Predicting the gains for European wells - · PDF fileExample cycle: Slug size 0.05 t [s]] Casing top Casing bottom Avg BHP - dyn P c,max ... Liquid hold-up in pipelines, severe slugging,

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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Joint Industry Project

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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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Joint Industry Project

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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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Joint Industry Project

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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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Joint Industry Project

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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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Joint Industry Project

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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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Joint Industry Project

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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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Joint Industry Project

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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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Joint Industry Project

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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)

May 02, 2012

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Joint Industry Project

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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

8

10

12

14

16

18

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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Joint Industry Project

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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

May 02, 2012

Wouter Schiferli

Joint Industry Project

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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

May 02, 2012

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Joint Industry Project

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Presenter details

Wouter Schiferli

TNO

Fluid Dynamics Department, Delft, NL

T: 088-8666488

E: [email protected]

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Joint Industry Project

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