3- procade overview
TRANSCRIPT
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Why use ProCADE?
Determine reservoir properties
Predict future production
Determine economic viability of treatment
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ProCADE
Modules
Water Control Diagnostics
Material Balance / Empirical Decline
Graphical Decline Curve Analysis Multi-Layer Forecasting
Single Layer Forecasting
Economics
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Differential Technology
Multiphase Flow Analysis
Multi and Single-Layer Forecast and Economics
Extensive Well Model Catalog
Complete PVT PackageLogical Analysis Procedure
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Water Control Diagnostics
Qualitative Indication of Water Control Problems
6 JGC
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Material Balance
Sensitivities to Determine:
Initial Reservoir Pressure
Drainage Area / Initial Fluids in
Place
Final Aquifer Influx Rate
Extrapolate Production to Time
or Pressure
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Graphical Decline Analysis
Graphical matching to determine reservoir properties
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Material Balance
Results
Average Reservoir Pressure
Drainage Area
Drive Mechanism Aquifer Influx
Average Reservoir Fluid Saturations
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Graphical Decline Analysis
Models
Unfractured Vertical Well
Blasingame and Fetkovitch Decline Curves
Infinite and Finite Conductivity FracturesAnalysis Options
Manual and Automatic Matching
Decline Curve Forecast
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Graphical Decline Analysis
Outer Boundary Conditions
Vertical Wells
No Flow (Closed Boundary)
Constant Pressure (Aquifer Influx)
Step and Ramp Rate (Water Flood)
Fractured Wells
No Flow Constant Pressure
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Graphical Decline Analysis
Results
Permeability, Mobility, and Skin
Drainage Area and Apparent WB Radius
Initial Fluids in Place Fracture Properties
Half Length
Conductivity
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Production Forecasting
Extensive Catalog of Analytic Reservoir Solutions
Commingled Multi-Layer Forecast
Multiple Time Step Analysis
Variable Inner Boundary Conditions Changing well model with time
Option to Include or Ignore Prod. History
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Forecast Validation
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Economics
Comparative Economic Analysis
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Economics
Comparative Economic Analysis Base Case Vs. Stimulated Case
Multi-Layer Forecasting
Accounts for Price Escalation/De-escalation
Oil and Gas Production
Water Disposal CostsBuilt In Tax Help for 50 States
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Who should use ProCADE?
Internal
DESC / HRT
Candidate Recognition
Special Projects
Sales / DESC / Field Engineers
Use in Conjunction with FracCADE for Design, Forecasting,and Economics
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Who should use ProCADE?
External
Production Engineers
Reservoir Engineers
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The following slides contain
information about the inputs on
the Zone Screen in the General
Inputs Module.
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Partial Completion Pressure Losses
Skin due to partial completion of pay zone
Main pressure losses occurs due to convergence flow
The effect is significant when flow rate is high
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Perforation Pressure Losses
Open Perf Model (McLeod-Brown)
Perforations modeled as small wellbore at a 90o
angle to thecased wellbore
Crushed zone permeability, kp, is a function of reservoir
permeability Underbalanced: kp = 0.6 k
Overbalanced: kp = 0.2 k
Crushed zone thickness is ~0.5 in thick
Phasing not considered in calculation
Gives lowest perforation pressure loss
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McLeod-Brown Model
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Perforation Pressure Losses
Stable Perf Model (Karakas and Tariq)
Developed from finite element modeling of fluid flow to holesin casing
Calculates the apparent radial flow steady state skin effect
due to: Horizontal flow (phasing)
Vertical converging flow
Wellbore configuration Crushed zone
Underbalance/Overbalance setting does not affect
calculation
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Perforation Pressure Losses
Stable Perf Model (Karakas and Tariq)
- User is allowed to specify damaged zone radius and
permeability
- Damaged zone radius can be less or higher than perforation
tunnel length
Gives higher pressure drop than Open Perforation Model
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Perforation Pressure Losses
Collapsed Perf Model
Calculates skin due to perforation being full of formation
sand
Produces highest pressure drop
Neither Phasing nor Underbalance/Overbalance settings
affect calculations
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Vertical Permeability
Vertical or Z-Direction Permeability affects:
Partial Completion Loss calculation
Horizontal Well Performance
Rule of thumb is that vertical permeability is 0.1 to 0.2 timeshorizontal permeability
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Gravel Pack Completion Losses
Correlations are different methods of estimating the inertial flow
coefficient,
McLeod and Saucier were developed specifically for gravel
packing
Cooke was originally developed for non-darcy flow in afracture
Firoozabadi-Katz was originally developed for non-darcy
radial flow Tenneco/Resin Pack is specifically for resin coated
applications
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Gravel Pack Completion Losses
Flow length in gravel is given by:
(Casing ID - Screen OD) / 2
McLeods correlation is a good place to start
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The following slides contain
information about the inputs on
the Reservoir Screen in the
General Inputs Module.
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Oil PVT Correlations
Many choices for Black Oil Reservoirs
Regional Defaults
Mix and match
Optimized settings for Volatile Oil Reservoirs
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Pb - Rsob
Solution Gas-Oil Ratio - Amount of gas that will dissolve in 1
stb of oil when both are at reservoir conditions. (scf/stb) Constant above Pb
Decreases with pressure below Pb
Correlation for Bubble Point and Solution Gas-Oil Ratio at the
Bubble Point
Equation can be re-arranged to solve for Bubble Point orSolution Gas-Oil Ratio at the Bubble Point
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Comparison of Pb - Rsob CorrelationsProCADE Rso Corrleations - Oil
0
50
100
150
200
250
300
350
400
450
0 500 1000 1500 2000 2500 3000 3500 4000 4500
Pressure (psia)
Rso
(scf/bbl)
Glaso
Standing
Petrosky-Farshad
Kartoatmodjo-Schmidt
Bubble Point
Pi=3000 psi
Pb=2000psi
T=180 F
=35 deg API
Tsep=80 F
Psep=100 psi
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Comparison of Bo Correlations
ProCADE FVF Correlations - Oil
1.00
1.05
1.10
1.15
1.20
1.25
1.30
0 500 1000 1500 2000 2500 3000 3500 4000 4500
Pressure (psia)
Bo
(rb/stb)
GlasoStanding
Petrosky-Farshad
Kartoatmodjo-Schmidt
Bubble Point
Pi=3000 psi
Pb=2000psi
T=180 F
=35 deg API
Tsep=80 F
Pse =100 si
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o Correlations
Dead Oil (gas-free) Viscosity is used by all the correlations
except Khan to calculate the viscosity at the Bubble PointThe viscosity at the Bubble Point is used as a reference to
calculate the saturated (PrPb) oil
viscosity
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Comparison of o Correlations
ProCADE Viscosity Correlations - Oil
0.0
0.5
1.0
1.5
2.0
2.5
0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000
Pressure (psia)
Visco
sity(cp)
od = Beal
os = Chew-Connely
=
od = Beggs-Robinson
os = Beggs-Robinson
= -
od = Glaso
os = Kahn
=
Pi=3000 psi
Pb=2000psi
T=180 F=35 deg API
Tsep=80 F
Psep=100 psi
Pi=3000 psi
Pb=2000psi
T=180 F
=35 deg API
Tsep=80 FPsep=100 psi
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Acid Gas Correction
Accounts for the presence of N2, CO2, or H2S in the oil.
Affects calculation of Pb or Rsob
Indirectly affects calculation of Bo
Practical upper limit of ~12% for each component
Referred to as Acid Gas Components because:
H2S Sulfuric Acid
CO2 Carbonic Acid N2 Nitric Acid
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Acid Gas Correction Comparison
ProCADE Acid Gas Correction Correlations
1700
1800
1900
2000
2100
2200
2300
2400
0 2 4 6 8 10 12
% Composition
Press
ure,psia
Original Bubble Point
Jacobson & Glaso (N2)
Glaso (CO2)
Glaso (H2S)
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Canadian Formation
Formation specific correlations
Cardium/Viking
D2-Nisku
D3-LeducAffects calculation of Pb, Rsob, Bo, and Co
C C l ti
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Co Correlations
39 JGC
ProCADE Compressibility Corrleations - Oil
1.0E-06
1.0E-05
1.0E-04
1.0E-03
1.0E-02
1.0E-01
0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000
Pressure (psia)
Co
(1/psi)
Vasquez-Beggs
Calhoun
Trube
Petrosky-Frashad
Bubble Point
Pi=3000 psi
Pb=2000psi
T=180 F
=35 deg API
Tsep=80 F
Psep=100 psi
R i l D f lt
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Regional Defaults
Automatic settings for:
U.S. Gulf Coast Alaska
California
Mid-Con U.S. North Sea
Saudi Arabia
Western Canada UAE
Nigeria
Colombia General
G PVT C l ti
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Gas PVT Correlations
Required Properties
Reservoir Gas Specific Gravity
Pseudocritical Temperature, TPC
Pseudocritical Pressure, PPC Ideal Gas Law Deviation Factor (Z-Factor)
Bg, g, and Cg
T d P
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TPC and PPC
Natural gas mixture physical properties are correlated using
van der Wals principle of corresponding states.This states that two substances at corresponding conditions,
such as critical temperature and pressure should have similar
physical properties.Research by Kay extended its use to multi-component mixtures
using pseudo critical temperature and pressure.
TPC and PPC have no physical meaning
42 JGC
Z Factor Comparison
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Z-Factor Comparison
ProCADE Z-Factor Comparision
0.5
0.6
0.7
0.8
0.9
1
1.1
0 500 1000 1500 2000 2500 3000 3500 4000 4500
Pressure, psia
Z-F
actor
s.g. = 0.65
s.g. = 0.9s.g. = 1.15
s.g. = 1.4
B Comparison
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Bg Comparison
ProCADE Gas Formation Volume Factor Comparison
0.0001
0.001
0.01
0.1
1
0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000
Pressure, psia
Bg,
rb/scf
s.g. = 0.65
s.g. = 0.9
s.g. = 1.15
s.g. = 1.4
Comparison
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g Comparison
ProCADE Gas Viscosity Comparision
0
0.005
0.01
0.015
0.02
0.025
0.03
0.035
0.04
0.045
0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000
Pressure, psia
Visc
osity,cp
s.g. = 0.65
s.g. = 0.9
s.g. = 1.15
s.g. = 1.4
C Comparison
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Cg Comparison
ProCADE Gas Compressibility Comparision
1.0E-05
1.0E-04
1.0E-03
1.0E-02
1.0E-01
0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000
Pressure, psia
Cg,
1/psia
s.g. = 0.65
s.g. = 0.9
s.g. = 1.15
s.g. = 1.4
Formation Pore Compressibility
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Formation Pore Compressibility
Depends on Porosity and correlation selection
Consolidated Sandstone
Carbonate (Limestone/Dolomite)
Unconsolidated Sandstone
Will be the same for Consolidated and UnconsolidatedSandstone below 20% Porosity
For multiple zones, this is calculated, but not displayed,
based on the porosity in each zone
Can also be user input
One value applies to all zones
Separator Configuration
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Separator Configuration
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The following slides containinformation about the inputs on
the ProdData Screen in the
General Inputs Module.
Wellbore Outflow Correlations
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Wellbore Outflow Correlations
Used to estimate pressure losses due to fluid flow in the
wellbore (i.e. convert wellhead pressure, Pwh, to bottomholeflowing pressure, Pwf)
Necessary because all reservoir solution procedures in
ProCADE use sandface flowing pressure, Pwfs Pwfs = Pwf+ Completion Losses
Most field production data does not include Pwf, but does
include Pwh
Wellbore Outflow Correlations
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Wellbore Outflow Correlations
Multiphase Liquid Flow
Duns and Ros
Orkiszewski
Beggs and Brill
Use when fluid is mostly liquid (oil with some gas)
Wellbore Outflow Correlations
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Wellbore Outflow Correlations
Dry Gas Flow
Cullender and Smith
Can handle small amount of liquid (up to 10 bpd)
Multiphase Gas Flow
Hagedorn and Brown
Can also be used as a liquid flow correlation
Wellbore Outflow Correlations
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Wellbore Outflow Correlations
When in doubt, try Hagedorn-Brown first
Be sure to check that calculated Pwfdoes not exceed reservoirpressure (Injection!)
Correlations are valid for vertical and deviated wellbores
Beggs and Brill is the most rigorous for deviated wells
Outflow Gas-Liquid Ratio
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Outflow Gas Liquid Ratio
Used for gas lift wells
If non-zero, use total GLR (injected + naturally produced)If set to zero, producing GLR is automatically calculated from
production data
Interpolation Setting
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te po at o Sett g
This setting is not used in the general inputs. It is used by the
forecasting engine in the Super-Position-In-Time calculationswhich account for prior production.