well unloading technologies and selection criteria - … · eni s.p.a. upstream & technical...

eni s.p.a.upstream & technical services

2013-2014 Master in Petroleum Engineering and Operations

Well Unloading Technologies and Selection Criteria

Author: Agozie Amadi Prince

San Donato Milanese 13-14-15 October 2014

eni s.p.a. upstream & technical

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Stage SubjectWell Unloading Technologies and Selection

Criteria


Author

Agozie Amadi Prince

Division eni S.p.A.

Upstream & Technical Services

Dept. TEOP

Company Tutors

Elisa di Biase

Salvatore Privitera

University Tutor

Prof. Francesca Verga

Master in Petr.Engineering & Operations 2013-2014


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� Project Scope

� Theoretical concepts

� Well Unloading Technologies description

� Well Unloading Selection Criteria

� Conclusions

List of Content


Criteria


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Project Scope

� Main activities for the scope� Physical mechanisms literature review� Technologies evaluation and comparison� Selection guidelines

� Industrial Impact and Expected BenefitsEnsure the gas production and extend the life of wells affected by liquid accumulation

� Current technology statusIndustry is using different methods in order to mitigate the liquid loading effects (i.e. foamer, velocity string, wellhead compressor, plunger)

� Technical Motivation

Manage the liquid accumulation (water and/or condensate) in

order to ensure the gas production


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� Project Scope




� Conclusions

List of Content


Criteria


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Theoretical conceptsWhat is liquid loading

A well is suffering from liquid loading when its gas production rate has fallensharply off its intended decline curve and remains there due to theaccumulation of water or condensate at bottom of the wellbore

Drawbacks

� Unexpected mechanical stress (slug flow)

� Corrosion

� Early well abandonment

� Production decrease

� Revenue falling

� Cost rising

ITALY TOTAL RECOVERED PRODUCTION ~ 500 kSm3/day (3.2 kboed, 100 k€/d)


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Theoretical conceptsIdentification of liquid loading

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Diagnostic actions

� Water sources

� Associated Water

� Water Produced from Another Zone

� Aquifer water

� Casing leak

� Water coning

� Condensate sources

� Retrograde condensation

How to identify liquid loading

Theoretical models

Monitoring actions

Critical velocityWell performance analysis

Production parameters analysis Well history review

P/T surveysSurface / Downhole samplingOther investigations (i.e. Logs)


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� Project Scope




� Conclusions

8

List of Content


Criteria


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� Artificially Liquid Lifting

Well Unloading Technologies description

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� Foamer Applications

� Velocity String

� Wellhead Compression

� Downhole pumps (rod, PCP, ESP)

� Reducing surface tension between gas & liquid, and also the liquid density

� Increasing gas velocity by reducing the tubing flowing section

� Increasing gas velocity by reducing wellhead pressure

� Intermittent production � Cycles of re-pressurizations

� Plunger lift

Techniques applied by eni

Gas wells Unloading techniques Worldwide

� Gas lift � Reducing liquid density


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Well Unloading Technologies descriptionFoamer applications

Foam preferentially adsorbs at the interface, lowering the surface tension between fluids (liquid and gas) and liquid density

+ foamer

CONS

� Cheap to apply

� Tolerance of particulates

� Versatile for different completions and environments

PROS

� Surfactant used may cause emulsion problems

� Wells with higher condensate may not foam well.

( )2

1

g

41

gL4

1

gρ

ρρσ1.92V

−=

Turner equation


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Well Unloading Technologies descriptionFoamer selection & treatments

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� Fluid compositions

� WCR

� Specific gravity

� Reservoir conditions (P&T)

� Lab tests

� Reactivity (height of foam)

� Foam Stability (Half-time)

� Compatibility with fluids

� Compatibility with treating equipment

� Foam breaker (Defoamer selection)

Foamer selection Injection treatments

� Dropping soap sticks down the tubing

� Batch treatments

� Continuous Injection via Capillary String

� Continuous Injection via Production annulus

� Combined treatments

Capillary injection

Batch injection


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Well Unloading Technologies descriptionVelocity string

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Velocity string can be defined as the installation of a wellbore tubular (usually from 1” to 3-1/2” in diameter) to modify the hydraulic characterization of an existing completion tubing

Evaluation of the best tubing size by Well Performance

Analysis in order to:

� Maximize velocity (v > vT)

� Minimize pressure losses

� CT velocity string

� Through tbg. installation

� Tubing replacement

� Higher velocities for a given rate

� Medium-long term solution

� Good in tight gas reservoir

PROS CONS

� Requires special tools

� High costs

� Further loading will be more severe than original

2 3/8” ODNo Loading, low frictions

1 11/16” ODNo Loading, high

frictions

2 7/8” ODLoading, low frictions

OPTIMUM SOLUTION


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Well Unloading Technologies descriptionWellhead Compressor

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Used to lower the wellhead pressure to increase gas velocity, even lower than flowline back pressure

CONS

� Reduction of the THP and BHP (drawdown increase)

� Increasing & stabilization of production rate

� Wide operating range

PROS� Surface modifications needed

� Maximum liquid production to be tolerated

� Not compatible with solid production and corrosive fluids

� Not suggested for low productivity wells

Sensitivities on

WHP reduction to define

� WHC characteristics (type, size)

� Energy needed

� Surface modifications


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Well Unloading Technologies descriptionPlunger lift

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Plunger lift system is an intermittent lift method that uses only theenergy of the reservoir to produce the liquids.

M O TO R IZ EDVA L VE

E LE CTR O N ICC O N TR O LLE R

LU B R ICA T O R

FL O W TEEW /O -RI NG

B LE ED

VA L VE

C A TC H E RW /A R R IV A LSE N S O R

EX T ER N ALC A B LE

M A ST ERVA L VE

B U MP ER SP R IN G

PLU N G ER

B YP A S SVA L VE

TU B IN G STO P

Conventional Continuous

� It is a rig-less operation

� Cheap to apply & maintain

� Requires no outside energy source

PROS

CONS

� Not efficient in solid production wells

� Limited by GLR, cannot work in low GLR wells

� Not efficient in highly deviated and horizontal well

M O TO R IZ EDVA L VE

E LE CTR O N ICC O N TR O LLE R

LU B R I CA T O R

FL O W TEEW / O -RI NG

B L E E D

V A L V E

C A TC H E RW /AR R IV A LSE N S O R

E X T E RN ALC A B LE

M AS T E RVA L VE

B U MP ER SP R IN G

PL UN G ER

B YP A S SVA L VE

TU B I N G STO P

or


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¼” OD Capillary injection

Well Unloading Technologies descriptionFoamers application Case histories (water)

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Benefit duration = 1 yr

Cost ~ 80 k€Total Income ~ 1000 k€

POT = 1 month

Batch injectionPRE POST

Gas rate (kSm3/d) 5 15

Liq rate (m3/d) 0.1 0.4

PRE POST

Gas rate (kSm3/d) 0 25

Liq rate (m3/d) 0 0.6

Benefit duration = 2.5 yrs


POT = 1 month


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Well Unloading Technologies descriptionWellhead Compressor Case Histories (water)

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10 installations in Italy since 2013

PRE POST

Gas rate (kSm3/d) 5* 18

Liq rate (m3/d) 0.8 1.5

* Cyclic production

Benefit duration = 1.5 yr (on going)

Cost ~ 300 k€Total Income (till now) ~ 1600 k€

POT = 2.5 month

Well A


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Well Unloading Technologies descriptionPlunger lift case histories (condensates)

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M O TO R IZEDVA LVE

E LE CTR O N ICC O N TR O LL E R

LU B R ICA T O R

FL O W TEEW /O -RI NG

B LE ED

VA L VE

C A TC HE RW /A R R IV A LSE N S OR

EX T ER N ALC A B LE

M A ST ERVA L VE

B U MP ER SP R ING

PLU N GE R

B YP A S SVA L VE

TU B IN G STO P

PRE POST

Gas rate (kSm3/d) 1 2.5

Liq rate (m3/d) 4 6

Benefit duration = 1 yr


POT = 2 months

Well APlunger lift Installed


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� Project Scope




� Conclusions

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List of Content


Criteria


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Well Unloading selection criteria

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Technical Evaluation

EconomicEvaluation

FINAL SELECTION

Constraints� HSE

� Logistic issues

� Authorizations

CAPEX, OPEXIncome, POT, ROI


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Well Unloading selection criteriaTechnical evaluation matrix

Velocity String Plunger LiftWellhead

CompressionFoamer Batch

Foamer

via Capillary

No corrosive fluids

Actual tubing > 2 3/8" OD

Deviation < 3°/100ft

Uniform Tubing size

No solid production

Gas rate < 350kScf/d

GLR ≥ 400 Scf/bbl/1000ft

Liquid rate < 350bbl/d

No corrosive fluids

No solid production

Gas rate < 700-875kScf/d

Liquid rate < 20 bbl/d

(without surface

modifications)

No corrosive fluids

Deviation < 12°/100ft

GLR range: 1000-8000 scf/bbl

Liquid rate range: 5-100 bbl/d

GLR range: 1000-8000 scf/bbl

Liquid rate range: 5-100 bbl/d

No corrosive fluids

Only Water 2 1 2 1 2

Only Condensate 2 2 2 0 0

Water +

Condensate2 1 2 1 1

High Reservoir

Pressure4 1 2 2 3

Low Reservoir

Pressure0 3 4 2 3

Low Permeability 3 1 1 1 1

High Reservoir

temperature2 1 2 1 1

Deep well (>

10,000 ft)3 3 3 1 2

Large Tubing 4 2 3 1 2

Small Tubing 0 2 4 2 3

Restrictions in

tubing2 1 3 2 3

3 1 1 4 2

sporadic continuous continuous none regular

Technical constaints

Liquid type

Reservoir

Parameters

Well/Completion

Parameters

Ranking

factors

ManagementMaintenance

frequency


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Well Unloading selection criteriaEconomic evaluation table

Cost = average CAPEX + OPEX for Italy

* Gas price assumed equal to 0.17 €/Sm3

Low cost Short-term benefit

High cost Long-term benefit

Approach

Cost, k€

Typical Benefit

duration,

monthsDelta prod

5 kSm3/d

Delta prod

15

kSm3/d

Delta prod

5 kSm3/d

Delta prod

15 kSm3/d

Delta prod

5 kSm3/d

Delta prod

15 kSm3/d

Batch 80 6 3.1 1.0 153 459 1.9 5.7

Capillary String 250 36 9.8 3.3 918 2754 3.7 11.0

Plunger 100 24 3.9 1.3 612 1836 6.1 18.4

WHC 300 48 11.8 3.9 1224 3672 4.1 12.2

POT (months) Income (k€) ROI

Velocity string not included; cost varies depending on the installation operation


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� Project Scope




� Conclusions

List of Content


Criteria


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� HSE and Logistics constraints have to be always taken into accountduring the selection process

� A proper understanding of the liquid accumulation problem and itsimpact is fundamental to design the most suitable unloadingtechnique

� The most suitable unloading technique to be applied must bechosen after proper technical and economic evaluations

Conclusions

� Nowadays, gas well loading impactis becoming more and moreimportant when dealing withmature & depleted gas fields


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Acknowledgements

I would thank eni for permission to present this work

and related results and TEOP colleagues for the

technical support and needed assistance.



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