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
1st page from original
C-18 well recap
2 John Downs - Formate Brine Ltd

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

Formate brines launched as low-solids drilling
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

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
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”

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 CO
2
and H
S. Vertical well. BHST : 280oF
2
• 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

KFo Micromax fluid formulation – 17.5 ppg, pH 11
Component , in order of
addition
In conventional formate fluids low-vis PAC is added to flocculate clay fines
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

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)
Bridging agent added continuously through a hopper to reduce fluid loss
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 CO
2
and H
S. Vertical well. BHST 300oF
2
• 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

Recommended

Recommended

More Related Content

What's hot

What's hot (20)

Viewers also liked

Viewers also liked (20)

Similar to Potassium formate brine with Micromax

Similar to Potassium formate brine with Micromax (20)

More from John Downs

More from John Downs (20)

Recently uploaded

Recently uploaded (20)

Potassium formate brine with Micromax