DRILL AND COMPLETE FASTER WITH CLEAR FORMATE BRINES

Reducing drilling and completion times by weeks

John Downs Formate Brine Ltd

www.formatebrine.com

Clear formate brines drill wells much faster than conventional drilling muds

Solids-free formate brines drill much faster than conventional drilling muds like OBM (Inverts)

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 metalsand elastomers

Aids rock cutting Scavenges acid gases

• Typically want to keep wellbore pressure @ steady 500 psi above pore pressure

Drilling fluids have many essential functions

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 function to drilling fluids

Compatible with drilling fluid filtrate

Scavenges acid gases (CO2/H2S)

Need correct fluid weight in wellbore at all times - for well control and well stabilisation

For optimal wellbore stability and safety the fluid weight in the wellbore should be higher than the rock pore pressure and lower than the rock fracture pressure

Making a weighted drilling 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) 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 – in 1924 the oil industry chose the wrong option ! Unfortunately the oil industry adopted Benjamin Stroud’s invention

filed in 1924 : Micronised barite – a bad mistake !

Barite-weighted drilling muds increase well costs and reduce production revenues

The high solids content of barite-weighted drilling muds : - Slows everything down, - Creates operational costs/risk - Damages the reservoirSome of the problems created by barite :

•Well control problems caused by high ECD and barite sag •Reduced drilling penetration rate and bit life•Differential sticking from thick mud cakes •Slow pipe and casing running speeds•Long mud conditioning and flow-check times •Failures/plugging of completion tools, seals and screens •Formation damage reduced production •Mud maintenance problems : barite same size as drilled

solids

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

The clear solution – Make a weighted drilling fluid using clear heavy brine with no barite Oxy Petroleum found big advantages to drilling with heavy solids-

free brine - see Conclusions of SPE 8223

The clear solution – Make a weighted drilling fluid using clear heavy brine with no barite In 1986 Dow Chemical tested the ROP of SG 1.56 calcium

chloride/bromide brine in a drilling machine - see SPE 13441

The clear solution – Make a weighted drilling fluid using clear heavy brine with no barite Dow found that heavy clear brines could drill sandstone up to 10

times faster than barite-weighted muds

But ... Many chloride and bromide brines are not safe to handle

The brines are hazardous for rig crew and for the environment

But.. chloride and bromide brines can ruin production from oil and gas reservoirs

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 :

But .... chloride and bromide brines can destroy metals and elastomers

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

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/gal1.59 g/cm3

13.2 lb/gal2.30 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

The clear solution – Make a weighted drilling 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

The clear solution – Make a weighted drilling 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

The clear solution – Make a weighted drilling 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 – Discovery and qualification by Shell

1987 1988 1989 1990 1991 1992

Shell patent the use of formates as

drilling 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 HPHT drilling fluids

Shell publish first SPE papers on formate brines

Start of Shell’s formate drilling fluid

development for HPHT wells

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 from the start, 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 Norway

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

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

Formate brines reduce HPHT well construction times by weeks

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 by several weeks

• Improving operational safety and reducing risk

• Delivering production rates that exceed expectations

• Providing more precise reservoir definition

More than 50 deep HPHT gas fields developed using formate brines since 1995

Country Fields* Reservoir Description

Matrix type

Depth, TVD (metres)

Permeability (mD)

Temperature (oC)

Germany Walsrode,SohlingenVoelkersen, Idsingen,Kalle, Weissenmoor, Simonswolde

Sandstone 4,450-6,500 0.1-150 150-165

Hungary Mako , Vetyem Sandstone 5,692 - 235Kazakhstan Kashagan Carbonate 4,595-5,088 - 100

Norway Huldra ,NjordKristin,Kvitebjoern Tune, ValemonVictoria, 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,ShedgumUthmaniyah Hawiyah,Haradh Tinat, Midrikah

Sandstone and carbonate

3,963-4,572 0.1-40 132-154

UK Braemar,DevenickDunbar,ElginFranklin,GlenelgJudy, Jura, KessogRhum, ShearwaterWest Franklin

Sandstone 4,500-7,353 0.01-1,000 123-207

USA High Island Sandstone 4,833 - 177

* More HPHT fields developed with formates in Kuwait, India and Malaysia

Potassium formate brine has been produced at Porsgrunn in Norway 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 % KOH4,500 m3

6,300 MT

94 % Formic acid5,000 m3

Feedstock storage tanks in Norway

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

W-Cluster

15000'

14800'

Z2Z6

Z5Z7

Z4

5000'

10000'

15000'

18000'

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 mDBHST : 157o C Section length: 345-650 mDrilling 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 – SPE 59191

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

190oC1100bar

5300m

Water Depth 90m

SIWHPFWHT

830bar180oC

::

GASCONDENSATE

3-4% C0230-40 ppm H2S

320barDEWPOINT

30% O1 Darcy K

K/Cs 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 Franklin1999-2011

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

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 - Heavy 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 potassium 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 SIDHPbara bara bara bara

A-11 AH 169 - 388 -A-12 T2H 175 487 414 510

A-13 H 395 514 412 512A-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]

Dep

th [m

TVD

MSL

]

A-11AHA-12HT2A-13HA-14HA-11 AH plugged back

Tune field – 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 heavy 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 - 30,000 bbl/day condensate

Good sustained production - 78% of recoverable gas and 89% of condensate produced by end of Year 7 - Despite rapid pressure decline.....

NPD current estimate of RR: - 17.5 billion m3 gas - 5.1 million bbl condensate

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 heavy formate brine, 2004-2013

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

- 48,000 bbl/day condensate

Good sustained production (end Y8) - 37 billion m3 gas - 17 million m3 of condensate - Produced 70% of original est. RR by end of 8th year

NPD : Est. RR have been upgraded - 89 billion m3 gas (from 55) - 27 million m3 condensate (from 22)

Note : Shut down 15 months, Y3-5 - To slow reservoir pressure depletion - Repairs to export pipeline

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 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

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)

Economic benefits from using formate brines

- 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

Economic benefits from using formate brines - 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)”

Economic benefits from using formate brines

- 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

Economic benefits from using formate brines - Operational efficiencies

Economic benefits from using formate brines - 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

Economic benefits from using formate brines - 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

Latest formate success : Shale drilling in Canada

Formates brines reduce shale drilling time by up to 50%

Latest formate success : Shale drilling in Canada

Formates brines reduce shale drilling time by up to 50%

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)

New explanation for shale drilling success with potassium formate – Osmosis