Potassium formate brine with Micromax

POTASSIUM FORMATE WITH MICROMAX®

DRILL-IN AND COMPLETION FLUIDS SINCE 1994

John Downs

Formate Brine Ltd

www.formatebrine.com

Gullfaks C-18 – first use of potassium formate brine

with Micromax in 1994

John Downs - Formate Brine Ltd 2

1st page from original

C-18 well recap

Gullfaks C-18 – first use of potassium formate brine with

Micromax in 1994

2nd page from original

C-18 well recap


Gullfaks C-18 – first use of potassium formate brine with

Micromax in 1994


3rd page from original C-18

well recap

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


Formate brines – Properties that make them

excellent drilling and completion fluids

• Density up to SG 2.3

• pH 9-10

• Only monovalent ions (Na+, K+, Cs+, HCOO-)

• Stabilise shales (K, Cs and low water activity)

• Protect polymers at high temperature

• Less corrosive than other brines

• Good lubricity

• Non-toxic and readily biodegradable


Formate brines are compatible with polymers-

so they can be used as drilling fluids

Component Function Concentration

Formate brine

Density

Lubricity

Polymer protection

Biocide

1 bbl

XanthanViscosity

Fluid loss control0.75 – 1 ppb

Lo- Vis PAC and modified

starchFluid 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


Formate brines launched as low-solids drilling

and completion fluids in 1992

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 and

launch date:

IDF : IDSALT-F (1992)

Baker Hughes : CLEAR-DRILL (1994)

M-I : FLOPRO (1995)

Baroid : BRINEDRIL

Filter cake on aloxite disc

8

Addcon’s potassium formate plant in Norway has

been supplying the oil industry since 1994

Production Site

ADDCON NORDIC AS

Storage tanks for raw

materials


Potassium formate production by Addcon

• The first and largest producer of potassium formate

- Brine production capacity : 800,000 bbl/year

- Non-caking powder capacity: 8,400 MT/year

• Direct production from HCOOH and KOH

• High purity product

• Large stocks on quayside location

• Fast service – by truck, rail and sea

• Supplier to the oil industry since 1994

50 % KOH

4,500 m3

6,300 MT

94 %

Formic acid

5,000 m3

Feedstock storage tanks in

Norway


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®

used for HPHT drilling in Kuwait and Saudi Arabia

Good results in the first 11 wells (TKMN 4 ,

RA286, AD 53, SA 297, LH 03, MU 15, AJ 03,

SBG 02, NMN 01, LH 04, RH 03) with 16 ppg

fluids in fractured carbonates and sandstone


Reasons why KOC use potassium formate brine

weighted with Micromax® for HPHT drilling

• Non-hazardous and satisfies environmental requirements

• Minimises formation damage in carbonates

• Compatible with hardware/tools and elastomers

• Better resolution and quality from wireline logs

• Elimination of solids sag at high downhole temperatures

• Micromax® is acid soluble


KOC use K formate brine weighted with Micromax® for

drilling deep HPHT fractured carbonate wells


First well drilled by KOC with KFo Micromax®

- Raudhatain field in 2009 (SPE 132151)

• Jurassic reservoir, light oil and gas, HPHT with CO2

and H2S. Vertical well. BHST : 280

oF

• 7-inch hole in fractured limestone/anhydrite

- 16 ppg K formate Micromax fluid (12.5-13.5% v/v Micromax)

- 472 metres drilled (14,790-15, 262 m) in 48.5 hours = 9.7 ft/hour

- 20-30% anhydrite/70-80% limestone

- No losses !

• 6-inch hole in fractured limestone/anhydrite/shale

- 1,278 metres drilled (15,262-16,530 m) @ 6-33 ft/hour

- Shale/anhydrite/limestone

- Low losses

- ROP comparable to OBM

- No hole cleaning problems. Low ECD and pump pressures




In conventional formate fluids low-vis PAC is added to flocculate clay fines


Component , in order of

addition

Mixing time

(minutes)Concentration

Potassium formate brine,

SG 1.50 - 0.79 bbl

Sodium carbonate 5 0.2 ppb

Viscosifier 10 0.15 ppb

“Starch Plus” 10 5 ppb

Starch 10 4 ppb

Sized marble 5/50/150 5 30 ppb

Micromax 10 281 ppb

KFo Micromax fluid formulation – 17.5 ppg, pH 11



In conventional formate fluids low-vis PAC is added to flocculate clay fines


Component , in order of

addition

Mixing time

(minutes)Concentration

Potassium formate brine,

SG 1.50 - 0.79 bbl

Sodium carbonate 5 0.2 ppb

Viscosifier 10 0.15 ppb

“Starch Plus” 10 5 ppb

Starch 10 4 ppb

Sized marble 5/50/150 5 30 ppb

Micromax 10 281 ppb

KFo Micromax fluid formulation – 17.5 ppg, pH 11



Bridging agent added continuously through a hopper to reduce fluid loss


16 ppg KFo Micromax fluid properties during use

Property Typical values

PV [cP] 42-64

YP [lb/100ft2] 20-25

10’ gel 7-8

HPHT fluid loss [mL] 5-6

API fluid loss <0.8-2.0

Manganese tetraoxide (% by volume) 12.5-13.5

KOC use K formate brine weighted with Micromax® for

drilling deep HPHT fractured carbonate wells


HPHT exploration well drilled by KOC with

KFo Micromax® in 2011 (SPE 163301)

• Marrat formation in deep Jurassic reservoir, light oil

and gas with CO2

and H2S. Vertical well. BHST 300

oF

• 7-inch hole in fractured limestone/anhydrite

- 15.9 ppg K formate Micromax fluid

- 1,534 ft drilled (15,516-17,040 ft) in 11 days

- Marrat formation (anhydrite/limestone )

- “ “Drilling was carried out without any of the complications

faced while drilling … with OBM”

- Good cement bond behind 5-inch liner casing

• Image Log quality in formate fluid was better than

the image log recorded in OBM


HPHT exploration well drilled by KOC with KFo

Micromax® in 2011 – Conclusions from SPE 163301


17,566 ft TD well drilled by KOC with 17.4 ppg KFo

Micromax® Production rate increased 3-fold


KOC review of using K formate brine weighted with

Micromax® for drilling deep HPHT wells (SPE 170472)


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


KOC – Lessons from using KFo Micromax® for

HPHT drilling (from SPE 170472)

• Keep viscosifier levels very low (< 0.25 ppb) and YP < 30

• KFo Micromax fluids foam badly if contaminated with OBM

• The pH buffering additives (but not formate) react with cement

• Stuck pipe should be released by spotting formic acid pills

• Excessive build up of LGS reduces the fluid lubricity

• Do not let the brine density drop below 12 ppg (soft cuttings)

• The Micromax became self-supporting after shearing through bit,

so high gel strengths not required.


Potassium formate brine with Micromax

Technology