1 4 Calculation of Acoustic BHP 2014

8/10/2019 1 4 Calculation of Acoustic BHP 2014

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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


7/60

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.


17/60

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


18/60

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.


19/60

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


21/60

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


23/60

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)


24/60

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


25/60

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


26/60

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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31/60

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


32/60

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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34/60

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


36/60

Automatic Annular Liquid Level and


37/60

Automatic Annular Liquid Level and

Casing Pressure Monitoring

Remote Fired

Gas Gun and

Pressure

Transducer


38/60

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%


39/60

Casing Pressure

and Liquid LevelDuring Liquid

Level

Depression Test.

Pumping rate is

kept constant

during test.

Typical test

data point.

SPE 14254


40/60

Gaseous Column Height vs. Casing Pressure

for 150 MCF/D in 5 & 2-7/8


41/60

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


42/60

Annular

Gaseous

Liquid

Column:

Effective Liquid

Fraction

vs.

Q/A

Actual Field

Collected

Data Point

fromprevious

slide

Heavy oil

data in TAM


43/60

Time = 0 Time = 4 min.Casing Valve Closed During Test


44/60

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


45/60

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


46/60

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


48/60

Gas Free Liquid - BHP Screen


49/60

Gas Free Liquid BHP Screen


50/60

Static BHP

SBHP: also known as thereservoir pressure at thedrainage radius.

Driving Pressure availableto push the fluids to thewellbore from theformation.


51/60

C l l ti f SBHP


52/60

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.


53/60

Static Bottom Hole Pressure


54/60

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


57/60

SBHP worksheet in TWM program

Enter

values


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Documents

1 4 Calculation of Acoustic BHP 2014