2. Well Fluid
(RESERVOIR)
Basic Principle of Oil production
• When oil is in reservoir,
it is under pressure from
the natural forces that
surround and trap it.
Medium
Pressure
Higher
Pressure
Lowest
Pressure
Still Lower
Pressure
The Production Process in an Oil Well
• If a hole is drilled, oil
from reservoir escapes
out due to the low
pressure opening.
To Processing
and Treating
Well Head
Lower
Pressure
3. Basic Principle of Oil production
• Oil flows to the surface due to a reduction of
pressure between reservoir and producing
facilities on the surface.
• There will be no flow if reservoir and wellbore
pressure equalizes.
4. Factors affecting Oil production
– Fluid properties of the oil
– Amount of gas, water associated
– Reservoir properties
– Size of the production tubing
– Related subsurface equipments
– Size & length of the flowline
All of these factors play an important part in an oil
well’s performance.
5. Fig.2.1
OVERALL PRODUCTION SYSTEM
(Vertical & Horizontal Flow)
V
E
R
T
I
C
A
L
Flow
Choke
INCLINED
FLOW
HORIZONTAL
FLOW
STOCK
TANK
SEPARATOR
GAS
Flow through Porous Medium
Inflow Performance
2.22
DIRECTIONAL FLOW
6. WELL PERFRMANCE
Well performance predictions
The overall flow configuration in a well as fluid
flows from the reservoir to the surface can be
separated into following segments:
– Fluid flow in reservoir/well bore
– Vertical or directional flow in tubing/casing
– Horizontal/inclines flow in surface flow lines
– Restricted or choke flow
7. WELL PERFRMANCE
Fluid flow in reservoir/well bore:
Darcy’s law is considered in predicting flow
from reservoir into the well bore
Pe
q = {(constant) (Kh) / ln (re/rw)} f(P) dp
Pwfs
This is normally referred to as INFLOW ‘PERFORMANCE
EQUATION’
8. WELL PERFRMANCE
Fluid flow in reservoir/well bore:
Darcy’s law for single phase
7.08(10־³) kₒ h (Pr-Pwfs)
qₒ = --------------------------------------
µₒ Bₒ { ln (re/rw)-0.75 +S+D. q}
9. WELL PERFRMANCE
Fluid flow in reservoir/well bore:
Where,
Kₒ – Effective permeability to oil, md
h – Effective oil pay thick ness, ft
re – Radius of drainage, ft
rw – radiud of well bore, ft
qₒ– Oil flow rate, bbl/day
Pwfs - wellbore sand face flowing pressure at centre of perforation
µₒ - VISCOSITY AT AVERAGE Pr & Pwfs, cp
Bₒ - Formation volume factor at average pressure
S – Total skin
D. q – Turbulent flow term
Pr – Reservoir pressure
10. Well performance predictions
• Well performance is governed by a large
number of factors that are often interrelated.
• Two basic categories:
– Inflow performance
– Outflow performance
11. • All flow in the reservoir up to the well bore is
designated as Inflow performance. It is controlled by
characteristics of the reservoir such as reservoir
pressure, productivity and fluid composition.
• All flow up the tubing and into the production facilities
is designated as Outflow performance. It is a direct
function of the size and type of producing equipment
Well performance predictions
13. CONCEPT OF PRODUCTIVITY INDEX
P.I = Q / ( Pr - Pwf )
Where ,
P.I = Productivity index.
Q = Total quantity of fluid.
Pr = Reservoir Pressure.
Pwf = Flowing bottom hole pressure.
Q Pr - Pwf
Q = K (Pr - Pwf)
K = Q / (Pr - Pwf)
Where K is a constant, known as PI
Pwf Pr
Pwf = Pr
Pwf
Pwf = 0
Q Qmax
14. INFLOW PERFORMANCE
INFLOW PERFORMANCE RELATIONSHIP
FIG.1 : Actual Case For P I
Pwf
q
It is basically a straight line or curve drawn
in the two dimentional plane, where X axis is
q ( Flow Rate ) and Y axis is Pwf ( Flowing
Bottom Hole Pressure ).
15. INFLOW PERFORMANCE
INFLOW PERFORMANCE RELATIONSHIP :
Q max for Straight P.I. >> Q max for IPR
Pwf
q
It is basically a straight line or curve drawn in the
two dimentional plane,where X axis is q ( Flow Rate )
and Y axis is Pwf ( Flowing Bottom Hole Pressure ).
STRAIGHT P.I. AND IPR
STRAIGHT P.I.
Q max
Q max
IPR
Pwf = Pr
16. INFLOW PERFORMANCE
IPR IN DIFFERENT CASES:
P
R
E
S
S.
P
I
G
O
R
CUMM. PROD.
P I
Typical Performance For A Water Drive Field
GOR
PRESSURE
* Active Water Drive :
1. Strongest drive ( Helps to exploit more than 35% of Initial oil
in place ) .
2. However intensity differs in different water drive
reservoirs. For e.g. Edge water drive is weaker than
Bottom water drive.
17. INFLOW PERFORMANCE
* Solution Gas Drive :
CUMM. PROD.
Typical Performance For A Solution Gas Drive Field.
RESV.
PRESS
GOR
PI
PI
GOR
RESV.
PRESS.
1. Called as ‘Internal Gas Drive’ or ‘Depletion Drive’.
2. Least Effective Drive Mechanism (Exploits about 15% of
Initial oil in place).
3. Reservoir Pressure influences the pattern of IPR. PI
declines sharply.
18. INFLOW PERFORMANCE
* Gas Cap Expansion drive :
1. Also called as Segregation Drive.
2. IPR curve is somewhere in between the Solution Gas
Drive & Water Drive. It is more effective than solution gas
drive reservoir. (Exploits about 20-25% of Initial oil in
place.
Typical Performance For A Gas cap Expansion Drive reservoir.
CUMM. PROD.
RESV.
PRESS.
GOR
PI
GOR
P.I
RESV.
PRESS.
19. INFLOW PERFORMANCE
* IPR-When Pr > Bubble Point Pressure :
Combination Constant PI and Vogel Behaviour
RATE.
PRESS .
0
0
Pwf
Pb
q
Qmax
qb
VOGEL
BEHAVIOR
CONSTANT PI
Pr
qv
20. INFLOW PERFORMANCE
* Change Of PI With Cumm. Recovery ( % Of Oil
In Place ) With Time :
IPRs for a Solution Gas Drive Reservoir with declining Reservoir pressure
PRODUCING RATE , M3/D
BOTTOM HOLE
PRESS -Kg/Cm2
Np/N = 0.1%
2 %
4 %
6 %
8 %
10 %
12 %
14 %
CUMM. REC., % OF ORIGINAL
OIL IN PLACE
21. INFLOW PERFORMANCE
VOGEL’S WORK ON IPR :
From general IPR equation i.e.
J = qo /(Pr -Pwf )--------------- ( 1 )
When Pwf is zero , the qo becomes maximum and denoted as
qmax.
That is J = qmax / ( Pr- 0 )
or J = qmax / Pr----------------- ( 2 )
Contd.-----------
22. INFLOW PERFORMANCE
VOGEL’S WORK ON IPR :
Dividing equation ( 1 ) by ( 2 )
J / J = qo /(Pr -Pwf ) * Pr / qmax
or qo / qmax = ( Pr - Pwf ) / Pr
or qo / qmax = ( Pr / Pr ) - ( Pwf / Pr )
or qo / qmax = 1 - ( Pwf / Pr )
since IPR curve below bubble point is not a straight line , he created
a parabolic equation from the above. Contd.----------
23. INFLOW PERFORMANCE
VOGEL’S WORK ON IPR :
He distributed {Pwf / Pr } in the following manner
20 % of {Pwf / Pr } & 80 % of {Pwf / Pr }²
Therefore , the new equation is established as :-
qo / qmax = 1 - 0.2 {Pwf / Pr } - 0.8 {Pwf / Pr }²
He then plotted dimensionless IPRs in two dimensional plane ,
where X- axis represents qo / qmax and Y- axis represents Pwf
/ Pr Contd.------
24. INFLOW PERFORMANCE
VOGEL’S WORK ON IPR :
The minimum and maximum values qo / qmax and Pwf / Pr
in each case is 0 and 1.0.
Inflow performance relationship for solution gas drive reservoirs (after Vogel).
0
0
0.20
0.40
0.60
0.80
1.00
1.00
0.80
0.60
0.40
0.20
Pwf/Pr
qo / qmax
25. INFLOW PERFORMANCE
FETKOVICH IPR EQUATION :
According to him, Oil well having reservoir pressure below
bubble point pressure also behaves like gas well so the IPR
equation being used for gas wells will also be applicable
for oil wells.
Therefore, the equation used for gas wells is also the same
as that for oil wells having reservoir pressure below bubble
point pressure, i.e. Qo = C ( Pr
2 - Pwf
2 ) n
Contd.----
26. INFLOW PERFORMANCE
FETKOVICH IPR EQUATION :
For determining C , at least one flow test data is
required. Let one flow test data be Qo corresponding to
the flowing bottom hole pressure Pwf
Then ,
C = Qo /( Pr
2 - Pwf
2) n
27. COMPARISON OF METHODS
MULTIPHASE FLOW
B
O
T
T
O
M
H
O
L
E
P
R
E
S
S
S
R
E
0 20 40 60 80 100 120 140 160 180
2000
1600
1200
800
400
0
FLOW RATE, BOPD
Straight P.I.
Fetkovich
Standing correction
in vogel
Vogel.
28. OUTFLOW PERFORMANCE
Well out flow performance depends upon many factors, viz.
Fluid characteristics
Well configuration
Conduit size
Wellhead back pressure
Fluid velocity
Pipe roughness
29. OUTFLOW PERFORMANCE PREDICTION
• Efforts are going on for many years to predict outflow
performance for multiphase fluid ( oil-gas, oil-water-gas, or
water-gas).
• The flow correlations have been developed to from this work
to predict the pressure at depth in a flowing vertical column
of multiphase fluid .
• The prediction with these correlations require extensive
calculations with computer and are plotted into generalized
pressure gradient curves.
32. INTRODUCTION TO ARTIFICIAL LIFT
PURPOSE OF ARTIFICIAL LIFT :
Pf Ps
To create a steady
low pressure or
reduced pressure in
the well bore against
the formation to allow
the well fluid to
come into the
wellbore continuously
for getting a steady
stream of production
to the surface end.
33. INTRODUCTION TO ARTIFICIAL LIFT
DEFINITION OF ARTIFICIAL LIFT
When a self flowing oil well ceases to flow or
is not able to deliver the required quantity to
the surface , the additional energy is
supplemented from surface either by mechanical
means or by injecting compressed gas or oil .
38. MOST COMMON METHODS
OF ARTIFICIAL LIFT
1. GAS LIFT (GL)
2. SUCKER ROD PUMP (SRP)
3. ELECTRICAL SUBMERSSIBLE PUMP (ESP)
4. HYDRAULIC PUMP
39. Produced
Hydrocarbons
Out
Injection
Gas In
Side Pocket
Mandrel with
Gas Lift Valve
Completion
Fluid
Side Pocket
Mandrel with
Gas Lift Valve
Single Production
Packer
Side Pocket
Mandrel with
Gas Lift Valve
GAS LIFT WELL WITH WIRE LINE RETRIEVABLE VALVE
50. MOST IMPORTANT FACTORS FOR CHOICE
OF LIFT MODES
FOR VERY HIGH VOLUME OF PRODUCTION
GL, ESP or HP
FOR VERY LOW VOLUME OF PRODUCTION
SRP or IGL
FOR MODERATE VOLUME OF PRODUCTION
GL, ESP, HP or SRP
FOR VERY DEEP WELL
HP
51. TYPE OF LIFT REQUIRED IS INFLUENCED BY
1. WHETHER CONVENTIONAL OR MULTIPLE COMPLETIONS
2. PRODUCING LOCATION - ONSHORE, OFFSHORE,
REMOTE LOCATIONS (IN ONSHORE / OFFSHORE)
3. WEATHER CONDITIONS
4. CORROSION
5. FLUID PARAMETERS
6. WELL DEPTH
7. WELL CONDITIONS & PARAMETERS
8. RESERVOIR
9. DESIRED PRODUCTION RATE
10. SERVICES AVAILABLE
11. ECONOMIC CONSIDERATIONS
52. GASLIFT
ADVANTAGES - I
1. EXCELLENT APPLICATION FOR OFFSHORE
2. VERY GOOD FOR WATER DRIVE, HIGH PI &
HIGH GLR FIELDS /WELLS
3. HIGH VOLUME LIFT & FLEXIBLE IN CAPACITY
4. EASILY HANDLES SANDS AND SOLIDS
5. MINOR PROBLEM IN DEVIATED WELLS
53. GASLIFT
ADVANTAGES - II
6. EASY TO RECORD D/H PRESSURE & TEMP.
7. CENTRALLY GL SYSTEM CAN BE ADOPTED
8. SUB-SURFACE EQUIPMENT ARE RELATIVELY
INEXPENSIVE.
9. IT HAS LOW PROFILE, HENCE IT HAS ADVANTAGE IN
URBAN AND OFFSHORE AREAS
10. SUB-SURFACE EQUIPMENT CAN BE ECONOMICALLY
SERVICABLE WITH WIRELINE UNIT.
54. GASLIFT
DIS-ADVANTAGES - I
1. CONSTANTLY IMPOSES RELATIVELY HIGH
BACK PRESSURE, WHICH RESTRICT
PRODUCTION
2. HIGH ENERGY OPERATING COST
3. LARGE CAPEX & OPEX – COMPRESSOR & HIGH
PRESSURE GAS INJECTION LINES
4. INSTALLATION OF COMPRESSOR PRESENTS
SPACE & WEIGHT PROBLEMS IN OFFSHORE
55. GASLIFT
DIS-ADVANTAGES - II
5. ADEQUATE GAS SUPPLY IS NEEDED
6. DIFFICULT TO LIFT EMULSIONS &VISCOUS
CRUDES
7. GAS FREEZING & HYDRATE PROBLEMS MAY
OCCUR ON SURFACE INJECTION LINES
8. CASING MUST WITHSTAND HIGH GAS
INJECTION PRESSURE
57. SUCKER ROD PUMPING
ADVANTAGES
1. RELATIVELY SIMPLE SYSTEM TO DESIGN
2. EASY FOR FIELD PEOPLE TO UNDERSTAND &
OPERATE
3. IT CAN PUMP OFF A WELL TO ALMOST ZERO
FLOWING BOTTOM HOLE PRESSURE
4. CAN LIFT VISCOUS CRUDE OILS
5. GOOD FOR LOW TO MEDIUM RATE WELLS
58. SUCKER ROD PUMPING
DIS-ADVANTAGES - I
1. CROOKED HOLES LEADS TO EXCESSIVE ROD
AND TUBING FRICTIONAL WEAR PROBLEM
2. SAND & SOLID CAN DAMAGE PUMP
3. GASSY WELLS IS USUALLY HAVING LOW
VOLUMETRIC EFFICIENCY
4. DEPTH LIMITATION MAINLY DUE TO LIMITED
ROD STRENGTH & EXCESSIVE STRETCH
59. SUCKER ROD PUMPING
DIS-ADVANTAGES - II
5. NOT SUITABLE IN DENSELY POPULATED CITY
OR PLATFORM WITH LIMITED DECK AREA
6. PARAFFIN PRESENTS PROBLEM
60. ESP
ADVANTAGES
1. VERY GOOD FOR EXTREMELY HIGH VOLUME
LIFT
2. CAN BE EASILY ACCOMODATED IN URBAN
AREA
3. SIMPLE TO OPERATE
4. APPLICATION IN BOTH ONSHORE & OFFSHORE
61. ESP
DIS-ADVANTAGES - I
1. CABLE CAUSES PROBLEM – CABLE DETERIORATE IN
HIGH TEMPERATURE
2. DEPTH LIMITATION DUE TO CABLE COST AND
OTHER PROBLEMS
3. GAS AND SOLID PRODUCTIONS ARE TROUBLE SOME
4. PRODUCTION RATE FLEXIBILITY IS LIMITED
62. HYDRAULIC PUMP
ADVANTAGES - I
1. CROOKED HOLE POSES NO PROBLEM
2. SAND & SOLID PRODUCTION PRESENT
MINIMUM PROBLEM USING HARDENED
NOZZLE AND THROAT
3. VISCOUS CRUDE CAN BE HANDLED EASILY
63. HYDRAULIC PUMP
ADVANTAGES - II
4. PRODUCTION CAN BE VARIED TO A GREAT
EXTENT BY CHANGING POWER FLUID RATE
5. FREE PUMP DESIGN IS AN ATTRACTIVE
PROPOSITION
6. IT CAN BE ACCOMODATED IN URBAN
LOCATIONS
7. IT CAN PUMPA WELL DOWN TO FAIRLY LOW
BOTTOM HOLE PRESSURE
64. HYDRAULIC PUMP
DIS-ADVANTAGES - I
1. POWER FLUID CLEANING IS A PROBLEM
2. POSITIVE DISPLACEMENT TYPE HAS SHORTER
LIFE THAN SRP & ESP
3. JETPUMP REQUIRES MINIMUM 500 PSI
PRESSURE AT 5000 FT & 1000 PSI AT 10000 FT
4. USUALLY SUSEPTIBLE TO GAS INTERFERENCE
65. HYDRAULIC PUMP
DIS-ADVANTAGES - II
5. NOT EASY FOR FIELD PERSONNEL TO
TROUBLE SHOOT
6. SAFETY PROBLEM FOR HIGH PRESSURE
POWER FLUID
7. JETPUMP IS VERY LOW ENERGY EFFICIENT
PUMP
66. PROGRESSIVE CAVITY PUMP
ADVANTAGES
1. SUITABLE FOR HANDLING SOLID & VISCOUS
FLUID
2. NO VALVE AT SUCTION OR DELIVERY END TO
STICK, CLOG OR WEAR OUT
3. GOOD FOR LOW TO MODERATE PRODUCTION
4. PCP COUPLED WITH ELECTRIC SUBMERCIBLE
MOTOR IS BETTER THAN SUCKER ROD
DRIVEN PCP
67. PROGRESSIVE CAVITY PUMP
DIS-ADVANTAGES
1. IT DOES NOT TOLERATE HEAT – IT SOFTENS
STATOR ELASTOMER
2. THOUGH GAS PRESENTS NO GAS LOCK
PROBLEM BUT GAS MUST BE SEPARATED TO
INCREASE EFFICIENCY OTHERWISE PUMP
WILL GET OVERHEATED
3. DEPTH LIMITATIONS
