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Drilling Engineering 1 Course (2nd Ed.)

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http://bit.ly/Q922-DE1

1. Drilling Fluid Circulation SystemA. Mud Pumps (Duplex PDP & Triplex PDP)

B. Solids Control Equipmenta. Mud Cleaners

C. Treatment and Mixing Equipment

1. The Rotary SystemA. Introduction

B. Kelly, Kelly Valves, and Kelly Saver Sub

C. Rotary Table and Components

2. Well Control System

3. Well Monitoring System

Introduction

The rotary system is the set of equipment necessary to promote the rotation of 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 to transmit axial force, torque, and drilling fluid (hydraulic power) to the bit.

Spring14 H. AlamiNia Drilling Engineering 1 Course (2nd Ed.) 5

Drillstring components

The basic 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

to perform several tasks and to lend to the drillstring special features.


Swivel

The swivel is suspended by the hook of

the traveling block and allows the drillstring to rotate

as drilling fluid is pumped to within the drillstring.

supports the axial load of the drillstring.

Without the swivel, drilling fluid could not be

pumped downhole, or the drillstring could not

rotate.

A flexible hose connects to the gooseneck

which is hydraulically coupled to the top of the swivel stem by a stuffing box.

The stem shoulder rest on a large thrust tapered

roller bearing, which transmits the drillstring weight to the swivel body, and then to the bail.

The thread connector of the swivel is cut left–hand so that

it will not tend to disconnect when the drillstring is rotated by the kelly or by the top drive.


cuts of a swivel showing the internal parts


Sample of Tapered RollerBearings Thrust

kelly

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 called kelly.

The purpose of the kelly is to transmit rotary motion and torque to the drillstring (and consequently to the drill bit), while allowing the drillstring

to be lowered or raised during rotation.

The square or hexagonal section of the kelly allows it to be gripped and turned

by the kelly bushing and rotary table.


A square kelly and a hexagonal kelly

kelly bushing

Torque is transmitted to the kelly by the kelly bushing. The kelly bushing

has an inside profile matching the kelly’s

outside profile (either square or hexagonal),

but with slightly larger dimensions

so that the kelly can freely move up and down inside it.

The overall length of the kelly varies from 40 ft to 54 ft.

Kelly bushingsSpring14 H. AlamiNia Drilling Engineering 1 Course (2nd Ed.) 11

kelly valves

It is common (and advisable) to include two special valves at both ends of the kelly, called kelly valves. (The upper kelly valve has left–hand

threads.)

The kelly valve consists of a ball valve which allows free passage of drilling fluids without pressure loss. This is a safety device that

can be closed to prevent flow from inside the drillstring during critical operations like kick control.

It also isolates the drillstring from the surface equipment and allows disconnecting the kelly during critical operations.

A kelly valveSpring14 H. AlamiNia Drilling Engineering 1 Course (2nd Ed.) 12

kelly saver sub

A kelly saver sub is simply a short length pipe with has male threads on one end and female on the other. It is screwed onto the bottom of the lower kelly valve or

top drive and onto the rest of the drillstring.

When the hole must be deepened, and pipe added to the drillstring, the threads are unscrewed between the kelly saver sub

and the rest of the drillstring, as opposed to between the kelly valve or top drive and the saver sub.


kelly saver sub (Cont.)

This means that the connection between the kelly or top drive and the saver sub rarely is used, and suffers minimal wear and tear, whereas the lower connection is used in almost all cases and

suffers the most wear and tear.

The saver sub is expendable and does not represent a major investment. However, the kelly or top drive component threads

are spared by use of a saver sub, and those components represent a significant capital cost and considerable downtime when replaced.

It is important that both lower kelly valve and kelly saver sub be of the same diameter of the drill pipe tool-joints to allow stripping into the hole during control operations.


master bushing and master casing bushingThe kelly bushing fits in

the master bushing,which, in turn, attach to

the rotary table. It connects to the master

bushing either by pins of by a squared link.

The master bushing transmit torque and rotation from the rotary table to the kelly bushing.

A master casing bushing is used to handle casings.

Master bushings, and casing bushingSpring14 H. AlamiNia Drilling Engineering 1 Course (2nd Ed.) 16

Kelly bushing and master bushing

Figure shows a kelly bushing, master bushing, and rotary table assembly.


Drillpipe slip (detail when set in the master bushing)

The master bushing (and also the master casing bushing) has a tapered internal hole. The purpose of the tapered hole is to

receive the pipe slips. During pipe connection or

drillstring trip operations, this tapered hole receives either the drill pipe slips, or the drill collar slips, or the casing slips, which grips the tubular and frees the hook from its weight.

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

drill collar slips (mandatory!) If the drill collars slides in the slips,

the safety clamp works as a stop to force the slips to grip the drill collar.


DC slips, safety collar, casing slips and A rotary tableA drill collar slips (a),

a safety collar (b), and a casing slips (c) are shown in the Figure.

The rotary table receives power from the power system (either mechanical or

electric.)

A gearbox allows several combinations of torque and speed.


well control & kick

The functions of the well control system are to detect, stop, and remove any undesired

entrance of formation fluids into the borehole.

An undesired entrance of formation fluid into the borehole is called kick and may occur due to several reasons

(high pressure formations,

insufficient drilling fluid density,

drillstring swab,

loss of circulation,

formation fracture,

etc).


blowout

If the undesired entrance of fluid feedbacks and the fluid continuously enters the borehole reaching the surface, it is called blowout.

Blowouts (in particular gas blowouts) are extremely dangerous and put the crew, the rig, the drilling operation, and the reservoir at risk.


well control system constituent

The well control system must detect, control, and remove the undesired entrance of fluids into the borehole.

The system is composed of sensors (flow rate, surface volume, annular and

drillstring pressure, and etc,) capable to detect an increase of flow or volume in the fluid system,

the blowout preventer (BOP),

the circulating pressure control manifold (choke manifold),

and the kill and choke lines.


the blowout preventer (BOP)

The BOP is a set of pack–offs capable of shutting the annular space between the surface casing and the drillstring.

Because of the diversity in shape of the annular, several different device types exist and they are normally assembled together (and in various configurations) called BOP stack. 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.


BOP stacks

A fixed rig BOP A floating rig BOPSpring14 H. AlamiNia Drilling Engineering 1 Course (2nd Ed.) 26

Annular BOP’s

The various types of BOP devices are:Annular BOP, Blind ram, Pipe

rams, and Shear rams

Annular BOP: The purpose of the annular

BOP is to shut the annular in front of any kind of drillstring equipment (except stabilizers) or even without drillstring.

The active element is an elastomeric ribbed donut that is squeezed around the drillstring by an hydraulic ram.

It is located at the top of the BOP stack.


an inside BOP

Controlling the pressure applied to the ram, it is possible to strip the drillstring in and out while keeping the annular closed (requires the use of an inside-BOP, which should be connected immediately to the drillstring when a kick is identified).

The inside BOP acts as a check valve, allowing fluid be pumped down the drillstring, but blocking back flow.


Blind & Pipe rams

Blind ram: The blind rams (normally one at the top of all other rams)

allows shutting the borehole with no drillstring element in front of it. (the upper ram in the figure)

If the blind ram is applied to a drillpipe, the pipewill be flatten but no seal is obtained.

Pipe rams: The pipe rams allows shutting the annular

in front a compatible drill pipe (not in front of tool joints.) Normally two rams are used

a special spool between the two is used where the kill and choke line is connected. (the lower ram in the figure) The use of two pipe rams also

permit to snub the drillstring during the well control operation.


shear rams

Shear rams: The shear ram

(normally one below the blind ram or below all other rams) can shear a drill pipe and provide seal.

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 lower one, the drillstring falls into the borehole.


BOP control panels

All these safety devices are hydraulically actuated by a pneumatic–hydraulic

system (actuators and accumulators),

which can operate completely independent of the power system of the rig.

Two control panels are normally used, one at the rig floor, and a remote one away

from the risky area.

BOP accumulators and control panelsSpring14 H. AlamiNia Drilling Engineering 1 Course (2nd Ed.) 31

The accumulators

The accumulators are steel bottles lined with a elastomeric bladers forming two separated compartments. One compartment is filled with oil,

which powers the 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. Rig power, during ordinary operation,

keeps the gas in the accumulators under pressure. The accumulators should be able

to provide hydraulic power to close and open all elements of the BOP stack a number of times without external power.


Choke Manifold

During a kick control operation, some of the BOP stack devices are actuated to close the annulus and divert the returning fluid to the choke line. The choke line directs the returning fluid to a manifold

of valves and chokes called choke manifold, which allows to control the flow pressure

at the top of the annular adjusting the flow area open to flow.

The choke manifold also direct the flow • to a flare (in case of a gas kick), or

• to the pits (if mud) or

• to special tanks (if oil)


Choke manifold


data required to control of operations under way in the rigSeveral sensors, gauges,

meters, indicators, alarms, and recorders exist in the rig to provide all data required to control (safely, efficiently, and reliably) of all operations 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.


indication of hook load and weight on bitAccurate and reliable indication

of hook load and weight on bit are essential for the efficient control of rate of penetration, bit life, borehole

cleaning, and borehole direction.

The weight indicator works in conjunction with the deadline anchor

using either tension or compression hydraulic load cells.

The deadline anchor senses the tension in the deadline and hydraulically actuates the weight indicator.

Most weight indicators have two hands and two scales. The inner scale shows the hook load and

the outer one shows the weight-on–bit.


Weight indicator and a deadline anchor

Weight indicator a deadline anchorSpring14 H. AlamiNia Drilling Engineering 1 Course (2nd Ed.) 38

weight–on–bit

To obtain the weight–on–bit, the driller perform the following steps: with the bit out of the bottom,

the drillstring is put to rotate and the weight of the drillstring is observed in the central scale; using the knob at the rim of the weight indicator,

the outer scale is adjusted so that the zero of the outer scale aligns with the longer hand.

The driller lowers the drillstring slowly observing the long hand. When the bit touches the bottom, part of the weight of the

drillstring is transferred from the hook to the bit (the weight–on–bit.)

The amount of weight transferred corresponds to the decrease of hook load, indicated by the long pointer (turning counterclockwise).


control consoles

All modern rigs have control consoles that shows all pertinent parameters in analog and

or digital displays.

All parameters and operations may be recorded in physical (paper) or

magnetic media for post analysis.

Some automated operations like constant weight–on–bit and

constant torque are possible in most rigs.


Drilling control console


1. Jorge H.B. Sampaio Jr. “Drilling Engineering Fundamentals.” Master of Petroleum Engineering. Curtin University of Technology, 2007. Chapter 2

1. Drillstring TubularsA. Drill Pipes

a. properties of drill pipes

B. Drill Pipe Elevator

C. Drill Collars & Heavy Wall Drill Pipes

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