Formate Brines - Reservoir drilling and well completion fluids since 1993

FORMATE BRINES
DRILL-IN AND COMPLETION FLUIDS SINCE 1993
John Downs
Formate Brine Ltd
www.formatebrine.com

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
2 John Downs - Formate Brine Ltd

LATEST FORMATE SUCCESS – Unconventional
shale drilling – Formates cut drilling times in half
Oil companies in Canada are exploiting a discovery from
1996 – formates are VERY fast in shale vs weighted
muds

Potassium formate brines excelling in Canada
as solids-free and polymer-free shale drilling fluid
118 shale wells drilled with DMK’s potassium formate
drilling fluid since mid-2013
Quote from Encana : “ The fluid is inhibitive, after drilling caliper logs displayed the
same response as invert (oil) drilled caliper logs. The ROP improvement has
allowed us to cut our lateral drilling time in half! “

New explanation for shale drilling success with
potassium formate – Osmosis
Paper to be presented to the 2015 SPE/IADC Drilling conference :
ROP Enhancement in Shales through Osmotic Processes
Eric van Oort, SPE, and Muneeb Ahmad, The University of Texas at Austin, and
Reed Spencer, SPE, Baker Hughes
“It will be shown that the mechanism responsible for the Deeptrek ROP results
with formate mud is chemical osmosis …..”
Potassium formate brine use in unconventional shale drilling
may become widespread

The traditional use 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

42 deep HPHT gas fields developed using formate
brines , 1995-2011. Now probably > 50 fields *
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

Almost every HPHT gas field in northern North Sea in
Norway drilled and/or completed in formate brine
More than 400 well construction jobs in Europe with high density formate
brines since 1995

Formate brines as packer fluids in USA (GOM)
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

BP High Island, Gulf of Mexico – Formate
brine used as a packer fluid for 6 years
• 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.

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
Detailed explanation and evidence later in this presentation

Formate brines used by OMV in Pakistan in
2005-6 for drill-in and completions in HPHT gas wells

Formate brines used by OMV in Pakistan in
2005-6 for drill-in and completion in HPHT gas wells

www.formatebrines.com
Source of all the latest formate information

Useful reference material
The Formate Technical Manual
- 26 chapters
- > 400 pages
- Available in English, Spanish and Chinese
- Updated and expanded every month
Recent SPE 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”

Another source of formate information
The Formate Brines group on LinkedIn – www.linkedin.com

And another source of formate information....
The Formate Brines newsletter – Issue #9 out this week

Formate brines – Discovery and qualification by
Shell Research
Shell patent the use
of formates as
polymer stabilisers
Shell discover
cesium formate
brine
Shell publish first
SPE papers on
formate brines
1987 1988 1989 1990 1991 1992
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
Start of Shell’s deep
slim-hole drilling
R&D programme

Formate Brines – Properties that make them
excellent drilling and completion fluids
• Density up to 2.3 g/cm3 and pH 9-10
• Only monovalent ions (Na+, K+, Cs+, HCOO-)
• Stabilise shales (K, Cs and low water activity)
• Protect polymers at high temperature
• Less corrosive than other brines
• Good lubricity
• Non-toxic and readily biodegradable

Benefits of formate brines – Compatible with
polymers, so can be used as drilling fluids
A traditional low-solids formate drilling fluid formulation
Component Function Concentration
Formate brine
Density
Lubricity
Polymer protection
Biocide
1 bbl
Xanthan
Viscosity
Fluid loss control
0.75 – 1 ppb
Lo- Vis PAC and modified
starch
Fluid loss control 4 ppb each
Sized calcium carbonate Filter cake agent 10 – 15 ppb
K2CO3/KHCO3
Buffer
Acid gas corrosion
control
2 – 8 ppb
This simple formulation has been in field use since 1993 – good to 160o C

Formate brines launched as low-solids drilling
fluids in mid-1990’s
John Downs - Formate Brine Ltd
Property Typical values
pH 9 – 10.5
PV [cP] 15 - 20
YP [lb/100ft2] 8 - 15
10” gel 2 - 5
10’ gel 3 - 6
HPHT fluid loss [mL] < 10
API fluid loss < 3
Service company brand names:
Baker Hughes : CLEAR-DRILL (1994)
M-I : FLOPRO (1995)
Baroid : BRINEDRIL
Filter cake on aloxite disc
21

Benefits of formate brines - they raise the
thermal stability ceiling of polymers
Bar graph showing the temperature at which polymers lose 50% of
their viscosity after 16 hours hot rolling
Temperature [deg C]
66 116 166
150 200 250 300 350 400
Temperature [deg F]
Starch
PAC
Xanthan
Potassium formate
(1.59 sg 13.25 ppg)
Sodium formate
(1.32 sg 11.05 ppg)
Potassium chloride
(1.16 sg 9.66 ppg)
Sodium chloride
(1.19 sg 9.91 ppg)
Sodium bromide
(1.53 sg 12.75 ppg)
Calcium chloride
(1.39 sg 11.58 ppg)
Freshwater

Benefits of formate brines - ROP enhancement
Low-solids formate brines increase drilling ROP by >100%
compared to OBM (in carbonates and shale)
Effect of Mud on Rate of Penetration
Carthage Marble with 7 Blade PDC Bit
50
40
30
20
10
0
Water
16ppg OBM
16ppg CsFm
16ppg OBM + Mn
0 5,000 10,000 15,000 20,000 25,000 30,000
Weight on Bit (lbf)
Rate of Penetration (ft/hr)
Data from DOE Deep Trek project , see SPE paper 112731

Zero-solids formate brines can increase drilling ROP by 200-300% vs
WBM
Zero-solids potassium formate brines are now breaking records as
drilling fluids in the Montney and Duvernay shales in Canada
Data from SPE paper 36425 (1996)

Ramsey et al found correlation between Fann 600 reading of drilling
fluids and ROP in sandstone
Note the effect of the calcium carbonate (solids) concentration on
Fann 600 reading and ROP with formate brine
Data from SPE paper 36396 (1996)

Benefits of formate brines – Zero/low solids
gives better hydraulics
• Lower Surge and Swab Pressures
- Faster tripping times
- Reduced risk of hole instability
or well control incidents
• Lower System Pressure Losses
- More power to motor
• Lower ECD
- Drill in narrower window between pore
and fracture pressure gradients
- Less chance of fracturing well
and causing lost circulation
• Higher Annular Flow Rates
- Better hole cleaning
John 26 Downs - Formate Brine Ltd

Benefits of formate brines – Natural lubricity
Steel-steel coefficient of friction in potassium formate brine (BP test)

Benefits of formate brines – Low methane
solubility
• Low methane solubility and diffusion rates
- Easier kick detection
- Low rate of static influx
• Mud properties not degraded by gas influx
Fluid Solubility (kg/m3)
Diffusion coefficient
(m2/sec x 108)
Diffusion flux
(kg/m2s x 106)
OBM 164 1.15 53.30
WBM 5 2.92 3.98
Formate brine 1 0.80 0.25
Solubility of methane in drilling fluids: T = 300°F (149°C), P = 10,000 psi (690 bar)

Finnish Environment Institute recommends the use of
potassium formate in sensitive groundwater areas

Extracts from summary of Finnish Environment
Institute report on potassium formate
“Potassium formate is already widely used in Finnish airports. According to a
recently completed follow-up study conducted over several years, formate
biodegrades rapidly in the ground, even at low temperatures. This prevents its
infiltration into groundwater”
“In Finland, potassium formate is currently the sole de-icing agent used on
nine roads crossing valuable groundwater areas…. For the follow-up study,
data on groundwater quality was collected from three of the groundwater
areas. No negative impacts were observed on groundwater quality, due to
the use of potassium formate, at any of the three areas in question”

Extracts from abstracts of Finnish Environment
Institute reports on potassium formate
Alternative deicing agents and ground water protection. Final report of MIDAS2-
project (published 2010)
This report summarizes….. novel data from a 7-year follow-up study on the ground water
quality at three areas (Kauriansalmi, Taavetti, and Jaamankangas aquifers) where
potassium formate has been used as a sole de-icing chemical.
On highway 13, running along Kauriansalmi aquifer (Suomenniemi municipality),
potassium formate was used as a sole de-icer from 2002 until the end of 2009. During that
period, no formate was found in the ground water at the area. The average chloride
concentration in the formation has decreased on average by 3,3 % a year since sodium
chloride application came to an end in 2002.
At Taavetti municipal water intake, chloride concentration decreased sharply after 2004
when potassium formate was introduced in de-icing at the area.
This study shows that potassium formate can be applied in winter road maintenance in
particular at sensitive ground water areas, and at airports to minimize the adverse impacts
on ground and surface water resulting from de-icing.

Formate brines – Production and first field use
- Milestones
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,
Shell)
Potassium
formate brines
used in USA,
Canada,
Mexico,
Venezuela,
First field use of
potassium formate
(with Micromax) :
Statoil drills and
completes Gullfaks
oil well
First use of
formate brine
as packer fluid:
Shell Dunlin
A-14
1993 1994 1995 1996 1997 1998
Brazil,
Ecuador
Sodium formate powder available. Draugen wells each produce 48,000 bbl oil /day
1994 - Potassium formate brine becomes available from Norsk
Hydro (now Addcon)
1997 - Cesium formate
brine becomes available
from Cabot

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 Addcon used in 15 deep
HPHT gas well constructions in Germany ,1995-99
Fluids service provided by M-I and Baroid
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

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

Addcon’s potassium formate plant in Norway has
been supplying the oil industry since 1994
Production Site
ADDCON NORDIC AS
Storage tanks for raw
materials

Potassium formate production by Addcon
• The first and largest producer of potassium formate
- Brine production capacity : 800,000 bbl/year
- Non-caking powder capacity: 8,400 MT/year
• Direct production from HCOOH and KOH
• High purity product
• Large stocks on quayside location
• Fast service – by truck, rail and sea
• Supplier to the oil industry since 1994
50 % KOH
4,500 m3
6,300 MT
94 %
Formic acid
5,000 m3
Feedstock storage tanks in
Norway

Addcon’s new potassium formate plant in
Bitterfeld, Germany
Only 7 hours drive from Bitterfeld to Vienna area

Potassium formate brine – Methods of shipment

Typical potassium brine grades
% w/w Density TCT*
SG oC
75 1.57 7
71 1.53 2
63 1.46 -13
* Crystals of potassium formate
added to encourage crystallisation

Formate brines – Some important milestones :
1999-2004
First
production of
non-caking
crystalline K
formate by
Addcon
First drilling
jobs with
K/Cs formate
brine:
Huldra and
Devenick
HPHT
First use of
Cs-weighted
LSOBM as
perforating
completion
fluid
(Visund)
1999 2000 2001 2002 2003 2004
First of 14
Kvitebjørn
HPHT wells
drilled and
completed
with K/Cs
formate
brines
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
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)
Individual Draugen oil wells (1993) and Visund oil wells (2003) have similar
flow rates of around 50,000 bbl oil/day

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
• Cs formate stock built up to 30,000 bbl

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

Formate brines – Some published milestones
2005 -2010
OMV
Pakistan
start using K
formate to
drill and
complete
(with ESS) in
HPHT gas
wells
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
Petrobras
use K
formate
brine for
open hole
gravel packs
in Manati
field
2005 2006 2007 2008 2009 2010
Total’s West
Franklin F9
well (204oC)
perforated in
K/Cs formate
brine
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 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
Aramco consume around 300 m3/month of K formate brine

Potassium formate brine weighted with Micromax®
in Kuwait and Saudi Arabia
Good results in first 9 HPHT wells –
could become the standard HPHT
fluid for KOC
SPE 132151 (2010) “Successful HPHT Application of Potassium
Formate/Manganese Tetra-Oxide Fluid Helps Improve Drilling
Characteristics and Imaging Log Quality”
SPE/IADC 147983 (2011) “Utilization of Non-damaging Drilling Fluid
Composed of Potassium Formate Brine and Manganese Tetra Oxide to
Drill Sandstone Formation in Tight Gas Reservoir
SPE 163301 (2012) “Paradigm Shift in Reducing Formation Damage:
Application of Potassium Formate Water Based Mud in Deep HPHT
Exploratory Well”

Potassium formate brine weighted with Micromax for
drilling deep HPHT fractured carbonate wells
10,000 psi, 140oC, H2S = 4-12%, CO2 = 1-6%

Potassium formate brine weighted with Micromax for
drilling deep HPHT fractured carbonate wells
“The results were extraordinary when compared to wells
drilled with ..OBM” – Production rates x 3 higher

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

OMV drills and completes using ESS in
potassium formate brine – Pakistan, 2006/7

Norway, 2002 - Perforating in solids-free oil-based
kill pill weighted with formate brine
• Visund field
- BHST: 118o C
- Fluid density: SG 1.65
- 13 wells – 1000- 2000 metre horizontal sections
- Drilled with OBM ,completed with perforated liners
• Justification for use:
- First 3 wells badly damaged by CaBr2 kill pill
- PI only 60-90 m3/bar/day

Perforating Visund wells in solids-free oil-based
kill pill weighted with formate brine
• Visund – Change to formate kill
pill (see SPE 73709, 58758 and 84910)
- Next 3 wells perforated in formate fluid
-Also used new perforating guns, in dynamic
underbalance
• Results :
- Eliminated formation damage problem
- PI increased up to 900 m3/bar/day
- 300-600% PI improvement
- Best well : 53,000 bbl/day
Visund well productivity
60 70 50
220
620
900
1000
900
800
700
600
500
400
300
200
100
0
Well
m3 oil/bar/day
Formate brine
Bromide brine

Formate brines used as HPHT cased well
completion fluids after drilling with OBM
Formate brines have been used as (perforating) completion fluids
for cased wells in 9 HPHT gas fields in the North Sea
• Shearwater
• Elgin/Franklin
• Braemar
• Rhum
• Judy
• Glenelg
• Kessog
• Jura
• West Franklin

Managed Pressure Drilling and completion of
fractured carbonates with formate brine
SPE 165761 (2012) “ Experience with Formate Fluids for Managed Pressure
Drilling and Completion of Sub-Sea Carbonate Gas Development Wells”
• Petronas - Kanowit field – 2 sub-sea gas wells
• Managed Pressure Drilling in fractured carbonate
with K formate brine improved economics by:
- Minimising fluid losses
- Reducing fluid cost (by using K formate)
- Improving production by 50%
- Eliminating need for stimulation (no acidising)

Kanowit SS-1 : Production profile from start-up - natural clean-up
– no stimulation . Carbonate reservoir
• 100 MMscfd gas and 4,000 bpd condensate after 5 hours
• >150 MMscfd gas and > 6,000 bpd condensate after 9 hours

Kanowit SS-1 : Multi-rate well test results from carbonate
Both wells can produce > 150 MMscfd gas and > 6,000 bpd condensate
MRT measurements on well SS-1 before acidizing (Mahadi et al, 2013)
MRT Test
Choke size
(/64)
Well Head
Pressure
(psi)
Gas Flow rate
Choke correlation
(MMscfd)
Gas Flow rate
Sonar
(MMscfd)
PDG Pressure
(psi)
PDG Temp
(oF)
1 112 2874.4 159.16 147.61 3857.0 252
2 88 3273.0 111.85 108.76 3932.2 252
3 64 3476.8 63.46 64.51 3978.5 251.7
4 40 3560.5 25.84 28.01 3998.8 250.1
The maximum potential flow rate figures are 50% higher than the technical
potential predicted in the original field development plan.

North Sea - 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
Well length [m MD]
• 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
Before After
• 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
3350
3400
3450
3500
3550
3600
0 100 200 300 400 500 600 700 800 900 1000
Depth [m TVD MSL]
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

Huldra field – HPHT gas condensate reservoir
drilled and completed with formate brine, 2001
• 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

Comments from Huldra project manager
65
TROND JUSTAD
Manager-Huldra Project
Bergen, Norway
“CESIUM FORMATE HAS PLAYED A KEY ROLE in the development of the Huldra field (a high-temperature,
high-pressure gas field being developed by Statoil in the North Sea). Without it Statoil
could not have developed the field without major consequences on our plans, including the very
expensive redesign of all wells. The need to use a cesium formate-based drilling fluid became clear
after we experienced severe operational limitations when we drilled the first reservoir section with a
different product. Also, quite early in the process, we found that good synergies could be achieved
when using the same fluid for the drilling and completion phases.
“Cesium formate has significantly improved the safety and well control aspects of the project. It has
demonstrated good drillability with good hole cleaning, faster tripping speeds and absolutely no sag.
During flow checks, the fluid is completely stable after only 20 minutes, compared to 45 to 60 minutes
when using another product. This results in significant savings on every trip, as several flow checks
must be done each time the drill string is run in and out of a high-temperature, high-pressure well.
“For the specific conditions of the Huldra field, there is no realistic fluid alternative for successfully
drilling and completing the wells” - TROND JUSTAD

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

Kvitebjørn field – HPHT gas condensate reservoir drilled
and completed with K/Cs formate brine, 2004-2013
• 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

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

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
- Latest paper

- 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
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
“ a remarkable record of zero well control incidents in all 15
HPHT drilling operations and 20 HPHT completion operations”

Formate Brines : Allow fast solids-free drilling
Solids-free formate brines drill deep horizontal well sections much
faster than muds like OBM – and cause less formation damage

- 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

- More efficient/faster completions
- 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)”

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

Formate brines enable open-hole screen
completions in high-angle HPHT wells
Formate brines are low-solids drill-in and completion fluid systems
that provide massive benefits in open-hole screen completions in HPHT
wells
• Generally non-damaging to reservoir and screens
• Clean-up naturally during start-up (10-20 hours)
• Low skins
• No well stimulation required
• Good with expandable screens (Saudi, Pakistan)
Formates are perhaps the only high-density fluids that routinely deliver
unimpaired open hole screen completions in HPHT wells

Finnish Environment Institute recommends the use of
potassium formate in sensitive groundwater areas
Environ Sci Technol. 2005 Jul 1;39(13):5095-100.
Use of potassium formate in road winter deicing can reduce groundwater deterioration.
Hellstén PP1, Salminen JM, Jørgensen KS, Nystén TH.
“Potassium formate was used to de-ice a stretch of a highway in Finland. The fate of
the formate was examined by monitoring the groundwater chemistry in the
underlying aquifer of which a conceptual model was constructed. In addition, we
determined aerobic and anaerobic biodegradation rates of formate at low
temperatures (-2 to +6 degrees C) in soil microcosms.
Our results show that the formate did not enter the saturated zone through the thin
vadose zone; thus, no undesirable changes in the groundwater chemistry were
observed. We recorded mineralization potential up to 97% and up to 17% within 24 h
under aerobic and anaerobic conditions, respectively, in the soil and subsurface
samples obtained from the site. This demonstrates that biodegradation in the topsoil
layers was responsible for the removal of the formate.
We conclude that the use of potassium formate can potentially help diminish the
negative impacts of road winter deicing on groundwater without jeopardizing traffic
safety.”

Formate Brines - Reservoir drilling and well completion fluids since 1993

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Formate Brines - Reservoir drilling and well completion fluids since 1993