Potassium formate from addcon

Potassium Formate from Addcon
An Oilfield Success Story : 1995-2014
Potassium formate from Addcon

Formate brines
Sodium
formate
Potassium
formate
Cesium
formate
Solubility in
water
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

Solubility of cesium formate in various
solvents
Solvent
Solvent
density
(g/cm3)
Cesium
formate
solubility
(% w/w)
Solution
density
(g/cm3)
Water activity
of solution
Water 1.00 83.0 2.30 0.25
Monoethylene
glycol
1.11 82.9 2.22 0.05
Diethylene
glycol
1.12
57
1.66 0.20
Triethylene
glycol
1.13 33 1.38 0.11
Glycerol 1.26 63.8 1.96 0.08

Formate brines – Discovery and qualification
1987 1988 1989 1990 1991 1992
Shell patent the use
of formates as
polymer stabilisers
Shell discover
cesium formate
brine
Shell R&D in UK study the effect of sodium
and potassium formates on the thermal
stability of drilling polymers
Shell R&D in The Netherlands carry out
qualification work on formate brines as
deep slim-hole (HPHT) drilling fluids
Shell publish first
SPE papers on
formate brines
Start of Shell’s deep
slim-hole drilling
R&D programme

The main application for formate brines is in
High-Pressure High-Temperature gas wells
Low-solids heavy fluids for deep HPHT gas well constructions
• Reservoir drill-in
• Completion
• Workover
• Packer fluids
• Well suspension
• Fracking
Used in hundreds of HPHT wells since 1995, including some of
Europe’s deepest, hottest and highly-pressured gas reservoirs

The economic benefits provided by formate
brines in HPHT gas field developments
Formate brines improve the economics of HPHT gas field
developments by :
• Reducing well delivery time and costs
• Improving operational safety and
reducing risk
• Delivering production rates that exceed expectations
• Providing more precise reservoir definition

42 deep HPHT gas fields developed using potassium
formate brine , 1995-2011*
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
* More HPHT fields developed in Kuwait, India and Malaysia during 2012-2013

Formate brines – Production and first field use
- Milestones
1993 1994 1995 1996 1997 1998
First field use of
sodium formate:
Shell drills and
completes first
Draugen oil wells
Start of deep
HPHT gas well
drilling with
formates in
Germany
(Mobil, RWE,
BEB)
Sodium formate powder available throughout, but no anti-caking additive. Draugen
wells each produce 48,000 bbl oil /day
1995 - Potassium formate brine becomes available from Hydro
Chemicals (now Addcon) in Porsgrunn – sold thru Forbrico Ltd
Potassium formate
brines used in
USA, Canada,
Mexico,
Venezuela,
Brazil,
Ecuador
First field use of
potassium formate
(with Micromax) :
Statoil drills and
completes Gullfaks
oil well
1997 - Cesium
formate brine
becomes available
from Cabot
First use of
formate brine
as packer fluid:
Shell Dunlin
A-14

Potassium formate brine has been produced at
Porsgrunn since 1994
Production Site
ADDCON NORDIC AS
Storage tanks for raw
materials

Cesium formate produced by Cabot in Canada
from pollucite ore
Pollucite ore
Cs0.7Na0.2Rb0.04Al0.9Si2.1O6·(H20)
• Mined at Bernic Lake, Manitoba
• Processed on site to Cs formate brine
• Cs formate brine production 700 bbl/month

Germany : Potassium formate brine has been used
to drill deep HPHT gas wells since 1995
First use : ExxonMobil’s Walsrode field, onshore northern Germany
- high-angle deep HPHT slim hole low perm gas wells
TVD : 4,450-5,547 metres
Reservoir: Sandstone 0.1-125 mD
BHST : 157o C
Section length: 345-650 m
Drilling fluid: SG 1.45-1.55 K formate brine

Potassium formate from Norway used in 15 deep
HPHT gas well constructions in Germany ,1995-99
Well Name Application Fluid Type Density s.g. (ppg)
Horizontal
Length(m)
Angle (°) BHST (°F) BHCT (°F) TVD (metres) MD (metres)
Permeability
(mD)
Walsrode Z5 W/C K Formate 1.55 (12.93) 345 26 315 na 4450 - 4632 4815 - 5151 0.1 - 125 mD
Wasrode Z6 W/C K Formate 1.55 (12.93) 420 40 315 na 4450 - 4632 4815 - 5151 0.1 - 125 mD
Walsrode Z7 Drill-In K Formate 1.53 (12.77) 690 59 315 295 4541 - 4777 5136 - 5547 0.1 - 125 mD
Söhlingen Z3A Drill-In Formix 1.38 (11.52) 855 89 300 270 4908 5600 na
Söhlingen Z3a Drill-In Na Formate 1.30 (10.85) 855 89 300 270 4908 5600 na
Volkersen Z3 W/C Formix 1.40 (11.68) 512 52 320 na na na na
Kalle S108 Drill-In Formix 1.45 (12.10) 431 60 220 na 6000-6500 6200-6600 na
Weißenmoor Z1 W/C Formix 1.35 (11.27) 634 31 300 na na na na
Idsingen Z1a Drill-In K Formate 1.55 (12.93) 645 61 321 290 4632 - 4800 5257 - 5821 0.1 - 125 mD
Söhlingen Z12 Drill-In
Na
Formate/Formix
1.35 (11.27) 452 28 313 285 4736 - 4937 4846 - 5166 1.0 - 75 mD
Simonswolde Z1 Drill-In K Formate/Formix 1.52 (12.68) 567 35 293 275 4267 - 4572 4236 - 4648 0.1 - 25 mD
Walsrode NZ1 Drill-In Formix 1.51 (12.60) 460 34 290 265 4632 - 4815 4541 - 4693 0.1 - 125 mD
Idzingen Z2 W/C Formix 1.40 (11.68) na na 320 na 4632 - 4800 5257 - 5821 0.1 - 125 mD
Voelkersen NZ2 W/C Formix 1.40 (11.680 na na 320 na na na na
Söhlingen Z13 Drill-In/Frac K Formate/Formix 1.30 (-1.56)(10.85) 1200 90 300 285 4724 5486 - 6400 0,1 - 150 mD
Further wells drilled for BEB and RWE-DEA in Germany with
Porsgrunn’s potassium formate brines via Baroid (1997 onwards)

Summary of potassium formate brine use in
HPHT gas wells in Germany,1995-99

Formate brines – Some further important
milestones : 1999-2004
1999 2000 2001 2002 2003 2004
First
production of
non-caking
crystalline K
formate at
Porsgrunn
First drilling
jobs with
K/Cs formate
brine:
Huldra and
Devenick
Formate brines used as packer fluids for HPHT wells in GOM.
First well : ExxonMobil’s MO 822#7 (215oC BHST) in 2001
Use of Cs-weighted oil-based completion fluids for
oil reservoirs : Visund, Statfjord, Njord, Gullfaks,
Snorre , Oseberg, Rimfaks 2001 – present
First use of
Cs-weighted
LSOBM as
perforating
completion
fluid
(Visund)
First use of
K/Cs formate
brine :
Completion
job in
Shearwater
well (Shell
UK)
Cs-weighted
LSOBM used
as OH screen
completion
fluid
(Statfjord)
First use of
K/Cs
formate
brine as
HPHT well
suspension
fluid
(Elgin G-3)
Individual Draugen oil wells (1993) and Visund oil wells (2003) have similar
flow rates of around 50,000 bbl oil/day
First of 14
Kvitebjørn
HPHT wells
drilled and
completed
with K/Cs
formate
brines

The first sustained use of K/Cs formate brine was in
the world’s largest HPHT gas field development
Cesium formate brine used by TOTAL in 34 well
construction operations in 8 deep gas fields in
period 1999-2010
Elgin/Franklin field – UK North Sea

Formate brines – Some published milestones
2005 -2010
2005 2006 2007 2008 2009 2010
OMV
Pakistan
start using K
formate to
drill and
complete
(with ESS) in
HPHT gas
wells
K/Cs formate brines used as well perforating fluids in 11 HPHT gas fields in UK North Sea : Dunbar,
Shearwater, Elgin, Devenick , Braemar , Rhum, Judy , Glenelg , Kessog , Jura and West Franklin
1999-2011
Saudi Aramco
start using K
formate to drill
and complete
(with ESS) in
HPHT gas
wells
Gravel pack
with K
formate
brine in
Statfjord B
First MPD
operation in
Kvitebjørn
with K/Cs
formate
“designer
fluid”
First of 12
completions
in the
Kashagan
field with
K/Cs formate
Total’s West
Franklin F9
well (204oC)
perforated in
K/Cs formate
brine
Petrobras
use K
formate
brine for
open hole
gravel packs
in Manati
field

Saudi Aramco have been drilling HPHT gas wells
with potassium formate brine since 2003

Saudi Aramco use of formate brines, 2003-2009
• 7 deep gas fields
• 44 HPHT wells drilled
• 70,000 ft of reservoir
drilled at high angle
• 90,000 bbl of brine
recovered and re-used
• Good synergy with ESS,
also OHMS fracturing

Summary from Aramco’s OTC paper 19801

Pakistan - OMV use potassium formate brine for
HPHT deep gas well drilling and completions

Extracts from OMV’s SPE papers and SPE
presentations – note 1,700 psi overbalance, and 350oF

North Sea - K/Cs formate brines used as
combined HPHT drill-in and completion fluids
33 development* wells drilled and completed in 7 HPHT offshore
gas fields
• Huldra (6 )
• Tune (4)
• Devenick (2)
• Kvitebjoern (8 O/B and 5 MPD)
• Valemon (1)
• Kristin (2) – Drilled only
• Vega (5)
* Except Valemon (appraisal well)
Mostly open hole stand-alone sand screen completions

Tune field – HP/HT gas condensate reservoir drilled
and completed with K formate brine, 2002
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
• 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)
Good early production from the 4 wells
- No skin (no damage)
- 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
Rapid and efficient drainage of the reservoir

• 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 K/Cs formate brine,
2001

Huldra – Production of recoverable gas and
condensate reserves since Nov 2001 (NPD data)
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:
- 17.5 billion m3 gas
- 5.1 million bbl condensate
Rapid and efficient drainage of the reservoir

• 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 K/Cs formate brine, 2004-2013

A few of the highlights from Kvitebjoern
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
“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 comments after well testing (Q3 2004 )
The Well PI was almost double the target
Fast completions and high well productivity

Kvitebjørn– Production of recoverable gas and
condensate reserves since Oct 2004 (NPD data)
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

Economic benefits of using formate brines
• 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”

Economic benefits from using formate brines
- Good well performance and recovery of reserves
• “High production rates with low skin” *
• “ We selected formate brine to minimise well control problems
and maximise well productivity”*
* Quotes by Statoil relating to Kvitebjoern wells (SPE 105733)

- More efficient and safer drilling
“ a remarkable record of zero well control incidents in all 15
HPHT drilling operations and 20 HPHT completion operations”
Better/safer drilling environment saves rig-time costs
• Stable hole: see LWD vs. WL calipers in shale
• Elimination of well control* and stuck pipe
incidents
• Good hydraulics, low ECD
• Good ROP in hard abrasive rocks
* See next slide for details

- Improved well control and safety
• Elimination of barite and its sagging problems
• Elimination of oil-based fluids and their gas solubility problem
• Low solids brine  Low ECD (SG 0.04-0.06) and swab pressures
• Inhibition of hydrates
• Ready/rapid surface detection of well influx
• Elimination of hazardous zinc bromide brine

- Drill-in and completing with
formate brine allows open hole
completion with screens
- Clean well bores mean no tool/seal
failures or blocked screens
- Completion time 50% lower than
wells drilled with OBM
“ fastest HPHT completion operation ever performed in North Sea (12.7 days)”
- More efficicient/faster completions

• No differential sticking
• Pipe and casing running speeds are fast
• Mud conditioning and flow-check times are short
• Displacements simplified, sometimes eliminated
Duration of
flow back
(minutes)
Fluid Gain
(bbl)
30 0.8
15 0.56
20 0.44
30 0.56
Flow check fingerprint
for a Huldra well
- Operational efficiencies

- Good reservoir definition if Cs present in fluid
• High density filtrate and no barite
• Filtrate Pe up to 259 barns/electron
• Unique Cs feature - makes filtrate invasion
highly visible against formation Pe of 2-3 b/e
• LWD can “see” the filtrate moving (e.g. see
the resistivity log on far right – drill vs ream
• Good for defining permeable sands (see
SAND-Flag on log right )
• Consistent and reliable net reservoir definition
from LWD and wireline

- Good reservoir imaging
• Highly conductive fluid
• Clear resistivity images
• Information provided:
- structural dip
- depositional environment
- geological correlations

Formate brines – Summary of economic
benefits provided to users
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
• Maximising well performance
• Providing more precise reservoir definition

OPERATOR LOCATION
Packer Fluid
(ppg)
BHT
(°C)
BHT
(°F)
Start
Date
End
Date
Comments
Devon WC 165 A-7 8.6 KFo 149 300 1/2005
Devon WC 165 A-8 8.6 KFo 149 300 1/2006
Devon
WC 575 A-3
ST2
9.5 KFo 132 270 5/2005
WOG/Devon MO 862 #1 12.0 NaKFo 215 420 4/2005 5/2006
Well P&A – H2O
production – G-3 in
excellent condition
BP/Apache HI A-5 #1 11.5 NaKFo 164 350 2/2002 4/2008
Well P&A - Natural
depletion – S13Cr in
excellent condition
ExxonMobil MO 822 #7 12.0 NaKFo 215 420 2001
EPL ST 42 #1 11.5 NaKFo 133 272 2006
EPL ST 41 #F1 13.0 NaKFo 105 222 2006
EPL EC 109 A-5 11.5 NaKFo 121 250 2006
EPL ST 42 #2 12.8 NaKFo 132 270 2006
Dominion
WC 72 #3
BP1
10.0 NaFo 121 250 2006
EPL
WC 98 A-3
ST1
12.7 NaKFo 153 307 2006
EPL WC 98 A-3 10.8 NaKFo 154 310 2007
Formate brines as packer fluids in GOM

• 177ºC, 14,000 psi
• S13Cr tubing failed from
CaCl2 packer fluid
• Well worked over and re-
completed with Cs formate
• 1.4 g/cm3 Na/K formate used
as packer fluid
• Tubing retrieved 6 years
later
• Tubing was in excellent
condition.
BP High Island – Na/K formate brine as
packer fluid for 6 years

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