3.19: A bottom hole PDM.


Page 3–15



Appendix A

Drill Pipe Dimensions (as in APIRP7C)

CHAPTER ADrill Pipe Dimensions

Page A–1



Table A.1: New Drill Pipe Dimensional Data(1) (2) (3) (4) (5) (6) (7)Size Nominal Weight Section Area Polar SectionalOD Threads and Plain end Wall ID Body of Pipe Modulusin. Couplings, Weight Thickness in. sq. in. cu. in.D lb/ft lb/ft in. d A Z23

84.85 4.43 0.190 1.995 1.3042 1.3216.65 6.26 0.280 1.815 1.8429 1.733

278

6.85 6.16 0.217 2.441 1.8120 2.24110.40 9.72 0.362 2.151 2.8579 3.204

312

9.50 8.81 0.254 2.992 2.5902 3.92313.30 12.31 0.368 2.764 3.6209 5.14415.50 14.63 0.449 2.602 4.3037 5.847

4 11.85 10.46 0.262 3.476 3.0767 5.40014.00 12.93 0.330 3.340 3.8048 6.45815.70 14.69 0.380 3.240 4.3216 7.157

412

13.75 12.24 0.271 3.958 3.6004 7.18416.60 14.98 0.337 3.826 4.4074 8.54320.00 18.69 0.430 3.640 5.4981 10.23222.82 21.36 0.500 3.500 6.2832 11.345

5 16.25 14.87 0.296 4.408 4.3743 9.71819.50 17.93 0.362 4.276 5.2746 11.41525.60 24.03 0.500 4.000 7.0686 14.491

512

19.20 16.87 0.304 4.892 4.9624 12.22121.90 19.81 0.361 4.778 5.8282 14.06224.70 22.54 0.415 4.670 6.6296 15.688

658

25.20 22.19 0.330 5.965 6.5262 19.57227.70 24.22 0.362 5.901 7.1227 21.156


Page A–2



Table A.2: New Drill Pipe Torsional and Tensile Data. Courtesy API


Page A–3



Table A.3: New Drill Pipe Collapse and Internal Pressure Data. Courtesy API


Page A–4



Table A.4: Premium Drill Pipe Torsional and Tensile Data. Courtesy API


Page A–5



Table A.5: Premium Drill Pipe Collapse and Internal Pressure Data. CourtesyAPI


Page A–6

Documents

Drilling Eng Fundamentals