Gas Well Deliquification Workshop

Sheraton Hotel, Denver, Colorado

February 27 – March 2, 2011

Deliquification Strategy for North Everest :Field Application of Betaine Surfactants

Sabina Rattan (BG Group)

Karl Stevens (NALCO)

Duy Nguyen (NALCO)

2

North Everest Field Overview

• Located in Central North Sea

• Started Production in 1993

• Field Partners:

- BG (Operator) 80.46%,

- Hess Corp 18.67%

- Total 0.87%

• Gas export via CATS (Central

Area Transmission System)

• Condensate export via FPS

(Forties Pipeline System)CATS

FPS

Cruden Bay

Grangemouth

(to Teesside)

Reservoir Summary

• Depletion Drive Reservoir

• Two main isolated reservoirs Forties and Lista-Maureen

Forties North Reservoir

• Forties North sands in the central part of the field is most depleted ; has highest density of wells

• 6 producing wells

• 5 wells liquid loading under normal operating condition~326 psi

• Reservoir Pressures & Temp. : 950 Psi, 250ºF

• Typical gas rates : ~3.5 – 5.5 MMscfd

• WGR : 5 - 8 BBL/MSCF; CGR: 20 BBL/MSCF

Surfactant Trial WellsCyclic well –

Not tested for Foamer TrialNon cyclic well under

normal operating regime

Well Information

LAST RECORDED HUD

• 5-1/2 inch completion with SSSV & Production Packer

• Deviations : 14 – 65 deg.

• Scale & Sand

Wells Well 1 Well 7 Well 8 Well 9

Tubing ID 4.67 4.67 4.67 4.67

Measured Depth - top of perforations (ft rkb) 13674 15797 10384 9166

Deviation (º) 63 65 34 14

Flowing Wellhead Pressure (psia)

326 329 334 326

Flowing Wellhead Temp (ºF) 77 122 117 99

Gas Rate (MMscfd) 3.5 4.6 5.5 4.5

Condensate Rate (Bbl/Day) 63 92 110 113

Water Rate ( Bbl/day) 18 37 33 27

Gas Specific Gravity 0.65 0.65 0.65 0.65

Condensate API gravity 68 68 68 68

Salinity Data ,TDS –mg/l

30000 50000 20000 30000

Nature of Liquid Loading Combination of factors:

Reservoir depletion

Oversized completion

Some formation water production plus condensed water in tubing

Wells inflows compromised due to scaling across perforations & possible formation damage due to water cycling

Sudden onset of liquids – slugging

Static dead column of water in the wellbore

Limitations:

Absence of appropriate telemetry to understand the dynamic behaviour of liquid loading.

Well characteristics & behaviour change with time, static well models of limited use

Deliquification Strategy

• Wells have been intermittent as early as 2006, cycled to

sustain production.

• Field trial of previous incumbent’s foamer in mid 2007 on 3

wells.

• Blowdown / venting : Limited vessel capacity prevents

unloading, vessel required to be pressured up to allow

continual liquid evacuation.

• Gas lift for kick-off.

• Other widely used deliquification strategies (velocity string,

process modifications) – Uneconomic in the time frame

considered.

Surfactant Usage history

• Initial trial conducted in 2007 using foamer chemical from an

incumbent supplier on well 1, well 7 & well 9. Results showed

that the trial was successful in unloading and increasing

uptimes during the trial phase.

• Routine application was fraught with challenges. Foamer

appeared to give good results only with well 7. Twelve (12)

batch injections have been achieved since the initial trial with

varying results and common underlying issues.

• Issues : Emulsion, foaming in separator , and overall poor

quality of O/W

• Process upsets offset any benefit obtained from the

surfactant treatments.

• Production losses due to cycling wells >20% in Q3 - Q4 2009.

Hence, motivation to explore another chemical solution

which potentially had higher tolerance for condensate but

was equally effective with water.

Foam Stability: Area per molecule – Packing at the air-liquid interface

Air Air

Liquid Liquid

•Unstable foamLoosely packed film Tightly packed film

- High area per molecule - Small area per molecule

•Stable foam

Area

Correlation between Area per Molecule and Foam Stability

Conditions: 400 ppm active surfactant in 10.2% NaCl and 3.7% CaCl2.2H2O

Dynamic Surface Tension Apparatus

2)( max rPP o

Figure 1 Figure 2

Figure 3

Correlation Between Max DST Reduction Rate and % Liquid Unloading

Olefin sulfonate

Alkyl ether

sulfate

Betaine

Conditions: 400 ppm active surfactant in 10.2% NaCl and 3.7% CaCl2.2H2O

0% condensate

Laboratory testing - Results

• Unloading efficiency results vary with

brine/condensate composition. Lower

condensate ratios yields higher unloading

efficiency.

• For all samples the amphoteric surfactant

showed greater potential for lifting fluids of

various concentrations

• Quality of foam in both cases was loose.

•Emulsion formation tendencies were

similar for both chemicals – amount of oil

entrained in the water was not significant.

Good separation for the fluids was observed

in both cases .

Limitations of the test:

• Ambient test conditions

Amphoteric

Unloading efficiencyBrine/Condensate Ratio - 90/10

0102030405060708090

100

1 2 3 4 5 6Time (mins)

% liq

uid

un

load

ing

Unloading efficiencyBrine/Condensate Ratio - 75/25

010

20304050

607080

90100

1 2 3 4 5 6Time (mins)

% liq

uid

un

load

ing

Unloading efficiencyBrine/Condensate Ratio - 50/50

0

10

20

30

40

50

60

70

80

90

1 2 3 4 5 6Time (mins)

% liq

uid

un

load

ing

Incumbent

Amphoteric

Incumbent

Amphoteric

Incumbent

Field Application: Quantity selection & Shut-in times

• Well 9 was chosen for 1st trial in loaded regime. Echometer survey showed the

static column of liquid 1000 ft above the top of the perforations.

• Initial dosage rate of 15,000 ppm (~50 litres) was batch injected flushed with 100

litres of potable water.

• Shut-in Time : Depth dependent,12 hrs shut-in estimated, but for practicality 24

hrs shut-in to flowback during day-shift.

• Anti-foam (EC9149A) was injected to prevent foaming in the separators.

• Well routed to the test separator initially: Samples taken showed no refoaming

tendencies. Due to limited test vessel capacity re-routed well to main

production separator.

Well 1, Well 7 & Well 8 treated in loaded regime

with dosage of 35 - 50 litres & ~2 - 4 litres of antifoam

Dosage optimised to reduce the risk of

process upset

Well 9- Oil in Water in Overboard samples at the outlet of TPS ( Initial Trial)

0

10

20

30

40

50

60

70

80

90

0 6 8 10 13 16 19 23 29 34 37

Elapsed Hours

O/W

(m

g/l

)

Results : Production Benefit• Wells re-instated back to

production from loaded

regime

• 7 Batch injections achieved

high unloading efficiency

• Post each batch injection,

wells returned to its pre-

treated cycle times.

• FWHT monitoring to shut-in

the well for pressure build-

up before it began loading.

• Overall production benefit in

2010 : 170 mboe up to Q2’10.

Trial phase

Number of Batch injections

Hours online per cycle w/o foamer

Hours online per cycle with

Amphoteric foamer

Uptime Increase

Well 1 2 6 30 500%Well 7 3 36 72 200%Well 8 1 52 79 152%Well 9 1 80 144 180%

Uptime Improvement

0

20

40

60

80

100

120

140

160

Well 1 Well 7 Well 8 Well 9

Hrs

on

lin

e / c

ycle

Hours online per cycle w/o foamer

Hours online per cycle with betaine

Results: Process Benefits

• No foam carryover in the vessels; chemical dosage rates

optimised. No refoaming tendencies observed.

• No emulsion issues noted.

• No degradation of water overboard quality; O/W increases

initially as the process is dealing with increased amounts of

water, but levels quickly stabilise to <30 ppm.

• Post unloading, overall process stability as slugging reduced

significantly.

Challenges

• Quick well start-up for unloading in contradiction with slow bean-

up for sand minimisation.

• Carry over of solids & fines in the foam; better wellbore cleanout

but causes blockage in the vessel bridles leading to faulty level

indications causing process upset.

• Proactive management by the control room operator to manage

process stability during unloading phase.

Way Forward

• Continuous injection through capillary string installation

most economic deliquification option in short term (<3 years)

• Potential to add >0.5 mmboe/year by increasing wells uptime

• Additional batch injections to get more comparative data on

all the cyclic wells.

• Work ongoing to assess chemical selection for continuous

application.

Feb. 27 - Mar. 2, 2011 2011 Gas Well Deliquification Workshop

Denver, Colorado

18

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Feb. 27 - Mar. 2, 2011 2011 Gas Well Deliquification Workshop

Denver, Colorado

19

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