SPE 165151 The Long-Term Production Performance of Deep HPHT Gas Condensate Fields Developed Using Formate Brines

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

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

Formate brines for HPHT gas wells
Low-solids heavy fluids for deep HPHT gas well
constructions – facilitating open hole completions with
screens
• 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

HPHT wells - What can go wrong when you try running open
hole screen completions in conventional heavy mud ?
Example 1
Production from 3 HPHT screen wells was plugged by heavy OBM
residues and needed stimulation
SPE European Formation Damage conference, 5-7 June 2013
4

Example 2
Production from 4 HPHT screen wells, accessing 40 billion m3 of
gas (i.e. 50% of gas reserves in place), is plugged by heavy OBM
Ref : http://www.ipt.ntnu.no/~jsg/undervisning/naturgass/lysark/LysarkZaostrovski2011.pdf
HPHT wells - What can go wrong when you try running open
hole screen completions in conventional heavy mud ?

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
* Now more HPHT fields in Kuwait, India and Malaysia during 2012-2013

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”
7

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
• Improving well/operational safety
and reducing risk
• Delivering production rates that exceed expectations
• Providing more precise reservoir definition
8Formate Brine Seminar - Stavanger, 22 November 2012

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
9
“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

But productive for how long ?
Question : Do HPHT gas fields developed using formate
brines deliver all of their recoverable hydrocarbon reserves ?
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)

Reviewed long-term production from 8 North Sea
HPHT gas condensate fields in 3 categories
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

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

Tune wells - Initial Clean-up – Operator’s view
(direct copy of slide) June 2003
13
13
• 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

Tune – Production of recoverable gas and condensate
reserves since 2003 (NPD data)
14
Good early production from the 4 wells
- 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

• 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

Huldra – Production of recoverable gas and
condensate reserves since Nov 2001 (NPD data)
16
Plateau production from first 3 wells
- 10 million m3 gas /day
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:
- 5.1 million bbl condensate
Open hole screen completions and single filtrate

• 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

Kvitebjørn– Production of recoverable gas and
condensate reserves since Oct 2004 (NPD data)
18
Good production reported from first 7 wells in 2006
- 20 million m3 gas /day
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

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
* 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
(NB)
4,500 701 136 Sub-sea 1.86
Rhum BP 3 4,750 862 149 Sub-sea 2.19
West Franklin* Total 2 7,327 1,154 204 Platform 1.94
Glenelg* Total
1
(NB)
7,385 1,150 200 Platform 1.78
Jura Total 2 3,935 702 127 Sub-sea 2.09

Fluid losses from HPHT wells in UK North Sea
perforated in overbalance in formate brines
20
Field Kill Pill Fluid losses during and
after perforating
(m3)
Comment
Braemar – 1 well No 2.3
Re-perforation of 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
Kessog
Yes – above
perfs
1.18
0.36 m3 in first 45 mins, then
0.22m3 in next hour and 0.6m3
over next 7.5 hours

Braemar field – Production of recoverable gas and
condensate reserves since September 2003 (DECC data)
21
Estimated (2003) recoverable reserves produced in full from
this single well development by Year 9
Estimated recoverable reserves
- 1.59 million m3 condensate
Cumulative production @Sep 2012

Glenelg – Production of gas and condensate since
March 2006 (DECC data)
25
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

BP Rhum field – largest undeveloped gas field
in UK in 2005
45 mD sandstone reservoir

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
Production suspended since late
2010
- EU sanctions against Iran

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
= 46 million boe in total
= 27% production of est. RR after 4 years

West Franklin – Production of gas and condensate
from West Franklin/Franklin 2001-11 (DECC data)
26
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 : 574 m3 of cesium formate brine was pumped into formation around F9Y

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

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 ?

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
• 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

Conclusions – Cat 3 HPHT wells - drilled with OBM and
completed in cased-hole with formate brines+ kill pill
Rhum, Jura and West Franklin are lean gas condensate fields drained by
2 or 3 cased wells, perforated in formate brines with kill pills
• Rhum : 35% recovery of reserves by Year 5,
before production suspended
• Jura : 27% recovery of reserves after 4 years
• West Franklin: No cumulative production
data available but was apparently producing
@ >30,000 boe/day in the years before Elgin gas
leak in March 2012
Too early to get a picture of long-term production performance

SPE 165151 The Long-Term Production Performance of Deep HPHT Gas Condensate Fields Developed Using Formate Brines

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