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Acoustic Determination of
Producing and Static Wellbore
Pressures
Well Analyzer Seminar
Reference Papers: SPE 14254 and SPE 13810
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Purposes of Performing an
Acoustic Fluid Level SurveysWell Performance and Potential Analysis
based on measured and calculated pressure
distribution in wellbore and the Static ReservoirPressure.
Pump Submergence Some operators shootthe well only to determine the amount of liquid
above the pump (FAP). This is inefficient use of
the fluid level information.
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TWM Computes
Wellbore Pressures from
liquid level survey and
casing head pressure
Fluid Level
Gaseous Liquid
Producing BHP
(PBHP)
Gas
Liquid
Pump
Static
Reservoir
Pressure
(SBHP)
Casing head pressureMicrophone
Pressure at Fluid Level
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Right Halfof BHP Tab ANSWERS THE FOLLOWING
QUESTIONS:
1. What is the distance (depth) to the top of the
liquid?
2. Is gas flowing up the annulus? At what rate?
3. What is the percentage of liquid in the annular fluid
column?
4. How much liquid exists above the pump?
5. What is the pump submergence ?
6. What are the pressures at the casing head, fluid
level, pump intake and opposite formation ?
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BHP tab, page 111 TWM manual
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Bottom Hole Pressures
Annular Fluid Distribution is a
Function of Wells Producing
Conditions
BHP is computed from acoustic fluidlevel surveys.
BHP = Surface Casing Pressure +
Pressure due to the columns of fluidsin the annulus or tubing.
The well is like a pressure gage with
a long stem.
PBHP
P casing
P g/l
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Pressure Gradients for Common Liquids
Fresh Water = 0.433 psi/ft
Field brine = 0.5 psi /ft
30API Oil = 0.38 psi/ft
10API Oil = 0.433 psi/ft
Approximations3 ft of oil column = 1 psi
2 ft of brine column = 1 psi
Pressure gradient
gives the increase in
pressure per foot of
depth increase
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Fluid Column Pressure Estimates
Pgc = gas column pressure increase, psi
Pgc = (Pc * Lg) / 30000
Pc = casinghead pressure, psi
Lg = height of gas, feet
Water Column Pressure
Increase
Pw = Wg * Lw (psi)
Wg=water gradient psi/ft
Lw=height of water
20 ft of water about 10 psi
Oil Column Pressure
Increase
Po = Og * Lo (psi)
Lo=height of oil
Og=oil gradient psi/ft
Og = 61.3 /(API+131.5)
30 ft of oil about 10 psi
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Accurate Pressure Distribution
Calculation Requires:
Stabilizedflow conditions
Determination of Liquid Level
Measurement of surface pressure and ofpressure buildup rate (at Producing andStatic Conditions)
Determination of % Liquid in gaseous fluid
Oil, water and annular gas densitiesWellbore description
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Stabilized Pumping Well
Requires a Stable FluidLevel
Requires a StableCasing Pressure
Requires a Constant
Production Rate andWOR
Gas
Brine
Gradient
Oil + Gas
Pump
Pc
Pt
PBHP
FL
Fluid leaving the wellhead =
Fluid entering from perfs
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Gas
Brine
Gradient
Oil + Gas
Pump
Pc
Pt
PBHP
FL
Stabilized
producing fluid
level
Oil-Waterinterface
at pump
intake
Shut-in
fluid level
Shut-in
oil-water
interface
Stabilization
ProcessStabilized
casing
pressure
PcStabilized
water/oil ratio
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Gas
Brine
Gradient
Oil + Gas
Pump
Pc
Pt
PBHP
FL
Separation of Fluids in a
Stabilized Well
The Liquid in the gaseouscolumn above the pumpintake is 100% OIL
regardless of well test water-oil-ratio .
Liquid below pump intakecontains more water than
well test water-oil-ratio.
Liquid below pump intakeexhibits BRINE gradient.
The wellbore is functioning as a
separator
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Downhole Video Shows:
Effect of oil slip velocityon water
holdup causes water to accumulate
below pump intake.
Effect of wellbore inclination causes
oil and gas to move to high side of
wellbore.
Flow from perforations is not uniformmixture.
http://exprogroup.com/products-
services/wireline-intervention/
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Fluid Distribution in Annulus of Pumping Wells
Gas Gradient
Liquid
Gradients
Gas &
Liquid
Mixture
Gradients
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Liquid Level at Formation
1. Casing Head Pressure is theMajor Portionof PBHP.
2. Pressure due to Gas Columnis Generally Small
3. Pump intake and liquid levelare near perforations.
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Liquid Level Above Formation with
NO Free Gas Inflow from the Reservoir
1. Fluid above tubing intake is100%oil.
2. Producing BHP = Casing Pressure +
Gas Columm Pressure +
Oil Gradient to Pump +
Primarily Brinegradient belowpump intake.
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No Inflow of Free Gas with Produced Liquid
Casing Pressure does
not increase when
Operator Closes theCasing Valve
Or the Casing Pressure
is less than the
Flowline Pressure.
Gas
Brine
Gradient
Oil
Pump
Pc
Pt
PBHP
FL
Oil,Water,Gas
When:
100 % Liquidbelow Fluid Level
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Liquid Level Above Formation
with Free Gas Flow from Perforations
1. GaseousLiquid Column existsabove the Perforations.
2. Producing BHP =
Casing Pressure +
Gas Column Pressure +
Gaseous Oil Pressure to Pump +
Gaseous WaterPressure tobottom.
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Annular Gaseous Liquid Column Exists
Normally, produced gas is flowingout from the casing annulus.
The casing pressure builds upwhen the casing valve is closedand gas is trapped inside thewellbore.
Gas
Liquid + GasPerfs
Pump
FlowlinePc
Pt
Gaseous LiquidColumn
Dip Tube
When:
Gas enters through perforations and is
bubbling through annular liquid from
perforations to gas/liquid interface.
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Foam @ Fluid Level
Foam consists of 98-99 % gas
Can exist only at very low annular
gas flow rates, less than 1 MCF/D
Does not contribute significantly to
BHP
It attenuates soundso that a LL
echo could be very low amplitudeor not visible on the acoustic
record.
Bubble flow98% liquid
below foam
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Foam Experiment Results
Foam is blown
away by increased
gas flow
Increasing gas flow
Foam
Liquid
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Producing BHP Calculation
Requires: Measuring the fluid level and casing pressure
Determiningpressure gradientof gaseous liquidcolumn. ( density of gas-liquid mixture in wellbore)
Pressure gradient of gaseous liquid columndepends mainly on % liquid and decreases
as gas flow rate increases.
Have to calculate the % Liquidin theGaseous Liquid Column
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Determination of Gaseous Liquid
Column Gradient (psi/ft)
Determined experimentally on a given well byrunning a liquid level depression test (Walker test).
Determined from an experimental correlation definedfrom large number of tests. Input: measured
pressure, gas flow rate and annular area. (S curve).Reference: Acoustic Producing BHP
Computed from mechanistic model(not practical in most cases due to lack of fluid
properties data and use of questionable correlations)
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Walker Test
Patent 1939
1. Operate pump atsteady rate using
different casing
head pressure.
2. Monitor change in
fluid level.
3. Ratio of casing
pressure change
(psi) to fluid level
change (ft) givesfluid mixture
gradient (psi/ft) and
% liquid
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Liquid % from Liquid Level
Depression Test (Walker Test)
Given:
Stabilized Production
Fluid Properties
Determine Liquid
Percent in Gaseous
Liquid Column byrelating casing back
pressure increase to
drop in fluid level.
Gas
Low PBHPPerfs
Pump
Flowline
Pc
Pt
Gaseous Liquid
Column with10 - 15%Liquid
HighFL
BackPressure
Valve
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Back Pressure Test Setup
Polished Rod
Oil and Gas
Tubing
Close valve to
flow line
Vent gas through casing
valve and back pressure
valve to tubing
Back Pressure Valve T
Adjust spring to
set casing
pressure
High Pressure
Hose
Gas
Gun
Attach Back Pressure Valve and gas gun to theTee attached to Casing Valve.
Connect the Back Pressure Valve outlet to theflow tee with the high pressure hose.
Adjust Back Pressure Valve to desiredpressure
Check frequently during depression to avoidpushing gas into the pump.
To ensure a stable condition, the casingpressure and the liquid level must beunchanging.
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Back
Pressure
Valve
B i f t t hil i
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Basis for test while pumping:Increase Casing Pressure => Depress Liquid Level
2300 ft
Pressure increase = 220 psi
Fluid Level
Drop 2300 ft
Gradient= 220psi/ 2300 ft
= 0.095 psi/ft
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Procedure for Liquid % Test
1. Maintain Well at NormalPumpingConditions.
2. Measure Liquid Level Depthand the Casing Pressure.
3. Increase casing pressure withback pressure regulator andallow well to stabilize.
4. Measure NEW Liquid LevelDepth at NEW Casing
Pressure.5. Repeat Steps 3 & 4, until
Liquid Level is Near Pump.
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Walker Test: Pressure vs. Depth Traverses in the Annulus
0
500
1000
1500
2000
2500
3000
3500
0 20 40 60 80 100 120 140 160 180
Casing Pressure, psi
Depth,
feet
17 psi110psi
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Measured BHP and Height of Gaseous Column as
Casing Pressure Increases
153.7 157.4
0
50
100
150
200
250
300
350
400
450
500
0 20 40 60 80 100 120 140
Gas-Liquid Pressure, psi
BHP
(psi)o
rHightofGaseo
usLiquid(ft)
G/L interface BHP sensor
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PBHP and Gradient from Walker Test
y = -0.3578x + 157
R2= 1
0
20
40
60
80
100
120
140
0 50 100 150 200 250 300 350 400 450 500
Height of Gaseous column ft
PressureatG/L/i
ntefrace,psi
Pressure @ G/L Linear (Pressure @ G/L)
Gradient = 0.3578 psi/ft
PBHP = 157 psi
Oil API = 20
Oil gradient = 0.407 psi/ft
Gaseous column gradient = 0.3578 psi/ft
Liquid fraction = 0.3578/0.407=0.88
% Liquid in Gaseous column = 88
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Back Pressure Test Setup
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Automatic Annular Liquid Level and
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Automatic Annular Liquid Level and
Casing Pressure Monitoring
Remote Fired
Gas Gun and
Pressure
Transducer
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Echometer S Curve Correlation
Performed numerous Walker testsin producingwells with different characteristics.
Determined % liquid as a function of annular
gas flow rate.
Correlated % liquidvs. gas flow per square inchof annulus area.
Range of well parameters:
Casing size = 4.5 to 7 inch Tubing size = 2-3/8 and 2-7/8
Well depth = 5000 to 9000 feet Gaseous columns up to 5000 ft
Gas flow rates = 13 to 120 MCF/D API gravity = 32 to 43
Liquid percentage = from 20 to 77%
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Casing Pressure
and Liquid LevelDuring Liquid
Level
Depression Test.
Pumping rate is
kept constant
during test.
Typical test
data point.
SPE 14254
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Gaseous Column Height vs. Casing Pressure
for 150 MCF/D in 5 & 2-7/8
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Gaseous Column Height vs. Casing Pressure
for 150 MCF/D in 5 & 2-7/8 Oil gradient = 0.4 psi/ft
A= 12.31 in2
Q/A=150000/12.31
= 12,254 cuft/day/in2
Mixture Gradient= 0.0962
Oil gradient = 0.4 psi/ft
Oil fraction= 0.0962/0.4
Oil fraction= 0.24
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Annular
Gaseous
Liquid
Column:
Effective Liquid
Fraction
vs.
Q/A
Actual Field
Collected
Data Point
fromprevious
slide
Heavy oil
data in TAM
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Time = 0 Time = 4 min.Casing Valve Closed During Test
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Gas flow into well = 45 MCF/D
Gas flow out= 45 MCF/D
46.2
psi
49.4
psi
PBHP = 572.8 psi
Casing Valve Closed During Test
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Calculation of annular gas flow rate is based on the
increase in casing pressure per unit time during the
casing pressure buildup test. Using the real gas law:
P1*V1= Z1n1RT1 at time t1and
P2*V2= Z2n2RT2at time t2 where in the well:
V1= V2= volume of annulus minus volume of liquid
T1
= T2
= average temperature
Z1 = Z2 = gas compressibility factor
R = gas constant
P1=initial casing pressure
P2= pressure at end of casing buildup testn2,n1= number of moles of gas in annulus
Then solve for (n2-n1) which is the increase in gas
mass during the time (t2-t1) and convert to standard
cubic feet per day.
Gas Flow
Calculation
ZRT
VPPnn1212
R i t f A f
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Requirements for Accuracy of
Pressure Buildup Test
Test should be short(2 to 10 minutes) so that
inflow of gas and producing bottom hole
pressure remain almost constant.Measured casing pressure buildup vs. time
should be linearindicating a constant gas
rate.
ID of casing, OD of tubing and well depth
data are correctly entered in well database.
Producing BHP and PIP Calculation
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Producing BHP and PIP Calculation
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Gas Free Liquid - BHP Screen
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Gas Free Liquid BHP Screen
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Static BHP
SBHP: also known as thereservoir pressure at thedrainage radius.
Driving Pressure availableto push the fluids to thewellbore from theformation.
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C l l ti f SBHP
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Calculation of SBHP
Gas
Brine
Oil
Pc
Pt
Static FL
Well Shut-in
SBHP
Static BHP =
Casing Pressure +
Gas Column Pressure +
Oil Column Pressure +
Brine Column Pressure.
Note:All flow from perforations has stopped
Fluids Segregated by Gravity
Position of Oil/Brine interface above pump
intake must be computed.
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Static Bottom Hole Pressure
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Static Bottom Hole Pressure,
Pump Intake near Perforations
Gas-free Liquid Level is Generally Above Pump when Producing
Need to compute % of
oil and water in annulus
at end of fill-up.
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Determination of Accurate SBHP
Pump should be shut-down for a time sufficient
to stabilize casing pressure and fluid level.
Periodic (once a day) fluid level and casing
pressure measurements identify stabilizedconditions.
Select Static in final fluid level record.
Enter the last ProducingFluid Level and %liquid in annular fluid column into the SBHP
worksheet.
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Pump Shut Down for 4 Days
SBHP k h t i TWM
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SBHP worksheet in TWM program
Enter
values
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