149655073-nodal-analysis.ppt

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

How Wells Flow

Basic Well Schematic Annulus flow control valve

Casing

Tubing Annulus Packer

Reservoir

Annulus head pressure (AHP) Tubing flow control valve Tubing head Pressure (THP)

How Wells Flow Fundamental Rules THP

AHP

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

Pbh

Pres

Note: BHP is the more common acronym for “Bottom Hole Pressure”

How Wells Flow Fundamental Rules THP

AHP

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 Pbh

Pres

How Wells Flow Pressure – Depth Diagram Pressure THP

AHP

SITHP

In reality: The reservoir pressure dictates the shut-in THP

SITHP = Pressure - Fluid column hydrostat head For flowing well simulations: Depth

• Split the system at the reservoir / wellbore interface

• Predict wellbore pressures from surface down

Pbh

Pres

Pbh = Pres

How Wells Flow Pressure – Depth Diagram Pressure THP

AHP

SITHP

If we open the tubing flow control valve: …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

D e p t h

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

Pbh

Pres

Pbh = Pres

How Wells Flow Pressure – Depth Diagram Pressure THP

AHP

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)

D e p t h

Pbh

Pres

• Free gas fraction function of pressure / temp)

Pbh

Pres

(a

How Wells Flow Quantifying Well Flow Performance For a given: • Fluid composition • FTHP • Tubing geometry Depth

Q1 2

3

We can predict the FBHP at a number of production rates Q1, 2 and 3.

Pressure

Q1

We can then plot FBHP vs Rate.

Rate

2 3

This is known as the Tubing Performance Curve (TPC) or Vertical Lift Performance (VLP)

Production rate, STB/D

Flowing bottom hole pressure, psi

Production rate, STB/D

Flowing bottom hole pressure, psi

Production rate, STB/D

Flowing bottom hole pressure, psi

Production rate, STB/D

Flowing wellhead pressure, psi

Flow Rate

Absolute Permeability Relative Permeability

Viscosity Net Pay Thickness Drainage Area

Drainage Area Shape Location of Wellbore

How Wells Flow Quantifying Well Flow Performance

Tubing Performance Curve (TPC)

FBHP

PRes

Inflow Performance Relationship (IPR)

SOLUTION POINT – WELL WILL PRODUCE AT THIS RATE

Rate

How Wells Flow Quantifying Well Flow Performance

Impact of Reducing FTHP Decrease THP by opening choke or reducing Psep

FBHP

PRes

PRODUCTION BENEFIT FROM REDUCING FTHP

Rate

IPR

How Wells Flow Quantifying Well Flow Performance

Tubing Size Changes If the tubing size is increased for the same: • Range of production rates • Fluid types • FTHP

Depth

Q1 2 3 Pressure

Q1 Rate

We can predict a different set of FBHP’s

2

We can then plot FBHP vs rate, and get a new tubing performance curve.

3

How Wells Flow Quantifying Well Flow Performance

Impact of Increasing Tubing Size 3 / ” tubing 1

2

5 1/2” tubing

FBHP

P Res

IPR PRODUCTION BENEFIT FROM INCREASING TUBING SIZE

Q (3 1/2”)

Q (5 1/2”) Rate

How Wells Flow Quantifying Well Flow Performance

Impact of stimulation to reduce skin TPC

P Res

FBHP

Improved IPR (SKIN = 0)

IPR (SKIN = 10) PRODUCTION BENEFIT FROM REDUCING SKIN

Rate

Summary Nodal Analysis Basic Concepts •

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

•

Inflow Performance is governed by: • • • •

•

Vertical Lift 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)

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

Flow rate

Net pay thickness Perforated interval Shot density Horizontal permeability Vertical permeability Drilling fluid damage Viscosity

References

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.