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PRODUCTION ENGINEERING I
Petroleum engineering
Faculty of Exploration and Production Technology
Universitas Pertamina
OUTLINE
• Pressure traverse for vertical pipe
• Pressure traverse for horizontal pipe
THE PRODUCTION SYSTEM
3
Pr PAY ZONE
WELL HEAD
WELL
SEPARATOR
LINE
Pwf Pup
Pdown Ps
FLUID PARAMETERS IN MULTIPHASE FLOW
SLIPPAGE HOLDUP
FLUID VELOCITY
FLUID PARAMETERS IN MULTIPHASE FLOW
SLIPPAGE: If a gas-liquid mixture flows up a tubing string, the effects of buoyancy on each of the phase will not be equal. The slip velocity, Vs, is defined as the difference in velocities of the two phase
Vs = Vg – Vo
HOLDUP: to define the volumetric ratio between two phases which occupy a specified volume or length of pipe. The liquid holdup for gas-liquid mixture flowing in a pipe is referred to as HL
HL = volume of liquid in a pipe segment
volume of pipe segment , Hg = volume of gas in a pipe segment volume of pipe segment
HL + Hg = 1
FLUID VELOCITY: to define velocity based upon the total cros=sectional area of the pipe despite the fact that each phase will occupy a fraction of the area (superficial velocity)
𝐕𝐬𝐠 = 𝐪𝐠
𝐀, 𝐕𝐒𝐋 = 𝐪𝐋
𝐀 for more accurate value for the velocity of each phase is 𝐕𝐠 = 𝐪𝐠
𝐀.𝐇𝐠
VERTICAL FLOWS - SPECIFICITIES
Gas hold up
DIFFERENT FLOW CONFIGURATIONS – VERTICAL FLOW
finely dispersed bubble
slug
annular
Ugs (m/s)
Continuous phase = the liquid one
U ls(m/s)
Dry gas
condensate Volatile oil Black oil
VLP CURVE
Frictions
0 pressur loss due to friction (bar)
liquid rate
+
Total pressure losses in the tubing
Total Pressure gradient (bar)
liquid rate
=
pressure loss due to gravity (bar)
liquid rate
gravity
Pwf hydrostatic pressure
q For given PVT, WHP, GOR, WC and completion
GENERAL SHAPE OF A VLP CURVE
When q increases and is high,
BHP increases because of turbulences
FRICTION DOMINANT REGION
When q increases, Pwf decreases, because gas and liquid phases slip
GRAVITY DOMINANT
REGION
Pressure loss in the
well
GLR →0 fluid heavier
GLR increases : lot of gas
→the velocity increases
→turbulences →P2increases
optimum GLR
GLR
Gas lift is the only solution to control GLR.
MULTIPHASE FLOW MODELS
• Correlation of
CORRELATIONS IN THE CASE OF A WELL FLOW
D g
L U
z f g
P g
c M f
c total
2
2sin
+
=
D g
U f
g g dX
dP
c
M f
c
2
2 +
=
➢ hypothesis 1: stationnary flow
➢ hypothesis 2: 2 phase fluid = homogeneous mixture
Bottom hole Well head
Pup Pdown
Pm1 = Pup1 – Pdown1 Pup
Pdown
Pm2 = Pup2 – Pdown2
Etc …
Pup Pdown
PmN = PupN - PdownN
Ha ged o rn and Br o wn’ s me th o d
pressure (100 psi)
depth (1000 ft)
a curve for a specific value of GLR
D, q, Gg, Ta, Go, Gw are fixed
H aged or n and B ro wn ’s me thod
pressure (100 psi)
depth (1000 ft)
When GLR is low and increases, the pressure loss decreases, but when GLR is too high, the pressure loss increases
GLR increases
H aged or n and Br own ’s me thod
15
depth (1000 ft)
Example : WHP= 800 psi GLR = 400
depth = 8000 ft
depth
= 7000 ft
7000 + 8000 = 15000 ft
Pwf = 3500 psi
Pwf?
Hagedorn and Brown’s method
16
depth (1000 ft)
Example : WHP= 0
GLR = 400 scf/bbl depth = 8000 ft
8000 ft
Pwf = 1100 psi
Pwf ?
pressure profile in the well, for WHP = 0
pressure loss in the well
Conclusion
When WHP increases, the column is heavier.
17
pressure profile in the well, for WHP = 0
P
T
P
T
gas holdup low column heavy
gas holdup high column light
G↑
G↑
OUTFLOW EXERCISE: effect of the well head pressure increase on the pressure loss
• Data:
• GLR: 300 scft/bbl
• well depth: 2000 m
• WHP = 20 bar or 40 bar
• Questions:
• With help from the following shart, estimate the bottom hole pressure for each WHP value.
• Calculate the difference of bottom hole pressure between both cases. What is your conclusion?
OUTFLOW EXERCISE: effect of the well head pressure increase on the pressure loss
300
GLR = 300 scft/bbl & Z = 2000 m WHP
(bar)
BHP (bar)
ΔP (bar) 20
40
OUTFLOW EXERCISE: effect of the well head pressure increase on the pressure loss
GLR = 300 cuft/bbl & Z = 2000 m WHP
(bar)
BHP (bar)
ΔP (bar) 20
40
20
300
300
40 136
136
178
178 42
OUTFLOW EXERCISE: effect of GLR increase on the pressure loss
• Data:
• GLR = 0, 100, 200, 300 or 400 scft/bbl
• well depth: 2000 m
• WHP = 0 bar
• Questions:
• With help from the following shart, estimate the bottom hole pressure for each GLR value.
• Calculate the difference of bottom hole pressure between both successive cases. What is your conclusion ?
WHP = 0 bar Z = 2000 m GLR
(cuft/bbl)
BHP
(bar) ΔP (bar) 0
100 200 300 400
OUTFLOW EXERCISE: effect of GLR increase
on the pressure loss
Multiphase Flow Correlation
• Vertical Multiphase flow (Oil Wells)
• Hagedorn and Brown,
• Duns and Ros,
• Ros and Gray,
• Beggs and Brill,
• Aziz
• Vertical flow (dry gas wells)
• Cullender,
• Smith,
• Poettman
• Vertical flow (wet gas wells)
• Ros and Gray,
• Beggs and Brill
Multiphase Correlation
• Beggs-Brill Correlation (Beggs and Brill, 1973)
This empirical correlation was developed from air/water two phase flow experiments. It applies to pipes of all inclination angles.
• Hagedorn-Brown Correlation (Brown and Beggs, 1977)
The correlation used here is actually a combination of two correlation:
Hagedorn-Brown correlation for slug flow and Grift Correlation for bubble flow.
They only appply only to vertical wells
• Poettman and Carpenter (Poettmann and Carpenter, 1952 )
Assuming no slip of liquid phase, presented a simplified gas-oil-water three
phase flow model to compute pressure losses in wellbores by estimating
mixture density and friction factor
Exercise 1.
A decision has to be made on whether to use 2.991 in. or 3.958 in. ID tubing for a well with the following conditions:
Pseudo steady state inflow
• Initial pressure = 2,500 psi
• PI = 2.0 STB/psi
• Bubble point pressure = 1,200 psi
• Depth (TVD) = 5,000 ft
• Required THP = 300 psi
• GOR = 200 SCF/bbl
Calculate the flow capacity of the well for 2.991 in. or 3.958 in.
A well producing from a pay zone
between 5000 and 5052 ft is completed with 2⅞-in. tubing hung at 5000 ft. the well has a static BHP of 2000 psi and a PI of 0.3 STB/(day)(psi) and produces with a GOR of 300 scf/bbl and a water cut of 10%.
a) At what rate will the well flow with a THP of 100 psi?
b) If rate of production 200 STB/d, what is total of pressure loss in tubing?
Exercise 2.
No. 1
A well completed with 10,000 ft of 2 7/8" tubing is flowing at a rate of 600 STB/D with a gas-liquid ratio of 1.0 MCF/STB. Assuming a tubing head pressure of 300 psi, calculate the bottomhole flowing pressure. If Tubing size 2 7/8 in ID, water spec
gravity 1.074, gas specific gravity 0.65, average flowing temperature 100 F.
Using each of the 2 7/8" tubing
gradient curves for 50, 100, 200 and 400 STB/d, we can estimate the
bottomhole flowing pressure Pwf for
each flowrate.
THE PRODUCTION SYSTEM
30
Pr PAY ZONE
WELL HEAD
WELL
SEPARATOR
LINE
Pwf Pup
Pdown Ps
Production system represented as a network
with branches and loops.
FLOWLINE PERFORMANCE
• Procedure for calculating the pressure losses occurring in a pipeline are required in the petroleum industry for:
• –Designing flowlines or
• –Designing gathering stations
• The pressure loss in the flowline, expressed as:
• It can be very small for short flowlines, such as might exist in an offshore situation, if the separator is located near
wellhead.
• Conversely, in many producing areas the distance between the wellhead and separator may be several miles, and the
pressure drop in the Flowline might be 20 to 30 percent of the
total pressure loss in the system.
PRESSURE DROP IN FLOWLINE
• The general pressure gradient equation will apply for flow in pipelines, and all three of the components will apply in most cases.
• Some pipelines can be considered to be essentially horizontal, and in this case the hydrostatic component would be zero. Thus. it is important to have a good correlation for friction factor in pipeline design.
• A substantial part of the total pressure loss in a pipeline can result from Lifting the
• fluids over hills or inclines.
• Also, it has been found that in most cases, hardly any of ' the hydrostatic
pressure loss in the uphill section of a line is regained in the down-hill section.
FLOWLINE SIZE
• Some aspects of the pipeline design problem are not related to pressure loss only, but include sizing lines and separation facilities such that the separator will not be
overloaded or flooded.
• Separators are usually designed based on a steady rate of gas and liquid flow. If extra liquid volumes or slugs arrive at the separator periodically, means must be provided to handle the extra liquid, this can be accomplished by installing slug catchers upstream to the separator.
• Before separation facilities can be sized, the production engineer must be able to predict the size or volume of the extra liquid and haw fast this volume must be handled.
• The extra liquid can result from changes in flow conditions, such as adding or deleting wells, which will usually changes the liquid holdup in the line.
• If conditions are changed such that liquid holdup is decreased, then the extra volume of liquid removed from the system will eventually arrive at the separator. Designing for this situation requires accurate holdup prediction methods. This type of problem can arise also during PIGGING operations.
HORIZONTAL FLOW PATTERN
FLOW PATTERNS INDICATION
FLOWLINE CORRELATIONS
• Correlations: Gilbert and Beggs & Brill
• They developed an elegant graphical method for finding the horizontal-flow
• pressure losses for Multi-phase flow.
• These approach to the horizontal two- phase flow problem was empirical; based on measured values of pipe-flow pressure losses. By supposing that the following measurements have been taken in a large number of flowing wells:
• Flowlinelength(pipe)Lf,ft.
• Flowlinesize(pipediameter)df,inch.
• Tubingsize(tubingdiameter)d,inch.
• THPpth,psig.
• Workingpressureofseparatorpsep,psig.
• Grossliquidrate,bbl/day.
• GLR,Scf/bbl.TubingdepthD,ft.
Exercise 3
From the following given data:
Q = 1000 bbl/day, P
sep= 80 psig, L
f= 2500 ft, d
f= 2 inch, GLR = 1000 Scf/bbl.
Find P
wh= ?
Hint: the same procedure is followed as in the calculation of
tubing performance pressure traverse curves.
Exercise 4
• A well is producing at a rate of 1500 STB/day with a GLR of 600 scf/STB. No water is being produced and the well is located at a distance of 6000 ft from the separator. If the separator pressure is fixed at 120 psig.
• Find the required wellhead pressure for flowline sizes of 2 in and 3 in.
• Dale Beggs – Production Optimization Using Nodal Analysis
• Appendix B. Pressure Traverse Curves
• For tubing: pg.197 – 335
• For flowline pg 336 - ….
REFERENCES
TO CALCULATE PRESSURE DROP IN PIPELINE
• Beggs and Brill Correlation can be used to calculate pressure drop in pipeline
• https://petroleumoffice.com/function/pressuregradientbeggsbrill
