1. 1. Explain the concept of Nodal Analysis
2. List 4 segments in the reservoir/well system where pressure
loss occurs.
3. Define the following terms: inflow performance curve,
outflow performance curve, system graph, solution node
2.
3. Basic Well Schematic
Reservoir
Casing
Tubing flow control valve
Annulus head pressure (AHP)
Annulus flow control valve
Tubing
Packer
Tubing head Pressure (THP)
Annulus
How Wells Flow
4. AHP
Pres
Pbh
THP
Rule 1
• Fluid flows in direction of reducing pressure
– If Pbh < Pres fluid will flow from the reservoir > well
• Pressure difference between reservoir > well
– Known as the drawdown
Fundamental Rules
How Wells Flow
Note: BHP is the more common acronym for
“Bottom Hole Pressure”
5. Pres
Pbh
THP AHP
Fundamental Rules
How Wells Flow
There will be a pressure difference (Hydrostatic Head)
between two points in a static fluid column.
dP = Density of fluid (psi / ft) height between points (ft)
If we know the THP and fluid density:
• Can calculate static pressure at any depth
• Plot on a Pressure vs Depth diagram
6. Pres
Pbh
THP AHP
Pressure
Pbh = Pres
SITHP
In reality:
The reservoir pressure dictates
the shut-in THP
For flowing well simulations:
• Split the system at the reservoir /
wellbore interface
• Predict wellbore pressures from
surface down
Pressure – Depth Diagram
How Wells Flow
Depth
SITHP = Pressure - Fluid column hydrostat
head
7. Pres
Pbh
THP AHP
Pressure
D
e
p
t
h
Pbh = Pres
SITHP
…and if the pressure in the flowline /
vessel downstream < SITHP.
• Since fluid flows in the direction of
reducing pressure
• Well fluids will flow into the
flowline
If we assume the pressure difference between the
wellhead and the bottom hole is constant
• Pbh will fall
• fluid will flow continuously from the reservoir to
the wellbore
Pressure – Depth Diagram
How Wells Flow
If we open the tubing flow control valve:
8. Pres
Pbh
THP AHP
Pressure
D
e
p
t
h
Pbh Pres
SITHP Once the well starts to flow the pressure
difference between the wellhead and the
bottom hole will not be constant.
It changes due to:
• Fluid friction ( a function of rate)
• Free gas fraction (a
function of pressure / temp)
Pressure – Depth Diagram
How Wells Flow
9. Depth
Pressure
For a given:
• Fluid composition
• FTHP
• Tubing geometry
We can predict the FBHP at a number
of production rates Q1, 2 and 3.
Rate
We can then plot FBHP vs Rate.
This is known as the Tubing
Performance Curve (TPC) or Vertical
Lift Performance (VLP)
Q
1
2
3
Quantifying Well Flow Performance
How Wells Flow
Q1 2 3
17. SOLUTION POINT – WELL WILL PRODUCE AT THIS RATE
Inflow Performance Relationship (IPR)
PRes
Quantifying Well Flow Performance
How Wells Flow
Tubing Performance Curve (TPC)
Rate
FBHP
18. Impact of
Reducing FTHP
PRODUCTION BENEFIT FROM REDUCING FTHP
Quantifying Well Flow Performance
How Wells Flow
IPR
PRes
Decrease THP by opening
choke or reducing Psep
Rate
FBHP
19. Q1 2 3
We can then plot FBHP vs rate, and
get a new tubing performance curve.
Depth
Pressure
Rate
Q
1
2
3
If the tubing size is increased
for the same:
• Range of production rates
• Fluid types
• FTHP
We can predict a different set of
FBHP’s
Quantifying Well Flow Performance
How Wells Flow
Tubing Size
Changes
20. 3 1/2” tubing
IPR
P Res
PRODUCTION BENEFIT FROM INCREASING TUBING SIZE
Impact of Increasing
Tubing Size
Quantifying Well Flow Performance
How Wells Flow
5 1/2” tubing
Q (3 1/2”) Q (5 1/2”)
Rate
FBHP
21. FBHP
IPR (SKIN = 10)
P Res
PRODUCTION BENEFIT FROM REDUCING SKIN
Improved IPR
(SKIN = 0)
TPC
How Wells Flow
Quantifying Well Flow Performance
Impact of stimulation to
reduce skin
Rate
22. • Wells flow in the direction of reducing pressure Q = P x PI
– Critical to understand reservoir and well pressure gradients
– Affected by rate, pressure and temperature
– Well flow performance is depicted on inflow / out flow plots
Summary
Nodal Analysis Basic Concepts
• Inflow Performance is governed by:
• Reservoir pressure
• Reservoir quality (permeability and thickness of payzone)
• Completion efficiency (or skin)
• Relative permeability (change in permeability as water production starts)
• Vertical Lift Performance is governed by:
• Tubing head pressure
• Tubing size
• Fluid properties (GOR, gravity, viscosity)
• Well depth
• Artificial Lift determines the maximum well potential
• different levels of drawdown achieved depending upon method employed
23. Flow rate
Net pay thickness
Perforated interval
Shot density
Horizontal permeability
Vertical permeability
Drilling fluid damage
Viscosity
24. 1. Mach, Joe, Proano, Eduardo, and Brown, Kermit E.: "A Nodal Approach
for Applying Systems Analysis to the Flowing and Artificial Lift Oil or Gas
Well," paper SPE 8025, 1979.
References
