Formate brines have been in use since 1995 as non-damaging drill-in and completion fluids for deep HPHT gas condensate field developments. The number of HPHT fields developed using formate brines now totals more than 40, and includes some of the deepest, hottest and highly-pressured reservoirs in the North Sea. The well completions have been both open-hole and cased-hole. An expectation from using formate brines as reservoir drill-in and completion fluids is that they will cause minimal damage to the reservoir and help wells to deliver their full productive potential over the life-time of the field. The validity of this expectation has been tested by examining the long-term hydrocarbon production profiles of eight HPHT gas condensate fields in the North Sea where only formate brines have been used as the well completion fluids. In five of these fields the wells were drilled with oil-based muds and completed by perforating in cased hole with high-density formate brines. In another two of the fields the wells were drilled with formate brines and completed with screens entirely in open hole using the same brines. The last of the eight fields was drilled with formate brine and the wells were then completed with same fluid in either open hole or cased hole. The results of the production analysis provide a unique insight into the impact of a single type of specialist drill-in and completion fluid on the rate of recovery of hydrocarbon reserves from deeply-buried reservoirs in the North Sea

1. SPE 165151
Gunnar Olsvik and Siv Howard, Cabot Specialty Fluids
John Downs, Formate Brine Ltd
SPE European Formation Damage conference , Noordwijk, The Netherlands, 5-7 June 2013
The Long-Term Production Performance of
Deep HPHT Gas Condensate Fields
Developed Using Formate Brines

2. Formate brines
SPE European Formation Damage conference, 5-7 June 2013 2
Sodium
formate
Potassium
formate
Cesium
formate
Solubility 47 %wt 77 %wt 83 %wt
Density 1.33 g/cm3
11.1 lb/gal
1.59 g/cm3
13.2 lb/gal
2.30 g/cm3
19.2 lb/gal
Formates are also soluble in some non-aqueous solvents

3. Formate brines for HPHT gas wells
Low-solids heavy fluids for deep HPHT gas well
constructions
• Reservoir drill-in
• Completion
• Workover
• Packer fluids
• Well suspension
• Fracking (OHMS)
Used in hundreds of HPHT wells since 1995, including some of
Europe’s deepest, hottest and highly-pressured gas reservoirs
3SPE European Formation Damage conference, 5-7 June 2013

4. 42 deep HPHT gas fields developed using formate
brines, 1995-2011* (published data)
Country Fields Reservoir Description
Matrix
type
Depth, TVD
(metres)
Permeability
(mD)
Temperature
(oC)
Germany Walsrode,Sohlingen
Voelkersen, Idsingen,
Kalle, Weissenmoor,
Simonswolde
Sandstone 4,450-6,500 0.1-150 150-165
Hungary Mako , Vetyem Sandstone 5,692 - 235
Kazakhstan Kashagan Carbonate 4,595-5,088 - 100
Norway Huldra ,Njord
Kristin,Kvitebjoern
Tune, Valemon
Victoria, Morvin,
Vega, Asgard
Sandstone 4,090-7,380 50-1,000 121-200
Pakistan Miano, Sawan Sandstone 3,400 10-5,000 175
Saudi Arabia Andar,Shedgum
Uthmaniyah
Hawiyah,Haradh
Tinat, Midrikah
Sandstone
and
carbonate
3,963-4,572 0.1-40 132-154
UK Braemar,Devenick
Dunbar,Elgin
Franklin,Glenelg
Judy, Jura, Kessog
Rhum, Shearwater
West Franklin
Sandstone 4,500-7,353 0.01-1,000 123-207
USA High Island Sandstone 4,833 - 177
4SPE European Formation Damage conference, 5-7 June 2013
* Now more HPHT fields in Kuwait, India and Malaysia during 2012-2013

5. The economic benefits of using formate brines in
HPHT gas field developments – Reference papers
• SPE 130376 (2010): “A Review of the Impact of the Use of Formate Brines
on the Economics of Deep Gas Field Development Projects”
• SPE 145562 (2011): “Life Without Barite: Ten Years of Drilling Deep HPHT
Gas Wells With Cesium Formate Brine”
SPE European Formation Damage conference, 5-7 June 2013
5

6. Formate brines – The economic benefits
provided in HPHT gas field developments
Formate brines tend to improve oil and gas field development
economics by :
• Reducing well delivery time and costs
- 12 years of use with screens
- Very good with ESS
• Improving well/operational safety
and reducing risk
• Delivering production rates that exceed expectations
• Providing more precise reservoir definition
6SPE European Formation Damage conference, 5-7 June 2013

7. Several highlights from some Kvitebjoern HPHT gas
wells drilled and completed with formates
Kvitebjoern
well
Completion
time
(days)
A-4 17.5
A-5 17.8
A-15 14.8
A-10 15.9
A-6 12.7 *
* Fastest HPHT well completion
in the North Sea
7
“The target well PI was 51,000 Sm3/day/bar This target
would have had a skin of 7”
“A skin of 0 would have given a PI of 100,000”
“THE WELL A-04 GAVE A PI OF 90,000 Sm3/day/bar
(ANOTHER FANTASTIC PI)”
Operator quote after well testing (Q3 2004 )
The Well PI was almost double the target
SPE European Formation Damage Conference, 5-7 June 2013
Fast open hole screen completions and high well productivity

8. But productive for how long ?
Objectives of the analysis presented in this paper :
• Map the production profiles of North Sea HPHT fields
where formate brines were the last fluids to contact the
reservoirs in every well
• Compare actual cumulative production over time against
published estimates of recoverable reserves at start-up
• See if the well construction design influences the
production profile (e.g. Cased vs. Open hole completions)
8SPE European Formation Damage conference, 5-7 June 2013

9. Reviewed long-term production from 8 North Sea
HPHT gas condensate fields in 3 categories
9SPE European Formation Damage conference, 5-7 June 2013
Category Fields Reservoir penetration and well completion
1
Tune
Huldra
All production wells drilled and completed in high-
angle open hole with formate brines. Single filtrate
in reservoir.
2 Kvitebjørn
All production wells drilled and completed in high-
angle open- and cased-holes with formate brines.
Multiple filtrate types in reservoir surrounding cased
holes.
3
Braemar
Glenelg
Jura
Rhum
West Franklin
All production wells drilled with oil-based mud, then
completed in cased hole with formate brines as the
perforating fluids (with and without kill pills).
Multiple filtrate types in all wells
Production data obtained from UK DECC and Norwegian NPD websites

10. Tune field – semi-HP/HT gas condensate reservoir
drilled and completed with formate brines, 2002
10
4 wells : 350-900 m horizontal reservoir sections. Open hole screen
completions. Suspended for 6-12 months in formate brine after completion
SPE European Formation Damage conference, 5-7 June 2013

11. Tune wells - Initial Clean-up – Operator’s view
(direct copy of slide) June 2003
SPE European Formation Damage conference, 5-7 June 2013
11
11
• Wells left for 6-12 months before clean-up
• Clean-up : 10 - 24 hours per well
• Well performance
• Qgas 1.2 – 3.6 MSm3/d
• PI 35 – 200 kSm3/d/bar
• Well length sensitive
• No indication of formation damage
• Match to ideal well flow simulations (Prosper) - no skin
• Indications of successful clean-up
• Shut-in pressures
• Water samples during clean-up
• Formate and CaCO3 particles
• Registered high-density liquid in separator
• Tracer results
• A-12 T2H non detectable
• A-13 H tracer indicating flow from lower reservoir first detected 5 sd after
initial clean-up <-> doubled well productivity compared to initial flow data
• No processing problems Oseberg Field Center
SIWHP SIDHP SIWHP SIDHP
bara bara bara bara
A-11 AH 169 - 388 -
A-12 T2H 175 487 414 510
A-13 H 395 514 412 512
A-14 H 192 492 406 509
Before After
3350
3400
3450
3500
3550
3600
0 100 200 300 400 500 600 700 800 900 1000
Well length [m MD]
Depth[mTVDMSL]
A-11AH
A-12HT2
A-13H
A-14H
A-11 AH plugged back

12. Tune – Production of recoverable gas and condensate
reserves since 2003 (NPD data)
12
Good early production from the 4 wells
- « No skin»
- 12.4 million m3 gas /day
- 23,000 bbl/day condensate
Good sustained production
- 90% of recoverable hydrocarbon
reserves produced by end of Year 7
NPD current estimate of RR:
- 18.3 billion m3 gas
- 3.3 million bbl condensate
Open hole screen completions and single filtrate
SPE European Formation Damage conference, 5-7 June 2013

13. • 6 production wells
• 1-2 Darcy sandstone
• BHST: 147oC
• TVD : 3,900 m
• Hole angle : 45-55o
• Fluid density: SG1.89-1.96
• 230-343 m x 81/2” reservoir sections
• Open hole completions, 65/8” wire wrapped
screens
• Lower completion in formate drilling fluid and
upper completions in clear brine
Huldra field – HPHT gas condensate reservoir
drilled and completed with formate brines, 2001
13SPE European Formation Damage conference, 5-7 June 2013

14. Huldra – Production of recoverable gas and
condensate reserves since Nov 2001 (NPD data)
14
Plateau production from first 3 wells
- 10 million m3 gas /day
- 30,000 bbl/day condensate
Good sustained production
- 78% of recoverable gas and 89% of
condensate produced by end of Year 7
- Despite rapid pressure decline.....
NPD current estimate of RR:
- 17.5 billion m3 gas
- 5.1 million bbl condensate
Open hole screen completions and single filtrate
SPE European Formation Damage conference, 5-7 June 2013

15. • 13 wells to date – 8 O/B, 5 in MPD mode
• 100 mD sandstone
• BHST: 155oC
• TVD : 4,000 m
• Hole angle : 20-40o
• Fluid density: SG 2.02 for O/B
• 279-583 m x 81/2” reservoir sections
• 6 wells completed in open hole : 300-micron single wire-wrapped
screens.
• Remainder of wells cased and perforated
Kvitebjørn field – HPHT gas condensate reservoir drilled
and completed with formate brines, 2004-2013
15SPE European Formation Damage conference, 5-7 June 2013

16. Kvitebjørn– Production of recoverable gas and
condensate reserves since Oct 2004 (NPD data)
16
Good production reported from first 7 wells in 2006
- 20 million m3 gas /day
- 48,000 bbl/day condensate
Good sustained production (end Y8)
- 37 billion m3 gas
- 17 million m3 of condensate
- Produced 70% of original est. RR by
end of 8th year
NPD : Est. RR have been upgraded
- 89 billion m3 gas (from 55)
- 27 million m3 condensate (from 22)
Note : Shut down 15 months, Y3-5
- To slow reservoir pressure depletion
- Repairs to export pipeline
SPE European Formation Damage conference, 5-7 June 2013

17. Formate brines have been used to complete all of
the cased wells in 5 HPHT fields in UK North Sea
All wells drilled with OBM
17SPE European Formation Damage conference, 5-7 June 2013
* The deepest, hottest and highest-pressured fields in UK North Sea
Field
Operator No.
of
wells
Depth
(meters)
Pressure
(bar)
Temp
(oC)
Wellhead Brine
density
(kg/m3)
Braemar Marathon
1
(NP)
4,500 701 136 Sub-sea 1.86
Rhum BP 3 4,750 862 149 Sub-sea 2.19
West Franklin* Total
2
(NP)
7,327 1,154 204 Platform 1.94
Glenelg* Total
1
(NP)
7,385 1,150 200 Platform 1.78
Jura Total 2 3,935 702 127 Sub-sea 2.09

18. Fluid losses from HPHT wells in UK North Sea
perforated in formate brines
18
SPE European Formation Damage conference, 5-7 June 2013
Field Kill Pill Fluid losses during and
after perforating
(m3)
Comment
Braemar – 1 well No 2.3
Re-perforation of 18 year old
appraisal well. Short flow and
then zero losses
Rhum Yes 0.5
Flowed in first few minutes,
then zero losses for 3 days
Glenelg – 1 well No 17.7
2m3 on perforating and then
15.7m3 seepage losses
Jura
Yes –over
perfs
1.46 Flow stopped within 3 hours
West Franklin No 565
F9Y - Pumping brine at intervals
during period 29 June-18th July
to maintain WHP during 2
perforating runs and fishing

19. Braemar field – Production of recoverable gas and
condensate reserves since September 2003 (DECC data)
19
Estimated (2003) recoverable reserves produced in full from
this single well development by Year 9
Estimated recoverable reserves
- 3.28 billion m3 gas
- 1.59 million m3 condensate
Cumulative production @Sep 2012
- 3.4 billion m3 gas
- 1.9 million m3 condensate
SPE European Formation Damage conference, 5-7 June 2013

20. Glenelg – Production of gas and condensate since
March 2006 (DECC data)
20
No published reserves information ? Similar to Braemar ?
Highest temperature and pressure reservoir developed in UK
North Sea (2006), accessed by single extended reach well
Good initial production
Operator statements :
- «30,000 boe/day capability»
- «500,000 m3/year condensate»
Cumulative production @ Feb 2011
- 2.2 billion m3 gas
- 2.13 million m3 condensate
SPE European Formation Damage conference, 5-7 June 2013

21. West Franklin – Production of gas and condensate
from West Franklin/Franklin 2001-11 (DECC data)
21
No published reserves information. Hottest, highest pressure
commercial development in world (2007), accessed by two
extended reach wells, F7z and F9y
Excellent initial production
Operator statements :
- « F9y has 40,000 boe/day capability»
- «one of most productive wells in
N. Sea»
- «2.6 million m3/day of gas from F9y»
West Franklin has sustained
the Franklin field output
- > 2.5 billion m3 gas per year from Y6
onwards
Note : 566 m3 of cesium formate brine was pumped into formation around F9Y
SPE European Formation Damage conference, 5-7 June 2013

22. BP Rhum field – largest undeveloped gas field
in UK in 2005
SPE European Formation Damage conference, 5-7 June 2013 22
45 mD sandstone reservoir

23. Rhum field – Production of recoverable gas reserves:
December 2005- October 2010 (DECC data)
23
After nearly 5 years the 3 Rhum production wells had produced
35% of the estimated recoverable gas reserves
Estimated recoverable reserves
- 23 billion m3 gas
Cumulative production Oct 2010
- 7.9 billion m3 gas
Production suspended since late
2010
- EU sanctions against Iran
SPE European Formation Damage conference, 5-7 June 2013

24. Jura – Production of gas and condensate since May
2008 (DECC data)
24
Estimated (2008) proved and probable reserves of 170 million
boe – no published segmentation by hydrocarbon type
Good initial production from 2 wells
- 1.87 billion m3 gas produced during Y2
Cumulative production @ June 2012
- 6.58 billion m3 gas
- 1.1 million m3 condensate
= 46 million boe in total
= 27% production of est. RR after 4 years
SPE European Formation Damage conference, 5-7 June 2013

25. Conclusions – Cat 1 HPHT wells - Drilled and
completed in high-angle open hole with formate brines
Tune and Huldra fields produced 100% of recoverable gas and
condensate reserves within 10 years – average 3.5 billion m3
gas /well
Gas – 90% in 7-8 years Condensate – 90% in 5-7 years
Provides evidence that drilling and completing HPHT gas production wells in
open hole with formate brines can be a successful strategy
25Formate Brine Seminar - Stavanger, 22 November 2012

26. Conclusions – Cat 2 HPHT wells - Drilled and
completed in open- and cased-hole with formate brines
Kvitebjørn field has produced 70 % of the original estimated
reserves by end of Year 8 – despite production constraints
• Gas production has been at a steady
6-7 billion m3/year for last 4 years – already
produced 3 billion m3 gas per well
• Need more time to see how the production
progresses towards upgraded recoverable
reserves estimate
• Good chance to compare durability of open- hole versus cased-hole
HPHT wells ?
26Formate Brine Seminar - Stavanger, 22 November 2012

27. Conclusions – Cat 3 HPHT wells - drilled with OBM and
completed in cased-hole with formate brines (no pill)
Braemar and Glenelg are both small rich-gas condensate fields
drained by single cased wells perforated in formate brines
without kill pills. Low brine losses.
• Braemar reached original est. RR figure by
Year 9
• Glenelg following same gas production track
and already exceeded 2 million m3 condensate
production by Year 5
27Formate Brine Seminar - Stavanger, 22 November 2012

28. Conclusions – Cat 3 HPHT wells - drilled with OBM and
completed in cased-hole with formate brines (no pill)
West Franklin is a «200 million boe» gas condensate field currently
drained by 2 cased wells, perforated in formate brines. Large brine
volume pushed into reservoir from well F9y
• No cumulative production data available but
was apparently producing >30,000 boe/day
in the 4 years before Elgin gas leak in
March 2012
• West Franklin Phase 2 development in
progress
Too early to get a picture of long-term production performance
28Formate Brine Seminar - Stavanger, 22 November 2012

29. Conclusions – Cat 3 HPHT wells - drilled with OBM and
completed in cased-hole with formate brines+ kill pill
Rhum and Jura are lean gas condensate fields drained by 3 and 2 cased
wells respectively, perforated in formate brines with kill pills
• Rhum : 35% recovery of gas reserves by Year 5,
before production suspended
• Jura : 27% recovery of gas reserves after 4 years
Too early to get a picture of long-term production performance
29Formate Brine Seminar - Stavanger, 22 November 2012