427625623-Nodal-Analysis-Presentation.ppt
- 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
- 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
- 16. Flow Rate Absolute Permeability Relative Permeability Viscosity Net Pay Thickness Drainage Area Drainage Area Shape Location of Wellbore
- 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