• Author / Uploaded
• Sajad Falah

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PIPESIM Software

Total Production System

Compressor

Separator

Riser

Choke

Pump

gas

Flow line

oil Safety Valve

Export lines

Tubing

Reservoir Completion

Content • • • • • • • • •

Introduction Fluid Properties Inflow Performance Out flow Performance Factors Affecting VLP IPR/VLP Relationship Tubing Selection Criteria Nodal Analysis Factors Affecting Nodal Analysis

Content (cont.) • • • • • • • •

Software Interface Data Collection Building a Well Model Data Matching Nodal Analysis using Pipesim Oil Well Modeling Gas Well Modeling Model a Gathering Network

Objectives for this Course • Overview of field development processes with the analysis of the reservoir and downhole data and improve the wells performance by the nodal analysis and the artificial lift systems using the pipesim software. • Using individual PIPESIM modules for a wide range of analyses, including well modeling, nodal analysis, field planning, artificial lift optimization, pipeline design and equipment sizing.

What do you expect from this course?

Reservoir Properties

Rock Properties The main Reservoir rock properties are:

• • • • • •

Porosity (total and effective) Permeability Saturations Compressibility Net pay thickness Reservoir shape

Fluid Properties Basic fluid parameters used in reservoir engineering:

• • • • •

Viscosity Compressibility Formation Volume Factor GOR Phase diagram

Viscosity () • • • • •

A measure of resistance to flow Symbols:  o,  g,  w Units: cp Sources: Lab measurements, correlations Range and typical values 0.25 to 10,000 cp, Black oil 0.5 to 1.0 cp, Water 0.012 to 0.035 cp, Gas

Fluid Compressibility (Co, Cg, Cw) • Fractional change in volume due to a unit change in pressure • Symbol: Co, Cg, Cw • Units: psi-1, microsips (1 microsip = 1x10-6 psi-1) • Source: Lab measurements, correlations

OFVF-Bo • The oil formation volume factor, Bo, is defined as the ratio of the volume of oil (plus the gas in solution) at the prevailing reservoir temperature and pressure to the volume of oil at standard conditions. • Bo is always greater than or equal to unity. The oil formation volume factor can be expressed mathematically as:

GOR is different from Gas in Solution (Rs) • GOR is the ratio of all the gas at surface and the oil at surface, while Rs is the ratio of gas in solution in the oil in the reservoir.

The Five Reservoir Fluids

Black Volatile Retrograde Wet Oil Oil Gas Gas

Dry Gas

Phase Diagram - Typical Black Oil

Pressure, psia

Pressure path in reservoir

Critical point

Dewpoint line

Black Oil % Liquid

Separator

Temperature, °F

Phase Diagram of a Typical Volatile Oil Pressure path in reservoir

1

Critical point

2

Pressure

Volatile oil % Liquid

3 Separator

Temperature, °F

Phase Diagram of a Typical Retrograde Gas Pressure path in reservoir 1

Pressure

Retrograde gas

2

Critical point % Liquid

3

Separator

Temperature

Phase Diagram of Typical Dry Gas

Pressure

Pressure path in reservoir 1

Dry gas

% Liquid

2

Separator

Temperature

Volatile Oil

Black Oil

2 Critical point

Dewpoint line

Black Oil % Liquid

Volatile oil

Pressure

Pressure, psia

Pressure path in reservoir

The Five Reservoir Fluids

Critical 1 point

Pressure path in reservoir

% Liquid

3

Separator

Separator

Temperature

Temperature, °F

Pressure path in reservoir

1

Critical point

Wet gas

% Liquid Critical point 3

Separator Temperature

Retrograde Gas

% Liquid

Pressure

1

2

Pressure

Pressure

Retrograde gas

Pressure path in reservoir

Pressure path in reservoir

1

Dry gas

% Liquid 2

Separator

Temperature

Wet Gas

2

Separator Temperature

Dry Gas

Three Gases - What Are the Differences? • Dry gas - gas at surface is same as gas in reservoir. • Wet gas - recombined surface gas and condensate represents gas in reservoir. • Retrograde gas - recombined surface gas and condensate represents the gas in the reservoir But not the total reservoir fluid (retrograde condensate stays in reservoir).

Field Identification

Initial Producing Gas/Liquid Ratio, scf/STB Initial StockTank Liquid Gravity, API Color of StockTank Liquid

Black Oil 3200

Wet Gas > 15,000*

Dry Gas 100,000*

< 45

> 40

> 40

Up to 70

No Liquid

Dark

Colored

Lightly Colored

Water White

No Liquid

*For Engineering Purposes

Exercise 1

Determine reservoir fluid type from field data?

Plot of Exercise 1 Data Producing gas/oil ratio, scf/STB

500 400 300 200 100 0

2

4

6

8

10

Months since start of production

12

Plot of Exercise 1 Data Three-Month Running Average Producing gas/oil ratio, scf/STB

500 400 300 200 100 0

2

4

6

8

10

Months since start of production

12

Exercise 1 Solution Black Oil

Inflow Performance

Objectives • Calculate the IPR for oil wells • Calculate the IPR for gas wells

Fluid Path

Pressure Losses

Pressure drop main components Z h

P



Elevation

After Brown, Technology of Artificial Lift Methods, Vol 4, p. 71

Friction

Acceleration

Ideal Flow Assumptions • • • • • • • •

Ideal well Purely radial flow Infinite reservoir Uniform thickness Stabilized flow Single phase Above bubble point Homogeneous reservoir

Ideal Flow Assumptions • • • • •

Perforations penetrate throughout reservoir Reservoir shape Wellbore clean / uncased No skin Darcy’s law

Non Ideal Flow • • • • • • • •

Departures from Darcy’s law Effects at boundaries Position of well Non homogeneous reservoir Perforation positions High velocities Fluid type / high GOR Relative permeability effects - oil/water/gas near the wellbore • Depletion of reservoir • Flow restrictions (skin)

Inflow Performance Radial Flow

dr

r

re Pwf Pr Pe

Pe = boundary pressure Pwf = well flowing pressure Pr = pressure at r re = drainage radius rw = wellbore radius

Reservoir Capabilities • Darcy’s Law – Liquid flow in Laminar Flow through a permeable medium is described by Darcy’s Law

7.08X 10 3 k h p  p w f  q   re     0.75  s   o Bo  ln   r w    

q = flow rate (STB/day) k = reservoir permeability (md) h = height of the pay zone (ft) P = average reservoir pressure (psi) Pwf = well flowing pressure at the sand face (psi) o = viscosity of the fluid (cp) Bo = formation volume factor (RB/STB) re = drainage radius (ft) rw

= wellbore radius (ft)

Reservoir Capabilities • S = Skin Factor (dimensionless)

 k   ra s    1 ln   rw  ka  where: k = ka = ra = rw =

Permeability of reservoir (md) Permeability of damaged zone (md) Radius of damaged zone (ft) Wellbore radius (ft)

  

Factors Affecting Inflow Performance Principle origins of Skin: • Formation damage (+ve) • Perforations (+ve) • Partial completions/limited entry (+ve) • Gravel pack (+ve) • Non-Darcy flow (+ve) • Multiphase flow (+ve) • Natural fractures (-ve) • Hydraulic fractures (-ve) • Deviated/horizontal wells (-ve)

Well & Reservoir Inflow Performance Factors Affecting PI :

1. Phase behavior •Bubble point pressure •Dew point pressure 2. Relative permeability behavior •Ratio of effective permeability to a particular fluid (oil, gas or water) to the absolute permeability of the rock

Well & Reservoir Inflow Performance 3.Oil viscosity •Viscosity decreases with pressure decrease to Pb •Viscosity increases as gas comes out of solution

4. Oil formation volume factor (Bo) •As pressure is decreased the liquid will expand •As gas comes out of solution oil will shrink

Which Curve? • If a sample of formation fluid (pressurized) is taken and analyzed for bubble point, then the decision can be made of what relationship to use.

Well Productivity Index (PI)

Well Productivity Index (PI) • Pwf > Pb : Q = PI x (Pws - Pwf) – For gas compressible reservoirs: Q = PI x (Pws2 - Pwf2) where, Pws = static reservoir pressure Pwf = flowing bottom-hole pressure Pb = bubble point pressure, Q = flowrate

Productivity Index • A common indicator of liquid reservoir behavior is PI or productivity index

q STB / D / psi J p  p wf

Productivity Index in Terms of Darcy’s Law 3

7.08 X 10 k h J   re   o Bo  ln    0.75  s    rw  

Calculating Flowrate • Using PI, we can calculate flowrate (q) quickly and easily from

q  J ( p  pwf )

Exercise 1 • Given reservoir parameters: k = h = o = Bo = hole size = s =0

30 md 40 ft 0.5 cp 1.2 RB/STB 8 ½ inches

Exercise 1 • Calculate: – J for re = 1,000 ft – q for a drawdown ( p  pwf ) of 750 psi

– q for a drawdown of 1,000 psi – With p = 3,000 psia, calculate q for a complete drawdown (absolute open flow potential).

Multiphase Flow

Multiphase Flow • Bubble point pressure (Pb) – Pressure at which first bubble of gas is released from reservoir oils

Multiphase Flow • Vogel’s Behavior – IPR Curve - Vogel plotted the data using the following dimensionless variables

p wf p

and

q qmax

Vogel Curve 1

0.8

pwf/pr

0.6

0.4

0.2

0 0

0.2

0.4

0.6

q/qmax

0.8

1

Multiphase Flow • Mathematical model for Vogel’s curve

 q    pwf    1  0.2   qmax    p

  pwf   0.8    p

2

    

Finding Vogel qmax 1

0.8

pwf/pr

0.6

0.4

0.2

0 0

0.2

0.4

0.6

0.8

1

q/qmax

1.2

1.4

1.6

1.8

2

Exercise 2 • Reservoir parameters: p = 2,350 psia k

= 140 md

h

= 35 ft

o Bo

= 0.8 cp = 1.25 rbbl/STB

re

= 2,000 ft

rw

= 0.411 ft

pb

= 3,000 psia

s

= 2

Exercise 2 • Calculate J • Calculate qmax

• Construct IPR curve

Fetkovich Equation • Alternative to Vogel’s equation • Empirical correlation q / qmax = [ 1 - ( Pwf / Pr )2 ] n

• The lower the value of n, the greater the degree of turbulence • Also known as “normalized backpressure equation”

Fetkovich IPR

Combination IPR • Vogel IPR Curve: (q/qmax) = 1 – 0.2 (Pwf/P) – 0.8 (Pwf/P)2 • Straight line IPR (q/qmax) = 1 –(Pwf/P) Pwf = bottom hole flowing pressure P = maximum shut-in bottom hole pressure

When the average reservoir pressure is above the bubble point and the flowing bottom hole pressure is below the bubble point, a combined approach using straight line and Vogel will describe the process.

Multiphase Flow • Combination Darcy/Vogel p

Pressure

pb

pwf J pb qb

qmax

1.8

O O

Rate

q

Multiphase Flow • How to find qmax: for q  qb , Darcy' s law applies : q  Jp  p wf       p wf p wf     for q  q then : q  q  q  q 1  0 . 2  0 . 8  b b max b pb   pb  

J pb qmax  qb  1.8

  

2

  

Heterogeneous Formations

Out Flow Performance

Vertical Multiphase Flow Objectives 1. List the 3 components of pressure loss for multiphase flow in vertical pipe. 2. Define liquid holdup. 3. Define and calculate critical rate to remove liquids.

Pressure Loss Components fm  v  m vm dvm dP g   m sin    dZ tot g c 2gc d g c dZ 2 m m

Elevation Friction

Acceleration

System Analysis • Friction losses are controlled by fluid viscosity and geometric factors (pipe diameter and roughness). • In the majority of oil field applications, (i.e. large elevation difference between inlet and outlet with liquids present) the gravitational component normally accounts for around 90% of the overall head loss. • Therefore, the total pressure drop function is not particularly sensitive to the value of the friction loss coefficient. • The acceleration component is usually small except in systems involving fluid expansion.

Pressure Loss in Inclined Pipe

h



Tubing Friction

Tubing Friction

Tubing Friction

Heat Transfer

Slippage Phenomena • The gas phase moves at a faster velocity than the liquid phase due to buoyancy forces. • Consequence is a change in the areas of each phase in an element. • The slip corrected liquid area is termed LIQUID HOLDUP. • Correction from phase volumes to holdup volumes through multi-phase correlations.

Annular Flow • Gas slippage tends to be decreased in the annular ring (as compared with a circular tubing of the same cross-sectional area) because of the decrease in the distance between wall faces.

• Under certain circumstances, the annulus between the casing and a tubing is a more efficient educator for the oil and gas than the tubing itself.

Liquid Holdup

Vg

VL

VL HL  VL  Vg

m  H L L  1  H L  g

Liquid Holdup

Slip and no-slip flows

Effects of phase slippage Uphill vG

v

Downhill

v

qG = vG AG

L

vG L

qL = vL AL

vL < vG H

L

> 

L

vL

>

vG

H


d1

INFLOW IPR

OUTFLOW

0 0

FLOWRATE, Q

Effect of Tubing size on Outflow

FLOW RATE, Q

FINDING OPTIMUM TUBING SIZE Effect of Tubing size on Outflow

UNSTABLE REGION DIAMETER FOR MAXIMUM FLOW RATE

TUBING DIAMETER, d

Effect of Tubing size on Outflow

Effect of Minimizing Flow Restrictionsin Reservoir & Tubing d1 BOTTOMOLE FLOWING PRESSURE, Pwf

Pr

2* WELL WITHOUT SKIN EFFECT

1

2 WELL WITH SKIN EFFECT

2** 0 0

PRODUCTION INCREASE

FLOW RATE, Q

d2>d1

Pr

Excessive GLR

Inflow Performance IPR

LIQUID PRODUCTION RATE, QL

(a) Gas lift well analysis

LIQUID PRODUCTION RATE, QL

BOTTOM HOLE FLOWING PRESSURE, Pwf

Gas Lift Well Performance Maximum liquid production

Available gas volume

Economic Optimum

GAS INJECTION RATE, Qgi

(b) Effect of gas injection rate

Effect of Water cut %

Effect of Water cut %

Effect of Water cut %

Effect of Tubing size & skin

BOTTOM HOLE FLOWING PRESSURE, Pwf

Well Restricted by Piping System & Near Wellbore Skin Effect Pr OUTFLOW

2

1 4

3

0 0 FLOW RATE, Q

INFLOW

Effect of Perforation Density on Inflow

BOTTOMHOLE FLOWING PRESSURE, Pwf

N = NUMBER OF PERFORATIONS PER FOOT

Pr

INFLOW OUTFLOW

N3>N2

N1

N2>N1

0 0 FLOWRATE, Q

Effect of Perforation Density on Inflow

Effect of Perforation Diamtere on Inflow

FLOWRATE, Q

Effect of Perforation Density on Flow Rate

NUMBER OF PERFORATIONS PER FOOT, N

Effect of Well Head Pressure on Inflow

Procedures for Nodal Analysis Application 1. Determine which components in the system can be changed. 2. Select one component to be optimized. 3. Select the node location. 4. Develop expressions for the inflow and outflow. 5. Obtain required data to calculate the pressure drop versus flow rate fall components.

Procedures for Nodal Analysis Application 6. Determine the effect of changing the characteristics of the selected component by plotting inflow versus outflow and read in the intersection. 7. Repeat the procedure for each component that is to be optimized.

Case History

Nodal Analysis Focused on Artificial Lift

BOTTOMHOLE FLOWING PRESSURE, Pwf

GAS LIFT

Pr ELECTRICAL SUBMERSIBLE PUMP (ESP)

1

BUBBLE PRESSURE

Pb Pwf

2

0 0

PRODUCTION INCREASE

FLOW RATE, Q

ESP Failed Due To Excessive Gas Rate Pwf Simulation settings > Erosion/Corrosion and confirm that the API 14e erosion model is selected and the default Erosional velocity constant (C value) of 100 is being used. 3. Run the Network Simulation task. 4. Go to Profile results tab and change the Y-axis variable to display Erosion velocity ratio. The erosional velocity ratio (EVR) is calculated as below.

Screen the Network for Erosion Issues

• If EVR > 1, there is an erosion risk.

Screen the Network for Erosion Issues • Identify the branches where the EVR exceeds one and compare them to the answers below: • Branches where EVR > 1 Well_1, Well_2 & Well_3 and connected flowlines WFL-1, WFL-2 & WFL-3 respectively

Screen the Network for Erosion Issues • Why do these specific branches have the highest EVR? • (These are the well branches. They have the highest flowing temperatures, hence highest fluid velocities).

Tips for large network models • •

•

Try to split the model into smaller networks, which can be solved independently, before linking them all together. (This helps trouble-shooting of the model) When first building the model, leave out equipment such as compressors and separators, then build them in one at a time. (Again this helps troubleshooting) Build all well models and branches containing equipment items in PIPESIM first. Run some sensitivity analyses to check they are behaving as expected.

Tips for large network models •

Try to avoid unnecessary nodes in a network, this increases the computing time required to solve the network.

•

If the program crashes part way through an iteration with file open errors, this is due to the processor running out of memory. The model can simply be restarted and the program will start from where it left off.

New Versions

New Version-2015 • The gas lift design and the flow correlation option were included again. • Has some new features like the perforation design.

New Version-2015

New Version-2015

New Version-2015

New Version-2015

New Version-2015

New Version-2015

New Version-2015

New Version-2015

New Version-2015

Thank You