An introduction to formate brines - a technical presentation by John Downs, June 2017

INTRODUCTION TO FORMATE BRINES
John Downs
Formate Brine Ltd
www.formatebrine.com

Seminar programme
• What are formate brines ?
• Specification for drilling and completion fluids
• The fluid weighting issue: solids-laden muds or clear brines ?
• The benefits of drilling with clear brine
• Formates as the best clear brines
• The history of formate brines
• Some HPHT field case histories
• The economic benefits of drilling and completing with Cs formate
• Shale drilling with formate brines

Formate brines – What are they ?
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 brines are simple aqueous solutions of the alkali
metal salts of formic acid

Formate Brines – What are their key properties ?
• Density up to 2.3 g/cm3 without adding solids
• Only monovalent ions (Na+, K+, Cs+, HCOO-)
• Low brine viscosity , typically ~5 cP (in water)
• Low water activity= ~0.3 at higher densities
• Non-toxic and readily biodegradable
• Can be buffered at pH 9-11
• Protect polymers at high temperature
• Less corrosive than other brines
• Low TCT and good hydrate inhibition
• Good lubricity
• Poor solvent for methane
They make the perfect universal well drilling and completion
fluids – any time, any place, any well, top to bottom

Objective of oil & gas well construction
To safely and responsibly deliver highly-conductive, secure
and durable reservoir drainage conduits at lowest cost
Lowest construction
cost
Deliver recoverable
reserves according
to plan
Structural integrity
and long lifetime
(No leaks)
Minimal
environmental impact
and liability
Reservoir evaluation
by well logging

Influence of drilling and completion fluids
Fluids have a critical influence on well construction economics,
safety, liability, reservoir evaluation and production rate/duration
Time to drill and
complete the well
Delivery of
recoverable
oil/gas
Well integrity
and lifetime
Environmental
impact and liability
Logging capability
and interpretation Waste management
costs
Well control/safety

Drilling fluids - performance requirements
Wellbore stabilization*
Well pressure control*
Lubrication
Hole cleaning
Fluid loss control
Non-damaging to reservoir
Safe
Power transmission
Low environmental impact
Allow formation evaluation
Compatible with metals
and elastomers
A lot of functionalities required in one fluid
Aids rock cutting
Scavenges acid gases
• Typically want to keep wellbore pressure @ steady 500 psi above pore
pressure

10
Completion fluids - performance requirements
Wellbore stabilization*
Well pressure
control*
Lubrication
Clay stabilization
Fluid loss control
Non-damaging to reservoir
and sand control completions
Safe Low environmental impact
Long-term compatibility with metals
Compatible with
elastomers
Similar multiple functionalities required in one clear fluid
Compatible with
drilling fluid filtrate
Scavenges acid gases (CO2/H2S)
• Typically want to keep wellbore pressure @ steady 500 psi above pore
pressure

Need correct fluid weight in wellbore at all
times for well control and well stabilisation
Fluid weight in the wellbore must always be kept higher
than the rock pore pressure and lower than the rock fracture
pressure

This is what can happen if you have the wrong
fluid weight in your wellbore
Macondo well blow out tragedy  Fatalities, loss of rig, environmental
disaster, $ 43 billion bill

Making a weighted fluid – Some options
• Suspend mineral particles in a fluid
( water, oil, etc) to make a heavy slurry
or “mud”
Barite powder
• Dissolve salts in a fluid (water, glycol, etc)
to make a clear heavy “brine”
• Emulsify a heavy brine in an immiscible fluid like oil
• Use molten salts or liquid metals

Making a weighted drilling fluid – the oil
industry backs the wrong horse for > 70 years
Unfortunately the oil industry adopted Benjamin K. Stroud’s
invention filed in 1924 : Micronised barite rock in water (and later oil)

Solids-weighted drilling muds increase costs and
reduce revenues
High solids content of barite-weighted muds slows everything down,
creates additional operational costs/risk and damages the reservoir
• Well control problems caused by high ECD and barite sag
• Reduced drilling penetration rate and bit life
• Differential sticking
• Slow pipe and casing running speeds
• Long mud conditioning and flow-check times
• Failures/plugging of completion tools, seals and screens
• Formation damage !!
• Mud maintenance : barite looks same as fine drilled solids
Slow, complicated, risky and they deliver a damaged well that will
need remediation/intervention = high cost and lower profits

Kristin – A HPHT gas condensate field offshore Norway
Production from 4 HPHT wells, accessing 40 billion m3 of gas (i.e. 50% of
gas reserves in place), is plugged by the mud
10 billion m3 of recoverable gas reserves have been lost
And look what happens when a solids-weighted
mud is mistakenly used as a completion fluid in
HPHT gas wells ....

Making a heavy clear completion fluid – the oil
industry backs another lame horse in 1970’s
Unfortunately the oil industry adopts Dow’s invention filed in 1978:
Corrosive and hazardous calcium/zinc bromide brines

The clear solution – Make a weighted drilling
fluid using clear heavy brine with no barite
In 1979 Oxy Petroleum in USA drilled 4 wells with SG 1.62 calcium
chloride/bromide brine - see SPE 8223

Oxy Petroleum found big advantages to drilling with heavy solids-
free brine - see Conclusions of SPE 8223

In 1986 Dow Chemical tested the ROP of SG 1.56 calcium
chloride/bromide brine in a drilling machine - see SPE 13441

Dow found that heavy clear brines could drill sandstone up to 10
times faster than barite-weighted muds

Conventional clear completion fluids can harm
field development economics
The brines are hazardous for rig crew and for the environment

Bromide brine accidents can be distressing and costly
RAYMOND BILLIOT, JR. versus SCHLUMBERGER NORTH AMERICAAND EDISON
CHOUSET OFFSHORE
Plaintiff, a 37 year old Jones Act seaman working aboard defendant’s vessel as mechanical
technician sustained second-degree burns to 45 percent of his body after being drenched with hot
zinc bromide when a tank mixing the zinc bromide with sand was allowed to overheat causing a
plumbing failure. Suit was filed alleging negligence under the Jones Act and General Maritime Law
Unseaworthiness.
Plaintiff, who was initially helicoptered to a local hospital, was later air-evacuated to a burn center
where he was admitted and remained for 33 days. Following his discharge, plaintiff was transferred
to an in house rehabilitation unit for 17 days. He continued physical rehabilitation and wound care
after returning home. Medical costs were approximately $300,000.
Following a bench trial, judgment in the amount of $5,644,496.00 was
rendered. The Court also awarded judicial interest at the rate of 5%
from date of injury, bringing the total judgment to $6 million with
costs included.

Bromide brines can block oil and gas production completely
In the latest problem to solve, zinc bromide standardly used in well completions for
years became the culprit. It turns out that in a high pressure, high temperature
environment as found at Davy Jones, the zinc bromide acts differently than it
usually does and becomes like putty. When it comes into contact with drilling mud,
it sets up like cement. That’s just what you don’t need in a small ultra deep well that
you need to flow.”
“McMoRan's Davy Jones #1 Well Close But Still
No Banana
McMoran have spent $ 1 billion on Davy Jones so far……
Forbes magazine article – 14 June 2012 :

The brines can destroy well metals and elastomers
- Failures of structural elastomers and metals
- Stress corrosion cracking of Corrosion Resistant Alloys (CRA)
Cracking of CRA after exposure to calcium bromide and oxygen at 160oC
Super 13Cr, 1 month 22Cr, 2 months 25Cr, 2 months
Downs et al, Royal Society of Chemistry – Chemistry in the Oil Industry Conference, Manchester, UK, 1st
November 2005

Risk of liability, clean up costs and fines as a result of zinc
bromide spillage/leakage
• Priority marine pollutant
• Heavy fines for polluting aquatic and
onshore environment
• Substantial clean up costs, and any contaminated waste is
classified as hazardous
• Financial consequences of contaminating your production
stream

S.O.B - the main sources of drilling and
completion problems when using conventional
fluids
• Solids – Solid weighting agents like barite
- Reduced ROP and short bit life
- Bad effect on circulating pressure losses and ECD
- Potential to sag, causing well control risk
- Gels required, causing high swab/surge pressures
- Can create thick filter cakes, encouraging differential sticking risk
- Mess up completion operations – get into seals, valves, etc
• Oil - Oil-based drilling muds – used to stabilise shales
- Solvent for natural gas, creating a well control risk
- Gas/condensate influxes can destabilise OBM, causing barite sag
• Bromide - Bromide brines as soluble weighting agents
- Source of localised corrosion and SCC failure of CRA tubulars
- HSE hazard and creation of additional risk/liability

Particular risks posed by traditional drilling and
completion fluids in HPHT wells
Presence of Solids, Oil or Bromides in HPHT well construction fluids
can have significant effects on project economics, safety and liability
• Loss of well control
• Differential sticking and loss of hole/string
• Loss of well integrity and zonal isolation
• Reduction in well productivity

The Perfect Clear Solution - 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

Formate Brines – Properties
• Density up to 2.3 g/cm3
• pH 9-10
• Safe, non-toxic and readily biodegradable
• Low corrosion
• Protect polymers at high temperature
• Good lubricity
• Compatible with reservoirs - no formation damage
Formate brines make excellent drilling and completion fluids

fluid using low-solids heavy formate brine
In 2008 TerraTek tested the ROP in shale of low-solids 16 ppg K/Cs
formate brine in a drilling machine - see SPE 112731

fluid using heavy low-solids formate brine
Terratek found that the heavy low-solids formate brine drilled shale
2-4 times faster than oil-based muds of the same weight

fluid using clear heavy formate brine
Field trials ( 140 wells) in Canada confirm that clear potassium
formate brines drill shale much faster than barite-weighted oil-based
mud
And much fewer bits needed : 2 versus 8

Formate Brines – Their origins – Shell EOR project
Early 1980’s – Shell was developing xanthan gum viscosifier for drilling fluids
and EOR . Needed a stabiliser to protect xanthan at > 120oC

Formate Brines – Discovery by Shell
Water soluble polymers (WSP) project for EOR use at Shell
Research Centre, Sittingbourne, UK in
1980’s
• 1985 – Discover that alkali metal formates
extend the thermal stability of WSP
in solution
• 1987 – Patent filed on the use of formates
in drilling/completion fluids to
extend the thermal stability of WSP
• 1988 – John Downs of Shell International Chemicals
begins to promote the use formate brines as
low-solids drilling and completion fluids

Next stage : HPHT drilling and completion fluid
development in Shell E&P Research, 1990-94
Objective: Design an improved HPHT drilling-in and completion
fluid for deep slimhole gas wells that was free of troublesome
conventional components
• Free of Solids
• Free of Oil
• Free of Bromides
1990- John Downs transfers to Shell E&P Research Centre in The
Netherlands to develop formate brines for deep slimhole HPHT
well constructions

Formate brines – Early development, qualification
and field trials by Shell and Statoil
• 1990 Cesium formate discovery
• 1991 Extensive laboratory testing of
formate brines – e.g. HSE, corrosion
• 1992 First SPE papers published
• 1993 First drilling trials with Na formate (Drilling – Shell Draugen and
Berkel fields) supplied by Schlumberger
• 1994 First drilling trial with K formate (Gulfaks)
supplied by Baker Hughes Inteq
• 1995 Shell Formate Technical Manual published

Benefits of formate brines – Compatible with
polymers, so can be used as drilling fluids
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
A traditional low-solids formate drilling fluid formulation
This simple formulation has been in field use since 1993 – good to 160o C

Low-solids formate drilling fluids
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
Baker Hughes : CLEAR-DRILL (1994)
M-I : FLOPRO (1995)
Baroid : BRINEDRIL

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

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

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

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
Solubility of methane in drilling fluids: T = 300°F (149°C), P = 10,000 psi (690 bar)
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

No stress corrosion cracking of CRA in formate
brines
SG 1.7 K/Cs formate brine, 160oC, 10,000 ppm Cl with 0.2 bar O2
Ref : SPE 100438
Super 13Cr, 3 months Duplex 22Cr, 3 months Duplex 25Cr, 3 months

The verdict of Shell R&D in 1993 at the end of
their preliminary qualification of formates
Formates should eliminate all of the drill-in and completion
problems created by SOB in conventional fluids
• Solids-free: better hydraulics, no sag, lower sticking risk
• Oil-free: low gas solubility, better well control
• Bromide/Halide-free: better corrosion control
• Stability: viscosity and fluid loss stable to at least 170o C
• Non-damaging: better well productivities
• Low toxicity and safe to handle
• Little or no risk to the environment
• Lubricious: lower torque and drag
• High osmotic pressure : good stabilisation of shales
Formate properties particularly beneficial in deep gas HPHT slim
hole wells

Formate brines – Discovery and qualification by
Shell Research - but only Na formate available !
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

Formate brines - Early commercial development
1995-6 : Norsk Hydro and Cabot Corp. build formate plants and
create their own specialist formate service companies
• 1995 Start-up Hydro potassium formate plant,
and sell into oilfield via Forbrico JV
• 1996 - CSF formed and TANCO mine investment
- First HPHT wells drilled with K formate
in Germany – high angle slim holes
• 1997 Forbrico sells K formate into drilling/completion jobs in
Canada, Mexico, Argentina, Venezuela and Brazil
• 1998 Forbrico JV terminates. K formate marketing taken over
by Hydro Chemicals – starts to make big sales in Norway

Hydro’s potassium formate plant in Norway has
been owned by Addcon GmbH since late-2004
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

Potassium formate brine – Methods of shipment

Laboratory equipment for QA/QC on potassium
formate brine for oilfield applications
Formate brines used in the oilfield must meet basic
specifications :
• Density
• Turbidity
• pH
• Ionic composition (monovalent – no multivalents or heavy metals)
• True Crystallisation Temperature (TCT)

Laboratory equipment for QA/QC on potassium
formate brine
Portable density meter Turbidimeter
pH meter ICP Ion chromatography
TCT measurement

Typical potassium brine grades
% w/w Density TCT
SG oC
75 1.57 7
71 1.53 2
63 1.46 -13
Potassium formate brines are supplied
additive-free

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

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,
Shell)
Sodium formate powder available. Draugen wells each produce 48,000 bbl oil /day
1994 - Potassium formate brine becomes available from Norsk
Hydro
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

1999 - Development of patented non-caking potassium
formate powder

Early adopters and champions of formate brine
• M-I and Halliburton with Mobil in Germany
• M-I/Schlumberger and Statoil in Norway
• Rawabi/EMEC with Saudi Aramco in KSA
• Driven by individual local champions in these companies
Largest formate user is still Statoil in Norway supplied by M-I and
Halliburton
Norwegian engineers embrace new technology and understand
VALUE. Clearly motivated to maximise recovery of reserves and
revenues

Formate brines – Later commercial development
1999-2002: Potassium formate sales grow to >10,000 MT/annum and
cesium formate sales take off in the North Sea
• 1999 First cesium formate completions
– UK HPHT fields (Shearwater, Devenick,
Elgin)
• 2000 6 more cesium completions in UK sector
- all HPHT
• 2001 21 cesium completions , mostly in Norway. First drilling job with
cesium formate in Norway (Huldra)
• 2002- present Average 27 cesium jobs per year, mostly in Norway
Nearly all are mixtures of potasium formate with cesium formate

2003 onwards – Emergence of polyol producers
as significant suppliers of potassium formate
• Celanese and then Oxea -Texas, USA
Oxea to increase production capacities in Bishop, Texas
January 15, 2013 11:00 AM
Oxea has developed several innovative continuous processes
to expand its production at its site in Bishop, Texas, USA.
The optimizations will add significant further volume, beyond the
already announced capacity increases for potassium formate
Potassium formate is used, among other applications, as a
component in well-servicing fluids for the extraction of oil and gas
and for de-icing.
• Perstorp - Sweden
Perstorp invests in potassium formate and di-TMP
29 February 2008 14:41
Perstorp is investing €9m ($14m) in potassium formate production
Potassium formate is used in the oil industry where it helps
maximise oil extraction from wells. Another growing use is as
de-icing agent on airport runways..

Formate brines – Some important milestones :
1999-2004
1999 2000 2001 2002 2003 2004
First
production of
non-caking
crystalline K
formate by
Addcon
First drilling
jobs with
K/Cs formate
brine:
Huldra and
Devenick
HPHT
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)
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

Clear formate brine recovered from formate drilling fluids
using Rotary Drum Vaccum Filters

Traditional oilfield uses for potassium and cesium
formate brines, 1994-2017
• Low-solids heavy fluids for deep HPHT (gas) operations
- Reservoir drill-in, particularly in open hole screen wells
- Completions, as above, particularly after drill-in with formate brine
- Workovers (well repair jobs)
- Long-term well suspensions
- SCP remediation (high density Cs formate brine)
• Low-solids medium-weight fluids for conventional operations
- Calcium-sensitive reservoir drill-ins, particularly in open hole screen wells
- Completions, as above, and including LSOBM fluids for oil reservoirs
- Workovers
- Long-term well suspensions
- Packer fluids
Shale drilling may consume big volumes of K formate in the future
Two broad categories

Historically the main application for formate
brines has been in HPHT 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 2012-2017

HPHT gas fields in northern North Sea drilled
and completed with cesium formate brine
Almost every field development (oil and gas) on this map has used formate brines as well
construction fluids . Zinc bromide brine no longer used in Europe – too hazardous and damaging

Potassium and cesium 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

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
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
Fluids service provided by M-I and Baroid

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

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
Aramco consume around 300 m3/month of K formate brine

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®
in Kuwait and Saudi Arabia
Good results in first 9 HPHT wells –
could become the standard HPHT
fluid for KOC

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

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
0
100
200
300
400
500
600
700
800
900
1000
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
• 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
Both wells can produce > 150 MMscfd gas and > 6,000 bpd condensate
The maximum potential flow rate figures are 50% higher than the technical
potential predicted in the original field development plan.
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
(o
F)
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

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
• 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
[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

• 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 brine, 2001

97
Comments from Huldra project manager
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

• 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

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 USA (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, Gulf of Mexico – Formate
brine used as a packer fluid for 6 years

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
“ 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

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

- 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 efficient/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 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

And now a reputable well engineering
consultancy quantifies the time savings...
Results of Ridge’s benchmarking study is published on-line by
Cabot

Latest formate success : Shale drilling in Canada
Formates brines reduce shale drilling time by up to 50%

Shale drilling success in Canada could propel
potassium formate brine into the mainstream
DMK exploiting a discovery from 1996 – formate brines
are fast in shale

Shale drilling success in Canada with potassium
formate brine
140 shale wells drilled with potassium formate drilling fluid
since mid-2013
The cost of drilling long horizontals in shale has been reduced by
27% (Chevron/Encana data)
“ 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

And now Professor Eric van Oort, confirms that
formate brines are the best shale drilling fluids

An introduction to formate brines - a technical presentation by John Downs, June 2017

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