[PPT] - Liquid Loading mitigation: the right method for the right well at PowerPoint Presentation

SLIDE 1

Gas Well De-Liquification Workshop

Adams Mark Hotel, Denver, Colorado March 5 - 7, 2007

Liquid Loading mitigation: the right method for the right well at the right time

Ewout Biezen, Chad Wittfeld, Gert de Vries, Dick Klompsma, Vincent Hugonet, Gerrit de Jong, Stathis Kitsios, Rob Smeenk (NAM)

SLIDE 2

Mar. 5 - 7, 2007

2007 Gas Well De-Liquification Workshop Denver, Colorado 2

Tail-end production management

LL affects ~125 million scf/d in the NAM onshore Netherlands area
Deliquification gains 2006: 3.5 billion scf

Production Time Typical gas well Production profile

Intermittent production

Traditional production enhancement activities e.g. re-perf, stimulations

Onset of liquid loading

Improved diagnostics for detecting or predicting onset of liquid loading Non-traditional production enhancement activities, e.g. foam lifting, velocity/insert strings, mobile wellhead compression, etc

Optimise

Aspiration

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Mar. 5 - 7, 2007

2007 Gas Well De-Liquification Workshop Denver, Colorado 3

Typical Well Information NAM

Mostly 3 ½” tubing, some 5” or even 7”
Varying liner sizes – 4 ½”, 7”, 9 5/8”
Subsurface safety valve legal requirement
Liquid loaded production ranges from 0.3–7 million scf/d
Varying perforated interval length: 120 ft – 900 ft gross
Mixture of sandstones and fractured carbonates
Depths of 3,500 – 12,000 ft
Some H2S
High-cost environment

SLIDE 4

Mar. 5 - 7, 2007

2007 Gas Well De-Liquification Workshop Denver, Colorado 4

NAM: Current deliquification and candidate selection methods

Batch foam – 60 wells, 700 jobs
Continuous foam – 6 installations, 6 more in progress
Velocity strings, tail-end extensions – 10 running, 5

planned in 2007

Plunger lifting – working first implementation in 2007
Mobile wellhead compression – start 2008

Candidate selection:

– Batch foam – Acoustic logging, FPGs (dynamic liquid level determination) – WGR measurements (well fluid sampling) – In/outflow modeling – Economics based on long-term (4 yr) production forecast

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Mar. 5 - 7, 2007

2007 Gas Well De-Liquification Workshop Denver, Colorado 5

Foam – Candidate Selection

Several methods currently being used to select wells for continuous foam application:

Batch foam success

– Convert if it makes economic sense to go from batch to continuous

Fluid sampling and foam testing on well fluids

– Can be very difficult to obtain good samples that are not corrupted with things such as

Flow from other wells (different reservoirs)
Condensate based corrosion inhibition chemicals

– Higher strength foamers being tested for areas with more condensate

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Mar. 5 - 7, 2007

2007 Gas Well De-Liquification Workshop Denver, Colorado 6

Candidate selection: Batch foam 60 wells, 700 jobs

Successful: Clear improvement
Inconclusive: Cannot conclude

either way (more BF jobs)

Not successful: No difference

with or without foam

Not applicable (inflow impaired,

e.g. HUD or reservoir problem)

Decide on conversion (has to

make economic sense)

48% Successful 33% Inconclusive 19% Not successful

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Mar. 5 - 7, 2007

2007 Gas Well De-Liquification Workshop Denver, Colorado 7

0.5 1 1.5 2 2.5 3 3.5 29-Nov-05 13-Dec-05 27-Dec-05 10-Jan-06 24-Jan-06 Flow rate [1e6 scf/d] 100 200 300 400 500 600 FTHP [psi] Flow rate Batch Foam FTHP

Candidate selection: Batch foam results COV-40

Lab foam testing on well fluids
Batch foam trials
In/outflow modeling
Economic evaluation
Continuous foam candidate

Foam stability (foam collaps time) COV-40 at 90 °C (3,2 % dose rate) with 10 and 30% condensate (liq vol intake 160 ml)

150.0 250.0 350.0 450.0 550.0 650.0 Minutes

Foam height in ml

1 5 3 10

0 min 1 min 3 min 5 min 10 min

Loaded Unloaded

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Mar. 5 - 7, 2007

2007 Gas Well De-Liquification Workshop Denver, Colorado 8

5 10 15 20 25 30

12-Oct-06 22-Oct-06 1-Nov-06 11-Nov-06 21-Nov-06 1-Dec-06 11-Dec-06 21-Dec-06 31-Dec-06

Gas Production [MMscf/day]

250 500 750 1,000 1,250 1,500

FTHP [psi]

Flow rate THP Batch foam

Difficult well to kick off: ANJ-2

Candidate selection: Batch foam results ANJ-2

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Mar. 5 - 7, 2007

2007 Gas Well De-Liquification Workshop Denver, Colorado 9 1 2 3 4 5 6 7 8 9 10 29-Nov-06 04-Dec-06 09-Dec-06 14-Dec-06 19-Dec-06 24-Dec-06 29-Dec-06

Gas Production [MMscf/day]

100 200 300 400 500 600 700 800 900 1000

FTHP [psi]; Foam injection rate [l/day]

Flow rate FTHP Foam injection rate

Continuous foam: Operating envelope

MKZ-3: 7” completion WGR: 110 bbl/1e6 scf Foam inj: 50-100 ltr/day

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Mar. 5 - 7, 2007

2007 Gas Well De-Liquification Workshop Denver, Colorado 10

MKZ-3: 7” completion WGR: 110 bbl/1e6 scf Foam inj: 10-25 gal/day

Continuous foam: Operating envelope

With foam injection: Critical rate lowered 30-50%

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Mar. 5 - 7, 2007

2007 Gas Well De-Liquification Workshop Denver, Colorado 11

Acoustic logging: Better Understanding

f Liquid Loading
Information available from acoustic logs and

FPG’s such as:

– Where is the liquid level? – What is the gradient of the gaseous liquid column? – What is the FBHP with liquid hold-up in the well?

Why is it important?

– Improves ability to select candidates and solutions for liquid unloading – Improves optimization of currently deployed liquid loading solutions – Improves ability to quantify gains

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Mar. 5 - 7, 2007

2007 Gas Well De-Liquification Workshop Denver, Colorado 12

Candidate selection: Tail-pipe extension

In/Outflow modeling
Severe (7”) liner

loading evident from FPG data

3.5” tubing still OK
Decision: 2” tail-pipe

extension, followed by full velocity string when tubing starts loading later on

Tail-pipe Velocity str. Current

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Mar. 5 - 7, 2007

2007 Gas Well De-Liquification Workshop Denver, Colorado 13

Candidate selection: WGR Campaign

Select ‘difficult wells’ – mainly Coevorden area

– Historically not much success unloading wells – Condensate makes foaming difficult – DH condensate-based corrosion inhibitor injection – No two wells are the same – Two producing reservoirs with different properties

Objectives of campaign:

– Unload & clean-up the well – Provide PQ-curve, improve well in/outflow modeling – WGR/CGR measurement – Obtain water and condensate samples for lab foam testing

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Mar. 5 - 7, 2007

2007 Gas Well De-Liquification Workshop Denver, Colorado 14

Foamer selection: Lab testing on well fluids

Tests done at 20°C and 90°C
Foam buildup time < 60 seconds: OK
Foam half-life > 180 seconds: OK

Example Well COV-26:

COV-26 Foam build-up time [s] 75/25 water condensate ratio (1,000 ppm foam)

30 60 90 120 150

A B C D

quality indicator Foam build-up time [s]

20°C 90°C

COV-26 Foam half-life time [s] 75/25 water condensate ratio (1,000 ppm foam)

60 120 180 240 300

A B C D

quality indicator

20°C 90°C

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Mar. 5 - 7, 2007

2007 Gas Well De-Liquification Workshop Denver, Colorado 15

New solution for NAM: Plunger lifting

Blocker/Issue New data/development Implication

Lowest possible plunger setting (above SPM's & other jewelry) is too far away from perfs. Likely that no liquid is present. Acoustic logs and FPG's show significant liquid hold-up above jewelry Significant reduction in FBHP can be realized from unloading above SPM's SCSSV's are required and prevent running plunger to surface to control 2-stage plunger developed and used in US Plunger can be run and controlled below SCSSV

Lowest possible plunger running depth in this well

2,000 4,000 6,000 8,000 10,000 12,000 14,000 250 500 750 1,000

Pressure [psi]

AH depth [ft]

Up run Down Run Acoustic log Points

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Mar. 5 - 7, 2007

2007 Gas Well De-Liquification Workshop Denver, Colorado 16

THP down to 22 psia

To pipeline/ Central facilities

Gas well location/satellite

Central compression Back pressure 85-145 psia

Shut in due to

liquid loading

Gas wells

To pipeline/ Central facilities

Gas well location/satellite Including wellhead compression

Central compression Back pressure 85-145 psia

Producing at low THP

Gas wells

Low cost

Movable booster compression

5 10 15 20 25 30 35 40 45 0.00 0.20 0.40 0.60 0.80 1.00 1.2

Gas Production Rate [mln m³/d] Tubing Head Pressure [bar]

OPK-1 PQ Curve (Jul 2004)

5 10 15 20 25 30 35 40 45 0.00 0.20 0.40 0.60 0.80 1.00 1.2

Gas Production Rate [mln m³/d] Tubing Head Pressure [bar]

OPK-1 PQ Curve (Jul 2004)

Liq Load Production Well PQ curve

5 10 15 20 25 30 35 40 45 0.00 0.20 0.40 0.60 0.80 1.00 1.2

Gas Production Rate [mln m³/d] Tubing Head Pressure [bar]

OPK-1 PQ Curve (Jul 2004)

5 10 15 20 25 30 35 40 45 0.00 0.20 0.40 0.60 0.80 1.00 1.2

Gas Production Rate [mln m³/d] Tubing Head Pressure [bar]

OPK-1 PQ Curve (Jul 2004)

Liq Load Production Well PQ curve

Mobile wellhead compression: Lower THP to 22 psia

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Mar. 5 - 7, 2007

2007 Gas Well De-Liquification Workshop Denver, Colorado 17

Summary

Diagnostic methods like batch foaming, acoustic logging,

FPGs, and in/outflow modeling are used to screen for long- term liquid loading mitigation strategy and sequence of solutions

Integrated modeling and long-term production forecasts

determine the economic viability of the selected deliquification methods

WGR testing combined with well fluids sampling and lab

foam testing is essential to select potential continuous foam applications in ‘difficult’ areas with high CGRs

Continuous foam application can ‘save’ a tubing size over

the life of the well by lowering critical rates up to 50%