Formate brines – Some published milestones 2005 -2010

20052005 20062006 20072007 20082008 20092009 2010 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

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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

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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

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Summary from Aramco’s OTC paper 19801

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Pakistan - OMV use potassium formate brine for HPHT deep gas well drilling and completions

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Extracts from OMV’s SPE papers and SPE presentations – note 1,700 psi overbalance, and 350oF

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North Sea - K/Cs 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

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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

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Tune wells - Initial Clean-up – Operator’s view (direct copy of slide) June 2003

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• 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

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• 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 K/Cs formate brine, 2001

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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

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• 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

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A few of the highlights from Kvitebjoern

Kvitebjoern well

Completion time

(days)

A-4 17.5

A-5A-5 17.8

A-15 14.8

A-10A-10 15.9

A-6A-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

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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

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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”

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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)

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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

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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

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- 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

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• 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

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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

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Economic benefits from using formate brines - Good reservoir imaging

• Highly conductive fluid

• Clear resistivity images

• Information provided: - structural dip - depositional environment - geological correlations

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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

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OPERATOR LOCATIONPacker 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 GOM

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• 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 – Na/K formate brine as packer fluid for 6 years

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