Predicting the gains for European wells - · PDF fileExample cycle: Slug size 0.05 t [s]]...
Transcript of Predicting the gains for European wells - · PDF fileExample cycle: Slug size 0.05 t [s]]...
Joint Industry Project on Deliquification
Predicting the gains for European wells
Wouter Schiferli Jordy de Boer Erik Nennie
Project structure and goals
Overall goal:
Transfer US knowledge on deliquification to Europe
Three phases:
1. Literature search
What techniques are applied, and how widely
Many common techniques in the US are not applied in Europe
2. Engineering guidelines to predict most suitable technology
Implemented as Excel-based tool
3. Quantitative tool
Calculate benefits of various technologies
Can serve as input to economic screening process
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Need for quantitative analysis
Selection methodology yields candidate technologies
Based on well depth, deviation, LGR, etc…
Actual deployment decision is a balance between:
Production and UR gain over time
CAPEX/OPEX
TNO’s expertise lies in modelling
Models were implement for a range of techniques
Implemented in a GUI for quick screening
Calculates modified production profile after implementing each
technology
CAPEX/OPEX analysis left to operator
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Technologies included in the tool
Allow the operator to evaluate the benefit of using
Velocity string
Foam
Wellhead compression
Eductor
Performance measured by
Ultimate recovery / abandonment pressure
Production profile and required power over time
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ESP
Plunger
Gas lift
Methodology
Basic wellbore and reservoir model required
Wellbore model calculates BHP
Reservoir model
Simulates depletion
Includes reservoir pressure drop
Semi-steady state models describing each technique
Goal: translate technique to modified well lift performance
Reservoir model is not modified
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Wellbore modelling
Correlation required to calculate wellbore dp
Deviated wells
Variable diameter
Many correlations are proprietary, choice was limited
Gray standard Gray does not handle deviated wells
Beggs and Brill universal
OLGA ss proprietary
Beggs and Brill was chosen
Good match with OLGA
Inclinations from horizontal to vertical
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Reservoir modelling
Tank (material balance model):
With re reservoir drainage radius, and ϕ porosity
Pressure drop is modelled using A and F factors:
A, F can be calculated from reservoir parameters
Ideally should be known from well tests
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Base modelling method
Beggs and Brill: tubing TPC at constant WHP
Reservoir IPR calculated, including depletion
Operation point continuously calculated
Loading occurs at TPC minimum
End of production
Yields abandonment pressure
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BH
P
Gas flow
Depletion
Tubing TPC
Loading
WHP
Line P Choke
assumed
open
Modelling mitigation measures
Mitigations modelled in different ways
Completion (diameter) change:
Velocity string
Tailpipe
Change in boundary condition:
Eductor: performance diagrams
Wellhead compression: simplified analytical model
Other models:
Gas lift – BHP is minimized, staying within available power
ESP – liquids are produced by pump through separate string
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V string
loading
BH
P
Gas prod
Tubing TPC
Tubing loading
V string TPC
Modelling: foamer
Assumed to be added continuously
Start-up not taken into account
Cap-string type of application
Foaming mechanism is complex
Reduction in surface tension
Reduces critical rate to 75% of original rate
Foam formation
Increases gas-liquid surface area
Reduced density, improved liquid transport
Further reduction in critical rate to 50% or less
Full modelling not feasible
Reduction in critical rate is input to the tool
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WHP
Line P Choke
assumed
open
Modelling: plunger lift
Most effective in smaller tubing (up to 3.5”)
Usually requires installation of new tubing
Most effective when annulus pressure buildup possible
Low-set downhole packer is unfavourable
Production is first assumed to occur through small string
When close to loading, plunger installed (see below)
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Line P Choke
assumed
open
WHP
Plunger “TPC”
BH
P
Gas prod
Tubing TPC
Tubing loading
Smaller string TPC
Lea plunger lift model (1999)
Method developed to compare plunger to velocity strings
Calculates a “TPC” for the plunger lift system
Assumptions:
Gas influx constant throughout cycle
Plunger rise velocity 5 m/s
No slip past plunger
Based on modified Foss-Gaul guidelines
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0 1000 2000 3000 4000 5000 60006
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10
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Example cycle: Slug size 0.05
t [s]P
[b
ar]
Casing top
Casing bottom
Avg BHP - dyn
P c,max
P c,min
Buildup Rise Blow
down Final flow
Tool output for 4.5” deviated well
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0 5 10 15 20 250
100
200
300
400
500
600
700
800
900
1000
Time [yr]
Cum
ula
tive g
as p
roductio
n [10
6 N
m3]
Cumulative gas production
No mitigation
Velocity string
WHC
Foam
Eductor
ESP
Gaslift
Conclusions
Tool was developed to predict performance of mitigation measures
Based on (semi) steady state models
Beggs & Brill pressure drop correlation
Reservoir depletion and pressure drop
Compressor, pump and eductor models
Simplified plunger and foam modelling
Performance was considered realistic for most wells
Beggs & Brill seems less suitable for specific cases
LGR >> 100
Larger diameter wells (>4”)
May be solved by implementing different correlations
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Outlook for a follow-up programme
Better match in cases where current models are unreliable
Further validation against field trials
Integrating other common pressure drop correlations
Adding additional functionality
Improved pseudo-pressure reservoir model
Better modelling of first phase of production (e.g. by including a
choke model)
Intermittent production requires more advanced modelling
Coupled dynamic well and reservoir model
Models available, but not readily integrated in fast tool
We are looking for participants to a second phase of this JIP
Conditions will be discussed with current participants
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Flow Assurance Course for Flowlines and Wells
Date: April 14 – 17, 2013
Location: TNO, Delft
Fundamentals of multiphase flow in flowlines and wellbores
Practical Flow Assurance
Multiphase dynamics: liquid loading, slug flow
Solid deposition, integrity, heavy oil
Well control, reservoir inflow
Exercises
Liquid hold-up in pipelines, severe slugging, slug catcher sizing, etc.
Presenters:
Prof. René Oliemans (Emeritus, TU Delft)
Prof. Ruud Henkes (TU Delft / Shell Global Solutions)
TNO Fluid Dynamics
To keep updated, contact presenter
More details and registration at www.tno.nl/FAcourse2013
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Presenter details
Wouter Schiferli
TNO
Fluid Dynamics Department, Delft, NL
T: 088-8666488
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