FOREWORD

Artificial Lift Training Manual was first brought out in June, 1996 in

response to demand for a comprehensive manual for the use of

production engineers handling different modes of Artificial Lift in

different fields of ONGC. This Artificial Lift Training Manual is

second edition of that.

In the dynamic oil and gas production industry, where

technological improvements and innovative ideas are constantly

applied, it was felt that updating of the original manual was

essential. Once the project of writing this second edition was

initiated, it was realised that there have been so much

improvements and changes in the technology that entire manual

needed rewriting. Accordingly, complete manual has been revised

and rewritten with up- to-date technological information and

thereafter, editing is done so as to make it easily comprehensible

by field engineers.

The opening chapter provides the introductory discussion and

inflow performance behaviour of wells. The other chapters deal

with “Multiphase Flow”, “Sucker Rod Pump”, “Gas Lift”,

“Electrical Submersible Pump”, “Jet pump”, “selection Criteria

For Artificial Lift Method” and “Nodal Analysis Of Oil Well”. The

Nodal Analysis part as a separate chapter is the new addition to

this manual.

The foundation of this manual is the rich experience of our

engineers in Artificial Lift design, installation, operation and

trouble shooting in various fields of ONGC. References have

however been taken from various literatures authored by eminent

personalities in this area, reputed universities and companies. API

literatures and guidelines, which have always proved to be very

useful, have also been referred.

An effort has been made for lucid elaboration of various Artificial

Lift modes prevalent in ONGC. Fairly extensive reorganization of

subject matters has been done and additional materials have been

added to make it more field-oriented and user friendly. The manual

has taken its present shape after it had gone through numerous

drafts with the required illustrative examples along with many

drawings that were either modified or redrafted.

H is sincerely hoped that this new edition of manual will be very

helpful to all production engineers and particularly those dealing

with Artificial Lift operation.

G.M. (IOGPT)
 ACKNOWLEDGEMENT

We are grateful to the sources that generously permitted the use of

illustrative materials from their respective publications and endeavour has been
made at each such instant to give due credit. So, in this respect we express our
gratitude to M/s Parveen Industries and M/s S.K. Oil field Equipt. Co. Pvt. Ltd.

We also express the sense of gratitude for the valuable suggestions drawn
from personalities Dr. K. V. V.S. N. Murthy, Dr. R.H. Gault, Mr. Paul Idd at different
times.

We are thankful to Sh. A. T. Patil, for assisting in preparation of manual along

with some drawings in power point.

Authors
 CONTENTS

Chapter Title Page No.

no.
= c
1. Inflow Performance 1.1 - 1.22

2. Multiphase Flow 2.1 - 2.35

3. Sucker Rod Pump 3.1 - 3.92

4. Gas Lift 4.1 - 4.81

5. Electrical Submersible Pump 5.1 - 5.70

6. Jet Pump 6.1 - 6.20

7. Selection Criteria for Artificial Lift 7.1 - 7.5

Methods

8. I Nodal Analysis of Oil Well 8.1 - 8.16

I
 Chapter 1

INFLOW PERFORMANCE

1.0 INTRODUCTION

[n the extraordinary process of formation of oil and gas deep under the earth
crust, followed by their migration and accumulation as oil and gas reserve, a great
amount of energy is stored in them. This energy is in the form of dissolved gas in
oil, pressure of free gas, water and overburden pressure. When a well is drilled
to tap the oil and gas to the surface, it is a general phenomenon that oil and gas
comes to the surface vigorously by virtue of the energy stored in them. Over the
years/months of production, the decline of energy takes place and at one point of
time, the existing energy is found insufficient to lift the adequate quantity of oil to
the surface, From that time onwards, man made effort is required and this is
what is known as artificial lift. In otherwords artificial lift is a supplement to natural
energy for lifting well fluid to the surface.

Therefore, the flow of oil from the reservoir to the surface can be fundamentally
dichotomized as self flow period and artificial lift period.

1.1 DEFINITION OF ARTIFICIAL LIFT

When a self flowing oil well ceases to flow or is not able to deliver the required
quantity to the suiface, the additional energy is supplemented either by
mechanical means or by injecting compressed gas.

1.1
Let us consider a well which can deliver the required quantity of oil to a certain
height in the well, say 500 meters from the surface, subsequently artificial liil
methods/equipments help to lift the required quantity from 500 meters upto the surface.

1.2 PURPOSE OF ARTIFICIAL LIFT

The purpose of artificial lift is to create a steady low pressure or reduced pressure
in the well bore against the sand face, so as to allow the well fluid to come into
the well bore continuously. In this process, a steady stream of production to
surface would result.

In other words, maintaining a required and steady low pressure against the sand
face, which we call steady flowing bottom hole pressure, is the fundamental basis
for the design of any artificial lift installation.

1.3 PATH-SECTORS INFLUENCING THE DESIGN OF ARTIFICIAL LIFT

SYSTEM

Broadly four main sectors influence (Refer 17g.1.f ) the design and
analysis of artificial lift system. The first ‘and second is the reservoir
component from the periphery of drainage area to around the wellbore
and then from around the well bore to the wellbore which represent the
wells ability to give up fluids into the well bore. The third component of
flow path is the entire tubing in the vertical/inclined/horizontal path which

include all systems like, downhole artificial lift equipment, sub-surface

safety valves, non return valves etc. The fourth component includes the
sutface flow path which consists of length and diameter of flowline,
valves, bends, wellhead, chokes, manifold, separator etc.

1,2
 Any change in the relevant parameters in any of the four sectors,
influences the parameters of other sectors. The required changes of
parameters should be made till the flow gets steady. The individual
sectors of flow-path area have been discussed as under.

1.4 FLOW THROUGH POROUS MEDIUM AROUND THE WELL BORE

No definite shape of flow conduit can be conceptualised in this sector of flow through
porous medium. So, it is largely an area of concern for determining the flow
parameters. In order to understand this, the fundamental concept of Reservoir
engineering which includes reservoir drive mechanism and P.I. (Productivity Index)
of individual wells are dealt.. The productivity index is the measure of the ability of
well to produce fluid into the wellbore. Mathematically, it can be expressed as :-

Q a, (P, - PWI)

Where: Q = Total quantity of fluid

Pr = Reservoir pressure

Pti = Flowing bottomhole pressure in the wellbore against

sand face

Therefore, Q = Constant x (P, - Pti )

This constant is the productivity index (Pi) of the well and is generally
abbreviated as “J”. In other words,

Q
J=
P, - PM

In fact, J is not a constant value but it varies with the type of reservoir,
type of drive mechanism, production rate, time of production, cumulative
production, perforation density, skin, sand bridging, gas coning, infill
wells on production etc.

1,3
 In order to define P.1 more correctly, the concept of inflow performance
relationship (IPR) is introduced to define the liquid inflow in the wellbore.
H is basically a straight line or a curve drawn in the two-dimensional
plane, where X - axis is q, the flow rate and Y-axis is Pwf, flowing bottom
hole pressure (Refer /%g. 1.2). Therefore, the concept that J is always a
constant is not correct. PI here can be described as just a point on IPR
curve. The following are some of the typical IPRs being mainly
influenced by different reservoir drive mechanisms.

1.4.1 IPR IN CASE OF ACTIVE WATER DRIVE (Refer Fig. 7.3)

Out of all types of reservoir drives, water drive is regarded as the strongest.
However, the intensity differs in different types of water drive reservoirs. Some
are moderately weak and some are strong, like edge water drive is weaker than
bottom water drive. In bottom water drive, when the oil pool is underlain with a
large aquifer of dynamic source, reservoir pressure is generally not mellowed at
all with the advancing years of production- that is, the reservoir pressure
practically remains constant and is not influenced by cumulative production. In
this case, the IPR curve will simply be a straight line i.e. the IPR curve will provide
oniy one value of P!.

1.4.2 IPR IN CASE OF SOLUTION GAS DRIVE (Refer Fig. 1.4)

This type of drive is also called as internal gas drive or depletion drive. This is the
least effective drive mechanism. If excessive draw-down is created, it results in
increase of permeability to gas and correspondingly decrease of permeability to
liquid, thereby, ability of well to deliver liquids is greatly reduced. Generally, the
reservoir pressure for this type of reservoir declines at a very fast rate and
accordingly it influences the pattern of I PR curve (Refer Fig. 1.5).

1.4.3 IPR IN CASE OF GAS CAP EXPANSION DRIVE (Refer Fig.1 .6)

1.4
This drive mechanism is also called segregation drive because of the state of
segregation of oil zone from gas zone, where oil zone is overlain by gas zone
called gas cap. Also, as production continues, the gas cap swells and because of
this the drive is also known as gas cap expansion drive. This type of reservoir

drive mechanism is more effective than solution gas drive and less effective than
water drive. Therefore, the profile of IPR curve for gas cap expansion drive lies
somewhere in between those for solution gas drive and water drive.

1.4.4 IPR -WHEN P,> BUBBLE POINT PRESSURE

(SATURATION PRESSURE) (Refer /7g.l .7)

Upto a point B in the profile, AB is a straight line representing constant Pt.

At B, the gas separation starts in the reservoir. With more drawdown i.e.
by further dropping-in of bottomhole pressure, more and more gas will
come out and this affects the flow of liquid due to generation of more gas
around the wellbore .

1.4.5 CHANGE OF PI WITH CUMULATIVE RECOVERY

(PERCENTAGE OF ORIGINAL OIL IN PLACE) WITH TIME

The pattern of IPR curves with cumulative recovery, that is percentage of oil in
place can be best described when a reservoir is allowed to produce over the
years without any pressure maintenance either with the help of water injection or
gas injection which results in continuous decrease of reservoir pressure.

A series of IPR curves with time are obtained where reservoir pressure indicates
a downward trend (Refer Fig. 1.8). The successive IPRs tend to approach the
origin (0,0) of the producing rate - pressure axis. This type of IPR curves trend
indicate that the reservoir is attaining fast the state of senescence, as such,
reservoir pressure has overbearing effect on the inflow of liquid in the wellbore .

1.5 VOGEL’S WORK ON ]PR

1.5
A publication by Vogel in 1968 offered an extra ordinary solution in determining the
Inflow Performance Curve for a solution gas drive reservoir for flow below the
bubble point or gas cap drive reservoir or any other types of reservoir having
reservoir pressure below bubble point pressure. Vogel’s performance curve is
generated in the following manner.

From general 1PR equation i.e

J= ‘0 ... ... ... ........(1)

P, - PM

When Pti is zero, the q. become maximum and is denoted as q~a..

q max.
Then J =
P,-o

q max.
or J= ...... ... ...... .....(2)
P,

Dividing equation (1) by (2)

J qo Pr
= x—
T P, – Pti q max
qo P, - Pw
or =
q max P,

qo P, P~
or = —— —
q max Pr Pr

qo PM
or ---------- = 1- -------, It is a straight line form of equation.
q max Pr

Since IPR curve below bubble point is not a straight line, he created a parabolic
equation from the above.

He distributed Pw in the following manner

{–} P,

20%0f{~}&80%0f{+}2
1.6
Therefore, the new equation is established as :-

{+}-0”8{+2
==’”0”2
This is known as Vogel’s equation.

He then plotted dimensioniess IPRs in two dimensional plane

qo PM
Where X - axis represents — and Y - axis represents — both are
q max br

Dimensionless quantity )

qo PM
The minimum and maximum values of — and — in each case is O and
q max P,

PM , Clo PM qo
1.0. When, ----- = ------ = O and when, ----- = 0, ------- = 1.
P, ‘ qrna~ P, qmax
(Refer Fig. 7.9).

1.6 STANDING’S EXTENSION OF VOGEL’S IPR FOR DAMAGED OR

IMPROVED WELL

While deriving the equation, Vogel assumed that flow efficiency is 1.00 which
implies that there was no damage or improvement in the well. Standing extended
the Vogel’s equation by proposing the comparison chart where he has
indicated flow efficiency either more or less than one.

According to him, flow efficiency is defined as

Ideal drawdown P, -P’M in actual drawdown ‘skin’

F.E. = = \ as not been considered]
Actual drawdown Pr– Pti

Where PIW = Pti + (DP) ~Mn

(Dp)skindefined by Van Everdingen is as below:

s qp
(DP)skin =

1.7
 21Ckh

Where,

h = Pay thickness
q = Flow rate

P = Viscosity
k = Permeability
s= Skin factor
S = + indicates damage
S = O indicates no damage/ no improvement
S = - indicates improvement
Therefore,
P’ti P’q
q~q.,. = 1-.2 ~ ) - 0.8 (—
r P)r

Where PIM = Pr - F.E. (Pr – Pti)

[ Since, from equation (1), F.E. (P, - Pti), = P, - PIM or PIM = p, - FE. (Pr- PA]
Flow efficiency value has to be either obtained or assumed.

1.’7 FETKOVICH IPR EQUATION

Fetkovich opined that oil well also behaves like gas wells so that IPR equation
being used for gas well will also be applicable for oil wells.

Therefore the equation used for gas wells is also the same as that for oil wells.

i.e. Q. = c ( P: – Pti2)n

For determining the value of C, at least one flow test data is required. Let one
flow test data be QOcorresponding to the flowing bottom hole pressure PM.

Qo
Then C =
(P: - Pti2) n

1.8
For convenience, n is taken as one.

1.8 PREPARATION OF FUTURE IPR CURVES

For the planning of future requirement of artificial lift and other surface and
downhole infrastructure it is imperative to know the future production potential of
oil wells. Therefore generation of future IPR curves assumes a paramount
importance.

Combination of Fetkovich and Vogel procedure for the generation of future IPR
curves is being commonly used.

Fetkovich has proposed the future IPR equation by correlating the current
reservoir pressure with the productivity indices of the present and future as

P,2
Q02= JO, (R22 - Pti2) n
Prl

Pfl is the future reservoir pressure and prl is the present reservoir pressure.

Eckmier put forward that the Fetkovich equation of the current and future IPRs
for Qmax for both the times can be obtained in the following way.

Qmax = Jo, (P,2 - PM2) n

1.9
 rl;:SGiiii
!!!!!
(&m
PURPOSE OF ARTIFICIAL LIFT :
To create a steady low pressure
or reduced pressure in the wellbore
against the formation to allow the
I
well fluid to come into the wellbore
continuously for getting a steady
stream of production to the surface
x
end.

>

FIG -1.1A 1.10

 A
m
!-c
%
t Pi
d-
d
-J
4
I
1
r
T
 CONCEPT OF PRODUCTIVITY INDEX:
d=
PJ= Q/( Pr-Pwf) Pwf = Pr

Where ,

P.I = Productivityindex. ~wf

I ...—

Q = Total quantity of fluid. [

W = Reservoir Pressure.

Pwf = Flowing bottom hole pre=o Q Qmax

QAPr-Pwf

❑ Q= K.(Pr-Pwf) lx
❑ K = Q/(Pr - Pwf)
Where K isconstant,
Known asPI
FIG-1 .2A
Pwf
P 1.12
Pr
INl?LOW PERFORMANCE RELATIONSHIP :

It is basically a straight line or curve drawn in the

two dimensional plane,where X axis is q ( Flow Rate)
and Y axis is Pwf ( Flowing Bottom Hole Pressure ).

PI= J=-dq/dPwf
Pwf

b
q

FIG.1.2B : Actual Case For P I

1.13
 It is basically a straight line or curve drawn in the
two dimensional plane,where X axis is q ( Flow Rate)
and Y axis is Pwf ( Flowing Bottom Hole Pressure ).
STMIGHTP.I. AND IPR
Pwt’ = Pr
~ STRAIGHT P.I.

Pwf

qQ
~ ISMX
Q max

Q max for Straight P.L >> Q max for IPR

FIG.1.2C : Actual Case For P I
1.14
IPIl IN DIFFERENT CASES:
* Active Water Drive :
1.Strongest drive ( Helps to exploitmore than 35% of Initial
oil
inplace) .
2.However intensitydiffersin different
water drive
reservoirs.
For e.g.Edge water drive is weaker than
Bottom water drive.

PRESSURE
P PI
1
G RI
o El
R sl---- GOR
s.
CUMM. PROD. ~
FIG. 1.3: Typical Performance For A Water Drive Field For A
Low Production Rate. 1.15
* Solution Gas Drive :
1.Called as ‘InternalGas Drive’ or ‘DepletionDrive’.
2.Least EffectiveDrive Mechanism (lkploits about 15% of
Initial
oilinplace).
3.Reservoir Pressure influencesthe pattern of IPR as it
declinessharply

REsv.

-.,
,.
-.
-..

Jti$j ‘..
. .

REsv.
PRESS
1-

CUMM. PROD. ~
FIG. 1.4: Typical Performance For A Solution Gas Drive Field. ~16
.
* Gas Cap Expansion drive :
1.Also calledas SegregationDrive.
2. IPR curve is somewhere in between the Solution Gas
Drive & Water Drive.Itismore effective
than solutiongas
drivereservoir.
(Exploitsabout 20-25% of Initial
oilin -
place.
t
REsv.
PRESS.
\
P*I

REsv.
PRESS. 1-
=.s8!9’ ‘,.
.,

b
CUMM. PROD.
FIG. -1.5: Typical Performance For A Gas cap Expansion Drive
—
Reservoir. 1.17
 00
u
1
&
L
.m . . . ..mm.
>\/ ‘“’””lL
--”+- ,-.
:
:
:
:
:
:
:
:
;
m
1
i
.
I :
. :
:
:
I :
:
.//‘..,
k; :
:
:::
‘,.,,
A . :
:
0
HI
-x
I
I
 s. Aq
,!

!:
@

&
In Place) With Time :

Np/N = 0.1?40

k 2
CUMM. REC.,
!’40OF

BOTTOM-HOLE
WELL PRESS .Kg/Cm2

PRODUCING RATE ,M3/D

FIG. -1.7: Computer Calculated Inflow Performance Relationship
s
For A Solution Gas Drive Reservoir.
1.19
@iiiiii

I!m
(K2GD Q+-—.&_:——— —— —_._______
,.

VOGEL’S WORK ON Il?R :

.
The minimum and maximum values l?,*m
each case isO and 1.0. 1 I

1.00
0.80

0.60 \

Pwf/Pr
0.40
Fraction
of 0.20
Res.Press.

o ().20 0.40 0.60 0.80 1.00 Fig-1.8

qo / qmax, Fraction of maximum
FIG. – 1.8 : Inflowperformance relationship for solution gas drive
1.20
reservoirs (after Vogel).
 7
arnm?!

Il!l!!
&
STANDING’S EXTENSION OF VOGEL’S IPR
FOR DAMAGED OR IMPROVED WELL :
According tohim, flow efficiency
isdefinedas :

F.E = Ideal drawdown /Actual drawdown

=(Pr - P’wf) / (Pr - Pwf) ---II)
Where,

P’wf = Pwf + (DP)skin Pwf

(DP)skin definedbyVanEverdingenk as below: ~PfSW

so, P’wf = Pwf + (DP) skin

(DP)skin = S qp / 27L kh
Fig-1.9
1.21
f&alin
,1
b
(!&D
COMPARISON OF METHODS
B 2000
o m ■ ■ ■ Straight P.I.
T
T ■ Standing correction
o 1600 in vogel
WI . .,,,.,, .
Fetkovich
H
o Vogel.
L
\
E

P \

R
E
\
s 400 $+
\
●
s 0

s
\
i
I \ ●
R !im ●
A

E !30 100 120 140 160 180

Fig. – 1.10: FLOW RATE,130PD 1.22
 Chapter 2

MULTIPHASE FLOW

2.1 INTRODUCTION

Single phase flow refers to one fluid medium only and whenever there is more than
one fluid medium, for example oil, water and gas, it is termed as multiphase
medium of fluid flow. In petroleum industry vertical / deviated tubing, horizontal
pipes and inclined pipes are commonly encountered . A typical overall production
system is shown in Fig. 2. 1. It is, in this respect, a necessity to predict pressure
gradients at certain intervals in the tubing or fiowline to correctly predict the

pressure, flow rates, etc. This facilitates, inter-alia, optimum tubing string and
flowline design and the designing of artificial lift for the production of oil.

To simplify the whole problem, at the outset, it is convenient to divide multiphase

flow into two broad categories, viz. horizontal on the surface and vertical in the well.

The material difference between these two categories is the effect of gravity in

association with the specific character of the flow or the specific flow regime.

2.2 HORIZONTAL FLOW

Eight different flow characteristics have been shown for horizontal flow in F&.
2,2(A, B, C, D, E & F). When more than one phase is present, the pressure loss
accounts for the interaction between the phases in addition to the pipe wall friction
which is normally the case in single phase pipe flow. There are other forces
present, viz. rotational forces perpendicular to direction of flow as well as the

2.1
accumulation of liquid in certain areas in the line resulting in momentum losses.
Because of all the above complexities, the pressure loss calculation has to be

made taking into consideration the various flow regimes,

The number of flow regimes may be divided into two broad divisions

1. Where one phase is continuous.

2. Where both phases are continuous.

Bubble, and spray are the examples where only one phase is continuous. Liquid is
the continuous phase in bubble flow and gas is the continuous phase in the other,
I,e, spray flow. All other flow regimes have both phases as continuous in various

degrees.

An attempt has been made by Dr. Shoham to define an acceptable set of flow

patterns in multiphase flow in horizontal and near horizontal flow conduit. He has

classified the various flow regimes in four principal divisions.

1. Stratified flow.

2. Intermittent flow.

3, Annular flow.

4, Dispersed bubble flow.

2.2.1 STRATIFIED FLOW

$iWaified flow is further sub divided into two groups

i) Stratified smooth flow. ( Refer Fig. 2.2A)

ii’) Stratified wavy flow. (Refer Fig. 2.26)

This flow pattern develops at low gas and liquid rates. Two phases txxorne
distinct and they are separated by gravity. The liquid phase occupies bottom of the

2.2
pipe and gas occupies the top. The transformation from stratified smooth flow to
stratified wavy flow occurs at relatively higher gas flow rates.

2.2.2 INTERMITTENT FLOW

Intermittent flow is again sub divided into two categories

i) Slug flow. (Refer Fig. 2.2C)

ii) Elongated bubble flow. (Refer Fig. 2.2D)

Intermittent flow is basically an intermittent flow of liquid and gas i.e. it is

characterized by alternate flow of liquid and gas.

The slug flow or plug flow of liquid occurs when entire pipe cross-sectional area is
separated by gas pockets at intervals as well as the conduit contains a stratified
liquid layer flowing along the bottom of pipe. Basically the flow behaviour of slug
and elongated bubble are same with respect to flow mechanism and as such they
cannot be distinguished. However, the elongated bubble pattern can be considered
to be limiting case of slug flow when the liquid slug is free of entrained bubbles.
Therefore, elongated bubble flow occurs earlier than the slug/plug flow, when
relatively the gas rates are low. As the gas rate increases, the flow at the front of

slug takes the form of an eddy due to picking up of slow moving liquid and this is

designated as slug flow. The occurance of slug flow is detrimental to fluid flow in
the pipe, because this may create severe flow disturbance and fluid hammering in
line. This also results in additional pressure losses.

2.2.3 ANNULAR FLOW (Refer Fig. 2.2E)

In the annular flow, gas occupies the central portion like a cylinder and liquid
remains near the pipe wall. This flow occurs generally at very high gas flow rates.
The gas flows in the form of a core with high velocity which may contain entrained
liquid droplets whereas liquid flows as a thin film around the pipe wall. The liquid
film at the bottom is usually thicker than that at the top.

2.3
Also when the flow rate of the gas is relatively low, most of the liquid flows at

bottom of the pipe while aerated unstable waves are swept around the other

portion of the pipe periphery. This flow generally occurs on the transition boundary

between stratified wavy / slug flow and annular flow. It is as such not stratified
wavy since liquid is swept around the pipe wall. It is also not a slug flow since no

liquid bridging occurs. It is not a fully developed annular flow which has a stable
film around the pipe periphery therefore this flow pattern is designated as proto-
slug or wavy annular flow and is a limiting case of annular flow.

Slug flow and wavy annular flow are more prominent in upward inclined flow on the
surface. In case of slug flow, backflow of liquid film between slugs is observed
whereas in wavy annular flow, the liquid moves forward uphill with frothy waves.
These waves move much slower than the gas phase,

2.2.4 DISPERSED BUBBLE @efer Eig.2.2F)

At very high liquid flow rates the liquid phase is the continuous phase and gas
phase is dispersed all around the liquid in the form of discrete bubbles. The

transition to this flow pattern is defined in the following manner. Bubbles are first
suspended in the liquid and then get elongated and touch the top of the pipe,
thereafter they are destroyed. ‘When this happens, most of the bubbles are
concentrated near the upper pipe wall but as the liquid rates becomes higher and
higher, the gas bubbles are dispersed in small particles more uniformly in the
entire cross-sectional area of the pipe. Under dispersed bubble flow conditions, as
the liquid flow rate increases, the two phases move at the same velocity and then
the total flow is considered as homogeneous flow.

2.3 VERTICAL / INCLINED FLOW PATTERNS

As given by Dr. Shoham, four possible flow regimes have been described. They

are :

2.4
1. Bubble flow.

2. slug flow.

3. Churn flow.

4. Annular flow.

In the case of vertical and inclined flow, the stratified regime as in the case of

horizontal flow isabsent andanew flow pattern isobserved which is called churn
flow.

2.3.1 BUBBLE FLOW (Refer Fig.2.3A)

Bubble flow occurs at relatively low liquid rates. The gas phase is dispersed as

small discrete bubbles in a continuous liquid phase and in this case the distribution
is approximately homogeneous throughout the pipe section.

The bubble flow regime is sub divided into two categories;

i) Bubbly flow.

ii) Dispersed bubble flow,

Bubbly flow occurs at relatively low liquid rates and is characterized by slippage

between the gas and liquid phases.

Dispersed bubble flow occurs at relatively high liquid rates and is characterized by

no slippage between gas and liquid phases and in this condition, the liquid phase
carries the gas bubbles.

2.3.2 SLUG FLOW (Refer Fig. 2.3f3)

Slug flow regime in vertical / inclined pipe is symmetric about the pipe axis. Gas

phase appears in the form of large bullet shaped gas pocket with a diameter

2,5
almost equal to the pipe diameter. This gas pocket is termed as “Taylor Bubble”.
The flow consists of alternate Taylor bubbles and liquid slugs in the pipe cross-
section. A thin liquid film trapped between the Taylor bubble and the pipe wall
flows downward. The film penetrates into the next liquid slug below it and creates a

mixing zone aerated by small gas bubbles.

2.3.3 CHURN FLOW (Refer Fig. 2.3C)

Churn flow is similar to slug flow but it appears more chaotic with no clear
boundaries between the two phases. The flow patterns are more symmetric
around the axial direction and less dominated by gravity. This flow pattern is
characterized by oscillatory motion. This type of pattern occurs at high flow rates
where the liquid slug bridging the pipe become shorter and frothy. The slugs are
blown through by gas phase and thus they break and fall backwards and
subsequently merge with the following slug. As a result, the bullet shaped “Taylor
bubble” is distorted and churning occurs, as such, it is named churn flow.

2.3.4 ANNULAR FLOW (Refer Fig. 2.3D)

In this type of flow, the liquid film thickness is more or less uniform around the pipe

wall and this liquid fi[m moves at a slow rate. There are also liquid droplets which
are entrained in the gas core.

This type of flow is characterized by a fast moving gas core and the interface
between the gas core and liquid film is highly wavy due to high interracial stress.

In case of vertical downward flow, the annular flow regime exist even at very low
gas rates in the form of falling film. The slug regime is, however, very similar to
that of upward annular flow except that the “Taylor bubble” becomes unstable and
are eccentrically located with respect to the pipe axis.

2.6
2.4 FLOW CORRELATIONS

A. Horizontal flow correlations.

B. Inclined flow correlations.

c. Vertical flow correlations.

2.4.1 HORIZONTAL FLOW CORRELATIONS

In horizontal section, flow characteristic depends on factors like:

1. Flow rates of gas and liquid.

2. Gas liquid ratio.

3. Physical properties of gas and liquids.

4. Line diameter.

5. Interracial energies and shear forces between the separate phases present.

In horizontal flow, the total pressure loss is the sum of the frictional and total kinetic
losses with respect to various flow patterns. The pressure losses for multiphase
flow differ significantly from those encountered in single phase flow. A great

aberration in flow is observed in case of very viscous emulsified flow.

Many investigators of horizontal multiphase flow pattern have chosen their

separate experimental data into various groups that match the various flow regimes

as described earlier and accordingly they have offered their correlations for

prediction. There is a great deal of discrepancy in all of this kind of work and

generally the justification as offered by different authors are not enough to

convince fully the degree of influence of different flow patterns on pressure losses
occurring at various sections of the pipe.

In fact, no line is truly horizontal. Therefore muitiphase flow occurs likely in uphill,
downhill as well as in horizontal direction. Any dip or change in the flowline profile

2.7
froma horizontal position will effect achange inthe flow pattern. Liquid buildsup
in the low spots wherever they are and this ultimately decreases the area available
for flow. In that portion, velocity normally becomes high. Also, when the liquid is
lifted over the hill, liquid also get collected in low spots. The collected liquid at
times overflows and contributes to build up of liquid in the next lower spot. A

portion of this liquid, in turn, is again lifted up. Therefore there is a liquid surging
process taking place repeatedly. This causes unstable fluid flow and pressure
loss. Thus excess pressure drop in the line operating beiow the designed

capacity is witnessed.

Therefore, in selecting multiphase flow system, there is a requirement of keeping

high velocity so that liquid segregation and accumulation will be minimal. In order
to achieve this, excessive oversizing of line must be avoided in the case of
multiphase fluid transportation on the surface.

The first known work in the development of multiphase horizontal flow was done in
1830. The first publication of horizontal multiphase flow of real significance was

made in 1949 by Lockhart & Martinelli. Commonly used correlations for horizontal

multiphase flow are:

1. Lockhart and Martinelli.

2. Baker.

3. Andrews et al.

4. Dukler et al.

5. Eaton et al.

6. Beggs & Brill.

LOCKHART & MARTINELLI

Lockhart & Martinelli presented a very good work on horizontal multiphase flow

correlations which has been widely used by industries. This correlation is

2.8
considered fairly accurate for very low gas and liquid rates and for small conduit
sizes.

BAKER

Baker has dealt with the multiphase flow in horizontal pipes specially in hilly terrain.

While using his method the slug and annular flow regions are found to be more

accurate. His method is better for pipe sizes greater than 6 inches. Also, his work

is found to be suitable whenever there is a case of slug flow. Baker has tried to

present different equations for each flow pattern and that is the main difference
between Baker and Lockhart & Martinelli’s approach.

ANDREWS ET AL

Andrews et al, presented a correlation to determine the pressure loss in 2.06

inches I.D. steel pipe at field conditions. He had conducted the tests with water,

distillates, crude oil and natural gas. He found that his correlation with the distillate
data came close to the water curve but the oil curve deviated at high Reynold’s
numbers. Also he found that in case of turbulent flow, frictional losses appear

abnormally high at the lower Reynold numbers, His correlation is found more
suitable for 2 inches pipe and for viscosities less than 10-15 cp.

DUKLER ET AL

Dukler et al, accumulated a huge data bank where more than 20,000
measurements have been taken. He actually segregated his work in two
categories.

At the outset, he tried to depict a comparison of different correlations viz. Baker,

Bankoff, Lockhart & Martinelli, Yagi etc. The second part was the development of

a new correlation, through the concept of above similarity analysis. While

developing his correlation, he identified forces due to pressure, viscous shear

2.9
forces, forces due to gravity, and forces due to inertia or acceleration of the fluid.
Thereafter the correlation was presented in the form of two cases viz. Case 1 &
Case 11,which are as follows :-

Case I - Dukler

There is no slip between phases and a homogeneous flow is assumed to exist:-

in Case i - i3ukier, the two phase mixture was considered equivalent to singie
phase. So, this method is very simpie to use and requires no flow pattern
calculation since it is essentially a singie phase pressure drop calculation.
Aithough, most horizontal fiow is highiy unsteady, the assumption taken here is of

steady state flow where the hold- up is defined as the ratio of iiquid superficial
veiocity to total superficial veiocity.

Case II - Dukler

In this case, slip occurs but the ratio of each phase velocity to average is assumed
constant ..-

Case - ii Dhkier, i.e. the constant siip method, is one of the most accepted method
as of today, for a wide range of conditions. The correlation of Dukier can aiso
handie viscous effects to a great extent. A wide range of conditions here means a
wide range of pipe sizes, a wide range of fiow rates and a wide range of other

reiated parameters. This correlation has been found to be more suitabie for the
iarge pipes.

EATON ET AL

Eaton et ai conducted an extensive fieid study covering various gas and iiquid rates
in long tubes. The diameter of tubes were 2 inches and 4 inches. He varied the
iiquid rates from 50 to 2500 BPD in 2 inch iine and 50-5000 BPD in 4 inch iine.
For each liquid rate, he varied the gas iiquid ratio from bare minimum to maximum

2.10
as allowed by the system. One of the most important contributions of Eaton was
“liquid hold-up correlation”. This hold-up related to fluid properties, flow rate and
the flow pattern in the line. Eaton applied a similar dimensional analysis to this
problem as had been done by Ros and also by Hagedorn & Brown for vertical flow.
This correlation has a limitation and does not apply when the flow degenerates to
single phase.

BEGGS & BRILL

The Beggs & Brill method is suitable for a wide range of conditions and is

considered realistic in approach. This method has been extensively tested for
large diameter pipes. For each pipe size, liquid and gas rates were varied and all
flow patterns of fluid were observed. The liquid hold-up in horizontal pipe was first
calculated while developing the correlation and the variation of liquid hold-up with
different pipe inclinations was found out.

2.4.2 INCLINED FLOW CORRELATIONS

Very few surface lines, in fact, are truly horizontal. Inclined flow in general, is

defined as, the flow through pipes that are lying on the surface and that deviate
from true horizontal. In fact, both inclined and directional flow (directionally drilled

wells) offer more or less similar problems.

The most widely used solution to the inclined multiphase problem has been offered
by Flanigan and then by Beggs & Brill.

FLANIGAN CORRELATION

Flanigan conducted several field tests for inclined flow and he observed that most
of the pressure drop occurred in the uphill section of the line and the pressure drop
in the line decreased as gas flow in the line increased. At the same time it was
observed that in horizontal line the pressure drop increased as the quantity of gas

flow increased. Flanigan explained this phenomena in the following manner.

2.11
According to him there were two main components of pressure drop in the

multiphase flow. The first one was the component due to friction and this was
considered to be predominant in horizontal lines. The second component was the
elevation effect due to the liquid head and was predominant when the gas

velocities were low. However, when gas velocities were high, acceleration

component was predominant. Therefore, the sum of two components i.e. the
friction and elevation effect due to liquid head together accounted for the total
pressure drop. Flanigan then analysed the Ovid-Baker correlation and worked out
his own correlation in determining the frictional loss component.

He then studied the deviation component. He treated the uphill section in the
similar manner as it would have been a vertical column containing same amount of
liquid. Flanigan used a dimensionless factor in the pressure drop equation of the
vertical flow.

BEGGS & BRILL CORRELATION

Beggs & Brill conducted gas-liquid two phase flow experiments in inclined pipe and

studied the effect of inclination angle on liquid hold-up and pressure drop. They
subsequently developed empirical correlation for liquid hold up and frictional factor
as functions of flow properties and inclination angle. They came out with different
correlations for liquid hold- up for three f!ow regimes, however, they observed that
friction factor was not dependent on flow regime. They observed that :

1) Liquid hold up and pressure drop were different with the change of
inclination angle.

2) In inclined two phase flow, the liquid hold up increased to a maximum at +50

degrees and a minimum at -50 degrees from horizontal.

3) Pressure recovery in the down hill section was noticed and the same

should be considered in pipe line design.

2,12
2.4.3 PRACTICAL APPLICATIONS OF HORIZONTAL / INCLINED

MULTIPHASE FLOW

In this respect, it is a primary requirement that a well should produce against a

minimum wellhead pressure possible to make the well flow to its capacity. But on
many occasions, the well produces against a higher well head pressure which at
times is excessive. This can be considered a serious problem. Therefore the
practical application of horizontal multiphase correlation for the self flowing or lift

wells is to arrive at the minimum necessary well head pressure for pushing the

fluids in the surface lines up to the separator against the predetermined separator
pressure. If this flowline diameter is very small then a high wellhead pressure is
required to flow the fluid from wellhead to separator. Again, on the other hand, if

the flowline diameter is bigger, then chances of fluctuating pressure loss and liquid

surging increase. Therefore by using a proper horizontal flow correlation, the

optimum sutiace flowline diameter and length can be selected.

EFFECT OF VARIABLES

Effect of line size (Refer FTg, 2,4)

It is clearly seen that pressure loss for a given length of flow line decreases very

rapidly with increasing of diameter. It is generally more sharp when diameters are
less and less rapid for higher diameters.

Effect of flow rate

The effect of flow rate with a wide range of different diameter pipelines have been

shown in the Hg. 2.5. For a fixed diameter, more is the quantity of flow, more is
the pressure drop.

Effect of Gas-liquid-ratios

Since, in horizontal flow, no fluids are being lifted vertically the presence of gas
merely represents additional fluids to be moved in the horizontal line. This in other

2,13
words, means more and more gas in the fluid causes increasing gas-liquid-ratio (

GLR ) and this increase in GLR, in turn, causes increase in pressure drop. Fig.
2.6 shows how approximately gas liquid ratios effect pressure drop in the line.

Different published graphs are available for different pipe sizes, and liquid flow

rates with approximate water specific gravity at 1.07, gas specific gravity at 0.65

and average flowing temperature at 140° F. The other sets of published graphs at
different conditions like average flowing temperature of 120°F etc. are also
available.

Effect of Water-oil-ratio

The effect of water-oil-ratio or in other words the density of the mixed fluid is not an
important factor for horizontal flow.

Effect of viscosity

Viscous crudes offer more of a problem in horizontal flow than they do in vertical
multiphase flow. The reason for this is that generally the crudes are cooler in the

surface flowline and hence more viscous. The Fig. 2.7 depicts an approximate

effect of change of viscosity on pressure drop for a given length of line.

2.4.4 VERTICAL FLOW CORRELATIONS (Refer Fig. 2.8)

Vedical multiphase flow pressure traverse is extremely important to select the

completion string, predicting flow rates and design of Artificial Lift installation.

It is essentially sum of three contributing factors viz.

- Static gradient or hydrostatic gradient.

- Friction pressure gradient or simply friction gradient.

Acceleration pressure gradient or simply acceleration gradient.

2.14
The other factors like viscosity, surface tension, density have also been included
upto a certain specific limit.

The historical development of the vertical multiphase flow was started as early as
1914 but its impact was greatly felt after Gilbert’s work.

W.E. Gilbert did considerable amount of work in 1939 and 1940 on multiphase flow
although he could publish the result only in 1954. Gilbert had a very important
contribution in presenting graphically pressure vs. depth values which are known
as the gradient curves.

Poettmann-Carpenter’s contribution in this area was also unique. They published

their correlation in the form of a set of gradient curves in 1952. It was regarded

that their approach was probably the first fundamental and mathematical pattern

towards a wide range of flowing conditions.

Subsequent authors used their correlations and plotted the gradient curves with
different ranges of flow rates for different conduit sizes.

The most important correlations for predicting pressure loss in vertical flow are :

1) Duns and Ros.

2) Orkiszewski.

3) Hagedorn and Brown.

4) Winkler and Smith.

5) Beggs and Brill.

6) Govier and Aziz.

These correlations are, in general, used judiciously for all pipe sizes and for any
field.

2.15
There are several other correlations and most of them are limited to only one pipe
size.

DUNS AND ROS

Duns and Ros did an extensive laboratory investigation using different field data.
Duns and Ros in their investigations assumed a pressure difference and after

calculating various required properties of fluids, they selected a flow regime. Due
to the different flow regimes, the liquid hold up and friction factor also were

different. They finally came out after calculating slip velocity, liquid hold-up, friction
factor, friction gradient, static gradient, acceleration gradient etc. to determine the
vertical length corresponding to the assumed pressure difference.’ This calculated
length was compared to actual length and by iterative procedure actual pressure
drop was found out. Liquid hold-up and pressure gradient depend on the gas flow
rate to a large extent. As per Duns and Ros, the bubble flow prevailed at low gas
flow rates and liquid then was the continuous phase. This kind of flow pattern
made the pressure gradient almost equal to the hydrostatic gradient of the liquid.

But when the gas rate was made to increase, bubbles grew in number. Bubbles

then at different locations merged and formed into bubbles of bigger shape, which

finally turned into bullet patterned gas plugs. These plugs then subsequently
became unstable and collapsed when gas flow rate further increased. Finally, the
flow pattern became alternating liquid and gas slug which are known as slug flow.
At still higher flow rates of gas, the slug flow pattern became mist flow and in this
situation gas, instead of liquid became the continuous phase and liquid got
dispersed and entrained in the gas medium. As per Duns and Ros, the wall friction
remained essentially negligible throughout the changing of flow patterns upto slug
flow. But the wall friction became very significant for the mist flow and the wall
friction further increased sharply with the increase of gas flow rates. As had been
exercised by other authors, Duns and Ros also used superficial velocities ( which
means each phase is flowing separately in the pipe ). According to them, when the

superficial velocity of liquid exceeded 160 ems/second, it became very difficult to

observe the various flow patterns. Even plug flow remained non-existent. Actually,
then the pattern became turbulent with liquid being frothy with dispersed gas

2.16
bubbles entrained in it. But again at the same time if the gas flow rate was made
to increase, the liquid got segregated and caused slug flow. Finally, this flow

pattern changed to mist flow when superficial velocity of gas. exceeded 5000 ems/

second.

Duns and Ros had divided the flow regimes into mainly three regions depending on
the amount of gas present.

1. The liquid phase was continuous. Bubble flow, plug flow and part of the

froth flow existed,

2. There was alternate phases of liquid and gas flow so this region covered

slug flow and froth flow regime.

3. The gas was in a continuous phase and there was mist flow.

Duns and Ros used these three regions and friction factor as well as liquid hold-up

separately for each region and developed the correlations.

They used four dimensionless groups such as gas velocity number, liquid velocity
number, diameter number and liquid viscosity number.

Duns and Ros correlation is one of the best for multiphase flow as this covers all
ranges of flow. However, this correlation is not accurate for stable emulsion.

ORKISZEWSKI

Orkiszewski’s correlation was based on the analysis of many published correlations

and he came out with some discriminatory features like considering liquid hold-up
in consideration to density and friction losses with respect to different flow regimes.
In order to simplify his approach, he had considered the whole aspect in three
separate categories. In the first category, the liquid hold up was not considered in
with density. The liquid hold up and wall friction losses were expressed by using
the empirically correlated friction factors and he did not make any distinction

2,17
between flow regimes. In the second category he used liquid hold-up in density
calculation and he arrived at the friction losses based mainly on composite
properties of liquids and gas. However here also he did not make any distinction
between any flow regimes. In the third and last category, he used liquid hold-up in
the density computation and the liquid hold-up was calculated from the concept of
slip velocity. Friction losses were then calculated by the properties of the

continuous phase and in this category flow regimes were taken into consideration.

Orkiszewski emphasized that liquid hold up was the result of physical phenomena
and that the pressure gradient was related to the distribution fashion of liquid and

the gas phase. He then recognized the four types of flow patterns viz. bubble,
slug, transition and mixed. He prepared separate correlations for each to establish
slippage velocity and friction. He took help of the work done by Griffith and Wallis
in establishing his correlation for a slug flow and he used basically Duns and Ros
correlation for transition and mist flow.

HAGEDORN AND BROWN

Hagedorn and Brown came out with generalized correlation which included almost

all practical. ranges of flow rates, a wide range of gas-liquid-ratios, normally all the

available tubing sizes and the effect of fluid properties. This study also included all

of the prior works done on the effect of the liquid viscosity. Hagedorn and Brown

also incorporated a kinetic energy term which was considered to be very significant

in small diameter pipes in the region where the fluid was having low density. They
used Griffith correlation when bubble flow existed. The liquid hold-up was checked
to make sure that it exceeded the hold- up for no slippage to occur.

Hagedorn and Brown on a similar line to that of Duns and Ros showed that the
liquid hold up was principally related to four dimensionless parameters like liquid
velocity number, gas velocity number, diameter number, and liquid viscosity

number. They used the regression analysis technique to relate the above four

dimensionless groups as well as pressure terms. The Hagedorn-Brown liquid hold-

up correlation is a pseudo hold-up correlation. Hold-up was not actually measured

2,18
but back calculated after knowing the total pressure loss and by using a friction
factor obtained from two phase Reynold’s number.

WINKLER AND SMITH

Work of building the fluid gradient curves by Winkler and Smith was the extension
of work by Poettmann & Carpenter, as mentioned in the foregoing discussion.
Winkler and Smith, in order to give their gradient curves a universal application,
selected some average liquid and gas conditions with corresponding PVT
characteristics and thereafter demonstrated the effect of each possible variable
upon the gradient curve like effect of tubing size, effect of flow rate, effect of gas-
liquid ratio, effect of oil & water gravity, effect of gas gravity, effect of well
temperature, effect of solution gas-oil-ratio etc. These effects were with certain
assumptions like no paraffin or scale build-up in the tubing wall, no loading of fluid

in the bottom of the tubing or the breaking out of gas from the fluid. As per Winkler

and Smith, a variation of one factor would not seriously affect the fluid gradient

curve, but when a large number of variables pointed in the same direction, an
appreciable error would be introduced into the gradient curves.

Considering all such aspects, Duns and Ros, Hagedom and Brown, Winkler and
Smith and others published fluid gradient curves with the consideration of the most
common field conditions such as Tubing I.D. (1 .610”} 1.995”, 2.44”, 2.992” etc.); oil
gravity as 35°APl, gas gravity as 0.65; water specific gravity as 1.08, average well
temperature as 140°F, 190°F etc., surface gas pressure as 14.65 psia, surface
gas temperature base as 60°F and surface compressibility factor, Z as 1.0. All the
curves were drawn for each condition such as “ail oil”, “all water” and “50?40oil and
50% water”.

BEGGS AND BRILL

Beggs and Brill developed the correlation by doing experimentation on a small

scale test facility. This small scale test facility consisted of 1 inch and 1.5 inches
sections of acrylic pipe of 90 ft long which was set up in Tulsa University fluid flow

2.19
section. The pipe could also be inclined at any angle from the vertical position to
horizontal. The following parameters were studied - gas flow rate, liquid flow rate,
average system pressure, pipe diameter (as in the set up, i.e., 1 “ and 1.5”), liquid
hold up, pressure gradient, inclination angle and horizontal flow patterns. The
fluids used were water and air. Liquid hold up and pressure gradients were noted
at every step. The original flow pattern was modified to include a transition zone
between the segregated and intermittent flow regimes.

GOVIER AND AZIZ

Govier and Aziz correlation was flow regime dependent. They came out with a new
method for the bubble and slug flow regimes in vertical two phase flow. For mist
flow they preferred Duns and Ros method. Govier and Aziz correlation performed
with accuracy.

2.5 PRESSURE VS. DEPTH FLUID GRADIENT CURVES

In order to have access to the multiphase correlation by the oil field design

engineers, multiphase correlations as developed by different authors are available

in two forms’:

i) In the form of a set of pressure-depth working curves.

ii) In the form of computer solutions.

Both are very useful. Computer solution provides the design in no time. However,
field engineers can acquire a fair idea when they apply working curves to solve
problems.

There are several publications of multiphase flowing pressure curves viz. (1)
Winkler and Smith curves in Gas lift Manual of Cameo, Inc., (2) Hagedorn and
Brown curves in the book titled “ Artificial Lift Methods “ by Kermit E. Brown,
Prentice Hall, Inc., (3) U.S. Industries curves in Handbook of Gas lift, etc.

2.20
These correlations are useful for

(i) Selecting tubing sizes.

(ii) To predict when the well will cease to flow i.e. when the well requires

additional gas to be injected at some point in the tubing to make it flow at the

desired rate.

(iii ) Designing of artificial lift system.

(iv) Determining flowing bottom hole pressures from the wellhead pressures and

vise versa.

(v) Predicting maximum flow rates possible.

All the correlations are based on certain common assumptions like

Fluid must be free from emulsion.

Fluid must be free from scale/paraffin build up.

Mashed or kinked joints should not exist in the tubing.

Flow patterns should be relatively stable.

No severe slugging should occur.

Fluid ( oil ) should not be very viscous.

_______________________________________________________________________________________________________

2.21
 b Pressure (psig)
200 400 600
0

10

15

Fig. 2.4: APPROXIMATE PRESSURE PROFILES FOR

DIFFERENT FLOWLINE SIZE (3”, 4“, 6“ & 8“
ETC) ON A PARTICULAR QUANTITY OF
FLOWRATE
2.31
 b Pressure (psig)
500 1000 1500

i,

I \

I
l?ig.
2.5:APPROXIMATE PRESSURE PROFILES
FOR DIFFERENT FLOWRATE USING A
PARTICULAR SIZE OF FLOWLINES.
 ➤ Pressure (PSIG)
200 400 600

o
0
0

10

12

14

16 –

Fig. 2.6: PRESSURE PROFILE IN SURFACE PIPE

(HORIZONTAL FLOWING PRESSURE GRADIENT)
WITH VARYING GAS LIQUID RATIO (GLR) 2.33
 —---”+ Pressure
100 200 300 400
o- I I I I
I

5.

s
\
* \
G 10 _ \ \
&
.
\\
@
m \ \
g ,\ \
\ \ \.\
A
15 _

\w n \ (J,\-\—_

20 .

Fig. 2.7; APPROXIMATE PRESSURE PROFILES

FOR FLUIDS OF DIFFERENT VISCOSITY

2.34
 + Pressure (PSIG)

o
Say, Flowline size = j 5 in
ID producing rate = ~500 b/d
Oil API grauity = 3 jo API
5 Gas Specific grauity ❑ 0.65
Average flowing tens = 1400F
~ Oil = 100VO
II
\
6
i
i

\
8 \
t
,
i,

\ “:
10
\

~J

14

16

Fig.
2.8:VERTICAL PROFILE IN TUBING
(VERTICAL FLOWING PRESSURE
GRADIENT) WITH VARYING GLR.
2.35
 Chapter 3

SUCKER ROD PUMP

3.0 INTRODUCTION

Sucker rod pump, abbreviated as SRP is a very old technique in the oil industry
for lifting of crude oil from the wells and in fact it is the most widely used mode of
artificial lift system in the present day scenario. As per published data
approximately 80% to 90% of Artificial lift wells have been operating on SRP.
SRP operated by beam pumping unit is more versatile and more common among
other types of operating SRPs.-

Although the sucker rod pumping system operation appears very simple,
resembling a simple reciprocating tube well pump but in actual field practice it has

3.1
been found to be a very complex one owing to very deep installation of pump,
lifting of a mixture of oil, gas and water which we technically term as multiphase
fluid and other several factors, like rod/tubing- stretch / contraction, fluid viscosity,
speed of pumping unit, length of stroke etc. The various factors which contribute
to the complexity of the pumping must be thoroughly studied by the design
engineer and therefore he needs to be very familiar with the distinguishing
features and the complex function of sucker rod pumping system.

Therefore a superficial knowledge on the subject of sucker rod pump is not

enough to understand operational complexities of pump and to make the running
of the sucker rod pump efficiently.

It is therefore, a necessity for a sucker rod pump engineer to have an in-depth

knowledge of the total SRP system. Once an engineer knows fully the
significance of the elementary principles of the pumping system, he will be then
make himself / herself familiar with the complex functioning and distinguishing
features of each part of the system and as such he/she will be in a position to
operate the pumping system in a fool proof manner, As a straight forward and
simple strategy let the whole pumping system be presented under three broad
units namely (Refer Fig 3. 7):

1) Surface unit.

2) Sub surface sucker rod pump.

3) Sucker rods.

It is important, in brief, to visualise the motion (of each of the units before they are
described in detail and how they tie them together into an unique pumping
system. With the help of a prime mover, say an electric motor of comparatively
low r.p,m. (like 720 r.p.m.) a rotating motion is generated. This rotating motion is

3.2
then passed on to the surface unit by the V-belt transmission system. It effects a
reduction in r.p.m. Thereafter, the onward rotating motion is further reduced to
about 1:29 with the help of a double reduction gear box of the pumping unit. This
very low rotary motion (say 6 r.p.m.) is then Converted with the help of different
components of pumping unit to linear motion at the polished rod.

This linear reciprocating motion is then transmitted to sub-surface sucker rod

pump through the sucker rods, which is the linkage of the surface unit and
subsurface pump. In this way a sucker rod pump operates and lifts well fluids to
the surface from the well.

3.1 PUMPING UNITS

Pumping unit cum prime mover at the surface converts the rotary motion of the
prime mover into the reciprocating / vertical motion with the help of several link
arrangement . Majority of this pumping operation, world wide, utilise walking
beam pumping unit and so it is named as beam pumping unit (Refer Fig. 3.2 A).

The structural parts of a conventional beam pumping unit are as follows :-

1. Walking beam.
2. Horse head.
3. Saddle bearing.
4. Equaliser bearing.
5. Equaliser.
6. Pitman arm.
7. Wrist pin or crank pin bearing.
8. Crank.
9. Counterweight. ( Fig. 3.2 B---Showing counter balancing effect)
10. Crankshaft.

3.3
11. Double reduction gear box.,
12. Unit sheave.
13. Sampson post.
14. Ladder. ,
15. Briddle (wireline hanger).
16. Carrier bar.
17. Electric motor.
18. Motor sheave or Motor pulley.
19. V-belt.
20. Belt cover.
21. Brake, its link and handle

22, Reducer gear box.

23. Pumping unit base.
24. Motor base.
25. Grouting nuts and bolts

When these are assembled, horsehead end of the walking beam hangs over the
x-mass tree of the well, as such, the polished rod clamp on the polished rod is
rested on to the carrier bar that is rigidly attached with the wireline hanger (
briddle ), which in turn is attached with the horsehead. The horse head which has
a curvature-shaped surface and flexible hanger ( i.e, briddle ) together ensure
that the polished rod is made to move in a vertical direction only. The other end of
the surface unit has the prime mover, the pulley of which is connected to the
gearbox reducer pulley with the help of v-belt.

Good operation of the pumping unit requires that friction losses in the structural
bearings are minimal. These bearings are generally grease (graphite grease)
lubricated as well as air tight sealed, thus requiring less maintenance and
ensures their smooth and trouble-free operation, Two stage gear reducer is filled
with proper lubricating oil upto the desired mark for lubricating the operating gears

3.4
as well as all the roller bearings on the gear reducer shafts get lubricated
continuously with the same gear oil with splashing by moving gears.

The whole structure is based on a rigid steel base ensuring proper alignment of
the components and this base is usually set on a concrete foundation. Two types
of base systems are followed. One is the skid based where the skid is not
grouted to the concrete foundation and the other is the base properly grouted by
the grouting bolts with the concrete foundation. As the motor sheave rotates, the
rotation is transmitted with the help of V-belt from the motor sheave to the gear
reducer sheave. During this transmission, speed reduction takes place in relation
to the ratio of the unit sheave to motor sheave diameter. Thereafter the speed is
further reduced in the ratio of 1:29 approximately in the double reduction gear.
Finally, the rotary motion of the gears is transmitted to the walking beam with the
help of the connecting link called Pitman Arm. The walking beam then makes
oscillating motion, moving the beam up and down on the pivot i.e. the saddle
bearing located near the middle of the beam. This motion is finally transmitted to
sub-surface pump through sucker rods.

3.1.1 DIFFERENT PUMPING UNIT GEOMETRIES

The pumping ~nits are broadly classified into WC grcups

1) Walking beam operates as a double arm lever (Class-l).

11) Walking beam operates as a single arm lever (Class-Ill).

1) WALKING BEAM OPERATES AS DOUBLE ARM LEVER (CLASS-1)

The conventional unit is perhaps the oldest and most commonly used beam

pumping of this class. The schematic of this unit is given in l%g.3.3. The walking
beam here acts as a double arm lever on the two sides of pivot i.e. the Sampson

3.5
post where pivot is near to the middle of the walking beam. The rear end of the
walking beam is the driving end and the front end of the walking beam is the
driven end. This is also called a “pull-up” leverage system. The walking beam is
in the horizontal position. The counterweights are positioned either at the rear
end of walking beam or at crank arm depending on the load at the well to reduce
the torque and horse power of the prime mover of the pumping unit. For less load,
counterweights are placed on the beam and for the moderate to heavier load,
counterweights types are placed on the cranks. As on date, all the sucker rod
pumping units operating in various ONGC fields are of conventional beam
pumping unit with counterweight loading on cranks. In some of the earlier smaller
capacity pumping units counterweights loaded walking beam were used.

H) WALKING BEAM OPERATES AS A SINGLE ARM LEVER (CLASS-Ill)

1. AIR BALANCED (Refer Fig.3.4).

The air balanced unit was developed in the 1920s for operating the SRP in deep
wells. This unit acts as a single arm lever (Class-111) system where the
horsehea.d and Pitman arm are on the same side of the beam and the pivot at
the extreme end of the beam. This is also called “push-up” leverage system.
Counter- balancing is ensured by the pressure force of compressed air contained
in a cylinder which acts on a piston connected to the bottom of the walking beam.

2. MARK 11 UNIT (Refer F~g.3.5).

This unit was developed in late 1950s by J.P. Byrd. This is also a Class-111 lever system

where the pivot is at one extreme end of the walking beam. The main advantage of this
unit is to decrease the torque and power requirements of the pumping units. It implies that
the pumping unit of this type having less torque and power requirement can work for
operating the pump at deeper depth in contrast to the heavier capacity conventional
pumping unit of required to operate at that depth. In Mark 11 Unit the counterweights are

3.6
placed on the counter balance arm that is on other side of the crank arm. This feature also
ensures a more uniform net torque variation throughout the complete pumping cycle.

3. TORQUE MASTER (Refer Fig.3.6)

Torque master is one of the latest developments of beam pumping of class-111
type where the pivot is at the extreme end of the beam. Some of the
distinguishing features in this pumping unit are that the gear reducer is located
further away from the Sampson post and the rotary countenveights, which are
placed on the crank arm, are kept by an angle of about 8 to 15 degrees from the
crank arm on the extended portion of the crank arm at one side.

3.1.2 DESIGNATION OF PUMPING UNITS

In order to identify a pumping unit, the following considerations are made.

1) The geometry of the pumping unit.

2) The maximum torque capacity of gear reducer.

3) Gear reducer type - whether double reductions, triple reductions etc.

4) The units structural capacity.

5) The longest polished rod stroke length available.

The API has standardised the above and accordingly designates pumping units.
For example in a C-456 D-256-144 unit, ‘C’ means crank balanced conventional
unit, 456 means gear box having a torque of 456,000 inch-ib maximum , ‘D’
means double reduction gear box, 256 means the unit having the PPRL (Peak
Polished Rod Load) capacity of 25600 tbs. and 144 means having maximum
possible stroke length of 144 inch. In the above, the first letter can be either B,

3.7
C, A, M or TM. ‘B’ is for beam balanced conventional unit, ‘C’ as described
above’, “A’ for air balanced unit, ‘M’ for Mark 11 unit and ‘TM’ for torque master
unit.

Other than the above pumping units, many new innovations are being done in the
geometry of pumping units for providing better results in the different applications.

3.1.3 DESIRABLE FEATURES OF A PUMPING UNIT

1 A long and slow upstroke is most desirable.

2. Downstroke should be faster than the upstroke.
3. Low torque factors on the upstroke is desirable.

3.1.4 PRIME MOVER

Two types of prime movers are very common :

1. Electric motor.
2. Internal combustion engine run on gas.

1. Electric Motor

Most sucker rod pumping units are being run on electric motors. Low cost, ease of
control, more compact and adaptability to automatic operations relative to other types of
prime mover have endeared it most. The primary requirement is that these motors should

have very low rpm say 720 rpm, 950 rpm etc. Electric motors used for pumping are

designated as NEMA B, C and D motors. The torque and speed characteristics of these

motors are some of the distinguishing features of thease motors. The most popular among
these in oil fields is NEMA ‘D’ type. These motors are generally having normal slip to

3.8
high slip. Motors with ultra high slip characteristics are more advantageous than those
discussed as above. These ultra high slip motors are specially useful where cyclic loading
exists. Slip is usually defined as

NS – N,
. --------- = 100

Ns

where:

NS : The synchronous speed.

N, : Nominal full load speed.

N, is less than the synchronous speed due to fully loaded condition. The main
benefits of ultra high slip motor include reduction of pumping unit structural loads,
peak torque and power consumption.

1.2 Internal Combustion Engine

Internal combustion engines are usually run on the well head gas from the casing
head. A gas scrubber is instaIled at the well head to knock out the liquid such as
oil and water from the gas before it enters the engine carburetor.

Slow speed engines with operational speed between 200-800 rpm are
preferable.

The choice between electric or gas engine is based on several factors :

1. Availability of gas or electricity at well site.

2. Investment cost of a gas engine and an electric motor. Gas engines have
higher initial cost.

3.9
3. Service life of gas engine and electric motor. Gas engines have much
higher service life.

4. Energy costs when using electric motors. In this respect, gas, if available,
can turn out to be more economical.

3.2 SUB-SURFACE PUMP

It is a sub-surface reciprocating pump, actuated by the up and down motion of

sucker rods, which is a connecting link between surface unit and sub-surface
pump. Its feature resembles a reciprocating tube-well water pump. It has five
main components:

- Barrel.
- Plunger.
- Standing valve.
- Traveling valve.
- Pump seat or nipple.

A conventional pump consists of a fixed “barrel” and a moving plunger, with

“standing valve” fitted at the barrel end and with “traveling valve” fitted at the
plunger end. The word ‘traveling’ implies that the valve moves or travels along
with the plunger. The standing valve is fixed with the stationary barrel hence the
word ‘standing’. Both the standing and traveling valves are unidirectional,
implying, both allow fluid to pass through them in the upward direction only. The
fluid will not pass through them in the downward direction. The pump seat or
nipple seals the annular area between the pump barrel and tubing and thus
prevents the pumped out fluid falling back into the pump intake again. The pump
seat also having other feature which make the pump to get locked in that depth.

3.10
q
S.=.- “
I PUMPING CYCLE: (Refer F~g-3.7)

a) Plunger moving down and near bottom of stroke

Traveling valve is open. Fluid is moving up through the traveling valve.

Standing valve is closed due to weight of fluid column in the tubing.

b) Plunger moving up and near the bottom of the stroke

The traveling valve is closed due to load of fluid column on it. Standing
valve begins to open to allow entry of fluid from the well bore.

c) Plunger moving up and near top of the stroke

The traveling valve is closed due to fluid load above it. The standing valve
is open and fluid entry from well bore into the barrel continues.

d) P/unger moving down and ,near top of stroke

The standing valve is closed by the increased fluid pressure resulting from the
compression of the fluids in the barrel between the standing and the traveling
valves due to downward movement of plunger, The traveling valve begins to
open to allow the compressed fluid in the barrel to push through it against the
tubing fluid load in the tubing. The plunger thereafter reaches the bottom of the
stroke and another cycle is started.

3.11
3.2.2 NPES OF SUB SURFACE SUCKER ROD PUMPS

The subsurface sucker rod pumps (Refer Fig. 3.8) are mainly categorized in two
principal groups.

a) Insert ( or rod ) pump.

b) Tubing pump.

In the insert or rod pump, the barrel, plunger, traveling and standing valve are the
integral part of entire sub surface assembly and is run as a unit on the sucker rod
string.

In the tubing pump the working barrel is run as part of the tubing and is placed at
the desired depth. The standing valve is then dropped into the well followed by
running in plunger along with sucker rod strings and is placed inside barrel.

Insert ( or rod ) pump is the conventional choice and is more commonly

used. As a general rule, tubing pumps are used where greater liquid volumes are
required to be pumped out. Tubing pumps are especially useful for pumping
from inclined wells. The pump itself is not as flexible as the tubing and therefore
it is very difficult to push the pump through tubing with close tolerance in inclined /
‘S’ – profile wells. In that case, tubing pump can be used since its barrel, as a
part tubing can pass easily in the inclined portion of the well having larger
clearance between O.D of the pump barrel and I.D of well casing. The plunger
having small length of say, four feet having sufficient clearance of plunger O.D.
and tubing I.D can easily be run through the inclined tubing to the desired depth.
Many ONGC oil wells in Assam area, which are inclined / ‘S’ – profile, are being
operated by tubing pumps.

3.12
3.2.3 BASIC PUMPCLASS1FICATION
ASPERAPI

1. Stationary barrel top anchor (or top hold down) rod pumps.

2. Stationary barrel bottom anchor (or bottom hold down) rod pump.

3. Traveling barrel rod pump.

4. Tubing pump.

3.2.3.1 STATIONARY
BARREL
TOPANCHOR
RODPUMP:
ReferFig-3.8 A)

API has named this pump as RHA or RWA pump. Where ‘R means rod, ‘H’
means heavy wall barrel, ‘W’ means thin wall barrel and ‘A’ means top hold down
pump. There is another pump, named by API as RSA which is a thin wall barrel
and a soft-packed plunger type pump.

Advantages

I.) The top hold down is recommended in oil wells, which are producing sand
because sand particles cannot settle in the pump-tubing annular space
due to the top hold down mechanism.

2.) This pump performs better in gassy wells because of having comparatively
larger opening of the standing valve, as such, larger opening of valve
registers less friction.

3.) This configuration of pump and top seating nipple facilitates in the
installation of a very simple and effective type of poor boy gas anchor
where the barrel of the pump serves as pull tube of the gas anchor.

3,13
4.) The top hold down pump owing to its top hold-down arrangement at the top
of the pump provides stability, while the pump is in operation.

Disadvantages

1) Due to the top hold down system, the outside of barrel is at suction
pressure while the inside of barrel experiences the pressure due to fluid
load of total tubing length. The suction pressure can be as low as 20-30
kg/cm2 or theoretically zero pressure, where as, depending upon the pump
depth, say for 3000 rots, the pressure inside the barrel may be 300
kg/cm2. This large differential pressure across the barrel wall may lead to
the bursting of barrel, Therefore, the pump has a limitation of depth. Thin
wall barrel can only be lowered in shallow wells or where very less
differential pressure across the barrel is encountered. Manufacturer of
pump specifies that say pump for 2 7/8” tubing and 1.75” plunger size with
heavy barrel can be lowered upto 1500 rots. If pump is required to be
lowered further deeper, then pumps with lower plunger sizes have to be
used. But beyond a certain depth, the top hold-down pump will not be
suited at all. Also the barrel is under high tensile load due to weight of
liquid column. Therefore, the mechanical strength of barrel also limits the
depth of insttalation such pumps .

3.2.3.2 STATIONARY BARREL BOITOM ANCHOR PUMP: (ReferFig-3.8 B)

The API has named as RHB, RWB and RSB pumps where ‘R means rod, ‘H’
means heavy wall barrel, ‘W’ means thin wall barrel, ‘S’ means a thin wall barrel
with soft-packed plunger and ‘B’ means a bottom hold down pump.

3.14
Advantages

1) The differential pressure across the barrel is much lesser in the case of
BOTTOM HOLD-DOWN pump as compared to the TC)P HOLD-DOWN
pump. During downward stroke of plunger pressure differential would be
zero and during the upstroke, it would be equal to tubing head less by
suction pressure. SO THIS PUMP CAN BE USED AT GREATER
DEPTHS. This pump as well is not subjected to the tensile stress as in the
case of TOP HOLD-DOWN pump.

Disadvantages

1) During intermittent operation of pump, sand or other particles can settle in

the barrel-tubing clearance space. Thus when it is required to pull out the
pump, smooth pulling out of pump will be prevented.

3.2.3.3 TRAVELING BARREL ROD PUMP: (ReferFig-3.8C)

The API has named this type of pumps as RHT, RWT and RST. Where ‘R
means rod or insert type pump, ‘H’ means heavy wall barrel, ‘W’ means thin wall
barrel, ‘S’ means thin barrel with soft-packed plunger and ‘T ‘means traveling
barrel pump. The traveling barrel rod pump has got the stationary plunger and
moving barrel i.e. the plunger is held in place while the barrel is moved by the rod
string. In this type of pump, there will only be only one hold down or anchor which
is at the bottom of the pump assembly. The plunger is attached to the bottom
hold down arrangement by a short narrow pull tube through which well fluid enters
the pump. The standing valve is located on top of the plunger.

3.15
Advantages

1.) Travelling barrel because ofitslarger diameter than theplunger createsa

greater turbulence in the fluid motion around the hold-down, thus
preventingsands/solids from settling inthe pump, during itsoperation.

2.) Thepump hasa rugged construction.

Disadvantages

1.) The size of the standing valveis less. Therefore, in case ofthe pumping of
moderately high viscous fluid excessive pressure drop takes place at
pump intake. That is why this pump is not recommended for lifting such
type of fluids.

2.) Because of the restricted entry of fluid in the pump, more gas separation
results, which may cause gas locking of the pump.

3.) In deep wells, high hydrostatic pressure acting on the standing valve may
cause the pull tube to buckle. This limits the length of the barrel that can
be used in deep wells.

4.) During the idle time ( i.e., when pump is not operating ) sand, fines, coal
particles etc. settle around and underneath barrel, causing jamming of
barrel and failure of pumping operation.

3.2.3.4 TUBING PUMP : (Refer F@-3.8D)

Tubing pumps are perhaps the oldest type of sucker rod pumps and have a
simple but rugged type of construction. The API has named it as TH & TP where

3.16
‘T’ designates tubing pump, ‘H’ heavy wall barrel, ‘P’ heavy wall barrel with soft-
packed plunger.

Advantages

1.) Tubing pumps provide the largest pump sizes for a given tubing size. Thus
this large barrel allows more fluid volume to be produced than with any
other rod type of pump for the same size of tubing.

2.) The tubing pump is stronger in construction than any rod pump. The barrel
is an integral part of tubing string and is slightly thicker than normal tubing
string.

3.) The rod string of suitable size (i.e. compatible to barrel I.D.) is directly
connected to plunger top without the necessity of an intermediate valve rod
thus making the connection more sturdy and reliable. The large standing
valve size results in low pressure losses in the pump and this facilitates
pumping viscous and comparably higher GLR fluids.

4.) In inclined well, with moderate or small diameter casing it is sometimes

difficult to lower insert pump since the entire rigid pump body of barrel & its
extensions can not match the profile of the bend tubing. It is in this
respect, the barrel of tubing pump, having larger barrel - well casing
annular area, can easily be lowered being it a part of tubing (i.e. along with
tubing as tubing part) and subsequently plunger having much shorter
length and less diameter with larger plunger O.D. - tubing I.D. clearance,
can easily be pushed through tubing and placed in the barrel.

3.17
Disadvantages

1.) Work-Over-Operations require tubing to be pulled out if pump barrel is to

be replaced.

2.) Large amount of rod and tubing stretch / contraction are expected because
of large standing valve and therefore, setting depth of pump is limited.
However, high strength sucker rods can be used whenever it is required to
place tubing pump at greater depths.

3.2.4 API PUMP CLASSIFICATIONS (SUBSURFACE PUMPS)

The American Petroleum Institute has adopted a classification system for

subsurface pumps. These classifications are mentioned in API Recommended
Practice 11 AR. These are as follows :-

RHA : Rod, stationary heavy wall barrel, Top Anchor pump.

RHB : Rod, stationary heavy wall barrel, Bottom Anchor pump,

RWA : Rod, stationary thin wall barrel, Top Anchor pump.

RWB : Rod, stationary thin wall barrel, Bottom Anchor pump.

RSA : Rod, stationary thin wall barrel, Top Anchor, soft packed plunger
pump.

RSB : Rod, stationary thin wall barrel, Bottom Anchor, soft packed plunger
pump.

RHT : Rod, Traveling heavy wall barrel, Bottom Anchor pump.

3.18
RWT : Rod, Traveling thin wall barrel, Bottom Anchor pump.

RST : Rod, Traveling thin wall barrel, Bottom Anchor, soft packed plunger
pump.

TH : Tubing, heavy wall barrel pump.

TP : Tubing, heavy wall barrel, soft packed plunger pump,

Complete pump designations are as follows:

(1) (2) (3) (4) (5) (6) (7) (8) (9)

XxXxXx)()()()( )()(

(1) Tubing Size 15 means 1 1/2” Nom. Size Tubing i.e. 1.900” OD (48.3 mm)

20 means 2“ Nom. Size Tubing i.e. 2 3/ 8“ OD (60.3 mm)

25 means 2 1/2” Nom. Size Tubing i.e. 2 7/8” OD (73.0 mm)

30 means 3 1/2” Nom. Size Tubing i.e. 3 1/2” OD (88.9 mm)

and so on
(2) Pump bore (basic): 125-1 1/4” (31.8 mm)

150-1 1/2” (38,1 mm)

175-1 3/4” (44.5 mm)
178-1 25/32” (45.2 mm)
200- 2“ (50.8 mm)

225- 2 1/4” (57.2 mm)

3.19
 250-2 1/2” (63.5 mm)
275-2 3/4” (69.9 mm)
and so on

(3) Type of pump : R - Rod

T - Tubing

(4) Type of barrel : H-Heavy wall pump

W-Thin wall pump
S-Thin wall pump with soft packed plunger
P-Heavy wall pump with sotl-packed plunger

(5) Location of seating assembly:

A-Top Anchored
B-Bottom Anchored
T-Bottom Anchored ( for Traveling Barrel pump

(6) Type of seating assembly:

C-Cup type

N-Mechanical type

(7) Barrel length : In feet, like 10’, 12’, 14’16’, 18’, etc.

(8) Nominal plunger length : In feet, like 3,’4’, 5’etc.

(9) Total length of extensions, which includes top and bottom extension of
barrel : In feet, like 2’, 3’ etc.

3.20
Example:

25-175 RHAM 16-4-3

Here, 25 means 2 1/2” tubing.

175 means 1 3/4” plunger opening or pump bore.

RHAM means Rod, Heavy wall, Top anchored, Mechanical type hold down.

16 means 16’barrel length.

4 means 4’ plunger length.

3 means a total of 3’ extension on both sides of the barrel say 2’ on one side &
1’ on the other side.

Calculation of barrel length& barrel extension length

Given plunger length =4’

and Surface stroke length (Max) = 144”

Therefore the effective total length = (4’ x 12icL) + 144”

ft
= 48” + 144” = I 9211

So, barrel length = 192” = 16’

12 irdft

3.21
Now in order to calculate barrel length, Rod stretch, over-travel, necessary
connections inside barrel like traveling valve’s connection, top connection of
plunger and with some allowable space known as dead space have to be taken
into account. Therefore barrel length must be more than 16’. It is an usual
practice to take barrel length of 16’ and then to add barrel extension on its two
sides to keep the pump cost minimum.
So, barrel length = 16’
and say barrel extension = 3’ ; Say 2’ at the top and 1‘ at the bottom of the barrel.
Therefore, the total effective length of the barrel = 16’ + 3’ =19’.

3.2.5 SPECIAL PUMPS

3.2.5.1 RING-VALVE PUMP (Refer /%g.3.9)

The Ring-valve pump consists of a conventional top-hold down pump with an

additional sliding check valve in the pump above the traveling valve. The ring
valve slides up and down along the valve rod. It resembles a two stage pump.

During upstroke of the pump, the traveling valve pushes the liquid up as usually
and the liquid passes through the ring valve in the tubing.

But during downstroke ring-valve gets closed at the outset due to the fluid load in
the tubing with theoretically no tubing load effect on the traveling valve. This
leads to drop in pressure in the space between traveling valve and ring valve and
that ensures an early opening of traveling valve and smooth transfer of fluid in
the barrel from below the traveling valve to above it.

3.22
The presence of the ring-valve in the insert pump has the following advantages.

1) Conventional pumps generally operate with low efficiency for pumping

fluids with substantial quantity of free gas. They also are susceptible to
gaslock or fluid pounding. Both of these conditions can be attributed to
the delay in the opening of the traveling valve. However, the ring valve
pump enables the traveling valve to open early and thus eliminates or
mitigates the occurrence of gas locking or fluid pound conditions. Thus, it
helps to increase the efficiency of the pump.

2) In case of sand laden fluids, the use of ring valve pump has a distinct
advantage. For Top Hold-down pump, during the idle hours of the pump,
sand settles on the top of the pump and some may get into the plunger-
barrel clearance specially when the plunger stays at the middle or at its
lower most position. Ring-valve pump only allows the sand to settle on top
of the ring-valve and thus arrests the sand to settle over the pump as well
as in the plunger–barrel clearance. So, break-down of pumping action will
not take place when the pump is restarted.

3) In the case of high viscous fluid, ring valve pump has certainly an edge
over the conventional pump because of its unique two stage pumping
action.

4) During the downstroke of the pump, the buckling of sucker rod string at its
lower most ends can be avoided in the ring valve pump since this type of
pump allows an early opening of the traveling valve. In other words, this
type of valve action can keep the lower sections of sucker rod strings
always in tension which thereby prevents to develop kinks in the rod and
so helps increase the rod life.

3.23
Notwithstanding the above number of advantages, Ring valve pump can create
fluid pound on the upstroke. During the upward movement of the sucker rod, the
ring valve does not open at the very start of the upstroke. Since the space
between the ring valve and travailing valve is only partly filled with liquid, so during
upstroke, the liquid column above the traveling valve can pound on the ring valve.
We can only logically say that this fluid pound occurring during upstroke will have
a minor adverse effect on the operation of the pump.

3.2.5.2 THREE -TUBE PUMP : (Refer Fig. 3.70)

Three-tube pump has the combined features of a traveling and stationary barrel
rod pump. The traveling barrel creates a fluid turbulence and thereby prevents
the sand getting settled in the pump. The top traveling valve prevents sand entry
in the barrel tubing clearance.

In the three-tube pump, the barrel tube with a standing valve is surrounded by two
concentric traveling tubes that are joined together at the top of the pump with a
traveling valve on top of them. The inner tube out of the two concentric traveling
tubes acts as a plunger and has another traveling valve located at its bottom.
The outer concentric tube is similar to a traveling barre!. These three tubes are
loosely fitted to each other with about three times as much clearance as the
largest fit between metal plungers and barrel of a conventional pump. Generally
the clearance of the three tubes is of the order of 0.015 inch between each
successive tube wall.

During upstroke both traveling valves are closed and standing valve is open.
Because of the loose fit among the three tubes, well fluid can leak through the
annular spaces from the high pressure area i.e. in the tubing above the pump
towards the low pressure area that is below the bottom traveling valve. Again
during the downstroke both traveling valves are open and standing valve is

3,24
closed. Well fluids from high pressure area that is below the lower standing valve
are displaced above the standing valves and a small fraction of the fluid escapes
through the small bore at the top of the plunger tube as well as through the loose
fit between the plunger and stationary barrel to enter into the tubing. The leakage
rates are not appreciable because of comparatively large pressure drop
developed in the clearances between the plunger and barrel fit.

If we look at the conventional pump for pumping sand-laden fluid, we experience

that abrasion wear is less if barrel plunger fit is increased but this, at the same
time, entails a drastic drop in the quantity of fluid pumped. In this respect three
tube pump results in negligible wear of the moving parts and at the same time
creates sufficient turbulence inhibiting sand from settling into the pump.

3.2.5.3 TOP AND BOTTOM ANCHOR ROD PUMP: (Refer Fig. 3.11)

In the top and bottom anchor rod pump, the advantages of top hold down and
bottom hold down pump are combined. Top hold down pump is a stable pump
and it is more common. It prevents the settling of the sand in the pump.
However, the barrel of this type of pump is subjected to high differential pressure
and therefore this pump cannot work at deeper depths. Bottom hold down has
the features which equalises the pressures on two sides of the barrel and is
therefore preferred for deeper installations but it is not as steady as the top lock
pump and there is chance of sand accumulation in the barrel-tubing clearance.
Therefore dual anchor rod pumps i.e. top and bottom anchor rod pumps are
recommended when the pump is to be installed at greater depths and specially
when sand-laden fluid is to be pumped out.

The bottom hold down is usually of the mechanical type and provides most of the
necessary hold down force. The upper or top hold down is a cup type one which
ensures a seal on top of the pump as well as prevents vibration of the pump.

3.25
3.2.5.4 PUMPS WITH HOLLOW VALVE ROD: (Refer Fig. 3.12)

The valve rod in stationary barrel rod pump connected to the plunger has a
tendency to buckle during the downstroke of pump due to compressive load
operating there. The chances are more, specially in deep wells. Therefore the
use of a hollow tube called ‘pull tube’ in place of a valve rod either greatly reduces
or totally eliminates the buckling problem.

The pump consists of a standing valve, fixed barrel, moving plunger, bottom
traveling valve and bottom hold down similar to a stationary barrel bottom hold
down rod pump. The critical difference is that here the plunger is connected. with
a hollow valve rod with a small port at its lower end and a top traveling valve at its
uppermost end.

During upstroke, the bottom traveling valve in the plunger is closed

due to the fluid load in the tubing. The standing valve opens and
well fluid enters the barrel below the bottom traveling valve. As the
upstroke proceeds, the plunger displaces out the fluid from the barrel chamber (
i.e., fluid from the top barrel chamber ). As the plunger starts the downward
journey , the chamber space above the plunger starts increasing which results a
drop in pressure in that area. This decrease in pressure causes an early closure
of the top traveling valve and early opening of the bottom traveling valve. The
standing valve is closed and the plunger displaces the fluid in the barrel below the
bottom traveling valve into the barrel chamber above the plunger.

This type of pump operation resembles a two stage pump operation so it can be
said to be a two-stage hollow valve rod pump. This pump provides good
operation in wells with both gas and sand problems. Although the fluid path as
provided inside the pump ensures a complete removal of sand particles during
pumping, but settling of sand in between the tubing and barrel cannot be
prevented. Therefore this two stage pumping action can be treated ideal for

3.26
pumping fluids with high GORS and in sand cut wells. This type of pump can also
find its application when the pump is run on a packer and the well fluid including
the free gas is forced to enter into the pump.

3.3 SUCKER ROD STRING

Sucker rod string, in fact, is the vital link between the sub surface pump and the
pumping unit. These sucker rods are available as per API in three different
lengths -25’, 30’and 35’. These are connected to each other upto the depth of
the pump. These are solid steel bars with forged upset ends with threads on it.
API has standardised these solid steel sucker rods. The diameter of the rod body
ranges from 1/2” to 1 1/8” with 1/8” increments. Usually the rod body of
diameters 5/8”, 3/4”, 7/8” and 1 “ are very common. At each end of the sucker
rod there is a short square section just before the sucker rod pin thread which
facilitates the use of sucker rod tongs for connecting two sucker rods. These
sucker rods are generally available with one coupling fitted at one end ( So, one
end of the sucker rod is called “pin end’ and the other end is called “box end”).
Sometimes due to limitations of tubing I.D slim hole couplings are used.

3.3.1 SUCKER ROD MATERIALS

The material of steel sucker rods has more than 90% iron content. Other
elements are added to increase strength and hardness, resist corrosion etc.
Steel used for manufacturing of sucker rods can be categorised in two ways viz.
carbon steel and alloy steel. Carbon steels contain carbon, manganese, silicon,
phosphorous and sulphur , whereas alloy steel contains additional elements like
nickel, chromium etc., as per the necessary requirements like more rod strength
etc.

3.27
API has standardised different grades of sucker rods of which grade ‘C’ is the
carbon steel sucker rods and is the least costly. Grade ‘D’ sucker rods is the
chorine molybdenum alloy for higher range of strength; other than the above
mentioned two grades, grade ‘K’ is a special nickel, molybdenum alloy used in
moderate corrosive fluids.

A table indicating different tensile strengths of different rod grades viz.’C’, ‘D’, & ‘K’
has been given below:

Rod Composition Tensile Strength, psi

I Grade
I Min. Max. I
K AISI 46 85,000 115,000
c AISI 1536 90,000 115,000
D Carbon or Alloy 115,000 140,000

Chemical and Mechanical Properties API Sucker-Rod Materials According to API Spec. 1.16.

Operating, sucker rods for a low fluid level at a much deeper depth of around
2500m or more, the grade ‘D’ rod fails to perform because of the calculated stress
in such cases exceeds its allowable stress. Due to this some Non-APl high
strength Sucker rods have come into the market. [Some of these are Norris
make ’97’ grade type and oilwell make ‘EL’ grade type].

Hollow sucker rod tubes can also be used to advantage in slim hole completions.
Since fluid lifting takes place inside the hollow sucker tubes, no tubing is needed
in the well. So, the application of hollow sucker rods is restricted to lower fluid
rates due to the obvious reason that large fluid volume involve greater pressure
losses inside the tube. The hollow rods also require special well head consisting
of hollow polished rod and flexible hose connected to flow line. Sometimes high

3.28
sand production can be well tackled with this system. Injection of corrosion
inhibitors can also be accomplished properly with the use of hollow rods.

Fibre glass sucker rods figure in the API specifications. These rods are low
weight, corrosion resistant, non-metal and therefore have definite advantages
over steel sucker rods specially when the pump is to operate in very deep
corrosive wells. A long steel rod string is normally heavy weight material and the
weight increases with the increase in area of the plunger due to the liquid load on
the plunger. The fibre glass rods became commercially available from 1977. The
individual fibres have high tensile strength and depending on the resin/glass ratio,
during the process of the manufacture of the final rods, the fibre glass rods
develop a strength of 110)000 -180,000 psi which is about 25% stronger than the
steel sucker rods. At the same time, rod weight of fibre glass sucker rod is only
about 1/3rd of the weight of steel sucker rods. When subjected to an axial force,
fibre glass rods elongate 4 times more than that of steel. This excessive rod
stretch prohibits the use of only fibre glass rod string in the well, rather they are
used in combination with steel sucker rod, where top portion of the rod string is of
fibre glass rods and bottom portion is of steel rods. This combination of fibre
glass and steel rods weigh only about 1/2 of that of an all steel sucker rods.
Fibre glass rods are available in nominal sizes ranging from 5/8” to 1 1/4”. While
installing the fibre gloss rods in the well, it must be ensured that the environment
in the well is within the safe operational temperature for fibre glass rods to
operate.

3.3.2 BENEFITS OF FIBRE GLASS SUCKER RODS

The advantages of using fibre glass rods are many. The most important
advantage is that the production rate can be increased manifold from a well with
the help of a smaller pumping unit. For example if the stroke length is 80 inches
at the polished rod, then at the pump, the stroke length will be even 3 x 80 i.e 240

3.29
inches. Therefore while installing sucker rod pump care is to be exercised that
sub-surface pump should have sufficient stroke length to match the requirement
of fibre glass stretches.

Fibre glass sucker rods, even today, are more expensive than steel rods as well
as these require very careful handling and that is why their application is very
limited.

So, when the wells are very deep say around 3500 m and above, static fluid level
is high/ low and P.1 is very high fibre glass sucker rods in combination with steel
sucker rods will logically be an appropriate choice of lift system.

3.3.3 SUCKER RODS JOINTS

Sucker rod joints are probably the most important aspect in making a perfect
integrated system of the rod string. It is of utmost importance for an engineer to
understand the mechanism of these joints. Sucker rods are joined with the help
of couplings. These couplings are also API specified. The threads are plain and
therefore it is easy to put a coupling on sucker rod pin and to rotate it just by
hand. The end of the sucker rod coupling (shoulder) which is in contact with the
pin flat face (shoulder face) should than be tightened ( shoulder to shoulder joint)
with a proper make-up torque between the two parts to enable the two sucker
rods to form one integrated body with a coupling in between them. The
distribution of stresses in a sucker rod joint has been given in {Figs. 3.13A, 3.7313
& 3.73C ), where upper portion of the coupling is in compression and pin-inside in
tension. Unless and until the stresses between them are relieved, it will not be
possible to disconnect the Sucker Rods. This ensures that the accidental
unscrewing of sucker rods will not occur during the operation of the pump.

Rod loads during pumping cycle are cyclic. During upstroke, the rod loads are
caused due to rod weight, fluid weight, load due to acceleration and friction and

3.30
during downstroke rod load is due to rod weight only which is to some extent
reduced due to negative acceleration. Therefore, the cyclic nature of rod weights
demands a perfect coupling of sucker rod pin-joint.

Rod joints are usually made up with the using pneumatic or hydraulic power
tongs. These power tongs exert a desired torque on the joint.

In many of the ONGC fields, a comparatively easy system to generate the

required make up torque is being practised.

At first the pin and coupling are made up to a hand tight position. Thereafter, two
spring loaded tongs (jerk type tongs) are put over the square area of two sucker
rods (one tong above the coupling and other is below it ) in such a way that they
make nearly 40 degrees between them in front of the person who is holding one
tong with one hand and the other tong with his other hand. With the help of
concurrent jerks from the two hands, approximately 3-4 times, a required make-
up torque is created. This matter was discussed with Mr. R.H. Gault (Bob Gault)
a renowned expert on sucker rod pumps. He was convinced and approved this
system but at the same time he cautioned that this system be restricted to a
shallower depth say within 1500 m. For greater depths, pneumatic or hydraulic
power tongs are a must.

3.4 GAS ANCHORS

Presence of free gas in the pump barrel ( Fig. 3.14 ) not only reduces the
efficiency of the pump but presents some typical operational problems. On the
downstroke, the traveling valve does not open at the start of the plunger making
downward journey, rather, the opening of it is delayed considerably. The free gas
collected over the liquid surface in the barrel, at first, starts dissolving in liquid with
very little increase of pressure in the barrel. When all the free gas goes into

3.31
solution, the fluid in the barrel turns into an incompressible fluid and as a result
the pressure in the barrel starts building up with the downward movement of the
plunger. As and when fluid pressure in the barrel exceeds the tubing load (fluid
load), the traveling valve opens and the transfer of fluid from barrel to tubing
above traveling valve takes place.

Secondly, on the upstroke, the standing valve does not open immediately at the
start of the upstroke. Its opening is again delayed. Due to dissolved gas in the
liquid in the dead space of the barrel, the pressure of the fluid in the barrel falls
gradually with the liberation of gas from it. When the pressure from below the
standing valve exceeds the pressure in the barrel, the standing valve opens
which allows fresh fluid to enter into it. This clearly demonstrates that the
plunger’s effective stroke length is savagely cut. As a result, a considerable
reduction of pump displacement, takes place, resulting in lowering of pump
efficiency. The decrease of pump Efficiency is quite unpredictable and may be in
the in the range of 30%, 40%, 50%, etc. depending upon fluid intake and free gas
generation. In extreme case, a complete 100% reduction of efficiency occurs. It
is then said that pump is “gas-locked”. In this gas-locking case, only the
expansion and contraction of a compressible fluid take place during the upstroke
and downstroke of plunger with no fluid transfer from barrel to tubing.

The presence of gas in the barrel creates operational problem in the sense that,
the barrel is then partly filled with liquid and gives rise to some peculiar problems
like “gas pound” and “fluid pound”. These can cause unscrewing of rods or
create kink or bend in the rod resulting in pump failure..

Free gas occupation of barrel space in the pump depends upon its depth of
installation. If the pump is placed at greater depth, the free gas generation will be
less and, if it is placed at shallower depth, the free gas generation in the pump
will be more.

3,32
Considering the above facts, it is essential to adopt some types of remedial
measures to prevent gas generation in the barrel. The pump of longer stroke
length, lesser SPM, more plunger diameter, lesser dead space, some other
special pump like ring valve pump etc. are some of the measures to mitigate
free gas interference in the pump. But the most effective method to prevent the
gas interference in the pump is to install downhole gas separator called gas
anchor before the intake of fluid in the pump. All the gas anchors operate on the
principle of gravitational separation. Liquid and free gas, owing to their large
difference in gravity, are separated in the casing tubing annulus. Gas goes up in
the annulus and is let through a non-return valve fitted on the well head annulus-
flow line. Also, this produced free gas from the annulus may be utilised to
operate the gas engine as prime mover of the pumping unit.

Gas anchors are broadly classified into three main categories as

1) Natural Gas anchor

2) Packer type gas anchor

3) Poor boy gas anchor

3.4.1 NATURAL GAS ANCHOR: (Refer /%g.3. f5)

The simplest and most effective gas anchor is the natural gas anchor. The very
meaning of the natural gas anchor is to facilitate gas separation from the fluid by
gravity before it enters into the pump, In order to do the natural gas separation,
the pump is set a few feet below the level of the lower most casing perforation, so
that when liquid and free gas enter the well bore, gas goes up the annulus and
finally finds its way out through a non-return-valve at the surface into the flow line
and gas-free oil goes into the downhole pump intake. The following are the

3,33
necessary requirement conducive enough to create a NATURAL GAS ANCHOR:-
(i) The well produce more free gas than the acceptable limit of the pump (ii)
surface unit, rods and pump types must permit to lower the pump at the reqtiired
deeper depth (iii) There should be adequate sump to place the pump below
perforation.

3.4.2 PACKER TYPE GAS ANCHOR: (Refer Hg.3.16)

Packer type gas anchor is considered next to natural gas anchor as per gas
separator efficiency is concerned. When Natural type gas anchor can not be
provided, because of the reasons as explained above, Packer type gas anchor
can be considered as a suitable alternative. The salient features of this Packer
type gas anchor is that the packer is installed below the pump intake point and
above the perforation. Formation is directed through a small by-pass pipe
extending through the packer upto a certain comfortable distance above the
pump intake point. As the fluid ejects out from the by-pass pipe into the much
larger cross-sectional area of casing-tubing annulus, a good separation of free
gas from liquid results. Free gas travels up the annulus and finds its way into the
flow line. Liquid then falls back and enters the pump intake.
Because of the very presence of packer, well completion is not simpIe.Sometimes
conditions do not favour the packer completion. Because of these factors the
packer type gas anchor is not very popular and is limited to certain categories of
wells. Also, small by-pass pipe may restrict the fluid flow rate.

3.4.3 POOR BOY GAS ANCHOR: (Refer Fig.3.f7A)

Next to the packer type gas anchor, poor boy gas anchor is considered. It
basically consists of a mud anchor perforated at the top and a dip tube called the

3.34
pull tube inside the mud anchor. The gas anchor is run immediately below the
pump where the pump suction has direct access to the pull tube.
The formation fluid, at first, rises through the gas anchor-casing annulus. It then
enters the mud anchor through its lower perforations with some free gas part
travels up the annulus. As the mixture travels downwards to the intake of the pull
tube during pump operation, the free gas separates out in the pull tube-mud
anchor annulus and finds its outlet through the top perforations of the mud
anchor, into the annulus and finally the gas is bled in the flowiine like in other
types of gas anchors. The gas-free oil goes into the suction of the pump through
the pull tube.

While making an effective poor boy gas anchor, the primary care should always
be taken for proper sizing of every component of the poor boy gas anchor. The
technical requirement of each component of the gas anchor are enumerated
below:-

Mud Anchor
Mud anchor is made out of the available tubular goods for example 3 1/2” tubing
or 4“ tubing or 4 1/2” tubing etc., primarily governed by the well casing diameter.

Pull Tube

Pull tubes are usually 1 “ or more in diameter and is limited by the I.D. of the mud
anchor.

Required Annular Area Between Pull Tube and Mud Anchor

More the annular area, better the separation of gas from oil. Therefore care
should be exercised so that larger annular area is made available for effective
separation.

3.35
Length of the Quiet Space

More the length of the quiet space better is the separation.

Diameter of the Pull Tube

If the diameter of the pull tube is more, then the liquid ( I,e.,gas-free liquid) during
the course of its movement towards pump inlet encounters less friction and this
will minimise further free gas generation to minimum.

Length of the Pull Tube

More the length of pull tube, more will be friction inside the pull tube and so there
would be greater chance of free gas breakthrough from the oil body, during the
liquid travel through the pull tube into the pump barrel.

By considering entire scenario along with the escape velocity in mind, a suitable
design of gas anchor can be worked out for each casing size, pump type and
fluid parameters. Some published empirical relations are considered to calculate
the proper size of poor boy gas anchor.

3.4.4 POOR BOY GAS ANCHOR WITHOUT PULL TUBE: (Refer Fig.3.17B)

Since the advantage of a poor boy gas anchor is negated to some extent due to
presence of pull tube as discussed in the foregoing statement, the poor boy gas
anchor has been made simple by omitting the pull tube and in place of that, pump
barrel itself is utilised as the pull tube. By looking at the Fig. 3.17 it is clear that
this type of gas anchor is applicable only for top hold-down insert pump. By this
measure an efficiency of the gas separation can be expected to be increased
further by about 20- 30%.

3.36
Inthelight of the above discussion itisclear that natural gasanchoris the most
preferred type where it is applicable or feasible. Next to that, for reasons of
simplicity, poor boy gas anchor is preferred and wherever the pumps are ofinsert
and top hold down type, the poor boy gas anchor without pull tube is, invariably
the first choice over the general poor boy gas anchor. The “Packer type gas
anchor can be utilised when neither Natural gas anchor is feasible nor Poor boy
gas anchor is effective.

3.5 SINKER BAR

A few number of sinker bars just above the pump provide the stability of the
downhole SRP operations due to their increased weight on the pump. These are
the bottom-most part of the sucker rod string.

During downstroke, the rod string as well as the plunger move downward but
generally both do not move at the same speed. The lower part, that is the
plunger, is subjected to compression because of the impact of fluid pressure
built-up in the barrel.

Also since barrel-plunger clearance is very small, as such, the movement of

plunger takes place with close tolerance, a viscous drag force results due to fluid
trapped in the clearance space. The total effect of these upthrust is highly
detrimental to the operation of the pump. This may lead to buckling, developing
kinks or unscrewing of sucker rods. This problem becomes more severe for the
kinds of combination of rod string, where the lowermost size of the in a tapered
sucker rod is 5/8”.

Besides, some loss of liquid production can take place due to reduced plunger
stroke, as a result of this phenomena as explained above.

3.37
Therefore in order to overcome these undesirable effects, heavier sucker rods or
sinker bars, which are heavy solid steel rods are run as part of rod string at its
lower most end i.e., they are located just above the pump. These heavy sucker
rods or sinker bars absorb the upthrust to a great extent as well as impose an
extra load on the plunger to speed up the plunger during its downward journey.
Thus its provide a stability of the operation of pump.

In erstwhile USSR, most of the sucker rod pump wells are completed with a few
heavier sucker rods installed just above the pump. For example, a sucker rod
pump well is completed with 1 “, 7/8” and 3/4” and in that well about 60 m or so 1
“ rods are installed at the lowest end of the string just above the pump. In USA,
many pumping wells are completed with a few 1 1/2” wireline sinker bars with
matching threads. Each sinker bar is about 4-5 feet in length. In many of the
ONGC oil wells a few heavier rods (about 6-18 in number) are lowered just above
the pump. Of late, a new type of sinker bar has been designed which is
approximately 12 feet in length and most of its part is of 1 1/2” dia with the top
neck of 1 “ dia for making the room to hold the sinker bar with 1” elevator with the
top end having similar end connection of sucker rod %“ pin end and the bottom of
%“ pin thread.

In fiber glass rod completion, heavy rods are an absolute necessity.

3.38
3.6 ROD GUIDES, SCRAPERS, ETC. LONG SUCKER ROD COUPLING AND
USE OF A NUMBER OF PONY RODS IN THE SUCKER ROD STRING
COMBINATION

Rod
When sucker rod pump is in operation, whole rod string moves up and down as
well as tubing also moves a little up and down because of the expansion and
contraction of tubing/sucker rods.

It invariably results in rod tubing friction. Since, metallurgy of the rod is inferior to
that of tubing, so most of the wear and tear results on rods. The friction becomes
severe when the wells are crooked and inclined. Due to the wear of the metal
parts, strength of the rod decreases and eventually failure of rods result.

In order to overcome such rod tubing friction, several common field practices
being used for a long time have been discussed as below :---

1) Use of a number of small length pony rods at the vulnerable points where
friction is more, help save the abrasion of sucker rod body Here only the
sockets get worn out. Due to wearing out of only socket (higher O.D than
the body sucker rod ), the frequency of failure of sucker rod string is
reduced.

2) Extra long sucker rod coupling is more effective than the normal coupling.
So, extra long couplings with pony rods at the vulnerable points can
further reduce the frequency of sucker rod failure.

3) The scrappers are fitted on to the sucker rods at the specified interval.
These scrapers not only protect the sucker rod body from getting worn out
but also creates turbulence to prevent the settling of sand and mitigate

3.39
 the paraffin build- up in the tubing. These scrappers areeither made of
hard plastic material or metal.

Metal scrapers are available in two hemispherical shapes. These two

hemispherical shapes are placed around the sucker rodsand then press-fitted
with the helpof specially designed vice. These press fitted parts are then welded
with each other ( welding is not done with the sucker rod ). Therefore scrapers
fitted on to the sucker rods are fixed at that point and are not liable to slide.
Plastic scrapers are placed around sucker rods with long heavy duty pipe wrench.
They are generally of blade-shaped.

These scrapers however have not been found very effective. Generally they get
dislodged and slide along with the up and down movement of rod and often they
get jumbled at one place. Plastic scrapers have been found to even get detached
from the rods and get accumulated around the sucker rod over the pump. These
often creates typical pump operational problem.

4) Rod Guides

The sucker rods with a few built-in rod guides located at suitable interval of the
length of the sucker rod has been found most effective. These rod guides are
factory-mounted metallic guides and moulded permanently to rods. The
perceptible advantage of this is that because of its very nature of fitting ( factory
moulding) with the rods they do not slide over the length of the rods and therefore
drastically reduces rod failure by minimizing the wear of sucker rod body. In
many oil fields, moulded guides are most preferred. The moulded-rod guides
system is considered the best for inclined wells (L or S type) and in the dog-
Iegged portion of the well.

There are other rod guides like wheeled rod guides where several wheels are
placed in special couplings. These wheels are placed at 45 degrees angle with

3.40
each other and roll on inside surface of tubing during the up and down movement
of the sucker rod and thus because of the rolling action the rod encounters a
minimum friction. Although the design feature seems very attractive but it
cannot work very effectively when the inclination is very severe, dog-legged and
well profile is in the shape of ‘S’. The wheels get flattened at one side of sucker
rod string where excessive friction takes place. These ultimately effects pump
operation.

3.7 WELL HEAD EQUIPMENT (Refer Figs. 3.18A & 3.18B)

The sucker rod wellhead is not like the normal wellheads. The material difference
is the presence of polished rods projecting out of wellhead in case of sucker rod
pumping system.

A normal wellhead consists of a master valve, flow Tee with wing valve and crown
valve. In case of sucker rod pumping wells, it is ideal to have one stripp er in
place of master valve and stuffing box in place of crown valve. The flow Tee
and wing, valve are similar to that of normal wellhead. The stripper in SRP well
can work as a master valve. When the stripper valve is closed, it closes the
polished rod-tubing annular space and thus cuts off the fluid flow.

Every care is to be exercised to prevent any leakage from the stufftng box. Many
improved designs of stuffing boxes are available in the market. To name a few,
are 2-tier, 3-tier stuffing boxes made by M/s. TRICO, USA. The stuffing box
packing is made of rubber element with metallic supports and needs to be
replaced as and when these are necessary. These rubber elements get worn
out quickly if the polished rod is not properly centred. Also, if the stuffing box is
very tightly packed or is not having the proper lubrication by the well fluids, the
rate of wear of rubber packing becomes very fast. In order to overcome this, a
small lubricator box made of aluminium inside of which is lined with flannel type

3.41
cloth material is placed just above the stuffing box. It stays on the stuffing box
around polished rod during polished rod movement. This lubricator is filled with
lubricating oil like engine oil. The engine oil stored in the lubricator drips slowly
into the stuffing box. It has been experienced that approximately once or Mice in
a month the lubricator is required to be filled with engine oil.

Self-aligned type stuffing box is also available. It aligns easily with the off-centred
polished rods. This type of stuffing box has the less damaging effect on the
rubber elements. This alongwith the polished rod lubricator will apparently be the
ideal choice of a stuffing box .

It is equally important that stuffing box cap should never be over-tightened since
over-tightening can squeeze the lubricating material out of the packing elements
and subsequently packing elements get dry and in such a case early damage of
packing material occurs. Therefore it is advisable to adjust the tightness of
packing elements periodically to have a longer trouble-free functioning of packing
elements.

The stuffing box and its packing sizes should conform to the size of the polished
rod, i.e., the diameter of the polished rods.

During the operation of the sucker rod pumps, free gas in the well accumulates in
the casing and finally finds its way out through the annulus to the surface either in
the well-fluid flow line or in the gas engine prime mover at the wellhead for
running the surface unit. Usually the flow line and casing vent line are connected
through a check valve which allows the gas to vent into the flow line and prevents
well-fluid to flow back in the well through the annulus.

3.42
3.8 TUBING ANCHORS

When the pump is in operation, the tubing string and rod string are successively

subjected to a varying load (Refer Fig. 3.19 ) On the upstroke, the rod is loaded.
The traveling valve is closed, and the fluid load is on the travailing valve. On the
downstroke, the fluid load is transferred to the tubing. The standing valve is
closed and traveling valve is opened and the liquid load in the tubing is on the
standing valve. Therefore, in each pumping cycle, a freely suspended tubing
string periodically stretches and contracts. This results into the buckling of tubing
string, which sometimes becomes very severe. Due to this effect, not only the
pump displacement is reduced because of reduction of stroke length, but also
causes operational problems due to alternate stretching /contraction of tubing
string and sucker rod. The friction between the rod and tubing can lead to rod or
tubing failure, There are several ways to contain the buckling of the tubing caused
due to movement of rods. The most effective way is to anchor the
tubing string by a tension type anchor. This tension type anchor can be set at any
depth in the casing and the tubing is always kept in tension such that the rod
movement will not create any up or down movement of tubing.

Two types of tubing anchors are known :

1) Mechanical type tubing anchor catcher.

11) Hydraulic type tubing anchor catcher.

1) MECHANICAL TYPE TUBING ANCHOR CATCHER

The mechanical type tubing anchor catcher has the advantages of both the
tension and compression anchors. This anchor is set by doing the left hand
rotation of string and at the same time by moving the string up and down. By
this process the cones pushes the slips out of the catcher body, which
subsequently is pressed against the casing tightly. Thereafter, the required

3.43
surface pull on the tubing string equivalent to the desired tension in the tubing
strings is given and with the tension in the tubing string, the wellhead is fitted at its
place.

In case, the unseating of anchor is required then the tubing string is given a right
hand rotation and along with it the tubing is made to move up and down slightly.
By doing so, cone retrieves back and the slips gets back inside the catcher body.
Thus, lower end of the tubing is made free before the tubing is pulled out of the
well or to readjust the length of the tubing string.

DRAWBACKS: This anchor has certain drawbacks, which are as follows: ---

1. Due to left hand rotation there are chances of opening up of tubing joints,
since tubing joints are right hand rotation type.

2. It is very difficult to release anchor-catcher even by doing the right hand

rotation of tubing string when anchor is kept in well for a prolonged period.

3. The special type of wellhead which should house slips to anchor and

support the tubing at its stretched position, is required.

11) HYDRAULIC TYPE TUBING ANCHOR CATCHER

Hydraulic tubing anchor is set in the well automatically by creating a difference of

tubing and annulus pressure (approx. 100-200 psi, where tubing pressure is
more than the annulus pressure) and when it is required to be released, the
pressures in tubing and anrwlus have to be made equal. Since hydraulic tubing
anchor-catcher operates due to pressure difference between tubing and annulus,
it is always to be placed above the pump in the tubing string.

3,44
DRAWBACKS

1 Due to alternating stress in tubing, the packing element of the piston of

hydraulic anchor catcher gets damaged and that point becomes a source of
leakage of fluid in tubing string. Thus the pump fails to pump any liquid to
the sutface.
Because of these shortcomings of both these type of anchors i.e.,
mechanical and hydraulic tubing anchor catcher, installation of tubing anchor-
catcher is discontinued in SRP wells of ONGC. Instead, in many SRP wells some
additional tubings, ( if possible tubings of higher p.p.f. ) known as tail pipes are
added below the pump catcher. This will always keep the tubing string as
stretched as possible and prevents tubing from getting buckled. Also it helps to
unload accumulated bottom water from the well & there by increase drawdown.

3.9 REGULAR CHECKING, MONITORING AND TROUBLE SHOOTING

3.9.1 REGULAR CHECKING

Once everyday for about 5-10 minutes the person from group gathering station
should visit each sucker rod pumping well and try to detect any type of disorder
by a visual inspection. If there is none, then there is no need of doing any
changes. If there is any disorder then the pump should be stopped and
necessary steps must be taken for rectification.

During the visual inspection, the following basic things should always be observed :-

1) There should not be any abnormal mechanical noise of continuous or

periodic in nature.

2) To take a look at a few important connecting bolts and nuts like crank-pin
bearing nuts, saddle bearing nuts and bolts, base nuts and bolts etc.
These should not be loose. Once the pump is installed and

3.45
 commissioned, it should be mandatory that in between 10-1 5 days of
operation of the pump all the connecting nuts and bolts are to be
retightened by applying leverage, special care should be taken that crank
pin bearing nuts are adequately tight and locked. This part should be
checked again after 15 days or so.

3) Motor V-belts should be in proper tension to prevent slippage of v-belts on

the pulleys. The crank should rotate in a direction as earmarked on the
gear box by the manufacturer of surface unit.

4) The person visiting a particular pumping well should have a record of

position of polished rod clamp. {f the polished rod clamp is displaced,
then immediate measures must be taken for reinstallation of it at original
position position.

5) The polished rod should always be more or less perfectly centred with
respect to the well. If found otherwise, measures must be taken to
correct it.

SRP units should be stopped for one hour once in every month and all of their
bearings must be thoroughly greased and the level of oil in the gear box must be
checked and topped with oil, if required, to ensure that the oil level in the gear box
is in the maxima-minima range. Within about six months of operation from the
date of the commissioning of the pumping unit there is no need to change the
gear box oil. However, approximately in the seventh month, the gear box oil
should be changed and after flushing thoroughly the gear box oil chamber, the
gear box should be filled with new specified gear oil. Thereafter, for about five
years there is no need to change the gear oil. Also, the lubricator fitted over the
stuffing box should be checked and refilled by engine oil once or twice in every
month.

3.46
3.9.2 MONITORING AND TROUBLESHOOTING - ACOUSTIC SURVEYS

A packer is not normally run in a rod pumped well. Thus well fluids which fill the
casing-tubing annulus can be viewed as the reservoir to feed the fluid in to the
pump. The height of the fluid column in the annulus above the mid-perforation
is a measure of the well’s actual static bottomhole pressure when the pump is not
in operation for a reasonably long period and also the height of the fluid column
is a measure of the flowing bottom hole pressure when the pump has been
steadily and continuously operating for a reasonably long period.

The acoustic survey instrument i.e. echo-sounder is the potent instrument for
measuring the liquid level in the annulus. This instrument consists of two basic
components.

1. Well head assembly.

2. Recording and Processing assembly.

Wellhead Assembly

The wellhread assembly is connected to the casing annulus by means of a

threaded nipple. It contains a mechanism that creates a sound wave and a
microphone attached with it picks up the signal. The conventional well sounders
utilise blank cartridges which are fired either manually or by remote control.
Some other well sounder units employ gas gun which provide the required
pressure impulse by suddenly discharging a small amount of high pressure gas.
The microphone converts this to electrical signal which comes to the recording
and processing unit.

Recording And Processing Assembly

In this unit, the electrical signals are filtered and amplified. The processed and
amplified signals are recorded on a chart recorder as a function of time.

3.47
A number of peaks in the chart will be visible. From these peaks the tubing
collars are easily identified and the length of the tubing is estimated from the
number of peaks and average length of each tubing. (Refer Fig. 3.20 ). The
sound wave which hits the liquid level is characteristically a larger deflection in
comparison to those of reflected waves from the tubing collars. Therefore, the
liquid level peak can be easily distinguished from collar peaks. The repetition of
collar peaks and the liquid level peak will be recorded in the chart with the
diminishing intensity waves. In this figure, every tubing collar is identified by a
small peak of the signal and the liquid level by a larger deflection i.e. larger peak.
Therefore, the depth of the liquid level is determined by counting the number of
tubing collar signals and multiplying the same by the average length of each
tubing.

3.9.3 BOTTOMHOLE PRESSURE CALCULATIONS WITH THE HELP OF

ECHOMETER

Initially, annulus of the well is filled with the technical water (water for subduing
the well). During pumping, initially the fluid in the annulus enters the pump and in
this process, the annulus level comes down to a point when formation fluid starts
coming into the well bore. With the continuous operation of the pump and steady
inflow of formation fluid in the well bore, an almost identical gradient of fluid in the
tubing & in the annulus sets up. With the fluid gradient in consideration ( gradient

is calculated on the basis of fluid rate measured at surface. ) and fluid level in the
annulus, flowing bottom hole pressure can be calculated.

Sample Calculation

Say gradient in the annulus is 0.7 kg/cm2 per 10 meters. With the helf of acoustic
survey during operation of pump and in the stabilized flow conditions the depth of

3.48
liquid level is found to be sayapproximately 800 meters. Also let the depth of
perforation is 1200 meters.

Therefore, the depth of fluid in the annulus = 1200-800 = 400 m.

Therefore, the pressure at the sand face in the well bore during flowing condition

is 0.7 x 400/1 O = 28 kg/cm2

For calculating the static bottomhole pressure, the pump has to be stopped.
During this period, the filling up annulus with the incoming formation fluid takes
place. After of 24 hours or 45 hours or more depending how fast the static
pressure is reached, the further build-up of annulus level becomes negligible.
Then the liquid level is found with the help of echometer. The calculation of
pressure in the well bore at the sand face can be made in a similar manner, as
has been explained above.

3.9.4 Dynamometer:

Surface & Pump Card :

Surface Card :

Surface card is the recording of polished rod load over a complete pumping cycle
at the polished rod on the surface. The dynamometer instrument is placed in
between the polished rod and clamp and carrier bar so that whole load on the
sucker rod gets communicated in the dynamometer equipment.

Surface card is a combined reflection of surface unit, sub surface pump

operation, rod and fluid dynamics besides various other unpredictable situation
like frictional forces, vibrational aspects, ( especially when pumping speed is

3.49
synchronous with natural frequency of rod string), sticking of plunger, dragging
effect of buckled /twisted rod on the surface of tubing etc. These above have
made surface card a very complex one and at times it becomes very difficult to
interpret even by a very experienced analyst of dynamometer card. The
interpretation of surface card has been demonstrated as follows starting from the
very simple to very complex card.

(i) Simplest / idea surface dynamometer card

Ideal conditions area as follows: ---

1. Sucker rod pump is operative at a very slow speed and as such there are
no acceleration forces in the sucker rods.
2. There are no vibrational forces within the overall pumping system.
3. There are no frictional forces in the surface unit part as well as in the
downhole (between plunger& barrel; Rod & tubing).
4. The standing valve (S.V) and traveling valve (T.V) opens / closes at the
appropriate plunger position instantaneously (without any delay)
5. There is no stretch / contraction of rod and tubing due to the cyclic transfer
of fluid load.
The shape of the dynamometer card will be a rectangle.
Upstroke

‘?’
I J
D 4 c
Down Stroke

(ii) In addition to the ideal conditions as given in (1)from SI.NO.1 to 4, let there
be stretch / contraction in the tubing / Sucker rod due to the cyclic transfer
of fluid load.

3.50
 Then the shape of the surface dynamometer card will be a parallelogram,
as indicated below :---
Upstroke
A ➤ B

D
L_/ c
Down Stroke

The above two shapes are rarely encountered in the fields. Actual card is
very complex and numerous shapes of actual card are available. One of
the typical shape is given as under.

B D

A E

G F

● Point “A indicates the end of the down stroke and the beginning of the up
stroke for the polished rod.
● Line A to B – The traveling valve closes due to the fluid load on it, as the
plunger started its upward journey and the polished rod begins to pick up
the fluid load. This accounts for increase in polished rod load from A to B.
● Line B to C – The momentary decrease in polished rod load from B to C is
the result of rod stretch that occur, when the rod takes over the fluid load
completely.
● Line C to D - As the rod moves upward in approximately simple harmonic
motion (because of the action of surface unit), the acceleration load is
increased unit it reaches a maximum at point ‘D’ which is theoretically near
the middle of the up stroke.

3.51
 Line Dto E–From point ‘D’to point ‘E’ the acceleration load decreases
(because of the action of the surface unit as mentioned above), as the rod
velocity decrease to zero.
Point ‘E’ represents the end of upstroke and beginning of downstroke.
Line ‘E’ to ‘F’--- As the rod falls, the fluid pressure in the barrel increases
which opens the traveling valve and closes the standing valve. At point ‘F’
the fluid load is transferred on to the standing valve, i.e., the fluid load is
transferred on to the tubing. This is indicated by a marked decrease in
polished rod load from ‘E’ to ‘F’.

Line ‘F’ to ‘G’--- This represents the negative acceleration load as a result
of the action of the surface unit, which decreases the polished rod load
further. ‘G’ is the point where minimum polished rod load occurs and this

point is approximately near the middle of downstroke.

Line ‘G’ to ‘A’ --- This represents the decrease of negative acceleration
load due to the action of the surface unit. This effects an increase in
polished rod load.
Thus, in this manner a full cycle of dynagraph ( A-B-C-D-E-F-G-A ) is made
on the dynamometer chart at the polished rod.

Points to note :

1. No account has yet been taken of the effect of rod vibration and frictional
forces between the plunger and the barrel / between the rod and the tubing
on the shape of the dynamometer card. They are generally present and at
times, significantly contribute to total polished rod load.

2. When the pumping speed is synchronous with the natural frequency of rod,
the rod vibration becomes severe,This has been explained by Dr.
Slonneger in his book on sucker rod dynagraph analysys.

3.52
3. The other abnormalities like sticking of plunger, fluid pound, gas pound,
gas locking, delay in opening and closing of standing and traveling valves
etc., have not been taken into account in the above representative
diagram.

Thus the real surface dynagraph is a complex one and is difficult to be

Analysed properly. Surface dynamometer card may have many shapes but in
contrast, Pump card ( downhole card ) has only 45 to 47 number of standard
shapes. So it is preferable to convert surface dynagraph to pump card and then
the pump card is matched with the standard pump card shapes to determine the
condition of the pump operation.
The standard shapes pump card are given in figure number---

DYNAMOMETER CARD (DYNAGRAPHS)

The dynamometer card (load displacement curve) is a continuous record of the

resultant of all the forces acting on the polished rod at any instant during the

operation of the pump. The dynamometer card is recorded with respect to

polished rod position. The rod position (stroke length) is recorded on the
abscissa (X-axis) and loads on the ordinate (Y-axis).

With the help of these dynamometer cards, the following information is

generated.

1. Peak and minimum loads at the polished rod.

2. Torsional load on the speed reducer and prime mover.
3. Work done by the polished rod in lifting the fluid load against friction.
4. Proper counterbalance.
6, Number of rod load fluctuations per crank cycle.

3,53
3.9.4.2 TYPES OF SURFACE DYNAMOMETER ( DYNAMOMETER
INSTRUMENTS )

The most common types are :

1) Mechanical dynamometer.
2) Hydraulic dynamometer.

In addition to the above two dynamometers, various types of electronic

dynamometers are also available.

These dynamometers are placed in the space between the carrier bar and the
polished rod clamp. Either these are placed by creating sufficient gap between
the polished rod clamp and carrier bar with the help of crane or by alternate
switching off and switching on the sucker rod pump by concurrent application of
pumping units brake. The other way is to make a permanent space for the
dynamometer with the help of metallic props/blocks to accommodate
dynamometer instrument there.

3.9.4.3 LOADS FROM DYNAMOMETER CARDS (Refer Fig. 3.21)

C = Calibration constant of the dynamometer, pounds per inch of card height.

D, = Max. deflection (along Y-axis), in.

D 2 =Min. deflection, in.

A, = Lower Area of card, Sq.in.

A 2 =Upper Area of card, Sq.in.

3.54
MAX. LOAD CXD1 .. (1)

MIN. LOAD CXD2 .. (2)

AVG. UPSTROKE LOAD = C (A, + A,). ..(3)

L

AVG. DOWNSTROKE LOAD = C.A, ..(4)

L

APPROX. CORRECT C.B. = C (A,+ A,l 2} ..(5)

L

Polished rod H.P= C(Az/L)x SXN ..(6)

33,000(12)
Where S = Stroke length, in,

N= Strokes perminute.

3.9.4.4 TORQUE FROM DYNAMOMETER CARDS

An accurate method for determining the instantaneous torque throughout the

pumping cycle is done by the torque factor method. This uses the torque factors’
at the corresponding positions of the polished rod supplied by the manufacturer.
The APlstandardl l-E stipulates that the manufacturer is required to supply the
purchaser, on request, the stroke and torque factors foreachl 50 positions of the
crank. The nettorque on the speed reducer is the difference oftorque duetowell
load and torque due to rotary counterweight.

3.55
Tn~t= TF (W-B) - M Sin 0
Where
Tn.t = Net Torque
TF = Torque factor
w = Well load at specific crank angle.
B = Load due to Structural imbalance of pumping unit (either plus or minus
value).
M = Maximum moment of crank and counterweights (about the crank shaft
supplied by manufacturers).
e = Crank - position] degree.

3.9.4.5 FACTORS AFFECTING SHAPE OF DYNAMOMETER CARDS

Following factors can cause a change in the basic shape of the dynamometer
cards: ---
1) Speed & pumping depth.
2) Fluid conditions.
3) Type of pump and its conditions including anomalies due to various factors
at the time of taking dynagraph.
4) Friction factors.
5) Pumping unit geometry

These factors can contribute singularly or collectively in presenting different

shapes of dynagraph, A few peculiar shapes of dynagraph are given as under :-:

1. Plunger Undertravel or Overtravel.

3.56
 = “VERT”VEL

2. Fluid pound,

3. Gas pound.

4. Gas lock.

5. Excessive friction of the sucker rod with the tubing wall.

6. Sticking plunger.

8,00 A.M.

3.57
 8.15 A.M.

7. Excessive friction in the pumping system.

eJ at two different times.

8. Vibrations.

3.10 PROGRESSING CAVITY PUMPS (PCP)

The progressing cavity pump has been in use as a fluid transfer pump for many
years in various industrial applications. For the last several years the progressing
cavity pump is being used as a method of artificial lift in oil wells. The use of
progressing cavity pump, as a means of artificial lift has one distinct advantage
over other conventional artificial lift methods in that it is perhaps the most efficient
method in lifting of very high viscous crude oil from shallow wells. Through years
of research and development in PCP design, the production capacity and lift
ellciency of PCPS are increasing their horizon to cover a wide range of areas. For

3,58
example, the progressing cavity pumps have now the ability to pump out abrasive
fluids. Their applications are also extended in other types of fluids. With various
and improved elastomer materials available, a wide range of well fluids can be
handled efficiently using the PCP. The low initial investment, ease of installation,
minimal maintenance and high volumetric efficiency are some of the other
advantages of the PCP.

3.10.1 PROGRESSING CAVITY PRINCIPLE

The progressing cavity pump consists of a single helical or spiral system (rotor)
which rotates inside a stationary elastomer-lined double helical or spiral system
(stator) of the same minor diameter and twice the pitch length. The rotor is
lowered down hole with the help of sucker rods. The sucker rods are rotated with
the help of electric motor ( prime mover). Thus the rotary motion is transmitted to
the rotor of the down hole pump. Some PCP manufacturers have recently
developed rodiess PCP using down hole electric motor which with a speed gear
arrangement is directly coupled to PCP. The schematic of progressive cavity
pump is given in Fig. 3.22 (a), (b) and(c)

The movement of the rotor inside the stator is actually a combination of two
movements:-

a rotation around its own axis,

a rotation in opposite direction of its own axis around the axis of the stator.

Because of this second type of movement it is also sometimes referred to as

“eccentered screw pump”.

As the rotor rotates eccentrically within the stator, a series of sealed cavities are
formed 80 degrees apart which progress almost pulsation-free from the suction to
the discharge end of the pump, that is, from bottom end to top end of the pump.

3,59
As one cavity diminishes, another is created at the same rate resulting in a
constant non-pulsating linear flow. The total cross-sectional area of the cavities
remains the same regardless of the position of the rotor in the stator. The

progressing cavity pump overcomes pressure because it has a complete seal line
between the rotor and stator for each cavity. The pressure capabilities in the
pump are based on the number of stages and the number of times the
elastomeric seal lines are repeated.

The minimum length required for the pump to create effective pumping action is
the pitch length of the stator. One pitch length forms a stage of the pump. Each
additional pitch length results in additional stages. Normally a stage is designed
and manufactured to be 1,1 to 1.5 times the pitch length of the stator. The reason
for this is to ensure a proper seal between the rotor and the stator to achieve the
desired pressure increase per stage. By increasing the number of seal lines or
stages the pressure build-up capability of the pump is increased allowing it to

pump from deeper depths. As the pump is of the positive displacement type, the
head capability is independent of the speed i.e. high lifting pressures can be
generated even at low speed. As pressure increases for the same number of
stages and speed, the flow rate decreases as this increases slip.
All rotary positive displacement pumps experience some slippage. The amount
of slippage depends on a number of factors, which are as follows: ---

- Differential pressure between suction and discharge i.e. total head.

- Number of stages.

- Degree of compression fit between rotor and stator.

- Viscosity of production fluid.

- Temperature at pump level,

3.60
Slip is however independent of speed.

Slippage means a loss of efficiency, but at the same time it ensures lubrication of
pump.

3.10.2 THEORY

The progressing cavity pump is theoretically pulsation free pump in that it has a
constant cross-sectional flow area with a constant velocity. This results in
constant quantity of flow by pump, which is calculated as

Q = (A) (V)

The cross-sectional area can easily be determined by calculating the cross-

sectional area of the opening and subtracting the same by cross-sectional area of
the rotor.

The dimensions of the rotor and stator are shown in Fig. 3.25 By obtaining the
areas of the circle and rectangle which make up the cross-sectional area, the
cavity area can be determined.

nD2RoT

AROT= area of a circle = ---------

4
AsTA = area of a circle +
zD2RoT
area of a rectangle = --------- + E DROT
4

nD2RoT nD2RoT
ACAV = A.sTA - AROT= ----------- + 4 E DROT- -----------
4 4

3.61
 = 4 E DROT

Thus area of the cavity, ACAVis

ACAV= 4 E DROT

This shows that the area of the cavity depends upon the size of the rotor diameter
and eccentricity. The length of the cavity is determined by the pitch of the stator.
The pitch length of the stator determines the velocity of the fluid moving through
the pump. For each rotation of the rotor, the fluid moves one pitch length of the
stator. The longer the pitch length, the higher is the velocity of fluid through the
pump.

Velocity of fluid is given by, V

V=PsN

Where

Ps : Stator pitch length

N : Number of revolutions

The flow formula, Q = A. V., can now be used by substituting the values of Am,&
V to obtain the following equation: ----

Q=4EDROTXP.SXN ( Where, Q is the Flow rate )

3.62
 DESIGN FEATURES

With the improved materials of pump construction, the Progressing cavity pump

has found its adaptability to a wide range of well conditions. The rotor suspended

by the rod string is the only moving part of the down hole PCP. it is a single

external helix with a round cross-section. It is made of high strength steel,

precision machined with chrome plating for abrasion resistance. The stator,

connected to the tubing string, is a double internal helix inside of which is lined

with synthetic elastomer ( factory moulded ). The elastomer lining of the standard

stator is made using a Buna N elastomers which is best suited for oil, gas and

water applications. Other stator elastomers available are ‘High Nitrile’ and ‘Nysar’.

High Nitrile elastomer is used for fluids containing higher percentage of aromatics,

while Nysar is used for fluids containing hydrogen sulfide fluids at elevated

temperatures.

-------------------------------------------------------------------------------------------------------------

3.63
 SUCKER
~ROD
I STRING
I

-
-CASING

~PRODUCTION
TUBING

m-l
Lb
UPSTROKE DOVVNSTROKE
TUBING STRETCHKONTRACTION FOR
FREELY SUSPENDED TUBING DURING
PUMPING OPERATION

Fig.: 3.26: SUCKER ROD PUMPING SYSTEM

3.87
 COUNTERBALANCE
EFFECTLINE

c
LOAD D3
D2 Al

ZERO LOAD LINE

DYNAMOMETERCARDSHOWING
STROKELENGTH,LOAD& AREAS

Fig.: 3.28: SUCKER ROD PUMPING SYSTEM

3.89
MAJOR MINOR
DIAMETER DIAMETER

MAJOR MINOR
IIIAMETER
STAT(IR IIIAMETER

MAJOR& MINORDIAMETERS
OFROTOR&STATOR OFPCP

Fig.: 3.31: SUCKER ROD PUMPING SYSTEM

3.92
 Chapter 4

GAS LIFT

4.1 INTRODUCTION

Gas lift term is a misnomer. In fact, liquid gets lifted with the aid of gas. Before

gas lift was introduced in oil industry as a very effective artificial mode of lift, a

similar form was in vogue as early as in eighteenth century. Water was being

lifted with the help of air. Air was conveyed through tubing and water received

on the surface through tubing - wellbore annulus. The same system of lifting, i.e.
with the air was adopted by oil industry in the beginning for lifting oil. It

continued in this fashion up till around mid 1920’s. The people started realising
the problems involved in the use of air as a lifting medium for oil, as mixing of air

with hydrocarbon not only may form explosive mixture but also causes corrosion

because of the presence of oxygen. So, from then onwards compressed natural

gas or high pressure natural gas is being used in general to lift oil.

Early applications of gas lift adopted the simple “U’’-tube or pin-hole principle in

producing oil from shallow wells. Then, with the advent of gas lift valves, the

gas lift application could be extended to deeper wells.

Gas lift system is now broadly classified into two categories :-

(1) Continuous gas lift,

(2) Intermittent gas lift.

4.1
4.1.1 CONTINUOUS GAS LIFT (Refer Fig. 4.1 A)

The basic principle underlying the natural flow and continuous gas lift is same.

The only difference between them is the source of gas. In the case of natural
flow, gas comes into the well bore either along with oil or in the dissolved
condition in the oil whereas, in the latter case, the gas is conveyed down the
hole and is injected into the oil body. That is why continuous gas lift can be seen
as an extension of the self flow period of oil well.

The basic principle of continuous flow gas lift is to inject the gas in the oil body at
some predetermined depth at a controlled rate to aerate the oil column above it
and as a result the density of oil column gets reduced to a point where a flowing
bottom hole pressure for a desired rate of production is sufficient to lift the oil to
the surface. Thus, oil is produced continuously from the well.

Gas injection is done at a slow rate and continuously. Because of this reason,
the port size of the gas lift valve is smaller in comparison with port sizes of the

gas lift valves for intermittent gas lift. Generally, the port sizes for continuous
gas lift are 3/16”, 1/40” and 5/1 6“.

It is also generally intended and the accepted practice that in the continuous gas
lift, only one valve will be accomplishing the gas injection work and that this valve
should be as deep as possible as per the available normal gas injection
pressure. This valve is termed as ‘operating valve’, The valves above it are
used to unload the well to initiate the flow from the reservoir. Once the gas
injection begins through the operating valve the upper valves, termed as
“unloading valves” are closed. In case there is disruption in gas injection, the well

will be loaded, So, when gas lift is resumed, the well is required to be unloaded
with unloading valves.

4.2
4.1.2 INTERMITTENT GAS LIFT (Refer Fig. 4,1 ~)

In intermittent gas lift suftlcient volume of gas at the available injection pressure
is injected as quickly as possible into the tubing under a liquid column and then
the gas injection is stopped. The volume of gas expands and in the process it
displaces the oil on to the sutiace. So, the assistance of flowing bottomhole
pressure is not required when gas displaces oil. Static bottom hole pressure,
flowing bottom hole pressure and productivity index of the well govern the fluid
accumulation in the tubing.

In this system, a pause or idle period is provided, when no gas injection takes

place. In this period the well is allowed to build up the level of liquid which
depends upon the reservoir pressure and P1. of well. Then again, next gas

injection cycle is initiated to produce oil. In this manner, as the name suggests,

intermittent gas lift works on the principle of intermittent injection in a regular

cycle. It is to be noted that in the cycle, injection time should be as short as
possible, so that a large volume of gas can be injected quickly underneath the oil
slug. As a result oil slug above the point of gas injection will acquire the terminal
velocity (maximum velocity) within shortest possible time, which would minimise
the liquid fall back in the tubing string. Less fluid fall back will not only increase

production but also help reduce the paraffin accumulation problem in the tubing,
if oil is paraffinic in nature.

For injecting large amount of gas, large ported gas lift valves are required. That

is why gas lift valves having port sizes 1/2”, 7/1 6“, 3/8” or 5/16“ are preferred.
In intermittent gas lift application, two different gas injection flow rates are

considered. One is the normal gas injection rate required for a well and other is

the instantaneous gas injection rate, commonly called per minute demand rate of

gas injection. The high rate of gas injection is calculated on the basis of short
duration of gas injection. It helps to minimize the injection gas breakthrough and

4.3
arrests liquid fall back to a desired extent. The other one is the cumulative
quantity of injected gas per day, called normal gas injection rate.

Similar to the continuous gas lift, a number of gas lift valves are also installed in
the intermittent gas lift well. The last valve is located as deep as possible
(conventionally last valve is just above the top of perforations). At every cycle,

the injection of gas takes place through this valve first and as such, it is also
termed as operating valve. The upper valves may or may not operate, when the
liquid slug crosses the valve during its upward travel. If the upper valve opens
as the slug crosses the valve, the additional gas further arrests fluid fall back and
thus results in more oil production.

In the light of the above discussion, it can be comprehended that continuous gas
lift system should be employed when well has moderate to high reservoir
pressure and P1. Continuous gas lift characteristically provide high volume of oil
production.

Intermittent gas lift system should be deployed when the well has a poor P1.

and low reservoir pressure. That is why, intermittent gas lift provides
comparatively much lower volume of oil production than that of continuous gas
lift.

4.2 TYPE OF INSTALLATION - CLOSED, SEMI-CLOSED OR OPEN

(Refer Fig. 4.2)

Closed Installation can be defined as

(i) When there is a packer in the tubing - casing annulus, below the deepest
gas lift valve and

(ii) When there is a standing or non-return valve in the tubing at the tubing

shoe.

4.4
Semi-Closed Installation can be defined as

When there is only packer in the tubing annulus as described above.

Open Installation is defined as,

When there is neither any packer in the tubing - casing annulus nor any
standing valve in the tubing shoe.

The installation of packer is recommended :

(i) To prevent U-tubing through the tubing, especially when reservoir

pressure is very low and the deepest gas lift valve is very near to the
perforation.

(ii) To prevent rise of fluid level in the annulus, especially when there is an
idle period of intermittent gas lift. So, the same liquid is to be U-tubed
again through the gas lift valve before the normal gas injection is
resumed.

(iii) To prevent production casing coming in contact with the well fluid.

(iv) In case of offshore wells, it is mandatory to have packer in the annulus.

This is primarily due to safety aspect for offshore wells to prevent

accidental leakage of oil and gas in the sea through leaked casing

The installation of standing valve is recommended when reservoir pressure is

low and PI is in the range of moderately high to high. Generally the lowering of
standing valve is decided afterwards during the production from the well. For
this reason, in most of the places, the general practice is to lower A-nipple or D-

4.5
nipple or equivalent along with the tubing in the initial installation period. If
required, the standing valve is either dropped or is lowered with the wireline on
the A or D-nipple. H is also likely that with the production of fluid from the well,
the sand slowly gets settled on the standing valve making the standing valve
non-operative. So, to avoid this problem the deepest gas lift valve should always
be placed just above or very near to the standing valve. The turbulence created
due to gas injection at that place inhibits the build up of sand on the standing
valve.

Generally, semi-closed type of installation is the standard practice for intermittent

gas lift wells, whereas open or semi-closed are for continuous gas lift wells.

4.3 GAS LIFT VALVE MECHANICS

A gas lift valve is analogous to a downhole pressure regulator. The surface

areas of the gas lift valve are exposed to tubing and casing pressures. So, in
response to casing or tubing pressure the gas lift valve opens, which allows

injection gas to enter the production string to lift fluid to the surface.

In the course of improvement of gas lift system several types of gas lift valves

were developed. Probably the differential type of valve was a very early
development and this type of valve was very prevalent before the World War Il.
Advent of metallic bellow for making the gas lift valve has revolutionalised the
gas lift system. The bellow operated nitrogen pressure loaded gas lift valve is
the most common type of gas lift valves being used by oil industries.

In ONGC oil fields, whether it is in offshore or onshore, casing pressure

operated, nitrogen loaded, unbalanced type gas lift valve is only being used.

4.6
A gas lift valve has five basic components. (ReferFig.4.3A, 4.3B, 4.3C and
4.3D) They are :

1) Body
2) Loading element
3) Responsive element
4) Transmission element
5) Metering element

1) BODY

The body is the outer cover of the gas lift valve and is generally of 1 1/2” O. D. or
1” O.D. Some pencil type of gas lift valve is also there, which has an O.D. of
5/8”. The body of the gas lift valve is generally of S.S. -304 or 316. For the
conventional type of gas lift valve, one end of it is threaded and that is screwed
with the mandrel. For wireline type, the “O” ring or VEE seal rings are provided
on the body for isolating the required portion of the gas lift valve from the

adjacent areas. The length of the gas lift valve i.e. its body varies usually from
merely a feet to around three feet.

2) LOADING ELEMENT

The loading element can be spring, gas (Nz gas) or a combination of both. The
spring or gas charge provides a required balancing force so that the valve can
be operated at a desired pressure. It means that above this pressure the valve
opens and below that it gets closed automatically

Spring provides the required compression force, so when spring-loaded valve is

required to open, the external pressure should be sufficient to overcome the

compression force of the spring. In case of gas-charged valve i.e. nitrogen-
Ioaded valve, the external pressure is required to overcome force due to nitrogen
pressure to make the valve open for gas injection.

4.7
3) RESPONSIVE ELEMENT

Responsive element can be metal bellows or piston. Bellows type of gas lift
valve is most prevalent. The bellow is made of very thin metal tube preferably of
3-ply monel metal. Its thickness is approximately 150th of an inch. This is
hydraulically formed into a series of convolutions. This form makes the tube very

flexible in the axial direction and can be compared with a similar rubber bellows.

The bellow is regarded as the heart of the gas lift valve. If bellows are properly
strengthened, the gas lift valves become very strong. Different gas lift valve
manufacturing companies follow their own method of bellows preparation. So, it
can be said that if bellows is of high quality, it is reflected in the quality of gas lift
valve.

4) TRANSMISSION ELEMENT

The transmission element is generally a metal rod, whose one end is fitted with
the lowermost portion of the bellow and the other end is rigidly attached with the
stem tip.

5) METERING ELEMENT

It refers to the opening or port of the gas lift valve, through which casing gas

passes into the well fluid in the production tubing.

Force Balance Equations

Let A~ = Effective area of bellows (Sq.in.)

Av = Area of valve port (Sq.in.)

4.8
P,d = Tubing pressure at valve depth (psig)

PM = Bellows charge pressure at well temperature (psig)

Pb = Bellows pressure at 60°F test bench.

P 5P = Spring pressure effect.

P.~ = Operating casing pressure at valve depth

P otd = Valve opening pressure when there is no pressure exerted over the
valve port area from the other side i.e. when tubing pressure is zero.

Pd = Valve closing pressure in casing at valve depth.

P~~o= Valve opening pressure at 600F in the test rack,

C~ = Temperature correction factor.

Gas lift valve dome pressure at 60”F

c, =
Gas lift valve dome pressure at well temperature

Td = Temperature at valve depth (°F)

Pi~ = Maximum injection pressure available at the surface.

(i.e. kick off pressure)

Pwhf = Flowing wellhead pressure.

G5f = Static fluid gradient,

4.9
 PI = Normal gas injection pressure available at the surface.

Cgt= valve correction factor for specific gravity and temperature at the

valve depth.

= 0.0544 ~ ((S. G.) (T,l + 460°F))

Two types of situations can be envisaged in the well

1) When valve is closed and ready to open.

11) When valve is open and ready to close.

I Valve is closed and ready to open

(a) For the valve (without spring)

Closing force = P~~x A~

Opening force = PO,x (AJ - P., x (%)

+ ‘td x (Av)

when opening force = closing force,

PO~(A~ - A,) + Pt~Av = P~~A~

==> PO~- (1-AJAJ + PtdAv/Ab = PM

4<10
 PM AJAb
==> P~ = ------------- - P,d ----------
(1 -&/Ab) (1 -&fA,)
[1

P~,
Where PO~ = -------------
(1 -Av/Ab)

and T. E. F. ~lA,
(Tubing effect factor) = ---------------
(1 -AVIA,)

‘=> PO(J= po~d- T E,

Where T. E. = Tubing effect= Pt~x T. E. F.

Note

Every gas lift manufacturer is supposed to supply A~ and ~ for each type of
valve.

AJAb
Then AJAW (1-AJAJ and T. E. F. = ----------
1-AJA~

can either be calculated or the same would be provided by the manufacturer for
each types of valve.

For spring loaded gas lift valve the manufacturer has to provide the spring
pressure effect (PJ (in psi say) of the valve.

4.11
When the same equation is used to find PM the form of the equation is re-
arranged as :

PM= P~ (1 -Av /AJ + P,~(Av/A,)

(b) For the valve (with spring)

Closing force = PM x A, + PsP(At) - &)

Opening force = pod (& -&)+ Ptd

Since opening force = closing force,

P~ (A~ - A,)+ Pt~~ = PM X A~ +PJA~ - Av)

==> PO~(1 -A, /A~) + Pt~A, /A~= P~~+ P,P(1 ‘&/&)

~lA, P bd
==> pod + ptd ------------- = ------------ + Psp
l-~/Ab ~-~/Ab

PM Avl A~–
==> Pd = ------------ + Psp - Ptd -------------
l-&/A~ J-MA).

==> P~ = PO,,- P,d X (T, E. F.)

PM
Here PO~d= ------------- + PSP
(1 -~Ab)

Also in terms of PM the equation can be re-arranged as

PM= (P~ - PJ (1 ‘Av/Ab) + ‘td (AvAb)

4.12
II When valve is open and ready to close

(a) For the valve (without spring)

Closing force =

Opening force =

Since, opening force = closing force

PC~x A~ = P~~X A~

or Pd = Pbd

(b) For the valve (with spring)

Closing force = Pbdx A,+ p,, (A, - Av)

Opening force = P~ x A~

Since, opening force = closing force

PC~x A~ = Pb~x Ab+ P,p (Ab - Av)

A~ Av
== > Pd x AJA~ = P~~x AJA~ + P~P( --- - ---- )
A~ A,

==> PC~= P~~+ P,P(1 -A~&)

The equation can be rearranged in terms of P~~as:

P~~= PC~- P,P (1 -Av/AJ

4.13
In the open bench calibration of valve, the valve is closed with the force of N2 -
gas in the bellows with or without spring. Thereafter the pressure is applied to
open the gas lift valve. It is a very convenient way of calibrating the gas lift
valve. It is a case of where valve is closed and ready tc open. So, with the little
modification of the equation, along with converting some terms to surface
condition, we get PO~~in place of PO~and since there is no tubing pressure in the

open test bench, so the term containing ?~~ is zero. Thus the expression without
spring
Pb
P OTB = --------------
( 1-AJA,)

Pb
For the valve with spring, it will be P OTB = -------------— + F~D
( ! - AJAJ

Here P~Pdoes not change with temperature.

4.4 OTHER COMMON VALVE TYPES

Other than the casing pressure operated unbalanced nitrogen charged bellows
type with or without spring two more types of valves are common for oil field

use. They are:

(a) Fluid Operated Gas Lift Valves (or Tubing Pressure Operated Gas
Lift Valve) (Refer Fig. 4.4)

As the name implies the fluid operated gas Iiil valves operate predominantly with
the pressure of tubing. So, its larger surface of opening and closing mechanism
i.e., the bellows area is directly exposed to tubing and not the casing pressure.
That is, the tubing pressure acts on the bellows and casing pressure on the
downstream side of the seat. Due to this, the force balance equations as

4.14
described for casing pressure operated valves are reversed. If it is required to
reduce the influence of the casing pressure, it is required to reduce the port size

to as minimum as possible.

(b) Pilot Operated Gas Lift Valve (Refer Fig. 4.5)

This is a casing pressure operated gas lift valve, but with some fundamental
differences in the construction of the valve as well as in its operating mechanism.
The principle behind the construction of this type of valve is to separate the gas
flow capacity from the pressure control system.

The pilot valve has two distinct sections. One is pilot section and the other is
power section. The pilot section is very similar to an unbalanced type of valve,
with the exception that injection gas does not pass through the pilot port into the

tubing.

The power section consists of- a piston, stem, spring and the valve pod through
which injection gas enters into the tubing.

As the casing pressure reaches the opening pressure of the valve, at first, the
pilot section port opens. The gas through the pilot port, then, exerts pressure
over the piston in the main valve section. The piston is, then pushed downward
against the compressive force of spring. This causes the downward movement
of the stem and the valve gets opened. Casing gas then, passes through the
main section port to find entry in the tubing. When the casing pressure

decreases below the closing pressure of the pilot section valve, the pilot section,
like in the normal casing pressure operated valves, gets closed. Then, the
trapped gas between the pilot port and piston is bled in the tubing through a
specially constructed bleeder line in the main valve section.

4.15
The same force balance equation is applied to the pilot section only for the
opening and closing of the valve, since it is the main functional area.

4.5.1 MERITS AND DEMERITS OF DIFFERENT CATEGORIES OF GAS LIFT

VALVES

Advantages of Casing Pressure Operated Nz Charged Bellows with

or Without Spring for Continuous and Intermittent Gas Lift

1. The valve is of a very simple design and is rugged.

2. The calibration of the valve is done very easily

3. Valves can be repaired easily

4. Valve can be suited both to continuous and intermittent gas lift by

differing the port sizes only. Small ported valve generally is
suitable for continuous gas lift and bigger ported for intermittent gas
lift.

5. N2- charged bellows with spring is not affected by the temperature.

So, the opening pressure of the valve is not changed with varying
temperature in the well.

Limitations of Casing Pressure Operated N2Charged Bellows with or

without spring for continuous and Intermittent Gas Lift

1. Excessive valve spread (difference of pressure at which valve

opens and closes) characteristic of the valve can result in an
excessive injection gas volume to be used in one cycle in
intermittent gas lilt.

4.16
2. For dual installation of gas lift valves in one well, with a common
source of gas injection, it is very difficult to control the gas injection.

3. Only bellows type of valve is temperature sensitive. It affects the

closing and opening pressure of valves.

4. N2-charged bellows type valve with spring has restricted gas

passage, therefore, this valve is not suitable for intermittent gas lift.

Advantages of a Tubing (Fluid) Pressure Operated Gas Lift Valve

It has got many advantages when used in intermittent gas lift design. The
most important application is for dually completed gas lift wells, i.e., when
two parallel tubings in a well both fitted with gas lift valves are used in a
well for producing two zones through two different tubings with the help of

gas lift.

Disadvantages of a Tubing (Fluid) Pressure Operated Gas Lift Valve

1. It is not a good valve for use in the well with low flowing bottom
hole pressure.

2. In absence of any control from the surface, optimum/capacity oil

production may not take place.

3. This type of valve is not recommended for continuous flow. While

trying to control the volume of gas injection, it has happened that
the upper valve opens and desired point of gas injection is not

maintained. This results in lower production.

4.17
 Disadvantages of a Pilot Valve

1. It is complicated in design and in case, the bleed hole in the power

section gets plugged, the valve, then, remains in open position.

2. It is costlier than the conventional gas lift valve, because of its

complex configuration.

3. Pilot valve is not recommended for continuous gas lift since the
discharge of gas in the tubing is very large and for a very short
period.

4.6 SELECTION OF PROPER GAS LIFT VALVE

From the foregoing discussions relating to merits and demerits of different types
of gas lift valves the simple solutions for the selection of proper gas lift valves for
continuous and intermittent gas lift are :

1 Unbalanced, bellows operated N2 -charged with bigger port viz 7/1 6“, 3/8”,
1/2” and 5/1 6“ can be preferred for intermittent gas lift.

2. Unbalanced, bellows operated, N2 - charged with smaller port opening viz

1/8”, 3/1 6“ and 1/4” can be preferred for continuous gas lift. However
where because of the high volume production, greater port area is
required, the gas lift valve of the required port area larger than 1/4” should
be utilized.

3. Unbalanced N2 - charged, bellows operated with spring can be used for

continuous lift wells, where production to be obtained is moderate and

4.18
 when well temperature is very high with high geothermal gradient. For
high volume of production, this is again not suitable.

4, For dually completed wells, tubing pressure operated valves are certainly
better. With unloading valves as tubing pressure operated and the
operating valve for both the string as casing pressure operated valves, are
a better proposition. Though, many a times casing pressure operated
valves are preferred for dually completed wells.

5. Pilot valve as the operating valve for intermittent gas lift is sometimes a
better choice. However, for application of PAIL (Program Assisted
Intelligent Lift), pilot valve as the operating valve is recommended by M/s,
Dapsco (manufacturer of PAIL system).

4.7 REVERSE FLOW CHECK VALVE

A reverse flow check valve is either. coupled with the gas lift valve or in-built with
the gas lift valve. Its function is to prevent the backflow of fluids from the tubing
to the casing. The back flow of fluids from the tubing to annuius is not desirable
because :

1. Back flow of fluid has to be stopped during setting of hydraulic packer with
gas lift valves in the tubing string.

2. It may damage the gas lift valve seats.

3. It may result in accumulation of sand etc. above the packer making the
servicing of well with workover difficult.

4,19
Two types of reverse flow check valves are available

1) Velocity type.

2) Weak-spring loaded..

The check valves ensure the tubing pressure to act below the seat, since this is
one of the requirements for proper functioning of gas lift valve. The force
balance equations involve the pressure from the tubing side below the valve
seat, when the valve is closed.

In the velocity type check valve, the valve is normally open and gets closed,
when there is a flow from tubing to annulus. So, when velocity type valve is
lowered, it is to be lowered in upside down fashion (i.e. after connecting with the

gas lift valve), so that it becomes a normally open check valve.

In the second category of reverse flow check valve, the only type is weak-spring
loaded check valve. It is normally closed. Because of weak spring action, even

though the check valve is closed, it ensures the tubing pressure to act on the
valve port -from below. The weak spring loaded gas lift valve can be loaded in
any direction.

The opening of all the reverse flow check valve is kept slightly more than 1/2”, so
that it should not restrict any amount of flow (maximum port size of the gas lift
valve is 1/2”).

4.8 GAS LIFT MANDREL

Gas lift mandrel is the port of tubing string. It houses the gas lift valve and check
valve. The mandrel’s length is very short - it ranges from 4’to say 7’to
8’depending upon the length of the gas lift valve and check valve.

4.20
There are two general types of mandrels in use - one for conventional or for fixed
valve and the other is for wireline retrievable valves. In the conventional mandrel
gas lift and check valves are fitted on to the exterior side of the mandrel with the
valve attachment lugs. The lower or inlet Jug has a theaded connection to
attach the check valve and gas lift valve (generally gas lift valve is coupled with
the check valve and check valve is screwed to the lower lug of the mandrel).
The lower lug is rigidly welded with the tubing part of the mandrel body in a
perfectly seal-proof manner. It has a number of small holes to connect with
inner side of the tubing. The upper lug, which is also called a guard lug or
protective lug and this lug with a proper chamfering protects the gas lift valve
from getting damaged during lowering and pulling out of tubing strings with gas
lift valves. The lower lug also has a proper chamfer at its bottom side.

The mandrel for wireline retrievable valve is of a different type. The gas lift valve
is housed inside instead of being on to the outside. The outer shape of
mandrel’s tubing body looks oval shaped with its eccentric end having box tubing
connections. It has a pocket welded inside it in the eccentric portion, which is
intended to house the gas lift valve. The pocket has drilled holes to connect the
pocket bore with the tubing i.e., with the mandrel and separate drilled holes to
connect with the inside of the tubing. The eccentric form of the mandrel is
required to ease the wireline job for the selective setting and retrieval of the gas

lift valve.

Generally, the conventional mandrel is having much less cost than the wireline

mandrel. But at the same time if the servicing of gas lift valves is required or re-
setting of pressure is required, for conventional mandrel, entire tubing string is to
be pulled out, whereas, only with the help of wireline job, redressal job of the gas
lift valve is carried out in wireline mandrel type. So, in this sense, wireline
mandrels are more cost effective since every effort is made to minimize the
workover job operations. In this respect wireline retrievable mandrels are very

4.21
attractive and the same is practiced all through the world especially in offshore
wells. In Bombay High areas also, all the gas lift mandrels are of wireline type.
In onshore areas of ONGC oil fields a majority of the mandrels are of
conventional type.

Many times, it has been experienced that wireline job is extremely difficult in a

well with high paraffin deposition in the tubing. Also, scale deposition inhibits the
movement of wireline tools. So, with the high initial cost of the wireline mandrel

coupled with the problems like paraffin, scale in the tubing, onshore wells of
ONGC fields have been lowered mostly with conventional gas lift mandrels.

Proper identification with respect to its size is most important for a mandrel. It
means how big a mandrel with gas lift valve in position (for conventional one)
can go into the well given the wells minimum casing I.D. So, maximum diameter
of mandrel is taken into account with tubing string coupled at its two ends with
respect to casing drift diameter

4.9 SURFACE EQUIPMENTS

Surface equipments for the gas lift wells mean the kind of equipments installed

on the gas injection line leading to a gas lift well.

For continuous lift well, two equipments are required - one is the adjustable or
fixed choke to regulate the volume of gas injection. The other is the pressure
controller to be fitted upstream of the choke to regulate the upstream pressure.

For intermittent lift, it is a usual practice to install a time-cycle controller. This

controller periodically opens and closes by itself with the pre-set tim,e and so

periodically injects gas into the tubing. So, a time-cycle controller has two basic
functions - one is idle period of the cycle or time between two injection cycles like

4.22
15 rein, 20 rein, 30 rein, 40 rein, 1 w, so on, when it will be closed and there will
be no injection of gas in the well. The other is the injection time, say 1 rein, 1
min 30 see, 2 rein, 2 min 15 see, 2 min 30 sec and so on. With the shortest
possible injection time, the required volume of gas should flow into the casing.
The time cycle controller operates with the pilot pressure of 25 psi-40 psi which
is obtained either by tapping the injection line gas with pressure reducing
equipment or from compressed low pressure air line.

Many times, intermittent lift well is operated with the help of bean or orifice fitted
in the injection line similar to continous lift. The bean or orifice continuously
allows the injection gas to flow into the casing. As and when the pressure in the
annulus reaches the valve opening pressure, the valve opens and gas enters
into the tubing. As the casing pressure goes down, the gas lift valve closes and

again the casing pressure slowly builds up by the slow incoming gas through the
orifice. This type of system works as a stop gap arrangement, whenever, time
cycle controller is not available, as intermittent lift through orifice is not
considered efficient. It makes gas lift valve throttle and thus results in large fluid
fall back.

4.10 TRC)UBLE SHOOTING OF GAS LIFT OPERATION

1) Bottom hole pressure and temperature survey of a gas lift well, especially
across each gas lift valve in the tubing string (i.e. a few feet above and below of

each valve) clearly indicates, which gas lift valve is the operating valve,

Also Bottom hole pressure and temperature survey pin points the leaky gas lift
valve, tubing leakage besides estimation of accurate tubing pressure at injection

point as an input for efficient gas lift design

4.23
2) APPLICATION OF ECHOMETER

With the help of echometer, the possible depth of injection can be determined,
especially when the well is of open completion type (i.e. without packer). As
well, in semiclosed condition, it can detect, whether the well is properly unloaded
or not up to the desired point.

3) TWO PEN PRESSURE RECORDER

Two pen pressure recorder is an instrument, which when connected to the

injection line and flowline at the wellhead, continuously records the casing and
tubing pressures, during the gas lift operation, The recordings on chart paper for
continuous gas lift and intermittent gas lift are different from each other. By
studying the charts carefully, many details of the operating system in the casing
and tubing can be ascertained and on the basis of these, many possible trouble
shooting jobs are planned and undertaken for smoothening the gas lift system
and obtain thereby desired oil production.

Some of the typical casing and tubing pressure recordings for continuous gas lift
are :

Casing }

Pressure }

} This shows good operation

Tubing }
Pressure }

} Possibly there is hole in the tubing below the

} operating valve, As the casing pressure rises,

} the hole possibly gets uncovered, some casing

Tubing } gas leaks through resulting in the

4.24
pressure ~ A /} lowering of casing pressure. Due to this,
——
} kicks are observed in the tubing.

} OR

} The action of valve is snap open or close type.

} The valve port is big. It allows more gas

} injection into the tubing. As a result, casing

} pressure falls. It behaves to some extent as

} an intermittent gas lift well which is intermitting

} at very short intervals.

Casing }
pressure~ } A possible case of gaslift

} valve throttling.
Tubing
~}
Pressure }

Casing
pressure~ ;
A case of freezing after the

1 surface gas mjecticm choke.

Tubing }
Pressure ~}

Some of the typical casing and tubing pressure recordings for intermittent gas hit
are :

Casing } The intermittent gas lift recorder chart indicates a

pressure ~ } sound& good operation. Quick cycle indicates that

} it is a high producer well. For each gas injection

Tubing } a kick in the tubiiig pressure has been observed.
A~
pressure }

4.25
Casing ‘ It is also a good operating intermittent gas lift.
1
pressure~ } In comparison to the first one, the well has lower

} capacity. Injection gas is adjusted for this

Tubing ~ } well. Time cycle controller is working perfectly.
pressure } Very slim kick in the tubing also indicates that
} each slug is very small and quickly comes to
} the surface allowing the tubing pressure to
} fall rapidly.

Casing } This is also another case of good intermittent

Pressure~ } gas lift with only difference from the earlier

} ones that here, there is no intermitted at the
Tubing } injection line. Intermittent gas injection is being
pressure } done through choke at the surface. Casing
} pressure slowly builds up to the va!ve opening
} pressure followed by the opening of valve and
} allowing sudden voluminous injection of gas
} into the tubing. The valve is a snap action one.
} Here the timing of intermittent cycle is adjusted
} as per the capacity of choke. No gas lift valve

} leakage or throttling has been observed from

} this chart.

Casing } H is a case of incorrect cycle frequency : There

.
pressure~ ~.. are intermittent kicks observed between the

} cyc!e, although no ieaky valves are observed.

Tubing Probab!y this well needs more frequent
~;
pressure -intermitting operation, which this definitely will

} augment oil production.

4.26
Casing } This indicates that there is excessive tubing
pressur } pressure against which the intermittent gas
} lifting is being done. It can cause excessive
Tubing } fluid fall back problem, resulting in high flowing
Pressure } bottom hole pressure and hence low influx
} into the well. Tubing back pressure need
} to be reduced for increase of production.

Casing } This clearly indicates a very sluggish valve

pressur~ action for intermittent gas lift. This leads to

} insufficient gas passage through the valve into
Tubing } the tubing. So slug flow in the tubing is
pressure ~ } absent. Gaslift valve needs to be
} checked/ replaced.

Casing It is a case of leaky gas lift valves. Once the

~}
pressure } Casing pressure takes time reaches the valve
} opening pressure, valve acts smoothly and

Tubing~ ~ ~ /} allows proper injection. After it reaches the

.— —
pressure } closing pressure, casing pressure slowly and
} continuously declines till another cycle of
} injection takes place. So it indicates leaky gas
} lift valve.

Casing } This indicates that alternate injection cycle is

pressure } is missing. Adequate injection gas is not
} going into the casing in the missing cycle. So,
Tubing } pressure on gas lift valve remains below the

pressurel_A—A——} opening pressure of the gas lift valve in the

} alternate cycle.
} The fact is clearly seen by the alternate tubing
} kicks.

4.27
Casing } This indicates that there is no control of
pressure ~} intermittent gas injection cycle. Casing
} pressure rises and fails. It is a case of leak
Tubing } in tubing string. So there is communication
pressure ~ } between the tubing & casing.

4.11 PACK - OFF GAS LIFT INSTALLATION

The pack-off gas lift technique consists of installing a gas lift valve inside the
tubing string between an upper and lower packoff assembly Refer Fig. 4.6. The
two pack-offs are placed above and below a pre-perforated section of the tubing.
Injection gas from the annulus enters through the tubing perforation and into the
tubing string via the gas lift valve. The well fluids are produced up through the
centre of the packoff assembly The pack-offs have sealing elements to prevent
casing pressure from entering the tubing until the GLV opens. Any number of
these packoff assemblies can be placed in a well similar to a regular gas lift
installation.

The pack off gas lift system differs from the conventional gas lift one in the
following respects :

a) in the conventional gas lift system, side pocket gas lift mandrels are
lowered with the tubing at different predetermined depths. Therefore,
these mandrels are a part of the tubing. Here, the mandrels not only
house the GLVS (gas lift valve), but also has a port facilitating
communication of injection gas from annulus to the GLV system.

The packoff gas lift mandrel, on the other hand, is not a part of the tubing
string. It is placed inside the tubing with the necessary seal and stopping

4.28
 arrangements at its top and bottom. Although the mandrel houses the
GLV, the injection gas is conveyed from the annulus to the GLV system
by making a hole in the tubing at the appropriate location..

b) In case of a wireline mandrel, GLVS are housed in one side pocket, built
at one end of the mandrel. The GLV is generally of 1 “ or 1 1/2” OD.

In case of packoff installation, the GLV is placed, in general, at the centre

of the mandrel (hence this system is often called a “Concentric packoff
gas lift system”). The GLV size ranges from less than 1” OD to 1“0.D.
However, in some models, the GLV is placed at the side and in such
cases the mandrels are of macaroni size with less than 1 “ OD GLV.

c) The conventional gas lift system is initially installed in the wells with the
help of the workover rig, whereas the packoff gas lift system does not
require manoeuvring the original tubing. For installation of pack-off system
only wireline job is needed.

As per the current literature, the packoff gas lift installation system is
being extensively used in offshore Gulf Coast area of USA and in other

parts of the world, presumably due to the unavailability of workover rigs.

A TYPICAL PACKOFF GAS LIFT SYSTEM

A typical packoff gas lift assembly (Refer Fig.4.7) consists of the following

- Upper tubing stop.

Upper packoff assembly
Gas lift mandrel with GLV/Check valve.
Lower packoff assembly
Lower collar stop.

4,29
The total packoff gas lift system consists of a number of such assemblies (one
for each GLV/Check valve) which are required to be placed in a well at the pre-
determined depths similar to the regular gaslift installation.

INSTALLATION PROCEDURE

Installation of packoff gas lift system is done starting from the bottom most GLV
assembly to the top most one. The installation procedure for each packoff
assembly is as follows :

1-) The bottom collar stop is run in and set with wireline just below the
desired depth of gas injection.

2.) A tubing perforator is then lowered which ultimately rests on the lower
collar stop. With the aid of this perforator, a hole of dimensions around
3/16” x 3/4” or a circular hole of around 5/16“ is perforated in the tubing
approximately 15“ above the bottom tubing stop.

3.) Tbe total assembly consisting of lower packoff, mandrel w~th GLV, upper
packoff and upper tubing stop is made at the surface and the whole
assembly is then run in and set on the lower collar stop. This ensures that
the hole in the tubing has direct access to the GLV in the mandrel.

The successive assemblies are run in the well at the predetermined depths
(above the previous set) in a similar fashion.

4.12 GAS LIFT DESIGN

Now-a-days all the gas lift designs are being done with computer. However, to
understand the design of a gas lift system every engineer associated with gas !ift

4.30
application must understand thoroughly the intricacies and variations of gas lift
design. He or she must do it either graphically or analytically by himself or
herself without the assistance of computer. Then, subsequently he could
accomplish the task of gas lift design for wells with the aid of computer.

The design of continuous gas lift and intermittent gas lift installation is explained
with the help of examples.

Data Required for Continuous Gas Lift Design :

To design a continuous gas lift installation, the following data (as much as
possible)is required.

1) Depth of perforation interval.

2) Tubing and casing size.

3) Inclination profile of the well.

4) API gravity of oil.

5) Formation gas-oil-ratio.

6) Specific gravity of injection and formation gas.

7) Specific gravity of water.

8) Desired liquid production rate.

9) Flowing wellhead pressure, FTHP.

1o) Injection gas pressure at well.

11) Volume of injection gas available.

12) Static bottom hole pressure, SBHP

13) Productivity index, PI or Inflow Performance Relationship, IPR.

14) Bottom hole temperature.

15) Type of reservoir.

4.31
TYPE OF DESIGN PROBLEMS

In gas lift design, there are three distinct types of design problems,

1) In the first case, gas lift is to be designed and gas lift valves run with the
tubing in an existing well.

2) Second case is encountered mainly in offshore operations where wireline

mandrels are spaced in the tubing string on the basis of an appropriate
design for later installation of gas lift valves. The dummy gas lift valves
are replaced with gas lift valves when need arises to install gas lift system
as per merits.

4.13 QUALIN CONTROL OF GAS LIFT VALVES

The concept of using unloading valves along with the operating valve and the
various design methods are explained in this section.

The quality of gas lift valves used in a gaslift well plays a very important factor in
the efficient operation of the well. The failure of valves in the well due to various
reasons could detrimentally affect the oil production from the well. This leads to
the situation where an effective quality control is essential to evaluate the
performance of different makes of gas lift valves.

The two API standards applicable for gas lift valve testing are API 11 V I for
static testing and API 11 V2 for dynamic testing.

4.32
(a) STATIC TESTS

The static tests can be normally considered as mandatory for accepting a lot of
gas lift valves for field use. The tests which can be categorized under static are
as follows :

(i) Leakage through seat and stem

(ii) Ageing Test
(iii) Shelf Test
(iv) Probe Test

(i) Leakage through seat and stem

In this test, the leakage through seat and stem of a gas lift valve is measured
when the valve is in its closing condition. Each gas lift valve will have a closing

pressure which depends on the opening pressure and port size of the valve. This

test can be performed in a closed test hood facility as well as open test bench
facility (Fig 4.26)

In the open test bench, the valve is initially allowed to open and the opening
pressure is noted down. The closing pressure is calculated based on the force
balance equation i.e. Pd = P~Ro( I - R), where R = A~/& The upstream pressure
is down to that the valve closing pressure.

As per API standards, the leakage rate measured downstream of the valve
should not be more than 35 SCFT/day for accepting a valve.

Recently ONGC is following much stringent criteria, where in the leakage in the
form of gas bubbles down stream of the valve is measured by keeping a beaker

of water below the valve. [f the gas bubbles formed are more than 1 bubble in 5

seconds, the valve is rejected for leakage. The leakage rate for acceptance in

4,33
this method is even less than 1 SCFT/day which makes it much more stringent
than API leakage criteria

(ii) Ageing Test

This test is mainly done to access the quality of bellows of the gas lift valve at
the pressure it is to be used. The valve is initially charged to a predetermined
dome pressure (normally the operating injection pressure of the field where the
valves are to be used); and the corresponding opening pressure is noted. The
valve are put in an Ageing chamber filled with water and then subjected to 5000

psi hydrostatic pressure for a minimum 15 minutes. The chamber is then

depressurized and again pressurized to 5000 psi within a minute. This is to be
repeated 3 times and then the valve opening pressure is again checked. Care
should be taken to maintain the temperature of the va{ve during initial checking
and final checking, by using a temperature controlled water bath.

The difference in opening pressures before and after this test should not be
more than 5 psi for acceptance.

This test will also check the proper design of the top plug of the valve as well,
since an improper design. would allow water to enter the valve dome which will
allow the dome pressure to increase.

(iii) Shelf test

In this test, the openiing pressure of the valves are noted down and the valves”
are kept on shelf for a minimum of 5 days. The opening pressure are again
checked after 5 days and the difference should be within 1‘?Jo for acceptance
(Pressures should be checked at same temperatures).

4.34
This test ensures that thedifferent joints inthe valve are proper and check for
minor leakage which is not instantaneously detectable. The above mentioned
three tests should be done on 10O?40of the valves.

(iv) Probe test

This test is to be done on randomly selected valves out of a whole lot offered for

inspection. The API standard recommends this test on atleast one valve of each
valve configuration.

The probe test set up is as shown on Rg. 4.26. In this test, a probe micrometer
is used to measure the stem travel of a valve with incremental upstream
pressure increase from the dome pressure, which is the closing pressure of a
valve. The stem travel is measured till the maximum travel of the particular valve
is reached, where the stem travel remains constant for further increase in
pressure. The pressures are then reduced, preferably by the same increment till
dome pressure is reached, where the valve stem should travel back to it’s

original close position. The upward and downward stem travel with respect to
pressure ,is plotted and the slope of the plot gives the bellow load rate,
measured in psi/inch. (Fig 4.27).

This test is of utmost importance in assessing the quality of bellows by the way

of load rate measurement and uniformity of bellow movement. The total travel
should be higher than the equivalent stem travel for particular port sizes which
ensure full area open for flow during normal operation. The stem travel with
respect to different pressure ranges can be used to analyse the behaviour of a
valve, i.e. whether it will operate as on orifice or it will throttle close during
different casing pressure conditions.

4.35
(b) DYNAMIC TEST

The dynamic test set up is an ellaborate set up with upstream and downstream

control valves, high pressure lines and different pressure, flow and temperature
transmitters for online measurement of different parameters. The set up can
effectively simulate different upstream and downstream pressure conditions
which will vary the gas through put for a gas lift valve.

The test is done to generate flow performance curves for a GLV with different
casing and tubing pressures, to predict the flow performance of the gas lift valve;
i.e. whether they are actually behaving in orifice regime or throttling regime under
particular conditions.

The following is one example of graphical design of a continuous gas lift system.

This type of design is available in the literature of different reputed manufacturer

of gas lift valve.

Data aiven :

Production rate 1500 BPD

Perforation interval 5900-6100 ft.
Depth 6000 ft.
Casing 5 1/2” ; 17-20 ppf
Tubing 2 7/8”; N-80, 8RD, EUE.
Gas lift valve J-40 (Cameo Co. 1” 0. D.) Port sizes:

3/1 6“, 1/4”, 5/1 6“

Gas lift mandral 2718”
Injection gas quantity Unlimited
Specific gravity of gas 0.65
Gas injection pressure 1100 psi
Separator pressure 120 psi

4.36
Flowing tubing head pressure = 160 psi
Load fluid (or kill fluid) gradient = 0.45 psi/ ft.
Static wellhead temperature = 74°F
Geothermal gradient = 0.019°F/ft
Gas oil ratio (GOR) = 300 SCF/bbl
Water cut = 509”0
Gas liquid ratio (GLR) = 150 SCF/bbl
Static Bottom hole pressure = 2020 psi at 6000 ft.
Flowing Bottom hole pressure = 1780 psi at 6000 ft.
Productivity Index = 4.6 bldlpsi

STEP -1

Well depth = 6000 ft

Packer depth = 5900-100 = 5800 ft.
Gas lift injection pressure = 800 psi at zero depth.
Flowing tubing head pressure = 160 psi
Static Bottom hole pressure = 2020 psi
Flowing Bottom hole pressure = 1780 psi
Static well head temperature = 74°F at zero depth are marked properly on
a graph sheet.

STEP -2

With geothermal gradient = 1.9°F / 100 ft. i.e. 0.019°F/ft, the Bottom hole
temperature at 6000 ft. = 74°F + (0.01 9 x 6000)°F

= 74°F + 114°F
‘m

74°F at surface and 188°F at 6000 ft are joined to obtain temperature gradient
line on the graph sheet.

4.37
STEP -3

Tavg = (74°F + 188°F) x 1/2 = 131°F = (131 + 460)0R = 591°R

Zavg = 0.84 ( assumed )

Using the formula for injection pressure at depth (P, )

Pd = P~U,x Ex P -------------
[
.
1
Gas gravity x Depth

53.3 x Tavg x Zavg

=IIOOXEXP
E5:::::8il
=1100x1158 = 1274 psi at 6000 ft

1100 psi at the surface and 1274 psi at 6000 ft are joined to obtain injection
pressure gradient line 1, on the graph sheet.

STEP -4

Hagedorn and Brown curve is selected for 1500 b/d producing rate through
2 7/8” tubing with producing fluid all water at average flowing temp. 140°F.

With the help of above vertical gradient curve, the minimum gradient line on the
graph sheet is drawn with FTHP = 160 spi (or PW~).

160 psi is located at 950 tl on the vertical gradient curve and therefore at 6000 ft

+ 950 ft = 6950 ft, the pressure = 1355 psi is noted. This pressure is marked on
the graph paper at 6000 ft. By joining PW~and 1355 psi point at 6000 ft, the
minimum gradient line is obtained on the graph sheet.

4.38
STEP -5

The zero GLR line is drawn on the graph sheet in the similar way. On the vertical
gradient curve, 160 psi = p~h is located at 325 ft. At 5325 ft, the pressure is read
as 2520 psi. Therefore 2520 psi is marked at 5000 ft on the graph sheet and 280
GLR line is drawn.

STEP -6

The depth of the top valve (Ll) is located from ,

Pinjat surface - PWh ( 1100- 160)ps’

L1 = -------------------------- = ----------------------
‘-=636”’
Kill fluid gradient 0.45 psi/ft

I_l is marked on the graph sheet; T, (Temp. at Ll) = 114°F, as obtained from
temp. gradient line.

STEP -7

From L1 depth line, a second injection pressure gradient line (line 2), which is
less by 50 psi than injection Iinel, is drawn parallel to injection line 1.

STEP -8

Approximate gas through - put (Q) through valve 1 and selection of valve port
size :-

From flowing gradient chart, the required GLR at L1

4.39
= 500 scf/bbl is obtained. P~in at L1 = 560 psi; Pinj I at L1 = 1160 psi

1500 b/d X 500 scf/b

.-. Q Calculated = .------------------. ----------- = 750 MCFD
1000

Q MI 750
Q corrected = ------------------------------------ = -------------------------------------
0.0544 ~S.G. X (T + 460 ) 0.0544 ~0.65 ( 114+ 460 )

750
= -------- = 714 MCFD
1.05

Q corr 714
C (Port coefficient) = ------------= ---------------- = 1.29, where K = 0.47
PUPx K 1174 x 0.47

The valve of K is calculated from gas through-put chart as provided by P. EADS

of M/s Cameo :

pd~~n 575
Against ------- = -------- = 0.48, K valve is obtained, Against the valve of C, the
P up 1174

Port size of 3/16” is calculated (For Ll) valve.

This value can also be obtained from Thronhill-Craver equation.

STEP -9

From P~in, a line parallel to zero GLR line is drawn, which cuts the injection line 2
at the depth of 2ndvalve location L2.

L2 = 3350 ft; T2 = 137°F

4.40
STEP -10

p~h and Pi.j2 at Lz are joined. It cuts LI depth line at ~~~X= 790 Psi. at the depth
L,.

STEP -11

The additional tubing effect (A.T. E.) for the valve 1 is calculated by the following
formula,

(A.T. E.)L1 = ( P~,x at L1 - P~in at Ll) T.E.F.

[ T.E.F. = Tubing effect factor, T.E.F. = 0.104 for 3/16“ size port gas lift valve]

= (790 -560 )x O.1O4 = 24psi

STEP -12

Operating pressure at the second valve, that is the valve opening pressure (POP)
at L2

= Pi.j2 at L2 - ( A. T. E.)L1 = 1150 -24 = 1126 psi

STEP -13

[t is similar to step 8

Required GLR = 800 scf/b

4,41
 pd~~n P~in at L2 834
------- = ------------ = ------- = 0.71. Therefore K = 0.445
P up Pinj2at L2 1164

QcaI = 1500 b/d X 800 scf/b X 1/1 000 = 1200 MCFD

1200 1200
Q corr = ‘----------------------------------- = -------- = 1120 MCFD
0.0544 d 0.65( 137+ 460) 1.07

!!
1120 1
.“. C = ----------------- = 2.16. Therefore, ----- size for second aas lift valve is
1164 X .445 4

selected.

STEP -14

Parallel to injection line 2, a line is drawn from L2 depth, which is less than line 2
pressure by 24 psi. This line is injection line 3.

From P~in at L2, a line is drawn parallel to zero GLR line, which cuts injection line
3 at the third valve location (L~).

L3 = 4060 ft; P~in at L3 = 960 psi; Pinj3at L3 = 1145 psi T3 = 151°F.

From Pinj3at L3 and p~h, P~~Xat L2 = 970 psi is found as in earlier step.

STEP -15

(A.T. E.) L2 = [ P~,X at L2 - P~in at L2 ] T.E.F.

4.42
 = (970 - 820)x 0.196=30 psi

POPat LS = Pinj~at L~ - (A.T.E.)LZ = 1145-30 = 1115 psi

STEP -16

pd~~n P~in at L3 975

------ = ------------ = ------- = 0,84
P up Pinj3at L3 1160

Therefore, K = 0.4

QMI = 1500 b/d X 800 scf/b X 1/1 000 = 1200 MCFD

1200 1200
Qcorr = ------------------------------------ = -------- = 1111 MCFD
0.0544 d 0.65 (151 + 460) 1.08

1111
.“. c = -------------- = 2.39; Gas lift valve port size = 1/4” is selected ( for LSvalve)
1160 x0.4

STEP -17

The injection line 4 is drawn from L3 depth and parallel to injection line 3. It is
less than injection line 3 pressure by 30 psi,

From P~in at L3, the line parallel to zero GLR, line is drawn to obtain L4 = 4450 ft,
as in the previous step.

P~in at L4 = 1040 psi; T4 = 158°F; Pinj4at L4 = 1130 psi

From Pinj4at L4 to p~h, a line is drawn to find P~,. at Ls = 1050 I’lsi

4,43
STEP -18

(A. T. E.)L, = [ P~.X at L, - P~inat L~ T.E.F. = (1050 - 960) x 0.196 = 18 p.s.i.

POPat Ld = PinjAat LA- (A. T. E.)L, = 1130-18 = 1112 psi

STEP -19

Pdown P~inat L, 1054

------ = -----------. = -------- = 0.92
P UP Pinjqat L, 1144

Therefore, K = 0,27

Q Cal = 1500 b/d X 800 scf/b X 1/1 000 = 1200 MCFD

1200 1200
Q corr = ------------------------------------ = ------- = I I oo MCFD
0.0544 d 0.65 (158+ 460) 1.09

1100 y
c = ----------------- = 3,56; Gas lift valve port size = ---- is selected (for Lqvalve)
1144 X 0.27 16

STEP -20

Parallel to injection line 4, injection line 5 is drawn from Ld depth, which is less
than injection line 4 pressure by 18 psi.

From P~in at LA, the line is drawn parallel to zero GLR line, which cuts Pinj~at the
fifth gas lift valve location L~.

4.44
L,= 4600 tl.; P~inat L~ = 1060 psi; T~ = 162°F; Pinj~at L~ = 1100 psi.

P~,X at Lq = 1070 psi, is found as in the previous step,

STEP -21

(A. T. E.)L, = (P~,X at L, - P~inat L,) (T. E. F.)

=( 1070 -1040) x0.342=11 t)si

POPat L~ = Pinj~at L~-(A.T.E.) LA= 1118- 11 = l107~si

STEP -22

Pdown P~inat L~ 1074

------ = ------------ = -------- = 0.96
P UP Plnj~at L, 1114

Therefore , K = 0.195

QCal = 1500 b/d X 800 scf/b X 1/1 000 = 1200 MCFD

1200 1200
Q corr = ---------------------------------- = -------- = 1100 MCFD
0.0544~0.65 (162+ 460) 1.09

1100 5,,
c = ------------------- = 5 : Gas lift valve (L~) port size = ----- is selected.
I114X 0.195 16

4.45
STEP -23

Since the difference of depth of 5th and 4th valve = 4600-4450 = 150 ft., the
difference of depth of 6th and 5th valve will be less than 150 ft.

It is generally accepted that the difference of depth of successive valves should

not be less than 200 ft.

A final table is made with all the relevant data as obtained from previous steps.

STEP -24

The bellows charge pressure at well temperature (Pbt) is calculated by using

equation, as below,

pb~= (POPat L) ( 1- Av/Ab) + (Prnin at L) (AdAb)

Where, ( 1 - Av/A~) and (Av/Ab) values are supplied by gas lift valve
manufacturer.

For, J-40; 3/1 6“ valve Port : ( 1- Av/A~) = 0.906; (Av/Ab) = 0.094

For, J-40; 1/4” valve Port : ( 1- Av/Ab) = 0.836; (Av/A~) = 0,164
For, J-40; 5/1 6“ valve Port : ( 1- Av/Ab) = 0.745; (Av/Ab) = 0.255

Therefore,

Pbtfor L1 = 1110 X 0.906 + 560 X 0,094= 1005.66 + 52.64

= 1058.30 I psi at 114°F

4.46
P~~for Lz = 1126X 0,836 + 820X 0.164 = 941.34 + 134.48

‘kE!2-l ‘“at‘370’
P~~for L~ = I115x 0,836 +960x 0.164 =932.14 +157.44

=1===’1
PS’’’I5I”F

P~~for LQ = 1112 X 0.745+ 1040X 0.255= 828.44+ 265.2

‘U!EE-l
‘s’”’1580F
P~tfor L~ = 1107X 0.745+ 1070X 0.255= 824,72+ 272,85

= I 1097.57 I psi at 162°F

STEP -25

The bellows charge pressure (P~) at test bench (60°F) is calculated from

P,
P~ = P~~x C~, Where C~= ----- and C~values are provided by the manufacturer
Pbt

Therefore,

Pb fC)rL, = 1058.30X 0.896 = 948.24 psi

P~ for Lz = 1075.82X 0.858 = 923.05 psi
P~ for L~ = 1089.58X 0.836 = 910.89 psi
P~ for L, = 1093.64 X 0.826 = 903.35 psi
P~for L~ = 1097.57 X 0.820 = 900.01 psi

4.47
STEP -26

The test rack opening pressure of the valve at 60°F (P~~o or PVO)is calculated

Pb
From PTRO = --------------
( 1- Av/A~)

Therefore,
948.24
PT~o for L1 = ----------- = 1046.62 psi; Adjusted PTRO(at 60°F)+ 1050 psi
(at 60°F) 0.906

923.05
PTROfor Lz = ----------- = 1104,13 psi; Adjusted P T~o (at 60”F) --+ 1045 psi
(at 60°F) 0.836

910.89
PTROfor L~ = ----------- = 1089.58 psi; Adjusted PTRO(at 60”F) + 1040 psi
(at 60°F) 0.836

903.35
PTROfor L4 = ----------- = 1212.55 psi; Adjusted PTRO(at 60°F) + 1035 psi
(at 60°F) 0.745

900.01
PTROfor L5 = ----------- = 1208.06 psi; Adjusted PTRO(at 60°F) + 1025 psi
(at 60°F) 0.745

STEP -29

A 2nd table is made for the convenience of calibrating gas lift valves and
numbering them before dispatching the valves to the field for installation.

4.48
CRITICAL ANALYSIS OF THE DESIGN

1. There is a scope of deeper installation of gas lift valves, upto a maximum

limit of packer depth, provided the injection pressure is more than 1100
psi.

2. Also, lowering of PW~,valves can be lowered slightly more deep, if

minimum gradient line is considered for gas lift design.

3. While operating the gas lift system against the designed PW~= 160 psi, if
tubing pressure, say, can be reduced to PW~= 100 psi, there can be three
likely possibilities.

i) Quantity of gas injection will be reduced.

ii) Quantity of fluid production will increase.
iii) Both the above can be achieved.

4. This gas lift valve design is for one rate of fluid production i.e. 1500 b/d.
To make the gas lift design more flexible in handling two to three rates of
production, for example, 1500 b/d, 800 b/d, 200 b/d, this can also be done
in the similar way. In this case, it is required to proceed the design first

with 1500 b/d, then 800 b/d and finally 200 b/d. A software developed at
IOGPT based on this named “GLIDE” can provide this flexible design.

5. Flowing gradient line, as drawn from FBHP, indicates that L~ will be the
operating valve, with L, and Lz closed and LA and L~ opened. However, if
the actual P.1. is less than the estimated P.1. , Lq or L~ will be the operating
valve.

4.49
6. While the well will be on steady production with continuous gaslift, the
injection gas quantity required minus wells gas.

7. While doing calibration of gas lift valves following must be ensured.

i) The gas lift valves must pass successfully the ageing test, shelf test,
leakage test and through-put test.
ii) For connecting the valves on the conventional mandrels, the
connecting joints of the gas lift valve and mandrel must be perfectly
leak-proof.
iii) Gas lift valve number and depth of installation must be properly
written on each mandrels before dispatching them to fields for
installation.

Table -1 : Continuous gas lift Design

Well No. ... .. .... ... Field, .. ... ... ... ... ... Type ofvalve,,, ... ..... Date ... ... ... .....

Valve Port Depth Temp.at Pmin Temp. Inject. Inject. A.T.E. Summ- Pop.
No. Size of Valve At CorrectionPress. Press.Less psi ation of AtLpsi
Ininch Valve Depth Lpsi Factor At By50psiat A,T,E.psi
Inft. OF (Ct) LPsi Lpsi

L, 3/16 2088 114 560 0.896 1160 1110 24 -- 1110

L2 1/4 3350 137 820 0.858 1200 1150 30 24 1126

L~ 1/4 4060 151 960 0.836 1219 1169 18 54 1115

Ld 5/16 4450 158 1040 0.826 1234 1184 11 72 1112

Ls 5/16 4600 162 1070 0.820 1240 1190 -- 83 1107

4.50
 Table -2: Continuous aas lift Desia~

Well No. . . .. . .. . .. .. Field . . .. . .. ... . .. . ... . Typeof valve . . .. . ... ... Date..., . .. . .. . ...

Valve Valve PORT SIZE DEPTH DPETH P~~o or

No. Type IN INCH (ft) (rots). PVOpsi

L, J-40 3/1 6 2088 635 1050

(l” O, D.)

L, J-40 114 3350 1019 1045

(1” O. D.)

L~ J-40 1/4 4060 1234 1040

(l” O. D,)

L1 J-40 5/1 6 4450 1353 1035

(l” O. D.)

L, J-40 5/1 6 4600 1400 1025

(1” O. D.)

DESIGN OF INTERMITTENT GAS-LIFT

The design of Intermittent Gas-lift can be done either in the multipoint gas
injection fashion or in the single point gas injection system, In the multipoint
injection system, as the liquid slug moves up due to the gas injection from
bottom valve, the upper gas lift valves will open allowing some gas entry into the
tubing that helps in lift efficiency, In single point injection, only the bottom valve
will operate during each cycle of injection gas, Generally for moderate volume of

production, multipoint injection is preferred and for a very low producing well,
single point injection system is adopted, Multipoint, however, has other
advantages like it reduce paraffin accumulation in the tubing etc.

The design of multipoint and singlepoint differs materially with the assumed
surface closing pressure (Pvc) of gaslift valve. If the values of Pvc for the

4.51
successive lower valves are taken same or with a little difference, multipoint
design system is obtained . It the values of Pvc for successive valves are
comparatively large, then singlepoint injection design will result.

The following problem illustrates the design calculation for an ideal multipoint gas
injection system.

Well No . . .. . . . .. . ... ... . .. . .. . .. ... . .. . ... Field . . ... .. . .. .. .. .. . .. . .. . .. . .. . .. . . . . .. . .

DATA GIVEN

● Tubing size :2 3/8” O.D. (1.995” I.D.) : EUE 8RD : N-80

● Casing size :5 1/2” :20-23 PPF ; N-80
● Petioration depth :6480 ft -6520 ft
● Mid-Perforation depth :6500 ft
● Operating injection pressure :800 psig
● Well head flowing pressure(PW~) :100 psig
● Temp. of gas injection at surface : 86’F
● Temp., bottom hole at 6500 ft : 160°f
● Static fluid gradient :0.45 psi/ft
● Specific gravity of gas :0.65
● Reservoir pressure (P~) :1700 psig
● Bubble point pressure = Reservoir pressure :1700 psig
● Water cut :3070
● API gravity of oil :35°
● Average P.1. :0.2 b/d / psi
● Desired liquid production :160 b/d
● Type of gas lift valve : J -20 (Cameo make)
● Gas lift valve port size :718”

4.52
The stepwise design procedure for intermittent gas lift is as follows:-

STEP -1

Depth of mid-perforation and depth of packer are marked on the graph paper.
Reservoir pressure (P~) = 1700 psi is marked on the 6500 ft depth line.

STEP -2

141.5
From, ‘API = --------- -131.5
Sp.Gr

141.5 141.5
Sp.Gr. of oil = ------------------ = ---------------= 0.85
‘API + 131.5 35+ 131.5

Considering 30% water cut and with Sp.Gr. of water = 1, the composite specific
gravity of the produced fluid =

0.85 X 0.7 + 1 X 0.3 0.595 + 0.3

------------------------- -- = ------------------ = 0.895
0.7 + 0.3 1

That is,

0.895 X 14.223
Composite well fluid gradient = 0.895 kg/cm2/l Om = --------------------- psi/ft
10X 3.28

Static fluid gradient is drawn from 1700 psi upwards with 0.388 psi/ft

4.53
STEP -3

Flowing wellhead pressure (PW~)= 100 psig is marked on the zero depth line.

The spacing factor (S. F.) in psi/foot is required to calculate the valve depths.
During intermittent lift operation, liquid fall back, fluid transfer along with fluid
production in the idle period, which determine the valves of S.F. Generally all gas
lift valve manufacturers use the valve of S.F. = 0.04 psi/ft for locating the depth
of 2nd valve and gradually increase the valves of S.F. for determining the
successive lower valves. The maximum valve of S.F. depends on the estimated
rate of fluid production and production tubing size. Sometimes, for a very low P.1.
well, the depth of first two or three valves from 2nd valve onward are calculated
by using the minimum valve of S. F., that is S.F. = 0,04 psi/ft.

A common practice is to use S.F. = 0.04 psihl to obtain the depth of 2nd valve
and to use increasing valves of S.F. for successively lower valves. For

determining the maximum valve of S.F. , it, is considered safe to use a little
higher valve of S.F. than will be obtained from the published chart (S.F. for
various fluid productions and tubing sizes,)

A line is drawn from PW~with S.F. = 0.04 psi/ft, which cuts the static gradient line

at ‘A’.

STEP - 4

For 160 b/d production and with average P.1. = 0.2 b/d/psi, and using equation,

Q
P.1. = ------------, where P~= flowing bottom hole pressure
PR - Pf

4.54
 Q Q 160
P~ - P~= -------- or, P~ = P~ - ------ = 1700 - ------
P.1. P.1. 0.2

Or, P~= 1700- 800=

m

P~= 900 psig is marked on 6500 ft line and flowing gradient line is drawn parallel
to the static gradient line.

STEP -5

For determining the maximum S.F. at 6500 ft., it is approximately estimated that

it is possible to give a maximum drawdown of 1500 psi, so, by using the equation

Q~,X= P.1. x drawdown = 0.2 x 1500 = 300 b/d.

Using the chart S.F. (psi/ft) vs. Q (b/d) for 2 3/8” tubing size,

The max. S.F. = 0.086 = o og which is the next whole number

u’

With 0.09 psi/n gradient a line is drawn from PW~which cuts 6500 ft deptth line at
“B”. It also cut P~gradient line at “C”.

STEP -6

Point “A and “C” are joined by a line which is called “intermediate spacing factor
line”.

4.55
STEP -7

Operating injection pressure = 800 psig is marked on the zero depth line. The
gas pressure gradient is calculated by using,

.
(Gas Gravity) x (Length of gas column) I
P at depth = Pat surface Exp ----------------------------- ------------------------ I
(53.3) x Tavg x 2 J

86+160
Tavg = ------------- = 123°F;
2
= (123+ 460)”R

Gas gravity = 0.65

Length of gas column = 6500 ft ; P at surface = 800 psig = 814.7 psig

Z = 0.85 (assumed)

.4.Pat depth = 814.7 Exp -------------

---------
=
1
0.65 X 6500

53.3 X (123 + 460)X 0,85

956 psia = m941 psig
at 6500 ft.

The gas gradient line is drawn from 800 psig point.

STEP -8

Temp. at zero depth = 86°F and 6500 ft = 160”F are marked and both are joined
by a line to provide temperature gradient line (i.e. geothermal gradient line).

STEP -9

Kill fluid gradient line = 0.45 psi/ft is drawn from pW~,which can be called zero
GLR line.

4.56
STEP -10

The depth (4) of the top valve (Ll valve), is calculated by using

Operating Inj. Press. - PW~ (800 - 100) psi

L, = ------------------------------------- = --------------------
‘m
Kill fluid gradient (0.45) psi/ft

A horizontal line is drawn at L, level.

STEP -11

Another Inj. Gas gradient line MN, which is DE inj. Gas gradient minus 100 psi, is

drawn parallel to DE. This ‘MN’ line is for determining the depths of 2nd valve
onward.

L, valve depth cuts PW~-Aline at q. From q, a line is drawn parallel to kill fluid
gradient, which cuts MN at W. So, W point is the dpeth of 2ndvalve. L2 depth line
cuts PW~-Cline at r. From r, a line is drawn parallel to kill fluid gradient, which cuts
MN line at x. Point x is the dept of 3’d valve. In this manner parallal line are
drawn from s, t, u and v and points y, z, g and h are obtained points y, z, g and h
are the depth of 4th, 5th, 6th and 7thvalve respectively.

It is noted that the location of 7th valve is located just below the packer and so,
this valve is relocated just above the packer depth.

STEP -12

4.57
All the depth of valves, temperature and injection pressure of valve depths are
marked on the graph. A table is prepared accordingly.

CRITICAL OBSERVATIONS / ANALYSIS

1) Closing pressure (PVC)at surface is same for all valves to effect the multi-
point intermittent gas lift desing.

2) First valve is located with the help of common pressure and gradient
formula. All the depths of valves from 2ndvalve onward is based on Pvt.

3) For single point intermittent gas lift, for eat valve depth, PVCat surface is to
be reduced by say 10 psig or 15 psig etc.
4) For locating the depths of gas lift valves, 0.04 psi/ft (S. F.) has been
considered for the calculation of distance between the first valve and
second valve. But for the remaining valves, the calculations have been
done with uniform increase of gradient of S.F, where max. S.F. at 6500 ft =
0.09 psi/ft. This is very conservative design. Otherwise design can also be

done Considering Intermediate S.F. line. (that is considering gradient PW~-

A - C - B, where A - C is the intermediate S.F. line.

5) Since the location of 6th valve (Le) is below point ‘C’, (FBHP Gr. Line meets
at C), the 6th valve, theoretically can be the operative valve to give desired
rate of production (160 b/d). However, there appears no harm if another

valve (7th valve) is located below the operating valve.

6) 1 1/2” O.D. gas lift valves with bigger port szie (7/1 6“) have been
considered for intermittent gas lift design. This valve has a lower Iocad rate
and allow to pass through it can adequate quantity of gas in a very short
time for efficient intermittent gas lift operation.

4.58
7) Allgaslift valves can well be calibrated with thecalculated valv.~sof P~~O
or PVO. Here it is slightly modified to take into consideration in any
aberration of considering various data for gas lift design.

CONVENTIONAL MULTIPOINT INTERMITTENT GAS LIFT DESIGN

TABLE

Well No. . . .. . .. . .. . .. . .. . .. . .. . .. . .. . .. . .. . .. . .. .... Field . . .. . .. . .. . .. . .. . .. . .. . .. . .. . .. . .. . .. . .. . ..

Date of design . ... ... . .. . .. . .. . .. . .. .. .. .. . .. . .. . .
Type of gas lift valve : J -20 (Cameo Make)
Gas lift valve port size : 7/16“

Valve Depth of Temp Ct Pvc at pbt ct pb PTRO or PVO

No, Valve From (OF) at ‘ Valve = pb 1- A@b considered
‘ Surface (ft.) Valve 1 I Depth (psig) = PTRO or P,, for calibration
Depth ‘ I = Pbt(psig) (psig) (psig)

L, 1555 103 $ 0.915 735 672 841 820

L, 2940 118 I 0.889 760 675 844 818

L~ 3950 130 0.869 780 677 847 816

L. 4750 138 0.856 798 683 854 814

L, 5400 146 0.844 809 682 853 800

L, 5950 153 0.833 817 680 851 795

L, 6300 156 0.829 822 681 852 791

Dome pressure at 60°F (Pb)

c, = Temp. Correction factor = ------------------------------------------------
Dome pressure at valve depth (P~J

(1 - AJA,) = 0.799

4.59
 Chapter 5

ELECTRICAL
SUBMERSIBLE PUMP

5.1 INTRODUCTION

The electrical submersible pump (ESP) is basically a high volume mode of lift
system. The minimum capacity of ESP is known to be around 200 bpd and the
maximum capacity is as high as 90,000 bpd, A typical ESP installation is given in
Fig. 5.la. Surface and Sub-surface set-ups are shown in Fig.5.lb & Fig.5.lc
respectively.

ESP, in some situations, can provide the maximum possible drawdown by

bringing annulus level to the top of the perforations.

The ESP is extremely suitable for a very low viscosity liquid. This pump is also
used to pump high viscosity fluids and can operate in, gassy wells and high
temperature wells.

The prime mover of the electrical submersible pump is the downhole motor
coupled directly with the pump. The motor rotates at 3475-3500 rpm for 60 Hz
power and 2900-2915 r.p.m. for 50 Hz power.

5!1
Under normal operating conditions, the operating life of ESP can be expected
from 1 to 3 years, with some units operating even over five years. With the
recent improvement of ESP metallurgy and cable technology, some
manufacturers claim that ESP run life is even more than five years under normal
operating conditions. One of the main reasons of failure of ESP is the
breakdown of insulation at the downhole either in the cable, cable joint, motor,
etc.

5.2 APPLICATIONS

If we hark back a few decades from now, we find that ESP had application in
lifting water from water well and thereafter ESP was used to produce an oil well
with high water cut. Perhaps the first version of ESP was brought out in the
name of REDA. The full form of REDA is ‘R’ stands for Roto, ‘E’ for Electro, ‘D’
for Dynamo, and ‘A’ for Arutunoff after the, name of a Russian Scientist who had
first patented the pump for lifting water from under the ice covered Alaska region.

Many offshore and onshore wells are currently being produced by ESP,
especially where wells are high producers. In ONGC, ESPS were tried in three
wells of western offshore but their life periods were short mainly due to different
types of down hole electrical faults either by itself or engineered by the
mechanical malfunction in the pump assembly. Currently, no offshore well in
ONGC is operating on ESP. However a good number of wells of ONGC’S Assam
field are being produced with ESP. Companies like M/s. REDA, Centrilift,
TRICO etc. manufacture electrical submersible pumps.

5.2
5.3 SURFACE AND SUB-SURFACECOMPONENTSOF
ELECTRICAL
SUBMERSIBLE
PUMPS

Electrical submersible pumps consist of many equipments and their allied parts.
The equipments can be broadly segregated as surface and downhole
components.

The downhole components are as follows :-

10 Electric motor.

2. Protector.

3. Pump intake/gas separator.

4, Multistage centrifugal pump.

5. Pr’essure sensing instrument (PSI).

6. Pothead extension power cable.

7. Power cable.

8. Centralizers.

9. Cable bands.

10. Check valve.

11. Bleeder valve (drain valve).

5.3
12. Pump top substitute Connection.

13. Lower pig tail.

Surface components are as follows:

1. Wellhead.

2. Minimandrel

3. Upper pig tail.

4. Surface cable.

5. Junction box.

6. Booster.

7. Switch board.

8. Power transformer.

5.4 DOWNHOLE COMPONENTS

5.4.1 ELECTRIC MOTOR

The electrical submersible pump motor is of two-pole three-phase squirrel cage

induction type one. These motors operate at a nominal speed of 3500 r.p. m. on
60 Hertz cycle and 2915 r.p.m. on 50 Hertz cycle. These motors are filled with

5.4
highly refined mineral oil e,g,, REDAmotor is filled with theprescribed REDAoil
from the manufacturer concerned. This highly refined mineral oil provides the
necessary dielectric strength as well as a good thermal conductivity which
prevent motor from getting overheated and thereby damaged. This mineral oil
by virtue of its quality also serves as a lubricant for the bearings installed around
the shaft inside the motor.

In general the motor, in any electrical submersible pump assembly, is attached

to the bottom-most part of the assembly. The intake part is placed above the
motor. Therefore, when the motor is in operation the well fluid first passes on
over the exterior of the motor and thereafter it enters the intake section of the
pump. In doing so, the fluid carries the heat generated by motor operation and
thereby keeps the motor relatively COOIto perform the motor operation within the
recommended temperature range, In some cases, the motors are placed above
the pump assembly and in that case, some sort of shroud is provided to divert
the liquid so that the well fluid flows past the motor housing before entering
intake section. In some cases the pumped fluid is routed through the exterior of
motor for transferring heat from the motor to the moving fluid up the surface.

The motor normally consists of low carbon steel housing with brass and steel
laminations placed inside. The motor shaft material is carbon steel or high
strength steel. The steel laminations are aligned with the rotor section whereas
the brass laminations are aligned with the radial sleeve bearings. The squirrel

cage rotor is made up of one or more sections depending on motor horse power
and length of the motor. In the case of motor stator it is wound as a single unit in
a fixed housing.

The standard motor has thrust bearing which is a type of fixed pad and whose
purpose is to support the thrust load of rotor stator as well as to keep the rotor
shaft aligned vertically with the stator’s magnetic field.

5,5
Motors are manufactured with different diameters as more conveniently named
by different series to suit the various physical dimensions of the well i.e., w.r.t.
the minimum I.D. of the casing. The smallest diameter motor is of 375 series for
4 1/2 inch cased hole. The other series are 456, 540, 738 etc. The horse power
of the motor ranges from 6.3 HP to even more than 1000 HP. (Refer Fig.5.2 –
Reda Motor, courtesy M/S Reda Co.)

Length of the motor ranges from a few feet say 5-8 feet to even more than 100
feet. When large HP motors are required, two or more number of motors are
coupled. This total combination of motors is called TANDEM motor. We have
experienced that for 375 series motors with 50 Hz, tandem configuration of
motor is required only when the motor H.P exceeds 25 HP. Most of the wells in
Assam oil fields of ONGC are being operated on single housing motor of around
18.3 HP and 22 HP with only a few have more HP, which are of tandem
configuration (two single motors are joined).

5.4.2 PROTECTOR

The very ’name of the protector implies that it protects the motor (Refer Fig.5.3a)
That is why the protector is connected just above the motor. During operation of
the motor, the highly refined oil inside the motor gets heated up and owing to

that, the internal pressure of motor gets increased. Again during the idle period
of motor, the oil inside the motor remains cool and due to this, a low pressure is
created inside the motor. If this is allowed to continue, then motor housing may
burst or collapse because of the differential pressure across the wall of it. The
protector acts as a breathing element of the motor. During running of the motor,
the protector breathes out, meaning, it releases some motor oil through the
protector in the well. Again during the idle hour, because of the low pressure
inside the motor, the motor inhales the well fluid inside it through the protector.
In this way it maintains a pressure balance inside and outside the motor /
protector by keeping the differential pressure to a minimum.

5.6
If the well fluid is allowed a straight entry from the protector to motor then in no
time the motor oil gets displaced by well fluid due to gravity segregation which
entails a complete break down of the motor insulation. That is why the protector
operates utilising the labyrinth path principle, This is accomplished by allowing
the well fluid and motor oil to communicate through labyrinth tube paths in
several U-tube fashion where each U-tube is enclosed in sealed chamber.
There is also another way of’ preventing the well fluid to have a direct access to
the motor by providing a bag or balloon inside the protector housing. The bag /
balloon collapses during the running of the motor and expands during the idle
moments of motor. This design is termed as “positive seal” design. (Refer
Fig.5.3b – Reda Modular Protector, which is a combination of labyrinth &
positive seal, courtesy M/S Reda Co.)

The protector also houses pump thrust bearing to carry the axial thrust
developed by the pump.

The labyrinth type of protector can be of two chamber, four chamber, six
chamber ,or eight chamber type as manufactured by different companies as per
their patented design. Again number of chambers means the equal number of
seals of the rotating shaft and the housings. For example two chamber means
two seals. It has been found by experience that even two chamber labyrinth
protector is sufficient to prevent the well fluid from making an entry in the
protector but whenever the breakdown of motor insulation has resulted, it has
been found, in most of the cases, the well fluid has entered the motor, through
the leaking seals. That is why we prefer 4 chamber protector over 2 chamber
protector. Since 4 chamber protector is not the common product of all ESP
manufacturers, two number of 2 chamber protectors are coupled to make 2 + 2
i.e., 4 chamber protector. In many North sea offshore wells 4 chamber protector
applications have been in use.

5.7
5.4.3 PUMP INTAKE / GAS SEPARATOR (Refer Fig.5.4a & Fig.5.4b)

The pump intake is connected in bolt-on-fashion to the lower side of the pump
section of the electrical submersible pump and to the top of the protector. In
other words this pump intake is connected between the protector and the pump
section. This provides a path for the fluid to enter into the pump. Very often, the
straight intake section is replaced by the other forms of intake sections called

gas separator for separating out the free gas from the liquid before the liquid
enter the pump. The free gas is routed up through the annulus to ultimately get
discharged in the flowline. The non-return valve installed after the valve of the
annulus of wellhead prevents the gas / flowline fluid from flowing back into the
annulus. In all the ESP wells of ONGC, gas separator intake is used rather than
straight pump intake. Gas separators are broadly categorised into two types.
The first one is the poor-boy type gas separator where the fluid bends 180
degrees i.e., from upward direction of flow to downward direction. In the process
free gas separates out and the liquid enters in the pump through inner pull tube
of the gas separator. The separated gas finds a way out to the surface through
the annulus. This type of separator is also called static or reverse flow separator.
Some companies like M/s REDA employ one inverted impeller just below the pull
tube of the static type gas separator. This inverted impeller owing to its inverted
operation, pressurises the fluid to some extent and in the process, if at all some
free gas is present, it gets dissolved into the liquid which then moves up into the
pull tube. Most of the wells of ONGC have this type of separator.

The second category is the rotary type separator. (Refer Fig. 5.4c – Reda Rotary
Gas Separator, Courtesy M/S Reda Co.) This rotary type separator by its rotary
centrifugal motion separates out the gas and liquid. This centrifugal action
keeps the denser fluid to the periphery and allows the lighter fluid like gas to rise
from the centre of the rotary gas separator through the path of flow divider /

5,8
cross-over section into the annulus, finally the separated gas to be discharged
into the flow line.

Rotary gas separator has some distinct advantages over the reverse flow type.
Due to centrifugal action, separation of liquid from free gas is more effective.
Secondly, remaining free gas in the form of minute bubbles can be dispersed all
through the liquid medium and make the liquid less dense. (This gas is other
than the free gas which is at the centre of the rotary separator). This less
densed liquid finally enters the pump and increases its efficiency. But in some
cases, this rotary gas separator has not proved effective. As the liquid rotates, it
can create an unbalanced lateral thrust and shaft vibration, which can accelerate
seal failure in the protector. Many rotary gas separator is in use in ONGC oil
fields located in Assam.

5.4.4 MULTISTAGE CENTRIFUGAL PUMP

Electrical submersible pumps are centrifugal pumps in a multi-stage fashion.

(Refer 5.5a - Reda high efficiency pump, courtesy M/S Reda Co.) Obviously

because of the physical parameters of the well ( ID of the casing ) diameter of

the pump is very much restricted and therefore it is different in this respect from
surface centrifugal pumps. The OD and the type of impeller design determines
the rate of fluid production. Whereas, the number of stages where each stage
consists of one impeller and diffuser are governed by the requirement of the
head of fluid to be lifted to the surface against the given tubing pressure.
The principle of ESP operation to accomplish its job simply follows the principles
of Physics. As the liquid under positive head enters into the eye of the impeller,
the liquid flows out laterally by the rotating impeller. As the impeller rotates, it
imparts a rotary motion to the fluid thereby considerably increases its kinetic
energy. Then the diffuser with its expanding area changes the high velocity
energy into low velocity energy i.e. transformation to pressure energy, before the
fluid is re-directed into the eye of the next impeller. In this way pressure energy

5,9
continuously gets built up in a particular ratio in each successive impeller as per

the ctesign of impeller-diffuser.

Two types of setting of the impeller diffusers are in vogue. One is floating or
balanced type where the impeller floats up and down a little and axially along the
shaft. Floating impeller means impeller is firmly fitted with the shaft and shaft
moves up and down a little. Depending on the flow rate, the impeller either sits
on the down thrust pad or touches the upthrust pad or freely floats in between
them. Most of the centrifugal pumps are of floating or balanced types especially
those for deeper wells and for low, moderate and moderately high fluid volume.
Therefore when a pump is operating at greater than designed flow rate, it may
induce an excessive upthrust which results in excessive friction between the
upthrust pad and impeller. On the other hand when a pump is operating at less
than designed rate it can create an excessive downthrust due to the friction
k)etween the impeller and downthrust pad. This is precisely the reason why a
centrifugal pump should be operated within a recommended capacity range
where frictional force is minimum. This recommended capacity range is
available from the pump performance curve as supplied by the manufacturer.

(Refer fig.5.5b - head capacity& pump efficiency curve of a typical ESP)

The other type is the fixed impeller type pump. It is used for pumping very high
volume of liquid . In this type, impeller is fixed to the shaft and the shaft cannot
move up and down axially. The impeller also does not sit on the diffuser pad.

In some earlier cases, electrical submersible pump companies sometimes used

to prefer combination pump where a certain number of the stages at its bottom
is of floater design and the remaining stages at the top are of fixed type. Now a
days, this type of combination of floating and fixed impeller pumps are not
normaliy being used.

5.10
During lowering of pump, pumps of different housing lengths are joined in series
as per the requirement of the total head to be generated. Pump housings are
normally available from as low as 2.1 feet to 14.8 feet or more. Each stage of
the submersible pump handles the same volume of fluid therefore the total
stages are only linked with total head generation. The pump stages are
available in different
groups called housings, where one hous~ng houses a
t
number of stages like 54, 74, 99, 151 stage’s etc. Two or more housings are
connected to create the necessary stages as per the requirement of well. So far,
the maximum pump size available is of around 400 stages, as per the
information available from M/s REDA.

METALLURGY

The pump housings are normally seamless, heavy walled, low carbon-steel
tubing in order to withstand the normal operating pressure of the pump. The
outside diameter of this housing ranges from 3.38 inches to even 11.25 inches
(designated as per the OD of the housing). Stages are manufactured with the
materials which can provide optimum performance as well as resist the corrosion
and erosion. Generally K-Monel shafts are provided as a standard shaft
material. The impellers normally are Nickel, Ryton and Bronze. Diffusers are
generally made of Ni, which provides hardness whereas, bronze imparts ductility.

5.4.5 PRESSURE SENSING INSTRUMENT

This pressure sensing instrument is coupled below the motor. It is composed of

a surface read-out unit and a surface detachable downhole pressure and
temperature sensing instrument. The surface unit is connected to the downhole
sensor through the motor windings and through the same power cable which is
used to operate the pump. It records the pressure and temperature of the fluid
at the pump depth.

5,11
5.4.6 POTHEAD EXTENSION POWER CABLE

Pothead extension power cable is used to connect the motor with the main
cable. One end of the pothead is joined with the main cable and the other end is
joined to the motor head. While connecting with the motor head, there should be
a compatibility of the motor head joining section with the pothead cable joining
section. There are two types of pothead extension power cable available in the
market.

(i) Plug-in type pothead.

(ii) Tape-in type pothead.

The plug-in type pothead is similar to althree pin plug with necessary ‘O’- ring
fitted for fluid seal. This is inserted into motor three pin hole and then rigidly
bolted with the motor body. This type of connection has some disadvantages:

1) When the plug-in pothead is used a number of times, it looses its proper
fitting with the motor body.

2) Due to more rigidity of this type of cable-motor connection there is always

a possibility that a hair crack in the pothead just above the plug-in point
may accidentally develop. This generally goes unnoticed and once the
tubings are lowered into the well it ( the damaged pothead ) comes in
contact with the well fluid and thus break in insulation results.

Tape-in type pothead is a better proposition and for this motor head should also
have the compatibility for this type of connection. This connection is similar to a
connection between two cables. The flexible wires inside the motor are taken
out first with the help of pliers and then necessary splicing job is carried out to
connect the pothead extension cable with the motor cable. Finally the flange
fitted with the pothead extension cable is fitted with the ‘O’- ring on the motor

5,12
body for fluid seal andrigidly fitted with bolts. Because of thevery flexible’nature
of connection with this tape in type system there is absolutely no room for having
any break in insulation, once the proper splicing job is ensured.

When electrical submersible pumps were introduced in ONGC as early as in

1975- 76, only the plug-in pothead connections were being used as per the
recommendations of the concerned manufacturers.

Subsequently with experience it was realised that tape-in type was a better
option. Number of pot-head insulation failures were reduced drastically to a bare
minimum.

These pot-head connections are normally available in lengths of 40 feet, 50 feet

and 60 feet so that connecting section of the main and pot-head cable remains
above the pump assembly. Normally, the pot-head cable being connected, just
above the motor, is subjected to less conducting capacity than the main cable.
For example the main cable is of # 4 AWG (American Wire Gauge) whereas the
pot-head extension cable is of # 6 AWG. Primarily this is because of economic
reasons, if the lower capacity cable is technically permissible.

Pot-head extension cable is a very sensitive part of the total ESP system.
ONGC has made a principle to procure pot-head extension cables in small
packages with sufficient shock absorbing cushions. Also, the pot-head extension
connection with the main cable is made at the well site after the main cable
passes over the hanging ESP pulley over the well head.

5.4.7 POWER CABLE

Power cable is the means through which power is supplied from the surface to
the downhole motor. The cable has been standardised by AWG (American Wire
Gauge) standards. In this standard, sizes of conductor ranges from # 1 AWG to

5,13
# 6 AWG. # 1 AWG signifies a thicker conductor. As we approach from # 1 to #
6 AWG, the conductor sizes become thinner and thinner. That means its current
carrying capacity becomes less and less. The total range meets all electrical
submersible motor amperage requirements. Almost all cables use copper as
conductor, however there are few where the conductors are of aluminium.
Although aluminium is cheaper th~n copper, their current carrying capacity is
much less than that of the latter. If the aluminium cable is used in place of
copper cable for a similar requirement of electrical submersible pump then cable
diameter will become bigger and it may not physically permit running of cable
into the well. In such cases the pump and tubing diameter have to be reduced
and therefore copper conductor is always used.

Cable is made up with three separate conductors separated from each other by
proper insulating material. Each conductor is meant for each power phase
where three phase supply is present. The composition of the insulation with
proper thickness which determines the cable’s resistance to current leakage as
well as to prevent permeation by well fluid especially gas are most important
aspects of the cable. Very few electrical cable manufacturers make as per these
standards suitable for use in electrical submersible pump operation in oil wells.

All ESP cables are armoured, like galvanized armour, which prevents the cable
from getting physically damaged. During lowering and pulling out jobs of ESPS,
it is obvious that cable suffers severe abrasion by the rubbing of casing-tubing
wall. Since bare cable (i.e., without any armour) cannot sustain this abrasion,
armoured cable is used.

The cable configuration is of two types -

i) Round cable.

ii) Flat or parallel cable.

(Refer Fig. 5.6, Reda Round & Flat cable, courtesy Reda Co.)

5,14
i) ROUND CABLE

Round cable, as the name implies, is round in shape. The three conductors,
each enclosed by insulation and sheathing material are placed side by side at
120° to each other and then finally all three are covered with insulation and
sheathing materials. On the exterior of it, armour is provided. It therefore forms
a round shape. To make a positive fluid seal at the wellhead with Hercules make
wellhead, round shape cable is preferable. But, sometimes overall diameter of
the cable and tubing coupling becomes more in case of round cable than that of
flat cable. More so, round cable, because of its less surface area in contact with
the tubing, the tight gripping of cable with the tubing is often difficult. The
frequency of failure of clamps holding round cable is more. As a result, a portion
of cable gets accumulated at one place and prevents, normal retrieval operation
and finally calls for complicated fishing job.

ii) FLAT OR PARALLEL CABLE

Flat or parallel cable as the name suggests, are those where all the three
conductors are placed side by side and parallel to each other and the cable
looks flat. Like in round cable, each conductor is enclosed by insulating and
sheathing materials and finally the whole cable is enclosed by insulating and
sheathing materials followed by metallic armour like galvanised armour.

With the use of parallel cable, the running in of ESP becomes comparatively
easy simply because of more rigid gripping with the tubing owing to the flat
surface of the cable.
However, this type of cable always poses a problem with the “ Hercules” type of
wellhead. Since flat cable in its same configuration, as such, cannot pass
through the rubber packings of the wellhead, the individual conductors with their
usual sheathing material get separated and are made to pass through the rubber

5,15
packing. This does not ensure a fool-proof sealing. However with modified, high
pressure wellhead like “seaboard” wellhead, this problem has been overcome.

5.4.8 CENTRALIZERS

At least one centralizer can be installed below the motor in the pump seat
assembly and another above the top of the pump assembly. This can keep the
motor in the central portion of the casing for better cooling effect. Also, many
more centralizers can be placed in the entire length of tubing string, which will
greatly minimise the dragging effect of cable between the tubing and casing wall.

5.4.9 CABLE BANDS

Cable bands, though a very small item, is one of the vital components of ESP
system. Cable band attaches the cable rigidly with the tubing with the help of
cable tensioner hand machine and clamping tool. A number of cable bands are
required to rigidly grip the cable with the tubing during the lowering of ESPS.
About 3 to 4 cable bands are required forcme stand (2 single tubing). In this way
whole cable weight is distributed equally to the total cable clamps used. (Refer
Fig. 5,7)

In case, one clamp breaks, the lower clamp has to bear’the cable weight of two
segments above it which make it susceptible to give way and then, automatically,
the successive lower cable bands give way under the increasing cable load
above them. This leads to the coiling of cable, while tubings are pulled out during
pulling out of ESPS. As the tubings are being retrieved leaving cable behind,
this may ultimately create jamming of tubing and even create a situation where it
is impossible to retrieve anything from well and virtually one has to abandon the
well. So proper number and quality of cable band must be used to prevent such

5.16
occ~rrence. Also the clamping tool must be in petfect condition. Time to time it is
necessary to replace this tool by a new one,

These cable bands are of one-time use only. During re-run of ESPS again new
cable clamps are required.

In the Motor-Protector-Separator-Pump section cable bands are protected from

getting damaged because of friction with the casing, by GI guard channel. In the
rest portion upto the top of the well, no such guard is necessary.

5.4.10 CHECK VALVE

Check valve is a non-return valve installed in the tubing just above the pump, It
is a flapper disc type valve and it allows the flow from bottom to surface and
does not allow the liquid to run down the well through it. It always helps to keep
the tubing full with the liquid and does not allow the liquid to run down through
the pump during the idle condition of the pump. Running down of liquid may
sometimes cause the impeller to rotate in opposite direction and if the pump
starts at that moment, it draws a sudden huge current, which can damage the
electrical components downhole resulting in the insulation failure and thereby
costly workover job.

5.4.11 BLEEDER VALVE (DRAIN VALVE)

Bleeder valve (or Drain valve) is installed above the check valve. It is used to

drain out liquid from the tubing during pulling out job. Before ESP is pulled out
the drain valve is broken by dropping a heavy rod from the top. If it is not
installed, only the wet tubings will be retrieved and on opening the tubing, oil /
water will be splashed on the derrick floor making it (floor ) very slippery and

5,17
create difficulty for the persons to work there. Besides this, it may’ create
condition for blow-out of the well.

This bleeder valve has got a disadvantage too. if during mechanical scraping
operation of tubing, scraping wire gets snapped and sinker bar falls, it breaks the
bleeder valves nipple and there will be no alternative other than to pull out the
tubing for changing the bleeder valve, which means a costly workover job.

5.4.12 PUMP TOP SUB

Pump top sub is a connecting substitute to connect the top of the pump with the
tubing. Its lower portion is a flange to flange connection with the pump top and
top portion is box-threaded to connect with the pin end of tubing.

5.4.13 LOWER PIG TAIL

Lower pig tail is a small length of main cable with one end to be spliced with the
main cable just before the wellhead is to be installed (as and when the running-in
is completed) and the other end is to be connected (coupled) with the electrical
minimandrel which is installed in a specially drilled hole in tubing hanger by the
side of the tubing connection. This type of lower pig tail - minimandrel
connection is meant for the “seaboard” or equivalent types of wellhead.

5.5 SURFACE COMPONENTS

5.5.1 VVELLliEAD

When the final run-in of the tubing is completed, it is required to cap the weli
properly so that only tubing and cable or the tubing and mini-mandrel are

5.18
protruding outat the surface. Onthetubing, X-mass tree is fitiedandprbtruded
cable or mandrel is connected to the surface cable. So, the wellhead is to
provide a petfect seal around the tubing and power cable and keeps the tubing
hanging by its tubing hanger. There are numerous types of wellheads available
in the market. Broadly, ESP wellhead can be categorised into two types:

(i) The wellhead through which the sub-surface power cable protrudes at the
surface: -This type of wellhead is having necessary rubber packings for
providing, leak proof sealing around the cable. “Hercules” make wellhead
is one such type. Wellhead is always required to be specified for parallel
cable or round cable as well as for the required AWG specification. This
type of wellhead, can withstand a pressure of around 1500 psi (100
kg/CM2),

Produced fluid leakage from such type of wellhead through cable-rubber

packing seal section is a common problem. Once the wellhead leaks, it
is sometimes required to subdue the well and new wellhead packings are
installed.

(ii) The wellhead through which mini-mandrel protrudes at the surface:- Here
the main subsurface cable is joined with one end of the lower pig tail and
the other end of the lower pig tail is coupled with the mandrel. Similar
type of pig tail ( upper pig tail ) connection is there at the surface. Mini-
mandrel is screwed on the wellhead with necessary “O” - ring.
“Seaboard” make wellhead is similar kind of wellhead, This type of
wellhead can withstand much higher pressure of around 3000 psi (200
kg/cM2).

Both the types of wellhead ‘Hercules’ and ‘Seaboard’ types were in use in
ONGC. Now-a-days only “Seaboard” type is preferred.

5.19
5.5.2 MINI-MANDREL

Three capper conductor of the required size and around them very good non-
conducting solid material in a cylindrical shape form mini-mandrel. It is screwed
into the slot of seaboard type well-head. FWbber ‘O’ ring seal is provided for

effective fluid seal. Upper and lower pigtails are coupled with the two ends of the
mini-mandrel.

5.5.3 UPPER PIG TAIL

The upper pig tail is similar to the lower pig tail. One end is connected to the
surface cable and the other end is coupled with the top of the minimandrel fitted
at the wellhead.

5.5.4 SURFACE CABLE

Surface cable is similar to the power cable. Approximately 100 m or so length of

cable is laid on the surface to connect the wellhead to the switch board. It is
advisable to pass the surface cable through a tubing so that the cable can be
protected from any kind of physical damage.

5.5.5 JUNCTION BOX

Junction box is required especially when ‘Hercules’ make wellhead is used. It is

a junction point of well cable and surface cable located at a safe distance from
the wellhead. It is a well ventilated box. In case any well gas migrates through
power cable at the surface, it gets vented at junction box. This prevents gas
getting vented in switchboard which can result in an unsafe condition to work and
potential fire hazard. (Refer Fig. 5.8, )

5.20
Though there is noscope of gas migrating through the mini-mandrel, it is always
a safe system to lay the cable from wellhead to Junction box and then from
Junction box to the switchboard.

5.5.6 BOOSTER

Booster is required to boost the surface voltage according to the requirement of

rated downhole voltage. It is connected preferably in between the junction box
and switch board.

5.5.7 SWITCH BOARD

The standard switch boards are weatherproof, but not flameproof. They are
available in different ranges of voltage say from about 440 volts to about 4900
volts. Also the selection criteria depends upon other factors like amperage,
horse power requirements etc.

It has many features like recording ammeter, fused disconnects, underload and
,
overload protection, signal lights, timers for intermittent auto start, etc.

In case of underload operation due to incoming of less fluid in the pump, which
causes motor to draw less current, the controller shuts down the unit
automatically. However with a selected time delay apparatus, say from 30 min.
to 2 hour the unit can be automatically restarted. Similar kind of auto re-start is
not provided in case the pump is stopped due to overload operation. Overload
shuthown has to be manually restarted, only after the necessary faults causing
overloading are rectified.

Switch board and booster compressor are housed in a well ventilated room at a
safe distance away from the wellhead. The room or switchboard house has its

5,21
floor padded with adequate thickness of rubber padding. The switchboard house
is also properly earthed.

5.5.8 POWER TRANSFORMER

Standard power transformer i.e. step down transformer say from 11 kV to

420/440 V is available with different kW range. Since all the ESPS in ONGC’S
onshore fields are having motors with kW range less than 22 kW, 25 kW
transformer is used to cater to the need of one well.

Other vital components of ESP are different types of Electrical tapes for splicing
the cable, copper-sleeve for cable conductor to conductor connection, different
sizes of rubberised “O” - ring, galvanised armour etc, which are required during
the installation of pump.

5.6 STANDARD PERFORMANCE CURVES

The standard performance curves are the most important graphs for ESP design
(Refer Figs. 5.9a, 5.9b, 5.fOa, 5.fOb, 5.lfa & 5. ffb). For every type of ESP, in
its dynamic flow condition standard performance charts are drawn. The abscissa
(horizontal axis) indicates the capacity of pumping in bbls/day or m3/day and the
ordinate (vertical axis) indicates liquid head to be generated, brake H.P. and
efficiency of ESP. For a small type of pump with different r.p. m. the standard
performance chart will be different. So for every pump performance chart r.p.m.
is mentioned.

The head capacity is plotted with the head either in feet or in metres. For
simplistic approach fresh water of density 1 gm/c.c. has been used to generate
the performance curve by the pump manufacturing companys.

5.22
Also, the performance curve is plotted either with 100 stages of pump or with
single stage, as such, some companies prefer the former one and some the
latter.

In the pump performance curve, at very low rate or almost zero rate, the head
capacity to be developed by the pump is maximum and as the pumping volume
increases the head capacity decreases and at one point of pumping the head
capacity is zero. It means there will not be any lifting of liquid in the tubing
beyond that volume. Keeping an eye on the pump efficiency, every
manufacturer has drawn a maximum and minimum range in each performance
curve, as such all ESPS are supposed to operate within this range. The space
between the maximum and minimum lines is called the recommended range.

As an example, say pump is required to pump 80 M3/D. The type of pump

suitable with r.p. m. (as per Indian condition, it is 2915 r.p.m. ) and casing size is

to be chosen where 80 M3/D falls somewhere in the middle of the recommended

range. Let the pump performance chart be made for 100 stages of pump. Let
the total head to be developed is equivalent to 800 Mts,

So, now 80 M3/D is marked on the abscissa. From there a vertical line is drawn
which cuts the head capacity curve and from there a line is drawn to
horizontally cut the ordinate. Let the value at the ordinate be 400 mitres. of
head.

It means each stage can develop 4 Mts. of head (i.e. 400 Mts. is divided by 100
stages).

Therefore, to develop 800 Mts.,

number of pump stages required = 800 Mts. = 200 stages

4 tits.lstage

5.23
 So, in this way required number of stages can be calculated.

Therefore, in order to find the motor capacity i.e. Horse power of motor,

H.P. = H.P./Stage x total stages of pump x specific gravity of fluid

It is always advisable to mark the highest B.H.P. from the graph. Say maximum
H.P is marked as 7.65, then it is better to consider 7.7 H. P. (i.e. the next whole
number after decimal)

Therefore, H. P. = 7.7/1 00 x 200 x 1.05

= 16.17 H.P

(Here kill fluid Sp.Gr is taken as 1.05)

Now say, no motor of that rating ( HP ) is available. So, always, it is advisable to

choose the motor of H.P. just higher than the calculated one, say 18 H.P.

5.7 TOTAL DYNAMIC HEAD (TDH),

Total Dynamic head, written in short as TDH, is a very common concept in

calculating the total stages of a centrifugal pump. This includes : (i) The friction

losses in the tubing and surface flow line, (ii) Tubing pressure against which

pumping is to be done, (iii) The difference in elevation of the dynamic level and
the surface, (iv) Any losses due to valves etc. in the flowline.

By taking into account only the elevation and tubing pressure and neglecting all
other factors, TDH can be written as :

5.24
 TDH = Tubing pressure [in terms of equivalent fluid (liquid) height]
+ Dynamiclevelas measured from top i.e., from the surface, (Refer

Fig.5.12)

For example,

Say tubing pressure = 10 kg/CM2,

= 100 m of water

and dynamic level from the surface = 600 m then,

TDH=100+600=700m

5.8 TROUBLE SHOOTING

Whenever any problem of ESP operation occurs, it is required to be properly

identified,” as some rectification of the surface equipments can overcome the
problem. In this manner costly workover jobs can be saved. So, in this respect,
it is required to generate sufficient well data like

(1) Rate of oil production.

(2) Water cut.

(3) Run-life of ESP unit.

(4) Dynamic & static fluid loads.

(5) GOR/GLR.

5,25
(6) Pump setting depth.

(7) Sand cut/corrosive fluid etc.

(8) How many times ESP has been serviced and for what reasons.

(9) Reservoir pressure, Reservoir Drive mechanism, Rate of fall of static

pressure etc.

(lo) Bottom hole temperature.

(11) Electrical power supply details like voltage, current, voltage fluctuation,
frequency of power cuts and other related details.

These data should recollected regularly, andparticularly more frequently in the

Beginning i.e. just after commissioning or recommissioning of the ESP unit (say
at first, every day & then in every 3 to 4 days, then say after a month and like
that ).

One of the very important source of information, when troubleshooting an ESP

installation, is the recording ammeter.

The recording ammeter continuously records the amperage drawn by ESP,

either it can be put on operation daily or periodically. It is already inbuilt in the
switch boa rd system.

Different probable recordings of ammeter charts have been discussed in the

following section.

5.26
5.8.1 TYPICAL AMPERE CHARTS OF ESP

Fig-5. 13 a NORMAL & SMOOTH OPERATION

It shows the ideal operating conditions. The chart draws a smoolh symmetrical
amperage curve at or near the name-plate amperage, The producing rate and
dynamic head are steady and possibly can vary by approximately 5Y0, which is
negligible. One spike is shown here, which is normal the occurrence during the
start-up of the motor. The spike very often extends through the, full spacing of
the pen for a very brief time and then comes to normal operating current.

Fiq-5.13 b NORMAL OPERATION WITH FREQUENT SPIKES

The graph depicting the spikes from time to time indicate the power fluctuations.
This may arise due to various reasons like:

(i) If the primary power supply voltage at source fluctuates. The amperage
naturally fluctuates in an attempt to retain constant horsepower output.
This type of fluctuation is commonly seen,

(ii) Periodic heavy drain of power in adjacent areas may cause such spikes,
especially when there is a common transformer for more than one ESP.
In most of the ONGC wells, separate transformer is provided for each
well, barring a few cluster wells, thus avoiding this problem.

(iii) These spikes can also be observed during an electrical disturbance such
as lightning / storm, since fluctuation of voltage can be witnessed in that
period.

Here, the range of spikes is contained within the overload and underload
settings.

5.27
Fiq-5.l 3 c FLUID PUMP OFF CONDITIONS/FAST LOWERING OF
ANNULUS LEVEL

This chart shows intermittent operation of the pump. The fluid pump off condition
occurs when the pumping unit’s capacity is larger than well intake capacity. As a
result the continuous drop in amperage is observed. When the amperage goes
below the underload setting, switchboard automatically switches off the power.
Immediately then re-start timer starts working and after a pre-fixed pause time
(time delay here is set at 2 hour, which is maximum.) the switchboard
automatically switch on the power to ESP.

Fiq-5.13 d PUMP OFF / GAS LOCK

It shows the typical chart of a pump which has gas locked and consequently had
an automatic shutdown. The well is being pumped out intermittently with the
help of timer device, where the well remains shutdown from 1/2 hr. to 2 hr. after it
shuts down automatically. In each idle period, the fill up of the fluid in the
annulus takes place. So, initially, production rate and amperage are more and
then amperage comes down to its normal value with more or less designed
production rate. Thereafter a decrease in amperage takes place, when the fluid
level falls below the desired level. Finally, before the pump gets under-loaded,
the erratic amperage, pointing to the cyclic loading of free gas and liquid slug in
the pump is observed.

Ficj-5.13 e INSUFFICIENT PAUSE TIME

It happens when sufficient annulus build up does not take place in the idle
period. This happens when the P.1. of the well is very poor. This is also a case
of pump-off phenomenon.

5,28
Fig-5.13 f FREQUENT SHORT DURATION CYCLING

Here the running time of pump is very brief and therefore it has created more
cycles. This type of situation arises due to various reasons like faulty adjustment
of amperage, very poor P.1. of the well, which is much less than the pump
capacity, excessive flowline pressure etc. This type of situation fails to maintain
proper cooling of motor which may result in early breakdown of motor insulation.

Fig-5.13 ~ NORMAL / HIGH GOR PUMP OPERATION

Interference of free gas is noticed here. Possible cause of this is the emulsified /
heavier fluid with free gas trapped in it. The fluctuation indicates very frequent
loading and off-loading of pump.

Fig-5.13 h PUMP OFF/ DRY RUN

This chart indicates that after a normal start-up, a decline in amperage has taken
place. The fluid production is very less. After a prolonged period of idle
operation, the unit shows overloading and stops. One of the possible reasons is
that underload relay system in the switchboard which is either not set properly or
not working. This condition is very serious as it may lead to breakdown of motor/
cable insulation.

Fig-5.13 i OVERLOAD CONDITION

Overload condition of the pump is another very common phenomenon, It may be

due to emulsion or very viscous liquid at the pump, mechanical problem of pump
or because of disorder of power supply. Just after the well is worked over this
type off phenomena has been observed mainly because of emulsion problem

5,29
due to the mixing of technical water with incoming gas-free oil from the
formation. Low voltage also makes the current high leading to overloading.
Overloading due to the mechanical problem arises when there is excessive drag
of impeller with the diffuser pads, shaft is not rotating freely or some bearing is
not working properly .

Other possible causes of overloading are lightning, motor overheating, etc.

Once the pump is overloaded, it will not get automatically started. Whenever it
occurs, pump is started once again only manually and if the same overloading
phenomena is repeated then it is mandatory to check it thoroughly from the
electrical aspects and with necessary rectification, if any, pump should be re-
started.

Fiq-513 i VISCOUS / EMULSIFIED FLUID ENTRY

The chart shows that during the initial starting period, there appears to be current
fluctuations, followed by drawing of normal current during the pumping operation.
This type of situation is also encountered after workover operations. It is
regarded as the cleaning operation with the help of pump for pumping out
muddy water or brine, very viscous oil-water emulsion, etc. Once these are
pumped out pumping operation becomes automatically normal. So electric motor
coupled with ESP should have adequate capacity to overcome this type of
situation.

5.9 ESP DESIGN

Given Data

Well depth :2500 Mts. ( 8220 ft )

5.30
Tubing :2 7/8 inch
Casing size :51/2 inch (17- 20ppf)
Reservoir pressure :205 kg/cm2 (2915 psi)
Flowing Bottom hole pressure :180 kg/cm2 (2560 psi)
Wellhead pressure :7 kg/cm2 (100 psi)
Water cut : 60?40
GOR :45 m3/m3 (252 SCF/b)

GLR :17 m3/m3 ( 96 SCF/b)

Design Liquid rate ( at stock tank ) :35 M3/D ( 220 b/d)

Degree API of oil :35° API (Sp.Gr. = 0.8489)

Specific gravity of gas (Air= 1) :0.65

Specific gravity of water :1.05

Bottom hole Temperature : 70°C(158°F)

Wellhead temperature : 30°c (86°F)
Bubble point pressure :80 kg/cm2 (1 137 psi)
Electric supply system :400 /440 V:50Hz
Well profile : S - shaped (Build-up and Build-down
Profile) and from 1000 mts depth from
surface it is vertical.
Formation volume factor (6.) : 1.q5

The following are the step-wise calculations :-

STEP -1: SIZE OF PUMP

From the catalogue of ESP manufacturer the best suited pump primarily with
respect to its OD and capacity is to be selected. Let the available ESP is of
REDA make.

Since casing size is 5 1/2”, at the first instance, 400/450 series REDA
pump/protector as applicable in 5 1/2”, is considered (Reference : REDA

5.31
catalogue). Now, maximum OD of Reda pump set with cable, cable guard and
cable clamp in position is required to be checked with 5 1/2” ; 20 ppf casing (that
is minimum ID of casing).

i) OD of 450 series protector =114.3mm

ii) Thickness of Armoured cable of = 12.3 mm

6 AWG of parallel shape

iii) Thickness of cable guard and cable = 2.0 mm (approx.)

clamp
Total = Max. OD of REDAPump = 128.6 mm
(400I 450 series)

1.0 of 5 1/2” , 20 ppf casing = 121.4mm

Drift diameter of 5 1/2”, 20 ppf casing = 118.2mm

Since drift diameter of 5 1/2”, 20 ppf casing is less than Max. O.D of Reda pump,
it is requi~ed to find out pump of one size lower.

The next lower size is of 338/325 series pump / protector as applicable in 4 1/2”
casing.

i) 00 338/325 series pump/ protector = 85.85 mm

ii) Thickness off Armoured cable = 12.30 mm

(6 AWG, parallel)

5,32
iii) Thickness of cable guard and cable = 2.00 mm
clamp --------------------- -
Total = Max. OD of 338/325series = 100.15 mm
Pump / protector

Therefore, clearance between minimum casing I.D. and max. pump O.D.

= (118.20-100.15)x 1/2

=18.05 xl/2 =9.0mm

From Reda catalogue, the compatible pump / protector set of 338/325 series is
selected which is to be coupled with 375 series motor OD = 3.75 inch = 95.25
mm).

STEP -2: STATIC AND DYNAMIC LEVEL

Considering the datum level at 2500 Mts,, and with specific gravity of water as
1.05, the fluid level at static condition = 2050 x 1/1 .05 = 1952 Mts. So, static fluid
level from the surface = 2500-1952 = 548 Mts.

The fluid level at flowing condition (that is, dynamic condition)

= 1800x 1/10.5= 1715 Mts.

Therefore, dynamic level from the surface = 2500-1715 =~=1

L I

STEP -3: LOCATION OF PUMP DEPTH

The pump has to be located below the dynamic. Also, to minimise the
interference of free gas, the pump, if possible, can be located in deeper depth,

5,33
i) Dynamic level from surface = 785 Mts.
ii) Bubble point pressure of 80 kg/cm2,
Which is equivalent to = 762 Mts.
-----------------
Total = 1547 Mts.

... Location of Pump

‘m fron’su”ace

STEP -4: FLUID VOLUME IN THE PUMP (Q)

Q = 35m3/dx Bo = 35x1.15

‘L!!!!4
STEP -5: PUMP SELECTION

A 400 pump is selected from performance curve as supplied by the manufacturer

for 50 Hz supply and 338 series pump with the desired fluid production rate of
40 m3/d lies in the recommended range for operating the pump on the accepted
efficiency level.

STEP -6: PUMP STAGES CALCULATION

From the performance curve, 100 stages develop 400 Mts. of head.

...1 stage develop 400/100 = 4 Mts. of head.

Now, TOTAL Head required, that is, total dynamic head (TDH) will be,

5,34
TDH = Dynamic level from surface + fluid friction in the tubing + Tubing ‘head
Pressure.
= 785 Mts. + negligible + 70 Mts.

‘EEI
855 Mts.
.O. Total stages of pump required = ------------------ = 214 stages.
4 Mts. / stage

From the catalogue of the manufacturer, the number of stages and housings
have been selected, so that total stages of pump is slightly more or equal to 214
stages.

2 numbers of housings each having 81 stages and 1 number having 60 stages

have been selected.

So, total stages = (2x 81) + 60)= 162 + 60

‘E

STEP -7: MOTOR HORSEPOWER REQUIREMENT

From performance curve, max. H.P. = 6.0 H.P. / 100 stages

The nearest whole number = 6.0 H.P./l 00 stages

= 0.06 H.P. / stage

So, Total H.P. requirement = H,P. /stage x Number of

Stages x specific gravity of water

5,35
 = 0.06X 222 X 1.05

= 13.98 H.P,

From catalogue, 375 series motor has to be selected, which has H.P. either
equal to this value or next higher value.
H.P. Motor selected = 16.3 H.P.

It is always advisable to choose a motor with low amperage rating, provided its
voltage rating is not very excessive. So, from two categories of 16.3 H. P., 50
Hertz motors,

That is from, 16.3 HP; 238 V ; 38 A; 50 Hertz

and 16.3 HP; 323 V; 25A ; 50 Hertz

the motor of 16.3 H.P.; 323 V; 25A; 50 Hertz is selected.

STEP -8: MAIN CABLE SELECTION

From manufacturers catalogue “Redelene” type (can work up to 205° F, where

B.H.T. is 158°F) flat cable and 4 AWG (considering cost and voltage drop factor)
has been considered.

STEP -9: SURFACE VOLTAGE CALCULATION

From cable voltage chart, supplied by the manufacturer,

Voltage drop = 11 volt/ loooft.

Total cable length = Subsurface cable length + Surface cable length

5.36
 = 1600 Mts. + 100 Mts. (say)

Total cable length = 1700 Mts. = 5576 ft

= 5600 ft

Ilv
So, the total voltage drop = ----------- x 5600 ft.
1000 ft

=61.6V

.-.Voltage required at the surface = name plate voltage + Total Voltage drop

= 323+ 61.6

= 384.6 V

= 385 V

STEP -10: CALCULATION OF KVA (KW) REQUIREMENT OF POWER

TRANSFORMER (STEP DOWN TRANSFORMER)

(Required Surface voltage) x (name plate amps.) x (1 .73)

KVA = ---------------------------------------------------------------------------------- + 2.5~0
1000

385x 25 x1.73
= ------------------------- + 2.50/o = 16.65 + 2.5%
1000

5,37
 16.65 X 2.5
= f 6,65 + ----------------- = 16,65 + 0.42
100

=17.07 =18KVA

Since the power transformer of 18 KVA is not normally available. The next size
available is 25 KVA So, power transformer of 25 KVA (25 kW) is selected.

STEP -11: SELECTION OF SWiTTCH BOARD

From the manufacturers catalogue, the switch board of the following type is
selected depending on max. volt, H.P. and max. full load amps.

Switchboard is class DFH-2, type 72, size 2, max. volt 600, H.P. 25 and max. full
load amp. 50.

STEP - ?2: LIST OF SUITABLE DESIGNED PUMP, ITS COMPONENTS AND

MISCELLANEOUS ACCESSORIES

All pump components must be compatible to each other.

mmf2 : A -400 :222 stages :2 Nos. of Housing each Of 81 stages

( 338 series) 1 No. of Housing of 60 stages.

Motor : 375 series : 16.3 HP; 323 V; 25A; 50 Hertz; Tape-in type

Protector : 325 series ; labyrinth type.

Intake Section : Reverse flow gas separator

5.38
Pot-head Cable : 6 AWG : Redelene flat galvanised ; 50 ft in length

Main Cable : 4 AWG; Redelene flat galvanised; around 1700 Mts.

(5600 ft) in length wound onto a reel.

Wellhead : “Seaboard” wellhead or equivalent for 5 1/2” casing; 2 7/8”

tubing with necessary fitting like upper and lower pigtails,
mini-mandrel etc.

Switchboard : Class DFH-2, type 72, size 2, max. Volt 600, H.P. 25 max.
full load amp. 50.

Power Transformer: 25 WA capacity with step-down voltage from 11 kV power

transmission line 400 / 420 V (standard industrial voltage).

Accessories : Junction box, Pulley and its arrangement for lowering /

pulling of ESP in and out of the well, sufficient quantity of
high quality insulating oil (REDA oil of M/S Reda Co.),
ammeter recording charts, full splicing kits, sufficient number
of cable bands, clamping of cable band tool-set, check
valve, bleeder valve with nipples, pump discharge head, Pot-
head extension guards or channels, centralizers, necessary
mechanical handling tools and necessary electrical
instruments

--------------------------------- ------------------------------ ------------------------------------------ ---

5.39
 Training On Artificial Lift Operations

Figure :5.13 a

Pump Is In Normal & Smooth Operation, Since

Pumping Operation Continues with Almost
Negligible Fluctuation In Amperage.

5.61
 Training On Artificial Lift Operations

Figure :5.13 b

Pump Is Operating As Normal. However, Spikes

Are Noticed, which Are Presumably Due To Voltage
Fluctuation. As A Result Current Fluctuates As
Spikes, Where Range Of Spikes Is Limited Within
The Overload & Underload Settings.

5.62.
 Training On Artificial Lift Operations
=.

Figure :5.13 c
This Is Pump Off Condition Of The Pump. The Discharge
Of The Pump > Fluid Intake From The Wellbore. As A
Result Continuous Drop In Amperage Is Observed And As
The Amperage Drops Below The Underload Setting,
Switchboard Automatically Switches Off The Power.
Immediately Then Re-start Timer Starts Working & After A
Pre-fixed Pause Time The Switchboard Automatically
Switches On The Power To ESP.

5.63
 Training On Artificial Lift Operations

Figure :5.13 d
This Is A Case Of Pump Off / Gas Lock . Due To More
Capacity Of Pump Discharge Than The Inflow Capacity Of
Well, Fluid Level In The Annulus Goes Down Continuously,
With Generation Of More And More Free Gas In The Pump.
Finally The Current Goes Below The Underload Setting
And Pump Stops. Thereafter The Auto Restarting Unit
Starts Operating & Pump Gets Restarted After A Pre-
determined Pause. Very Frequent Current Fluctuations
Prior To Shut-down Indicates Gas Locking Phenomena.

5.64
 Training On Artificial Lift Operations

Figure :5.13 e

This Indicates Insufficient Pause Time Before The Pump Is

Restarted. This Is Possibly Due To Very Low Influx Into
The Wellbore &As Such Length Of The Pause Time Should
Be More. This Is Also A Case Of Pump-Off Phenomena.

5.65
 Training On Artificial Lift Operations

Figure :5.13 f
This Indicates A Large Number Of Times Of Operation And
Shutdown Of Pump. The Possible Reasons May Be :
QIIfPump Is Of Very High Capacity And Inflow Into The Wellbore Is
Very Less, Then This Phenomena Can Occur. However, In Practice,
Except At The Initial stages Of Pump Commissioning, This Is
Remote.
OIf Flowline Pressure Is Excessively High, It Will Lead To Early
Shutdown Of Pump Due To Underload Phenomena.
After A Pre-fixed Pause, The Automatic Restarter Starts.
This Condition Shortens The Operating life Of Pump And Hence
Should Be Avoided.

5.66
 Training On Artificial Lift Operations

Figure :5.13 g

It Is A Normal / Hi@h GOR Pump Operation, Provided There Is

No Voltage Fluctuation To That Extent. The Fluctuation
Indicates ‘ The Loading And Off-loading Of Pump Very
Frequently Due To Interference Of Gas.

5.67
 Training On Artificial Lift Operations

Figure :5.13 h
This Is Case Of Pump Off/ Dry Run Of Pump. This Case Arises
When Underload setting Is Not Done. Due To relatively Low
Intake Of Formation Fluid Into The Well-bore, Amperage
Gradually Drops & Then maintains A Very Low Value All
Through The Pump Operation. There Is No outflow Of Fluid At
The Surface.
This Resulted In Abnormal Heating Of The Motor/ Cable And
Thereby Damage The Insulation. This Condition Must Be
Avoided.

5.68
 Training On Artificial Lift Operations

Figure :5.13 i
This Is Case Of Overload. The Current Goes Up Gradually &
Finally When It Crosses The Overload Setting mark, The Pump
Stops. Overloading Phenomena May Arise Due To Power
Fluctuation Or Due TO Mechanical / Fluid Problem. As Per
convention Of The Manufacturer, After Overload Shut-down,
Pump Will Not Get Automatically Re-started. This Needs To Be
Checked By Electrical & Production Engineers For Locating
The Actual Fault. Once The Fault Is Located & Rectified, Pump
Is Then Run Manually.

5.69
 Training On Artificial Lift Operations

Figure :5.13 j

This Is Case Of Viscous / Emulsified Fluid Entry InThe

Pump. Once The Viscous & Emulsified Fluid Are Pumped
Out, Pump Is In Normal Operation.

5.70
 Training on Artificial Lift Operations

Chapter 6

JET PUMP
6.1 THEORY

The hydraulic jet pump (Refer Fig. 6.1 & 6.2) requires no moving parts to develop
the pumping action. This is accomplished by momentum transfer of fluid through
an ejector nozzle, throat and diffuser assembly. As the high pressure fluid comes
out from the nozzle and enters in the throat or mixing tube, it is converted into a
high velocity and low pressure fluid Jet. Thus the surrounding well fluid, having
comparatively higher fluid pressure and having access to the throat chamber will

be sucked in the throat. On passing from throat to diffuser, the mixture of well
fluid and power fluid loses velocity and consequently acquires equivalent

discharge pressure to a value sufficient enough to lift the total fluid to the surface.

Nozzle and throat sizes determine flow rates while the ratios of their flow areas

determine the trade off between produced head and flow rate. For example, if a

throat is selected such that the area of the nozzle is 60% of the throat area, a
relatively high head, low flow pumping operation will result. There is a
comparatively small area around the jet for well fluids to enter in the throat,
leading to lower production rates compared to the power fluid rate, and with the
energy of the nozzle being transferred to a small amount of production, high
heads will be developed. Such a combination of nozzle throat sizes of the jet
pump is suited to deep wells with high lifts.

Conversely, if a throat is selected such that the area of the nozzle is only 20% of
the throat area, more production rate is possible, but since the nozzle energy is

being transferred to a large amount of production compared to the power fluid

6.1
rate, lower heads will be developed. Shallow wells with low lifts are candidates for
such a combination of nozzle & throat sizes of the jet pump.

A large number of combinations of nozzle and throat areas are possible to match
different production rates and head requirements. Attempts to produce small
amounts of well fluids as compared to the power fluid rate with a nozzle throat
ratio of 0.2 will be inefficient due to losses as a result of high turbulent mixing

between the high velocity jet and the low rate ( slow moving ) of production.
Conversely, attempts to produce at high rates with a nozzle-throat ratio of 0.6 will
be inefficient due to losses resulting from high friction as the produced fluid
moves rapidly through the relatively small throat area. Selection of required ratio
involves a trade-off between these two extreme losses viz. losses due to turbulent
mixing and losses due to friction.

It is also required to be ensured that Cavitation must not occur in the pump. The
throat and nozzle flow areas define an annular flow passage at the entrance of
the throat. The smaller this area, the higher the velocity of a given amount of
produced fluid passing through it. The pressure loss of the fluid in the annular

passage is proportional to the square of the velocity and eventually may reach the
vapour pressure
. of the fluid at high velocities. This low pressure will cause vapour
cavities to form, a process called cavitation. This results in choked flow in the
throat, and then, no more production is possible at that pump intake pressure,
even if the power fluid rate and its pressure are increased. Subsequent collapse
of the vapour cavities happens as pressure is built up in the pump diffuser. This
may cause erosion due to implosion of the vapour cavities which is known as
cavitation damage. Thus, for a given rate of production and pump intake
pressure, there will be a minimum annular flow area required to avoid Cavitation

problem.

The pump is defined by the nozzle and throat sizes. A given nozzle number
coupled with same throat number will always give the same ratio of nozzle area to
throat area. This is designated as ‘A’ ratio. Successively larger throat number
when matched with a given nozzle number wit give the B, C, D and E ratio.

6.2
Sometimes “A-” ratio is also used, which will have the throat just smaller than that
of A ratio pump for any nozzle. The standard nozzle to throat area ratios and their
.,
designations as provided by the reputed manufacturer of hydraulic Jet pump M/s.
KOBE have been given as under :----

Pump Ratio Designation Nozzle area to Throat area

A 0.41

B 0.328

c 0.262

D 0.21

E 0.168

The other manufacturers of hydraulic Jet pumps may have slightly different pump
ratios from the ones as given above by M/s. KOBE. The most commonly

employed area ratios fall between 0.235 and 0,40. Area ratios greater than 0.4
are sometimes used in very deep wells, or when the power fluid pressures are
low. Area ratios less than 0.235 are used in shallow wells or when very low

bottom hole pressures require a large annular flow passage to avoid cavitation.

Thus the higher ratio pumps are suitable for low production rates and high heads,
while the lower ratios are suitable for high production rates and low heads.

Three flow configurations are possible for jet pump installation, The first is the
standard circulation type (Refer Fig. 6.3) where the power fluid is pumped
through the production tubing (hence called power fluid tubing or PFT) and the
production is taken through the tubing-casing annulus, The second one is the
reverse circulation type (Refer Fig. 6.4), where the power fluid is pumped through
the tubing-casing annulus and the production is taken through the tubing. The

third configuration is the parallel tubing completion type (Refer Fig. 6.5) where the

6.3
power fluid is pumped through one tubing (power fluid tubing or PFT) and the
production is taken through the other string (return tubing or RT). The size
., of the
return flow tubing is normally bigger than the power fluid tubing since only power
fluid flows through power fluid tubing whereas, power fluid plus produced fluid
flow through return flow tubing. All the three configurations will require seating of
jet pump in the bottom hole assembly (landing nipple) which is required to be

lowered along with the tubing at pre-determined depth.

Normally, the pump is lowered and retrieved by standard wireline techniques.

Only the standard circulation type enables the pump to be retrieved by pumping
the power fluid through the annulus (which is opposite to the normal flow direction
of power fluid). In this case, wireline operations are not required and the pump is
known as “Free pump”.

6.2. MERITS & DEMERITS OF JET PUMP

MERITS :

1) Handles solids:

The wear and tear is less in the jet pump, because primarily the pump has
no moving parts. However, high velocity power fluid as the fluid ejects
through the nozzle can cause erosion of pump parts. Therefore to
minimise the erosion of pump parts, the abrasion resistant materials like
tungsten carbide is used in the construction of nozzles and mixing tubes.

2) Handling corrosive fluids:

The simple construction of the jet pump allows the use of corrosion
resistant alloys, thus corrosive fluids too can be produced.

3) Use in crooked holes:

Short length of the pump allows it to pass through the tight spots created
by highly deviated well bore profile. Since only the high pressure fluid

6.4
 flows through the tubing and there is no tubing movement as such, tubing
wear does not arise.

4) High volume pump:

Jet pumps can handle high volumes of well fluid.

5) Adaptability to sliding sleeves:

The size of jet pump is easily adaptable to sliding sleeves.

6) Handles gas:

The simple mechanical design of jet pump with no moving parts enables it
to produce gassy well fluids with no damage to the pump. However, the

volumetric efficiency of the pump goes down with the increase in free gas
content at the pump intake.

7,) Adaptability to variation in well production rates:

The jet pump can be adjusted to the varying production rates by changing
the power fluid rate to the pump. Higher production rates can be achieved
by increasing power fluid rate, provided the well is capable of giving the
higher rates of production.

8) Suitability to low gravity crude oils:

Mixing of power fluid (water or light oils) with formation fluid, especially in
case of heavy crudes, provides viscosity blending, which results in lower
viscosity of the overall mixture. This in turn reduces the frictional pressure

losses in production string as well as makes the handling of produced fluid

at surface easier.

10) Saves workover cost

A “Free pump”, that can be circulated in and out of the well without the
necessity of a workover rig under normal circumstances, reduces
reinstallation / repair costs to a great extent. For the case of “Free Pump”,
wireline job is also not required.

6.5
1f) Centralised surface facility
Considerable cost can be reduced by a common surface set-up to

generate power fluid for its use as motive fluid simultaneously in number of
near-by wells.

Demerits

1) The jet pump requires higher pump intake pressure than other

conventional pumps to avoid cavitation. A minimum of 20°/0 submergence

is required at the pump intake under dynamic condition.

2) The mechanical efficiency is low in the jet pumps as compared to the

positive displacement pumps, because of higher surface pump horsepower
requirements.

3) The power fluid should be clean and free from solids.

4) The fluid handling capacity of surface facilities (including the separation

facilities) needs to be increased to handle the increased fluid volumes

(I,e.,produced fluid plus power fluid).

5) Parallel string / concentric tubing completions may often be required for jet

pump application, when flow through casing-tubing annulus is not desired.

Parallel tubing completion increases the completion cost.

6) Use of diesel or other similar liquids as power fluid increases operating

costs.

6.6
6.3 COILED TUBING DEPLOYED JET PUMP

This is a type of jet pump installation which does not require deployment of work
over rig to pull out the existing tubing. This involves the attachment of the bottom
hole assembly of pump either with 1 1/4” or 1 1/2” coiled tubing and running-in of

the same as a unit in the existing production tubing. The pump can be operated

as a “free” pump, that is, it can be circulated in and out of the coiled tubing, thus
this avoids utilisation of a service rig as required for total maintenance of
conventional down hole jet pump. The pump can also be set and retrieved with
the help of standard wireline tools.

The power fluid can be pumped down the well through the coiled tubing and the

production can be taken through the annulus of coiled tubing and production
tubing. Though it is a standard circulation type of Jet pump the larger casing or

production casing is not subjected to any fluid flow and associated pressures. The
completion would, however, require a deeper setting of SCSSV which is to be
placed below the Jet pump with 2 7/8” or 3 1/2” tubing. A miniature hydraulic fluid

line as usually will trace the tubing O.D from SCSSV to its surface control set-up
for actuation of SCSSV.

Coii m~lng Jeployed jet pump reduces the size of the jet pump and hence the

production capacity of the pump is reduced. However M/s. Trico, a reputed

manufacturer of hydraulic jet pump claims that the Trico-manufactured coiled
tubing jet pump can handle upto 1000 bbl/d formation fluid in 2 7/8” tubing under
ideal pumping conditions.

The rig-less servicing job of the jet pump makes it a cost-effective option. The

entire hydraulic surface package can be custom-designed to suit the space

requirement and the existing equipments / facilities.

6.7
6.4 SURFACE FACILITIES FOR JET PUMP SYSTEM

Surface facilities for providing two types of power fluid are as follows:

1. Produced well fluid:- When power fluid is the well fluid, separation of the
produced fluids at the surface is done with a three phase separator, which
also acts as a reservoir for the surface power fluid pump. The power fluid
from the separator is cleaned of solids by means of cyclone separators,
before it is taken into the suction of high pressure power fluid pump. A

centrifugal pump is used to supply the power fluid to the inlet of the

cyclone. The pressurised power fluid is then metered and sent to the well.

Oil, gas and part of the water is taken to the GGS for further separation.

Chemicals (corrosion, scale or paraffin inhibitor) can be dosed into the

suction side of the power fluid pump, if required.

A typical scheme of the surface facilities used with well fluid as power fluid
is shown in Fig. 6.6.

2. Water as power fluid:- As per the existing and suitable conditions, external
water source, such as available high pressure water injection water can
also be used as power fluid. In this case, the separation of power fluid at

the well site is avoided as the same can be done at the GGS

6.5 SIZING OF DOWNHOLE HYDRAULIC JET PUMP

The following method of sizing of Downhole Hydraulic Jet Pump is adopted by

down hole Jet pump manufacturers. In order to select the appropriate pump
design, they have drawn head ratio and efficiency Vs flow ratio curves. Dr.
Brown in his book “Artificial Lift Methods” has provided the procedures for sizing
of down hole Jet pump in the similar fashion.

6,8
Let PP, Pf and PR are the power fluid pressure before the nozzle, flowing bottom
hole pressure and return fluid pressure ( all in psi ) respectively. (Refer Fig.6.7)

qp, qf and q, are the corresponding fluid rates in b/d.

so, q,= qp + qf . . . . . . . . . . . . . . . . . . . . . . (1)

Also, it is considered that Jet pump is placed very near to producing zone.

The ratio of qf and qp is termed as ‘Flow Ratio’ and is designated here as F.

qf
That is, F = ------ . . .. . .. ... . .. . .. . .. . .. . .. (2)
qP

GLR of the return fluid (GLR), is calculated from ‘Flow Ratio’ = F.

From equation (2)

F qf qf F qf
-------- = ----------- = ------- or, -------- = --------
I+F -qP+ qf qr
1+1= qr

[1
Produced gas Produced gas qf
Now (GLR), = ------------------- = ---.-.--..----.---- X ---
qr qf qr

Produced gas Produced oil F

NOW(GLR)r = ------.-.----------- x ------------------- x -------
Produced oil qf I+F
[ 1

F
= (G. O. R.) x (Produced oil cut fraction) x --------
l+F

6.9
 = (G.O.R.) x ( 1- Produced W/C fraction) x ---E---
l+F

F
=(G.O.R.)x( 1- fti)x -------- . . .. . ... .. . .. ... . .. . . (4)
I+F

Now water cut in the return string is found as follows :-

With oil as power fluid : To calculate f~r

qf
From equation (2), that is, F = -----
qP

F qf (0)f + (W)f (0)f (W)f

3 ------- = --------- = ------------ = ---- + -.---

I+F qf + qp % qr qr

F (0)f qf F
s ------- = ------- x ---- + f~r = (1 - fwf) X ‘------- + fwr
I+F. qf qr I+F

=’ f~r = ( -:-;-;) - (--:-----) + fwf x -;;-;

I+F

F
~ fwr = f~ x -------- . . .. . .. . .. . .. . .. . .. . ... . (5)
l+F

With water as power fluid : To calculate fwr

Now, considering power fluid as total water than water fraction in the return fluid
qp+f~ qf qp+f~f
= ----------- = ----------
if+ qp qr

6.10
 1 qP
Now, from (2), --------- = ----- . ... . .. . .. . .. . .. . .. . ....(6)
l+F q,

Again, considering produced fluid contains water cut then from equation (5), the
contribution of water from formation to the total water cut in the return string
F
= fw x ------- . . .. . ... .. . .. . .. . .. . ....(7)
I+F

Therefore, with water as power fluid, the final water in the return fluid (fw) will be

fwr = (
---!-- ) + ( f~ )( --:----)
I+F I+F

l+ fW, xF
= fwr = --------------- ........................(8)
1+1=

P~is calculated from I.P.R of the well.

PP is calculated from the published multiphase flow correlation, considering qp.
P, is calculated from the published multiphase flow correlation, considering, q~

Then, the head ratio (HR) is calculated by using

P, - Pf
HR = ------------
Pa - P,

It is therefore, logical that the values of HR will be less than 1.

The sizing calculation is first started with an assumed value of F, which is equal to
0.5. That is, F = 0.5

6.11
After calculating “HR’ the value of F is calculated by using Head Capacity Curve
as provided by the manufacturer, considering the best efficient part of the curve.

The value of F, so obtained, is multiplied by a factor known as volumetric

efficiency factor as obtained from M.B, standing’s correlation. This provides a
corrected value of F.

Now if the value of F is found very close to the assumed value, then this will be
the final value. But if this value is not close to the assumed value, then the

calculation is to be done again with a new value of F. In this iterative procedure,

the appropriate value of F is calculated.

Now, with this value of F, the procedures to calculate the pump sizing are as
follows :-

qf
STEP -1 qp is calculated from F = -----
qP

STEP -2 By using the equation,

‘ qP
AN = -------------------------
1214.5 dpy Pf
GE

Where AN = Area of nozzle in sq.inches,

Pp and Pf are is psig.

qp in b/d

Gp = specific gravity of power fluid.

6.12
STEP -3 The next higher nozzle size is selected from the list of sizes available
with the manufacturer.

STEP -4 With this higher size nozzle, the new power fluid rate (qP) is calculated

by using the equation as given in step -2.

STEP -5 HP (of the power fluid) = 1.7 x 10-5 qp PPS

Where, Pp~ = surface operating pressure of the power fluid.

STEP -6 The flow is to checked to ascertain, where it is “cavitating” or “non-

cavitating” Flow must be “non-cavitating”.

From the equation,

1- Rn~
FC = ---------- j 1 + KC E
Rn~ Ic (Pp - Pf) + Pf

Where, R~t = nozzle area / throat area

K. = nozzle loss coefficient = O.15

Ic = Cavitation Index = 1.35

FC = New flow ratio to check cavitation.

If F < F., then flow is non-cavitating, otherwise, if F> FC, the whole calculation is
required to repeated with another value of F.

6.13
6.6 CRITICAL OBSERVATIONS ON HYDRAULIC JET PUMPS.

i) Hydraulic Jet pumps are extremely useful to produce oil from very deep
well, where all other Artificial Lift Systems do not perform properly.

ii) Hydraulic Jet pumps can be very economically utilised to produce oil from
marginal and isolated offshore oil fields / wells.

iii) Hydraulic Jet pump has also found its applicability for de-watering to
produce coal-bed methane gas.

iv) Hydraulic Jet pump appears to be very effective in deep and highly

deviated well like S-profile well.

v) Since hydraulic Jet pump is very sensitive to surface pressure of return

fluid ( i.e., tubing pressure or back pressure of the well ), this lift can be

combined with continuous gas lift for significant reduction in horse power
and power fluid requirement. However along with sensitivity analysis, trial
fiekj application is required to establish all the benefits of this type of
combined lift in the same well.

---------------------------- ----------------------- -------------------------------------- -------------------

6.14
 Chapter 7

SELECTION CRITERIA FOR

ARTIFICIAL LIFT METHODS

7.0 INTRODUCTION

Selection of the appropriate and economical artificial lift method is imperative for
the long-term profitability of most producing oil wells. With a number of factors
influencing such a selection, it becomes a complex task. Artificial lift mode

capabilities and the well productivity are required to be perfectly matched so that an

efficient lift installation results. Design considerations must commence before

drilling a well or a group of wells. In order to obtain optimum rates by artificial lift at
some date, sullicient tubular clearances should be provided. Application of any of
the lift techniques will also depend on whether a group of wells will be put on lift or
only a single well needs artificial lift.

The type of Iifi may be influenced by whether or not the wells are conventional or
multiple completions. Multiple completions present several problems. Often, here,
the choice of lift method may be determined not by optimum design but by the
physical limitations of the well.

7.1
Producing location is yet another factor governing the choice of lift method.
Capacity to withstand load and the limited space of offshore platform largely govern
the type of Artificial lift system. The best artificial lift method for onshore may not be
practical for offshore locations. Again, choice ofa proper lift method for marginal
fields especially in the offshore is a difficult exercise. Severe weather conditions like

extreme heat or cold, high winds, dust or snow may limit the choice of lift. Corrosion
again is very important in the selection of lift methods. Produced solids such as
sand, salt and formation fines along with paraffh asphalting, are also important
factors for the selection of lift mode. Depth and temperature of producing zone and

type of hole deviation are important considerations while considering the

application of a type of lift. Reservoir characteristics must be considered for section
of lift. For example, in a depletion drive reservoir, in the initial period of exploitation
high production is expected. Artificial lift may not be required at this stage.
However, if it is decided to lower lift before the start of production the type of
artificial lift and design considerations must be anticipated for operating lift at a later
date. A comparatively rapid decline in production with the rapid decline of reservoir

pressure are some of the important characteristics of depletion drive field for
artificial lift selection and design.

In an active water drive reservoir, increasing water cut with the ongoing of
.
production is anticipated. Logically therefore, in future, it requires larger volume of

production to maintain desired oil production. So, type of lift must be considered on
future production volumes as well as present volumes.

In a gas cap expansion reservoir, changing gas-oil-ratios with oil production affect
the type and size of artificial lift. More and more quantities of gas production take
place with time. The increasing amount of gas gradually lowers artificial lift
efficiency. The choice of lift must take into account the anticipated maximum GOR /
free gas during the life of the reservoir.

Thus, the proper selection of any artificial lift mode depends upon several factors,
as described above.

7.2
7.1 High volume lift and their selection:

Out of the all common modes of lift, the following are considered the high volume
ones :-

1. Continuos Gas lift (GL)

2. Electrical Submersible pump (ESP)
3. Hydraulic jet pump.

Continuos Gas lift is used, where, primarily a high pressure source of gas is
available. It can be a very appropriate mode of lift for the oil well, which can
produce at a very high rate with relatively high flowing bottom hole pressure. At the
initial period of the exploitation of field, oil production can be obtained on self- flow
from wells with a very low to medium water cut. If it is felt that artificial lift is needed

during this period of self-flow, then continuous gas lift can be tried which will
produce more oil by lowering the flowing bottom hole pressure further. Also, due to

effect of water injection or natural active water drive, if water break through occurs,
the water cut continuously rises. This increases fluid gradient in the tubing. As a

result there will be an increase of flowing bottom hole pressure with consequent
decrease of well’s production. Thus with more and more water cut, a gradual fall in
well’s production is observed. Therefore, in order to arrest the fall in well’s
production continuous gas lift system is installed. But again the continuous gas Iifi
system is not a permanent solution. The weight of a minimum gradient of liquid in
the tubing string with the ongoing gas injection in the tubing always remains in the
well against sand face. As a result there will be a patilcular value of flowing bottom
hole pressure below of that is not possible to be achieved with the continuous gas
lift system. At some later date when the producing water quantity will be very high

with very low quantity of oil, it will be then obligatory to increase the volume of liquid
production so that a proportionate significant oil production may result. At this
condition electrical submersible pump may prove to be very effective in creating a
large draw down across the sand face effecting a large volume of production. Also

when very large amount of water production takes place continuous gas lift system
may become uneconomical since a very large quantity of injection gas is required.

7.3
In certain circumstances, for very high volume of fluid withdrawal, combination of
ESP and gas lift (In the bottom ESP will be there and above it gas lift system will
.,,
exist) is very useful, especially when either very long stages of ESP or very high
pressure gas injection are not workable.

The above discussion is of a general nature. Many a time, ESP is lowered right at
the beginning of the introduction of Artificial lift.

In offshore areas, either the wells operate on ESP or on continuous gas lift, where
the primary motive is to produce wells at a very high rate, that is, to produce at a

economical rate (In offshore area, economical rate is supposed to be very high).

Hydraulic Jet pump is able to create a very low flowing bottom hole pressure and
hence it can create a very large drawdown. The pump has the non-moving parts
and in this respect it is different from all other pumps. Lack of moving parts in this
pump is its greatest advantage. Besides, the free pump category of jet pump does
not require either workover or wireline for repair / replacement jobs. But inspite of
this unique advantage the pump has many shortcomings, inter alia, a few are
mentioned. It is the lowest energy eficient artificial lift mode out of all conventional
lift systems. The size of the return fluid line is required to be increased sufficiently to
.
accommodate both produced and power fluids together, where the requirement of
power fluid sometimes exceeds six / seven times or even more than the quantity of
produced fluid. The handling capacity of surface equipments like separators etc.

are required to be increased because of the same reasons. The pump is extremely
sensitive to backpressure.

The efficiency of Jet-pump system can be enhanced if it is coupled with continuous

gas lift system. This will be possible when two strings will be there in the well - one
for conveying the power fluid into the well and the other for producing well fluid
alongwith the power fluid.

Normally, continuous gas lift or electrical submersible pumps are used for high
volume lift. But when depth of well and / or bottomhole temperature will be very
high, hydraulic jet pump is preferred over them by default.

7.4
Therefore, one has to select the modes of lift for a field very judiciously. Either one
..,
mode of high volume lift is to operate in the field throughout its life time or one
mode in the initial period and some other mode or combination of two high volume
modes in the latter period of producing life.

7.2 MODERATE TO LOW VOLUME LIFT AND THEIR SELECTION

Conventional sucker rod pumps, Intermittent gas lift, hydraulic jet pump and

progressive cavity pump are the important artificial lift methods for moderate to low
volume of oil production. For very low producing wells intermittently operated
sucker rod pump or plunger assisted intermittent gas lift will be good choice. For
lifting of very high viscosity oil, progressive cavity pump or sucker rod pump with
extremely low spin. ( say 2 spm ) will be very useful,

A large number of stripper wells in U.S.A. are being produced with sucker rod
pump. Most of them are straight holes and having producing zones located at
shallow to medium depth.

Also, many oil companies do certain variations depending on mainly capital and

operational expenditures. Low to medium producing wells are being produced with
plunger assisted intermittent gas lift, where as, large producing wells with sucker
rod pump and very large producing wells with electrical submersible pump.

Dr. Brown in his book on Artificial Technology has provided elaborate comparisons
of different lift methods and their suitability of application. In fact, there is a wide
range of applicability by various lift methods and therefore one well can be
satisfactorily produced by any of the two or more number of methods of Artificial lift
systems. Actual selection, many a times, is weighed in favour of personal
preference as well as depends on the operational experience of the field personnel.

. . . . . . ..- ------------------------- ------------------- -----------------------------------------------------

7.5
 Chapter – 8

NODAL ANALYSIS OF OIL WELL

In a fluid flow system a “Node” is described as a point, across which a

perceptible pressure difference exists. Dr. Brown in his famous book titled
“Artificial Lift Methods” has provided graphic details of nodal system analysis
considering the various components of flow path for the fluid, which flow from
reservoir to separator/ stock tank.

Total flow path of a fluid flow system is an integral flow system and as
such, any disturbance created in any sector would in most of the cases affect the
flow in other sectors. Disturbances in the fluid flow would give rise to unstable and
fluctuating pattern of fluid flow. In the crude oil and gas production system, fluid
flow first is initiated in the reservoir, far away from the well bore, that is, deep in
the reservoir. Steady fluid flow in the reservoir is always considered mandatory. It
provides better sweep efficiency, better recovery and overall sound health of
reservoir. Therefore, in this aspect, an overall perception of nodal system analysis
is very important.

The whole fluid flow path can be segregated into distinct main sectors,
which are as follows :

Path -1 : Fluid flow from deep in the reservoir to very near to well bore .

8.1
Path -2 : From very near to well bore to inside the well bore, that is, just

across the sand face.

Path -3 : From bottom of the well to the well head.

Path -4 : From well-head to the flow line, that is, just across the choke or
bean.

Path-5 : From after the choke or bean to the separator /stock tank.

In Path -3:

Many other nodes exist like bottom hole choke or bottom hole standing valve in
the tubing string, surface controlled subsurface safety valve (SCSSSV) etc. So, in

case, pressure drops across them are significant, it will be necessary to divide
path 3 into two or three sectors. In this sector, tubing size plays a very important

part. If tubing size is less than adequate than an excessive friction results, which
increases the flowing pressure against the sand face and thereby, it stems the
.
optimum flow into the well bore. If tubing size were more than adequate,
excessive fluid fallback would result, which again would increase the flowing
bottom hole pressure. This occasionally leads to surge flow in the well bore as
well as in the reservoir.

In path -4:

Surface flow line choke, which is primarily a necessity in most of the cases of
natural flow for safety reasons, should be so sized that it would create always a

critical flow after the choke and formation of hydrates would not occur downstream
in the flow line, At the same time fluid flow at the desired rate will be maintained.
In case of critical flow rate, any fluctuation of pressure at the downstream of choke
would not affect the pressure at the upstream of the choke and hence fluid flow in

8.2
the tubing string and in the reservoir would not be disturbed. This is because the

quantity of fluid flow in the critical flow condition is always maximum and as such it
does not change even if the downstream pressure is increased or decreased
(within the critical region).

In path -5:

Adequate size of flow line is necessary for basically two reasons : First, there
should not be any excessive pressure drop in the flow line. Excessive pressure
drop occurs when the flow line is of smaller diameter and its length is too long.
This effects a higher pressure after the well head choke, which may give rise to
flow in the sub-critical region. Hence it would lead not only to reduce the flow rate

but also create undesirable disturbed flow. Secondly, if the flow line is excessively
of large diameter, multiphase fluid flow would create slug flow in the pipeline,
which again would increase the back pressure and thereby curtail the fluid flow
rate and cause disturbed flow. It is in this respect quite logical that the separator
pressure should be kept as minimum as possible to facilitate critical flow condition
with minimum tubing pressure possible.

In path -2:

Very often large pressure drop occurs very near the well bore. It greatly restricts

the fluid flow into the well bore. The restriction in the fluid flow is due to the effect
of well bore damage called “Skin effect” and it is resulted during drilling / well

servicing jobs. It is always desirable to have the skin effect zero, so that the

permeability of this part of the zone will be as good as that of the reservoir.

Therefore, the discussion above underlines the necessity, as far as possible in

practice, to carry out a thorough nodal system analysis to produce from a new well
and for suggesting the minimum required changes in the existing well flow system.
In order to accomplish the task of nodal analysis, it is required to refer several

8.3
standard flow equations and / or several published vertical, inclined and
horizontal multiphase correlations.
.,

Following is one example of nodal system analysis of oil and gas production from
a well.

EXAMPLE: GIVEN DATA:

Separator Pressure = P~,P = 60 psig

Reservoir Pressure = PR = 2800 psig
Bubble Point Pressure = P~ = 2500 psig
Well depth (Mid Perforation) = 7000 ft.
Water cut = 30?40
GOR = 2000 SCF/bbl
GLR = GOR x oil cut = 2000 X 0.7 = 1400 SCF/bbl
Oil gravity = 35° API
Gas gravity = 0.65
Surface Temp. = 170°F
Temp. at well depth = 800F

One test ‘ liquid Production = qLT = 700 b/d

Rate } at F. B.H. P = Pfi = 2000 psig
L = Length of flowline = 5000 ft.

To Select : (1) Tubing size from the given tubing sizes :2 3/8” (1 .995” I.D.);
2 7/8” (2.441” I.D.) and 3 1/2” ( 2.992” I.D.)
(2) Flowline size from the given flowline sizes : 3“ I.D. ; 3 1/2” I.D.;
4“ I.D.

With approximate and optimum steady liquid flowrate.

8.4
Solution

In order to solve such problem NODAL ANALYSIS is conducted. one

approximate procedure for Nodal Analysis is as follows: -

Ske3: constructionof IPR Curve

With the given valves of PR, F’b,PFTand q~T,the equation to generate IPR is made.

From the values of PR, pb and Pm, it is seen that PR > pb > Pff. This provides an
approximate shape of the IPR curve.

PR Straight P.1. relationship

Pb ----------
I Vogel curve relationship
I
Pf I

----------- ; ---- _------,

1
1 I
1
I 1

1 !
1 1
! I ‘.
‘.
1 I ‘.
‘.
1 ‘.
‘.
‘.
1 1 ‘.
1 1 ‘.>
1 I
‘.

I
I

+ q~~+4’-- q“~ + Qmax

I
1
1

I ~ qL (b/d)~
4
qL(max) = qbL + qVL

Equation to generate IPR is

Pf Pf

qL = qbL + qVL [1 -0.2 ( ----) -0.8 ( ----)2]

pb pb

8.5
qbL and qVL, being the maximum values in the respective regions of the IPR curve
, i.e. qbL in the straight P.1. relation region and qvL in the vogel retation region.

The VdUe of pb is given.

qbI_and qvL are required to be found with the help of one test result, that is, qLT =

700 b/d and Pm = 2000 psig. Thereafter, the IPR equation is generated with pf and
qL as unknown values. For various assumed values of Pf, the corresponding
values of qL are found and then the required IPR for the well is drawn. In order to
accomplish this task, the following method, as adopted by different authors like
Brown, are followed. :-

Portion AB is a straight line and it provides a straight P.1. relationship. Let P.1.

denotes the productivity index of straight P.1. relationship. The Productivity Index
for one situation, which is located on the curve BC will be less than the P.1. value

to meet the requirement of an approximate parabolic shape of the curve.

If the portion AB continues to be straight in all the situations of the quantity of fluid
withdrawal, then maximum possible (Theoretical) production = Q~~X, is obtained
with Pf = O.

That is, Q~~X=P.l. x (P~-o) =P.l. xP~ . . .. .. . . .. . .. . . (i)

Now, considering portion “AB” as straight line,

qbL
P.1. = ---------- s qbL = P.1. X (PR - P~) ... . .. . ... . .. . .. (ii)
PR - pb

Let it be assumed that portion BC is straight and similar to AB. Also, let pb be the
assumed Reservoir pressure, then

qVL = P.1. X (Pb-o) = P.1. xpb . . .... . .. . .. . .. (iii)

8.6
Since BC is actually a parabolic vogel curve, so qvL in equation (iii) is modified as
P,l. X F’b P.1. xpb
= ----------------- = ------------ . . .. . .. . .. . . . . ..(iv)
qVL
I + 80% of 1 1.8

From equations (ii) and (iv), eliminating P.1.

----
=-----
qVL PR
-
Pb
-----------
~ [1 Pb 1
qbL = 1.8 qvL ----------
qbL 1.8 x (PR - Pb) pb

[1
PR
~
•1 qbL = 1.8 qvL ----- -1
Pb
. . .. . .. . .. . .. . .. (v)

%o, qLT = qbL + qVLT

... . .. . .. ..... . . (vi)

Again, considering BC a straighhtline similar to AB,

qvLT ‘= ml. . x( Pb-PfT) ... . .. . .. . .. . .. (vii)

Eliminating P.1. from equations (iii) and (vii),

qVLT f’b - ~fl Pm

------ = ---------- = 1 - ----- . . .. . .. .. . . ..(viii)
qVL Pb Pb

Since, BC is a vogel curve ( parabolic), the equation (viii) is modified as,

qVLT Pf-r Pf-r

------ = 1- 200/0 of ( ------) - 80% of ( ----- )2

qVL pb Pb

= qvLT = qlfi
[
pm
1 -0.2 ( -----
Pb
)- 1 0.8( -~)’
Pb
... . ... . .. . . . . . (ix)

8.7
By putting the values of qb: from equation (v) and qvLT from equation (ix) into
equation (vi),

~=t,~”[~:--~ +q”~-().2(-:)-0.8 (~)~

7
PR
a qLT = qv~ 1.8 ( ---- ) -1.8 + 1 -0.2 (-~-) -0.8 (-~-)’
[ f’b pb 1

\ -1.8 + 1 -0.2 (.fl.j - ().8 (-~-)

“E =qL/~.8(:-/ p, P,] . . ..(X.

The values of qbL~vL,

— — as found in equations (v) and (x) respectively are put in

equation (1) to obtain the desired IPR equation.

Now, as per the given data, that is,

qLT = 700 bid; PR = 2800 psig: P~ = 2500 psig; Pff = 2CIO0,

So, from equation (x),

qv, = 700 r POOO) 2000 2000 21

f .-------
/ l!”8ba - 0“8 ‘0”2 () xi - 0“8 \ 2!500)1

=700/ ( 2.016 –0.8 -0.16-0.512 )

“ ‘VL= L!w?!!I ............... (xi)

From equation (v),

2800 -
------- -1
Qm = 1.8 X 1287 X
[ 2500 _
‘Izw?-l .. .. . .. .. . . .. . . (xii)

8.8
Therefore, by putting the values of qv~ from equation (xi) and qbL frOm eqUatiOn

(xii), the equation (l), takes the final shape as:

QL =278+1287 [ml1-02 . . .. . .. . .. . .. ..(xiii)

Equation (xiii) is thus the requred IPR relation of this problem, where PR> F’b> Pff.

In order to draw the required IPR curve, qL values are obtained from equation (xiii)
for different valves of Pf, as arbitrarily chosen. These are placed in the tabular
form. (Reference table 1).

TABLE -1

Pf QL Remarks
I
I
2800 : 0 i Pf = PR; So, there is no flow
Pf
2600 ; 184 ~
D 2500 ! 278 pf = Pb; So, qL = 278 = qbL
E
2400 369
c
R 2200 541
E 2000 700
A
1800 846
s
E 1500 1040
s 1000 1297
—
500 1472
0 1565 QL= 1565= qL(max)! When Pf = O .

Pf (psig) vs. qL (in 100 bbl/d) is plotted on a graph paper to produce

curve. Straight P.1. relationship has also been drawn, which is an extension of the
straight-line relationship AB. This is named as Graph -1.

With the given P~~P= 60 psig; L = 5000 ft; GLR = 1400 SCF/bbl; the “after-bean”
pressure (PA~ in psig) have been calculated for different values of qL as in table 1
for different diameter of flowlines viz. 3“, 3 1/2” and 4“ I.D. These required values

8.9
are obtained from the published multiphase flow correlations in horizontal pipes
( Reference : Book - Artificial lift methods - By Dr. Brown).

TABLE -2

For 3“ I.D. For 3 1/2” I.D. For4° I.D.

Horizontal Horizontal Horizontal
pipe pipe pipe
qL (b/d) PAB (psig) PAB (psig) PAB (psig)
200 75 70
400 120 100 85
600 170 120 100
800 230 160 118
1000 280 180 125
1500 430 280 180

PA~ (psig) vs. qL (in 100 b/d) plotted on graph - II for 3“, 3 1/2” and 4“ I.D.
horizontal pipe.

The sound oil and gas production practice is to flow the well at a steady rate. The
flow rate will fluctuate when tubing head pressure (P~h) fluctuates. So, it is
imperative to maintain a constant value of p~h.

Usually, the separator is regulated by a back-pressure regulator on its gas outlet

line, which maintains constant separator pressure. But due to some routine

maintenance in gathering system, flowline etc. some amount of variations in PAB

cannot be ruled out. Because of this, the variation in pwh will take place and the
net result is unsteady flow and loss of production. So, to avoid tthis situation, it is
required to maintain the wellhead pressure (P~h) of atleast double the afterbean

pressure (PAB), that is p~h 22 PAB. In this condition, p~~p~h ratio is called the
“critical pressure ratio”.

This is obtained by placing a choke or orifice in the line, where the upstream
pressure (P~h) will be twice the value of the down stream pressure (PA~)
immediately downstream of the choke, at the vena contracta. This ensures the

8.10
velocity of fluid to attain sonic velocity at the vena contracta and thereby any
disturbance downstream of the choke will not affect PW~,as long as sonic flow is
maintained.

From the graph -11, it is observed that pressure loss is maximum in 3“ I.D. line and
minimum in 4“ I.D. line and this difference is quite significant for larger production

rate.

On the basis of PA~, as obtained for different diameter flowlines, approximately

~ is chosen, where as at 1000 b/d, 3 1/2” and 4“ I.D. have been

found as appropriate choice, since P~B in both the cases is less than 200 psig.
Also, for larger production rate, say around 1250 b/d, 4 1/2” I.D. pipe is found only
suitable,

Let 4“ 1.D. flowline be selected.

Now. suitable choke or orifice sizes can be found from PWh= 400 psig = 414.7
psia and R = 1.4 MSCF/bbl GLR, with the different values of q~ viz 1250 b/d, 1160
b/d and 1000 b/d.

Several empirical choke performance equation based on sonic flow condition have

been provided by different authors. The following empirical equation is suggested

by T.E. Nind :

qL R1/2

PW~= 0.115 -----------, where, A = orifice area in in2

A

= n ~, where r is the radius of the orifice in inches.

So, for q~ = 1250 b/d; R = 1.4 MSCF/b; PWh= 414.7 psia,

1250 X(1 .4)1’2 23,,

414.7 =0. I15X -------------------- - r = 0.36” = -----
7CX+ 64

8.11
So, dia of orifice =
:;- ‘m

for qL = 1160 b/d; R = 1.4 MSCF/b; Pti = 414.7 psia

1160 X(1 .4)1’2 **I,

414.7= 0.I15X -------------------- > r = 0.34”= -----
7CX? 64

So, dia of the orifice =

:~=w

for qL = 1000 b/d; R = 1.4 MCF/b; p~h = 414.7 psia

1000x(1 .4)”2 20”

414.7 = 0.I15X -------------------- > r = 0.32” = -----
7CX+ 64

SO, dia of,the orifice =

;4- = m

However, some trial and error method is required to find out the exact value of

orifice size.

Now, keeping the value of p~h = 400 psig, Pf(psig) vs. qL (in 100 b/d) for different
sizes of tubings viz. 2 3/8”, 2 7/8” and 3 1/2” have been plotted, after calculating
the values of P~ from appropriate published vertical performance curves (Refer
vertical performance curves from gas lift design manual of Cameo Co.). These

curves are called outflow curves.

The points, where the Outflow curves for three different sizes of tubing have cut
the Inflow curve, provides the required flow rate with respect to the particular
tubing size.

8.12
The different values of P~against the values of q~ chosen are given in table -3.

Well depth = 7000 ft; GLR = 1400 SCF/b; PW~= 400 psig

Vertical flow performance curve for 35° API oil, average flowing temperature =
140°F, 50% oil and 50% water, sp. Gr. = 1.08 and gas gravity = 0.65.

For 2 3/8” For 2 7/8” For 3 1/2”

O.D. tubing O.D. tubing O.D. tubing

qL (bid) P~(psig) P~(psig) P~(psig)

I I 1

200 1500 1300 ----

400 1430 1230 1080

600 1440 1240 1090

I 800 I 1510 I 1250 I 1100 I

I 1000 I 1560 I 1270 I 1105 I
I 1500 j 1720 I 1360 ~ 1130 I

From the Inflow/outflow curves on Graph -1, [t is observed that

(i) 1000 b/d qL is possible if 2 3/8” tubing is used.

(ii) 1160 b/d qL is possible if 2 7/8” tubing is used.

(iii) 1250 b/d qL is possible if 3 1/2” tubing is used.

Say 1250 bld is the target production, so 3 1/2” tubing is chosen.

CRITICAL OBSERVATIONS

1. If the “Inflow” curve would have been a straight P.1. relationship (possible if
f’b would have been very low), more liquid production through the
respective tubing sizes were possible. Like around 1100 b/d through 2 3/8”
tubing (inter section point E’), 1350 b/d through 2 7/8” (intersection point F’)
and 1525 b/d through 3 1/2” (intersection point G’).

8.13
2. If PW~= 400 psig is reduced (by increasing the surface flowline choke size),
the general phenomena will be to witness the increase of flow rate .”

3. If reservoir pressure P~ drops, the inflow curve will be closer to the origin of

the graph and it results in decrease of flow rate through the respective
tubing sizes.

4. If the well is allowed to flow through a very large tubing size, there will be

more possibility of slippage of gas. AS a result liquid hold-up or loading will

take place. This will create an unsteady state of flow and hence loss of
production will result.

5. If the tubing size is too small more friction will result and this will restrict the
flow rate,

8.14
1. Kermit E. Brown, et al., “The Technology of Artificial Lift Methods”, Pennwell
Books, Tulsa, Oklahoma, 1977.
2. William C. Lyons., “Standard Handbook of Petroleum & Natural Gas
Engineering”, gulf publishing company, Houston, Texas, 1996.
3. M.A. Mian., “Petroleum Engineering Handbook for the Practicing Engineer”,
Pennwell Books, Tulsa, Oklahoma.
4. T.E.W. Nind., “Principles of Oil Well Production”, McGraw - Hill Book
company, New York, USA, 1981.
5. T.E.W. Nind., “Hydrocarbon Reservoir and Well Performance”, Chapman
and Hall, New York, USA, 1989.
6. Howard B. Bradley, et al., “Petroleum Engineering Handbook”, society of
petroleum Engineers, Richardson, TX, USA, 1992.
7. Craft, Holden and Graves, “Well Design Drilling and Production”, Prentice -
Hall, Inc., Englewood cliffs, New Jersey, USA, 1962.
8. Richard W Donnelly, “Oil and Gas Production : Beam Pumping”, The
university of Texas at Austin in cooperation with API, Dallas, Texas, USA,
1986.
9. H.W. Winkler & Sidney S. Smith, “Cameo Gas Lift Manual”, Cameo,
incorporated, Houston, Texas, 1962.
10. Catalog of Rod pumps complete Assemblies of Harbison-Fischer, Texas,
U.S.A.
11. Catalog of REDA, a Cameo company, Bartlesville, O. K., USA,
12. API Recommended Practice for Design calculations for sucker Rod pumping
systems, API, Washington D. C., issued by API, Dallas, TX, USA.
13. API recommended practice - “Care and Handling of Sucker Rods”, “Care
and Use of Subsurface Pumps”, - issued by API, Dallas, TX, USA.
14. API specification for gas lift values, Orifices, Reverse flow check valves and
Dummy valves, - API specification 11 Vl, 1988, API, Dallas, TX, USA.
15. API Recommended Practice of “Operation, Maintenance and Trouble-
Shooting of gas lift installation” – API recommended practice 11 V 5,1995,
API, Washington, DC, USA.
16. Nelson. 1. Geyer, UNDP consultant to IOGPT, ONGC, India. “First Mission
Engineering Technical report for UNDP project on Marginal Field
Development and Artificial Lift”, JAN, 1993.
17. D.D. Allen, “High volume pumping in the Rangely Weber Sand Unit”, S.P.E
(586), August 1963, Journal.
18. K. K. Kahali, et. al, “Artificial Lift Methods for Marginal Fields”, SPE (21696),
April 7-9, 1991.
19. C.M. Laing, “Gas Lift Design and Production Optimization Offshore
Trinidad”, SPE (15428), Oct., 5-8, 1986.
20. J.C. Mantecon, “Gas Lift Optimization on Barrow Island, Western Australia”,
SPE (25344), Feb., 8-10, 1993.
21. Joe Dunn Clegg, “High - Rate Artificial Lift”, SPE 17638, March, 1988
(Journal).
22. C.M. Laing, “Gas Lift Design and Performance Analysis in the North West
Hutton Field”, SPE (19280/1) 5-8 Sept., 1989.
23. S.G. Gibbs, “Predicting the Behavior of Sucker - Rod Pumping Systems”,
SPE (588), July, 63 J.
24. K.B. Nalen, “ Deep High Volume Rod Pumping”} SPE (2633), Sept., 28-
Oct., 1, 1969.
25. L.K. Bothby, et al, “Application of Hydraulic jet pump Technology on an
Offshore Production Facility”, SPE (18236) Oct., 2-5, 1985.
26. F.A.F. Noronha, et al, “Improved Two-phase Model for Hydraulic Jet pumps”,
SPE (37427), 9-11 March, 97.
27. S. Buitrago, et, aI, “Global Optimization Technologies in Gas Allocation for
Continuous Flow Gas Lift Systems”, SPE (35616), 28th April -1 May ‘1996.
28. G.C. Bihn, et, al, “Electrical Submersible pump Optimization in the Bima
Field”, SPE (1 9495), 13-15 Sep., ’89.
29. Gabor Takacs, “Profitability of Sucker-Rod Pump Operations is Improved
Through Proper Installation Design”, SPE (38994), 30 August-lst Sept.,
1997.
30. J.F. Lea, “Optimization of Gas Lift Operations for Oil & Natural Gas Fields in
India - Gas Lift Consulting for Bombay High Field”, Dated 6/24/96 (as
submitted to ONGC).
31. Weatherford Artificial Lift Systems Manual.
32. R.H. Gault, “Report on Consultation with the Institute of Oil and Gas
Production Technology, Panvel, India”. (Report submitted to IOGPT,
ONGC).
33. J.F. Lea & Henry Nickens, “Gas Lift Papers”, Artificial Lift and Production
Optimization Group, TULSA / EPTG.
34. Dr. L. Douglas Patton, “Seminar on Sucker Rod Pumping,” - as an UNDP
consultant on SRP to IOGPT, ONGC, Nov., 1989.
35. ESP Manual, Reda, a Cameo Co.
36. J.D. Clegg., et, al, “Recommendation and Comparisons for Selecting
Artificial Methods,” - SPE (distinguished author series), 1993
37. Gabor Takacs, “Modern Sucker Rod Pumping”, Pennwell Publishing co.,
USA.
38. Product catalogue of M/s Parveen Industries Pvt. Limited, India.
39. Different Research Papers from TUALP, TULSA UNIVERSITY, TULSA,
USA.
40. Brill & Mukherjee H K - Multiphase Flow, SPE Monograph, 1999.
41. Beggs H D - “Production Optimization Using Nodal Analysis”, OGCI, 1991.
 UNITS & THEIR CONVERSIONS

(A) Length

1 ft = 0.3048 m = 30.48 cm

1 m =100 cm = 1000 mm = 3.28 ft = 39.37 in

1 in = 2.54 cm = 0.0254 m
1 km = 1000 m =0.62137 mile

(B) Weight

1 kg = 2.205 lb. = 9.807 n = 1000 gm =1000000 mg

1 lb. = 453.592 gm = 0.45359 kg =16 ounces.
1 ounce = 0.0625 lb. =28.35 gm
1 gm = 0.002205 lb.
1 tonne = 1000 kg =2205 lb. = 1.102 U.S. short tons.
1 U.S. short ton =2000 lb. =907 kg

(C) Area

1 sq. in = 6.4516 sq. cm

1 sq.’ft = 929 sq. cm = 0.0929 sq. m

1 sq. cm = 0.165 sq. in

1 sq. m = 10.7693 sq. ft

(D) Volume

1 cu. In = 16.387 cc
1 Iitre = 1000 cc= 61.024 cu. In = 0.2642 U.S. gallon
1 cu. M = 35.3148 cu. Ft = 6.289 U.S. barrels = 1000 Iitres
1 cu ft = 0.028 cu. M = 0.1781 U.S. barrel = 7.48 U.S. gallons = 0.1728 cu. In

= 28.32 Iitres
1 U.S. gallon = 231 cu. In = 3.785 Iitres = 0.833 Imperial gallon = 0.1337 cu. ft

= 0.28381 U.S. barrel

1 Imperial barrel =48 U.S. gallons =40 Imperial gallons = 6.42 cu. ft
= 1.143 U.S. barrel
 1 U.S. barrel = 42 U.S. gallons = 35 imperial gallons = 5.6146 cu. ft
=0. !w cu.!-n
1 imperial gakm = 1.2 iJ.S. gallon

(E) Pressure

1 a?m. = 760 mm of Hg. = 29.92 in of Hg. = 14.696 psi. = 1.033 kg/ cmz
= 33.94 feet of water
1 kg / cm2 = 14.223 psi. = ICI m of water.
1 foot of water =0.433 psi
1 in of Hg = 1.134 ft of ‘water = 0.4912 psi
1 psi =0.07031 kg / cm2 = 2.309 ft of water = 2.036 in of Hg

(F) Gradient

lkg/cm2/10m= 0.433 psi / ft = Sp. Gravity.

For example, 0.85 kg / cmz / 10 m = ( 0.433 * 0.85 ) psi / ft = 0.85 Sp.

Gravity.

(G) Specific Gravitv

‘API = [ 141.5/ Sp. Gravity] – 131.5
Sp. Gravity= 141.5 i [ 131.5 + 0 API j

(H) Temperature
0F=[l.8*0C] +32
OR=OF +460

OK=O C + 273

(1) Gas – Liquid Ratio

1 S. C. F/BBL ( U.S. )= 5.6146 M 3/ M3

1 M3/M3 =0.1781 S. C. F/BBL (U. S.)

(J) Productivity Index

1 b / d / psi (U. S.) = 0.4415 m3/d/kg/cm2
lm3/d/kg/cm2= 2.265 b/d / psi ( U.S. )
 GLOSSARY

Acoustic Survey: By sending sound wave in the casing, the liquid level in the
annulus is measured.

Annular Flow : Gas occupies the central portion and liquid remains near the pipe
wall. It is seen in both vertical & horizontal flow.

Bleeder Valve (Drain Valve): It is installed in the tubing of one to two tubings

length above check valve in the electrical submersible pump installation. Before the

tubing is pulled out from the well for replacement of pump or for doing any well

services job, the bleeder valve is to be broken by dropping a sinker bar from the
surface. It would then be possible to pull out dry tubing since liquid with be drained
out through bleeder valve in the wellbore.

Booster: Booster is required to boost the surface voltage according to the

requirement of downhole electric motor in Electrical Submersible Pump installation.

Bottom Hold Down (Bottom Anchor\ : H refers the fluid sealing and support to
hold the sub-surface sucker rod pump at its bottom ( i.e., at the pump bottom ).

Bubble Flow : In vertical flow, the gas phase is dispersed as small discrete

bubbles in a continuous liquid phase.

Cavitation: It is a typical characteristic of the hydraulic jet pump. Very low

pressure of the produced fluid causes vapor cavities, which cause choking in the
entry of produced fluid as well as due to implosion of vapor bubbles, it can cause
erosion of pump sutface which is called cavitation damage.

Check Valve: Check valve is a non-return valve placed in the tubing string about
one or two tubing strings above the pump head in the downhole Electrical
Submersible Pump. It prevents the back flow of pumped liquid into the wellbore
through the pump. It also provides a stabilized operation of pump.

(i)
Churn Flow : in vertical flow, it is similar to slug flow but it is more chaotic.

Closed Installation: Gas lift installation is called closed installation, when it is

completed with a packer and standing valve in the well.

Continuous Gas Lift: It is a high volume Artificial lift system. High pressure gas

injection is done downhole into the producing fluid conduit at predetermined depth

continuously.

Diffuser: It is a part of hydraulic jet pump. The high velocity and low pressure
mixture of power fluid and produced fluid lose velocity and acquires higher
pressure.

Dispersed Bubble Flow : In horizontal flow at very high liquid flow rates the liquid
phase is the continuous phase and gas phase allarourrd it is in the form of discrete

bubbles.

Dynamic level: When the well is producing at a steady rate, the distance from the

surface to the liquid level in the annulus of the well is called dynamic level.

Dynamometer: It is an instrument normally fitted onto the polished rod for

continuous recording of polished rod load with respect to the stroke Itmgth. Many
inferences of the condition of pumping can be drawn from this study.

Fluid Pressure Operated Gas Lift Valve: The opening and closing of gas Iifi
valve is predominantly governed by the pressure of producing fluid.

Free Pump: “Free Pump” is a type of hydraulic submersible pump. Power fluid is
conveyed down through the tubing in the normal operation of the pump. When the
power fluid is sent down in the reverse direction, that is a either through the casing-
tubing annulus or thrwgh a parallel tubing, the pump gets dislodged from its

position and comes to the surface with the fluid pressure underneath it. For

(ii)
resetting, the pump is dropped again through the same normal power fluid tubing.

So, for servicing of free pump wireline or workover jobs are not required.

Gas Anchor (Gas Se~arator\: It refers to the downhole gas separator in

combination with sub-surface sucker Rod pump or electrical submersible pump. It
separates free gas from produced fluid, where liquids passes through pump and
free gas finds its way out through annulus into the surface flowline. There are
several types of gas anchors for sucker rod pump like Natural Gas Anchor, Packer-
type Gas Anchor, Poor-boy Gas Anchor etc. and for electrical submersible pump
like Reverse Flow Gas Separator, Centrifugal Gas Separator etc.

Gas Lift Mandrel: It is a part of tubing which houses gas lift valve. It may house

conventional or wire line type gas lift valve depending on its configurations.

Gas Liquid Ratio (GLR): Itis the ratio of the produced gas and produced liquid. It
is expressed as m3/m3 or S.C. F. / bbl.

Inflow Performance Relationship (IPR) : It is a curve drawn in the plane, where

X-axis is the rate of liquid inflow in the well bore and Y-axis is the flowing bottom
hole pressure.

Injection (or Casing) Gas Pressure Operated Gas Lift Valve: The opening and
closing of gas lift valve is predominantly governed by the injection pressure.

Insert (rod) pump : It is a sub-surface sucker rod pump and is run inside the
tubing strings as a single unit with the sucker rods to the desired depth where its

pump seat is located. Pump seat is a part of tubing string.

Intermittent Gas Lift: It is a low volume lift. High-pressure gas injection is done

downhole in the producing fluid conduit intermittently.

Intermittent Flow : In horizontal flow, the flow is characterized by alternate flow of

liquid and gas.

(iii)
Junction Box: It is used for electrical submersible pump installation. Junction box
is a connecting point of two main surface cables – one coming from the wellhead
and the other coming from the switch side. It is housed in a small well ventilated
box, where main surface cable from the well head side and the switchboard side
one separately connected. This junction box is for safety reason and allows the
percolated wellbore gas as trapped in the cable from the well head side to bleed to
the atmosphere at the junction box. Therefore gas, which is extremely inflammable
cannot migrate to the switchboard.

Main Power Cable: Through the main power cable, the power is supplied from the

surface to the downhole motor. The cable is armored. It is either of round or flat (i.e.
parallel) shape. It has been standardized by AWG (American Wire Gauge)

standards. It ranges from # 1 AWG to # 6 AWG, where # 1 AWG indicates thickest

conductor and # 6 AWG indicates thinnest conductor.

Multistage Centrifugal Pump: Electrical Submersible Pump of one impeller and

one diffuser together provides one stage. When several such stages are added
together, it is called multistage centrifugal pump. More stages generate more head
to lift well fluid and as such more stages create more draw down across the
formation.

Nozzle: It is a part of hydraulic jet pump. The high pressure fluid converges in it
and turns into much higher velocity and lower pressure fluid.

Open Installation: Gas lift installation is called open installation, when it is

completed without any packer and standing valve in the well.

Overload Shutdown: This occurs in electrical submersible pump operation. When

the amperage drawn by the operating pump exceeds the upper limit of amperage in
the switchboard, the pump automatically shuts down. After overload shutdown, the
pump cannot be automatically restarted after a prefixed time. The electric supply
and other aspects are first checked to rectify the faults and then the pump is
restarted manually. The overload shutdown prevents the motor from over heating
resulting in the insulation failure.

(iv)
Pack - Off Gas Lift Installation: Pack-off gas lift installation technique is the
installation of gas lift valve inside the tubing string at its center. It is a difficult
wireline installation job and therefore its application qualifies in default only.

Pig Tail (Lower and Upper): Lower pig tail is a small length of main cable with
one end to be spliced (connected) with the main downhole power cable and the
other end is to be fitted with electrical conductor minimandrel fitted on to a electrical
submersible pump wellhead.

Upper pig tail is same as above, with only exception that the one of
its end is to be connected with the main surface cable instead of the main
subsurface cable. Also, connection configuration of pig tail with mini mandrel is
different for upper and lower pig tails to suit to their spacing requirement.

Pilot Operated Gas Lift Valve: It is a form of injection (or casing) gas pressure
operated valve. It has a power section as well as a pilot section. It reduces valve
spread and at the same time facilitates a very high rate of gas injection through it.

Pot Head Extension Cable: H is a small length of armored electrical submersible

pump cable, where its one end has got compatible connecting head with the motor

cable head connection. The other end is to be connected with the main power
armored cable. The pot head extension cable is either of plug-in type or tape-in

type. It is generally of flat (or parallel) type.

Power Transformer: Power Transformer is a step down transformer say from 11

KV to 420/440 V.

Productivity Index (Pi) : It is the measure of the ability of well to produce fluid into
the wellbore. It is equal to quantity of produced fluid divided by pressure drawdown
across the sand face.

Protector: The protector is used in electrical submersible pump installation. It is

connected just above the down hole electric motor to facilitate the operation of
motor without any problem. It houses thrust bearing to take care of the load on the

(v)
impeller shaft of the pump. It provides the motor a circuitous passage and breathing
outlet to the wellbore for equalizing the pressure inside and outside the motor
.,
housing.

Pump Intake (g as separator): It is used in electrical submersible pump

installation. It is connected just below the pump in the well and works as a intake
section of the pump. This is also called gas separator, as it separates the free gas
from liquid, where liquid enters the pump and free gas finds its way out through the
annulus in the flowline at the surface.

Reverse Flow Check Valve: It is a type of non-return valve. It is connected with

gas lift valve. It allows injection gas (casing gas ) to pass gas through it into the
producing fluid conduit and prevents the produced fiuid to enter in the casing. It is
also required for setting the hydraulic packer in the well with the gas lift system. It

also prevents repeated liquid U-tubing through gas lift valve. It may be of velocity or

weak spring-loaded type.

Ring-Valve Pump : The ring-valve pump is a type of Sucker Rod Pump. It

provides an additional sliding check valve in the pump and this check valve is
located just above the traveling valve.

Rod Guides: Rod guides are fixed on the Sucker Rod at suitable internals. It
prevents rubbing of Sucker Rod with the inner wall of the tubing. There are many
forms of rod guides.

Scrapers: The scrapers, either metallic or made of hard plastics, are fitted to the
sucker rods at suitable intervals. The reciprocating motion of sucker rods with the
scrapers mounted on it prevent accumulation of paraffin in the tubing during the

operation of pump and fluid production.

Semi-closed Installation: Gas lift installation is called semi-closed installation,

when it is completed with a packer and no standing valve in the well.

(vi)
Sinker Bars: The sinker bars are installed in the sucker rods just above the sub-

surface Sucker Rod pump. It provides the stability of the downhole SRP operation.

SIUCJFlow : In vertical flow a large gas pocket underlain and overlain by gas
bubbles - aerated liquid slug.

Standing Extensicn of Voqe!’s IPR : Standing introduced skin factors in the

Vogel’s IPR cuwe.

Static Level: When the well is not producing, the flowing bottom hole pressure

inside the well at the sand face, attains the maximum, that is , the reservoir or static
pressure. At that condition, the distance from the surface to the liquid level in the

well (or in the annulus of the well) is called static level.

Stationary Barrel Rod Pump “ it refers to the Sucker Rod Pump, where, barrel of
the pump is stationary and plunger is given the reciprocating motion with sucker
rods.

Stratified-.—
——. flow .-...
: It_________
is for horizontal _ flow. Two phases become distinct as they are
separated by gravity.

Surface Unit (Pumping Unit~ : Pumping unit generate the motion of the sub-
surface Sucker Rod Pump through a long string of sucker rods. The various types

of Surface Unit are Conventional, Air balanced, Mark 11 unit and Torque Master.

Three Tube Pum P : It is a type of Sucker Rod Pump. It has the combined features

of a traveling and stationary barrel pumps.

Throat: It is a part of hydraulic jet pump. In this region motive (power) fluid attains
very high velocity and low pressure. As a result, it sucks produced fluid from the
surrounding. Both motive and produced fluid get mixed in the throat region.

Top Hold Down (Top Anchor] : It refers the fluid sealing and top support to hang
the sub-surface Sucker Rod Pump at the pump head ( i.e., at the pump top).

(vii)
Total D~namic Head (TDH): It is a common concept in calculating the total stages
of an Electrical Submersible Pump for installation in a well.
TDH = liquid height equivalent to tubing pressure + Dynamic level as measured
from the surface.

Travellinq Barrel Rod Pum~ : It refers to the Sucker Rod Pump, where plunger is
made stationary and the barrel is reciprocated with sucker rods.

Tubing Pump : It is a sub - surface sucker rod pump, where the working barrel is

run as a part of tubing up to the desired depth. Then the plunger is run through
tubing with the sucker rods to place it ( plunger } inside the working barrel.

Tubin~ Anchors: It anchors the tubing with the inner surface of the casing, thus
prevents tubing stretching / contraction, Tubing anchors are either of mechanical
type or hydraulic type.

Two Pen Pressure Recorder: This is an instrument installed at the wellhead to

continuously record surface injection pressure and tubing pressure. This gives an
indication about the gas lift system performance.
.

Underload Shutdown: This occurs in electrical submersible pump operation.

When the current drawn to operate the pump goes below the minimum amperage
setting in the switchboard, the automatic shutdown of pump takes place. After a
pre-set timing, say, after 2 hrs, the pump is again automatically restarted. This
provides sufficient cooling to Motor.

Valve Soread: The difference between the opening and closing pressure of the
valve is called valve spread. More valve spread occurs, when valve port size is
bigger.

Voqel’s Method (for IPR) : He gave a solution in determining Inflow performance

curve mainly for solution gas drive reservoir flowing below bubble point pressure at

the well bore.

(viii)