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/gal1.59 g/cm3

13.2 lb/gal2.30 g/cm3

19.2 lb/gal

Formates are also soluble in some non-aqueous solvents

John Downs - Formate Brine Ltd 2

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

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

Paper to be presented to the 2015 SPE/IADC Drilling conference :


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


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

DevonWC 575 A-3

ST29.5 KFo 132 270 5/2005

WOG/Devon MO 862 #1 12.0 NaKFo 215 420 4/2005 5/2006Well P&A – H2O production – G-3 in excellent condition

BP/Apache HI A-5 #1 11.5 NaKFo 164 350 2/2002 4/2008Well 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

DominionWC 72 #3

BP110.0 NaFo 121 250 2006

EPLWC 98 A-3

ST112.7 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


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

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 – 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 biodegradableJohn Downs - Formate Brine Ltd 19

Benefits of formate brines – Compatible with polymers, so can be used as drilling fluids

Component Function Concentration

Formate brine

DensityLubricity

Polymer protectionBiocide

1 bbl

XanthanViscosity

Fluid loss control0.75 – 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

BufferAcid gas corrosion

control2 – 8 ppb

A traditional low-solids formate drilling fluid formulation

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

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 increase drilling ROP by >100% compared to OBM (in carbonates and shale)

Data from DOE Deep Trek project , see SPE paper 112731

Effect of Mud on Rate of PenetrationCarthage 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)

Ra

te o

f P

en

etr

ati

on

(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) John Downs - Formate Brine Ltd 24


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) John Downs - Formate Brine Ltd 25

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

Potassium Formate - Mild Steel

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

1 1.1 1.2 1.3 1.4 1.5 1.6

Specific Density

CoF

31 kg side load 21 kg side load 11 kg side load

WBM

OBM

pure water

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


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


Extracts from summary of Finnish Environment Institute report on potassium formate

“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”

“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”


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

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 (now Addcon)

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


W-Cluster

15000'

14800'

Z2

Z6

Z5Z7

Z4

5000'

10000'

15000'

18000'

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 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-InNa

Formate/Formix1.35 (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


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 % KOH4,500 m3

6,300 MT

94 % Formic acid5,000 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

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


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

190oC1100bar

5300m

Water Depth 90m

SIWHPFWHT

830bar180oC

::

GASCONDENSATE

3-4% C0230-40 ppm H2S

320barDEWPOINT

30% O1 Darcy K

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 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


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


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

0

100

200

300

400

500

600

700

800

900

1000

Well

m3

oil

/ba

r/d

ay

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

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

(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

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 SIDHPbara 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]

Dep

th [

m T

VD

MS

L]

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


65

Comments from Huldra project manager

TROND JUSTADManager-Huldra ProjectBergen, 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 - 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 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

- 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 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 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

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 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.”


http://www.ncbi.nlm.nih.gov/pubmed/16053115



http://www.ncbi.nlm.nih.gov/pubmed?term=Hellst%C3%A9n%20PP%5BAuthor%5D&cauthor=true&cauthor_uid=16053115

http://www.ncbi.nlm.nih.gov/pubmed?term=Hellst%C3%A9n%20PP%5BAuthor%5D&cauthor=true&cauthor_uid=16053115

http://www.ncbi.nlm.nih.gov/pubmed?term=Salminen%20JM%5BAuthor%5D&cauthor=true&cauthor_uid=16053115

http://www.ncbi.nlm.nih.gov/pubmed?term=Salminen%20JM%5BAuthor%5D&cauthor=true&cauthor_uid=16053115

http://www.ncbi.nlm.nih.gov/pubmed?term=J%C3%B8rgensen%20KS%5BAuthor%5D&cauthor=true&cauthor_uid=16053115

http://www.ncbi.nlm.nih.gov/pubmed?term=J%C3%B8rgensen%20KS%5BAuthor%5D&cauthor=true&cauthor_uid=16053115

http://www.ncbi.nlm.nih.gov/pubmed?term=Nyst%C3%A9n%20TH%5BAuthor%5D&cauthor=true&cauthor_uid=16053115

http://www.ncbi.nlm.nih.gov/pubmed?term=Nyst%C3%A9n%20TH%5BAuthor%5D&cauthor=true&cauthor_uid=16053115

formate brines - reservoir drilling and well completion fluids since 1993

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