spe 165151 gunnar olsvik and siv howard, cabot specialty fluids john downs, formate brine ltd spe...

SPE 165151

Gunnar Olsvik and Siv Howard, Cabot Specialty Fluids

John Downs, Formate Brine Ltd

SPE European Formation Damage conference , Noordwijk, The Netherlands, 5-7 June 2013

The Long-Term Production Performance of Deep HPHT Gas Condensate Fields Developed Using

Formate Brines

Formate brines

SPE European Formation Damage conference, 5-7 June 2013 2

Sodium formate

Potassium formate

Cesium formate

Solubility 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 for HPHT gas wells

Low-solids heavy fluids for deep HPHT gas well constructions

• Reservoir drill-in

• Completion

• Workover

• Packer fluids

• Well suspension

• Fracking (OHMS)

Used in hundreds of HPHT wells since 1995, including some of

Europe’s deepest, hottest and highly-pressured gas reservoirs

3SPE European Formation Damage conference, 5-7 June 2013

42 deep HPHT gas fields developed using formate

brines, 1995-2011* (published data)

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


* Now more HPHT fields in Kuwait, India and Malaysia during 2012-2013

The economic benefits of using formate brines in HPHT gas field developments – Reference 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”

SPE European Formation Damage conference, 5-7 June 20135

Formate brines – The economic benefits provided in HPHT gas field developments

Formate brines tend to improve oil and gas field development economics by :

• Reducing well delivery time and costs

- 12 years of use with screens

- Very good with ESS

• Improving well/operational safety

and reducing risk

• Delivering production rates that exceed expectations

• Providing more precise reservoir definition


Several highlights from some Kvitebjoern HPHT gas wells drilled and completed with formates

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

7

“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 quote after well testing (Q3 2004 )

The Well PI was almost double the target

SPE European Formation Damage Conference, 5-7 June 2013

Fast open hole screen completions and high well productivity

But productive for how long ?

Objectives of the analysis presented in this paper :

• Map the production profiles of North Sea HPHT fields

where formate brines were the last fluids to contact the

reservoirs in every well

• Compare actual cumulative production over time against

published estimates of recoverable reserves at start-up

• See if the well construction design influences the

production profile (e.g. Cased vs. Open hole completions)


Reviewed long-term production from 8 North Sea HPHT gas condensate fields in 3 categories


Category Fields Reservoir penetration and well completion

1 Tune

Huldra

All production wells drilled and completed in high-angle open hole with formate brines. Single filtrate

in reservoir.

2 2 Kvitebjørn

All production wells drilled and completed in high-angle open- and cased-holes with formate brines.

Multiple filtrate types in reservoir surrounding cased holes.

3

Braemar

Glenelg

Jura

Rhum

West Franklin

All production wells drilled with oil-based mud, then completed in cased hole with formate brines as the

perforating fluids (with and without kill pills).

Multiple filtrate types in all wells

Production data obtained from UK DECC and Norwegian NPD websites

Tune field – semi-HP/HT gas condensate reservoir drilled and completed with formate brines, 2002

10

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


11

• 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)

12

Good early production from the 4 wells - « No skin» - 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

Open hole screen completions and single filtrate


• 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 brines, 2001


Huldra – Production of recoverable gas and condensate reserves since Nov 2001 (NPD data)

14

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

Open hole screen completions and single filtrate


• 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 formate brines, 2004-2013


Kvitebjørn– Production of recoverable gas and condensate reserves since Oct 2004 (NPD data)

16

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


Formate brines have been used to complete all of the cased wells in 5 HPHT fields in UK North Sea

All wells drilled with OBM


* The deepest, hottest and highest-pressured fields in UK North Sea

Field Operator No.

of wells

Depth

(meters)

Pressure

(bar)

Temp

(oC)

Wellhead Brine density

(kg/m3)

Braemar Marathon1

(NP)4,500 701 136 Sub-sea 1.86

Rhum Rhum BP 3 4,750 862 149 Sub-sea 2.19

West Franklin*

Total 2

(NP)7,327 1,154 204 Platform 1.94

Glenelg*Glenelg* Total 1

(NP) 7,385 1,150 200 Platform 1.78

JuraJura Total 2 3,935 702 127 Sub-sea 2.09

Fluid losses from HPHT wells in UK North Sea perforated in formate brines


Field Kill Pill Fluid losses during and after perforating

(m3)

Comment

Braemar – 1 well No 2.3Re-perforation of 18 year old

appraisal well. Short flow and then zero losses

Rhum Rhum Yes 0.5Flowed in first few minutes, then zero losses for 3 days

Glenelg – 1 well No 17.72m3 on perforating and then

15.7m3 seepage losses

Jura Jura Yes –over

perfs1.46 Flow stopped within 3 hours

West Franklin West Franklin No 565

F9Y - Pumping brine at intervals during period 29 June-

18th July to maintain WHP during 2 perforating runs and

fishing

Braemar field – Production of recoverable gas and condensate

reserves since September 2003 (DECC data)

19

Estimated (2003) recoverable reserves produced in full from this single well development by Year 9

Estimated recoverable reserves - 3.28 billion m3 gas - 1.59 million m3 condensate

Cumulative production @Sep 2012 - 3.4 billion m3 gas - 1.9 million m3 condensate


Glenelg – Production of gas and condensate since March 2006 (DECC data)

20

No published reserves information ? Similar to Braemar ?

Highest temperature and pressure reservoir developed in UK North Sea (2006), accessed by single extended reach well

Good initial productionOperator statements : - «30,000 boe/day capability» - «500,000 m3/year condensate»

Cumulative production @ Feb 2011 - 2.2 billion m3 gas - 2.13 million m3 condensate


West Franklin – Production of gas and condensate from West Franklin/Franklin 2001-11 (DECC data)

21

No published reserves information. Hottest, highest pressure commercial development in world (2007), accessed by two extended reach wells, F7z and F9y

Excellent initial productionOperator statements : - « F9y has 40,000 boe/day capability» - «one of most productive wells in N. Sea» - «2.6 million m3/day of gas from F9y»

West Franklin has sustained the Franklin field output - > 2.5 billion m3 gas per year from Y6 onwards

Note : 566 m3 of cesium formate brine was pumped into formation around F9Y


BP Rhum field – largest undeveloped gas field in UK in 2005

SPE European Formation Damage conference, 5-7 June 2013 22

45 mD sandstone reservoir

Rhum field – Production of recoverable gas reserves: December 2005- October 2010 (DECC data)

23

After nearly 5 years the 3 Rhum production wells had produced 35% of the estimated recoverable gas reserves

Estimated recoverable reserves - 23 billion m3 gas

Cumulative production Oct 2010 - 7.9 billion m3 gas

Production suspended since late 2010

- EU sanctions against Iran


Jura – Production of gas and condensate since May 2008 (DECC data)

24

Estimated (2008) proved and probable reserves of 170 million boe – no published segmentation by hydrocarbon type

Good initial production from 2 wells - 1.87 billion m3 gas produced during Y2

Cumulative production @ June 2012 - 6.58 billion m3 gas - 1.1 million m3 condensate

= 46 million boe in total = 27% production of est. RR after 4 years


Conclusions – Cat 1 HPHT wells - Drilled and completed in high-angle open hole with formate brines

Tune and Huldra fields produced 100% of recoverable gas and condensate reserves within 10 years – average 3.5 billion m3 gas /well

Gas – 90% in 7-8 years Condensate – 90% in 5-7 years

Provides evidence that drilling and completing HPHT gas production wells in open hole with formate brines can be a successful strategy

25Formate Brine Seminar - Stavanger, 22 November 2012

Conclusions – Cat 2 HPHT wells - Drilled and completed in open- and cased-hole with formate brines

Kvitebjørn field has produced 70 % of the original estimated reserves by end of Year 8 – despite production constraints

• Gas production has been at a steady

6-7 billion m3/year for last 4 years – already

produced 3 billion m3 gas per well

• Need more time to see how the production

progresses towards upgraded recoverable

reserves estimate

• Good chance to compare durability of open- hole versus cased-hole

HPHT wells ?


Conclusions – Cat 3 HPHT wells - drilled with OBM and completed

in cased-hole with formate brines (no pill)

Braemar and Glenelg are both small rich-gas condensate fields drained by single cased wells perforated in formate brines without kill pills. Low brine losses.

• Braemar reached original est. RR figure by

Year 9

• Glenelg following same gas production track

and already exceeded 2 million m3 condensate

production by Year 5



in cased-hole with formate brines (no pill)

West Franklin is a «200 million boe» gas condensate field currently drained by 2 cased wells, perforated in formate brines. Large brine volume pushed into reservoir from well F9y

• No cumulative production data available but

was apparently producing >30,000 boe/day

in the 4 years before Elgin gas leak in

March 2012

•West Franklin Phase 2 development in

progress

Too early to get a picture of long-term production performance



in cased-hole with formate brines+ kill pill

Rhum and Jura are lean gas condensate fields drained by 3 and 2 cased wells respectively, perforated in formate brines with kill pills

• Rhum : 35% recovery of gas reserves by Year 5,

before production suspended

• Jura : 27% recovery of gas reserves after 4 years

Too early to get a picture of long-term production performance


spe 165151 gunnar olsvik and siv howard, cabot specialty fluids john downs, formate brine ltd spe...

Documents

deep hpht gas fields

kvitebjoern hpht gas

hpht fields

use of formate brines

hundreds of hpht wells

pressured gas reservoirs

years of use

economic benefits