SPE 130376 A Review of the Impact of the Use of Formate Brines on the Economics of Deep Gas Field...

SPE 130376

A Review of the Impact of the Use of Formate Brines on the Economics of Deep

Gas Field Development Projects

John Downs

Cabot Specialty Fluids

2010 SPE Deep Gas Conference, Bahrain, 24-26 January

Deep gas wells are expensive .....

•12 times more expensive than conventional gas wells *

•Last 10% of deep gas well accounts for 50% of total well cost *


* US Department of Energy website - Onshore gas well costs in USA** Snead (2005) - The Economics of Deep Drilling in Oklahoma

Gas well cost versus depth**

Some basic principles for improving the economics of deep gas field developments ?

Working at depth is expensive, so.. :

•Use technologies that will accelerate deep well construction *

• Get it right first time – avoid costly interventions

• Know what is down there - ensure accurate reservoir evaluation

•Focus on recovering your substantial investment - extract

recoverable reserves as fast as the reservoir (engineers) will allow

* US DOE ”Deep Trek” R&D programme aimed at identifying some of these technologies


How can well construction fluids influence economics of deep gas field developments ?

WCF performance impacts on costs and revenues

• Time taken to drill and complete the required wells

• Well design and placement

• Well control and safety

• Well integrity, lifetime and maintenance

• Logging capability and interpretation

• Waste management and liabilities

• Rate of recovery of reserves


Extreme conditions in deep wells expose the performance

deficiencies of conventional WCF

High temperatures and hydrothermal chemistry -Barite sag, leading to well control problems -Need gels, causing high swab, surge and start-up pressures-Corrosive gas influx into halide brines will destroy ”corrosion resistant alloys”


Super 13Cr, 1 month 22Cr, 2 months 25Cr, 2 months

Extreme conditions in deep wells expose the performance

deficiencies of conventional WCF

High pressures and hard rocksHigh solids loading have negative effects on ECD, ROP, bit life, swab and

surge, differential sticking, hole cleaning, tools, screens, seals, formation, etc ......!


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

From :SPE 112731 “Optimisation of Deep Drilling Performance with Improvements in Drill Bit and Drilling Fluid Design”

Best fluid for high ROP and long bit-life is solids-free water …

Extreme conditions in deep gas wells expose the

performance deficiencies of conventional WCF

Narrow drilling windows, aggravated by pressure depletion from

production

-Production while drilling lowers pore pressure and fracture gradient

-Solids-weighted muds may not be able to stay within ECD limits

-Well control problems if fracture pressure gradient exceeded

-Increasingly the domain of MPD and ”designer fluids” providing Fracture Gradient

Enhancement (FGE) or Stress Caging effects


FGE - Increasing hoop stresses around the well bore by creating short stabilised fractures

http://www.oilproduction.net/imgenes/Aug06Bar_WellSet_bb.jpg


Conventional high-density completion fluids used in deep

gas wells have a high cost of ownership


Software tool now available that calculates the full cost of

owning and using high-density completion fluids


Prices the full operational costs, waste costs and the cost of “incidents”


Cost of fluid ownership


- Purchase /leasing fee - Transport onshore /offshore- Sub-optimal rig time- Well clean up time - Waste treatment and disposal - Stand-by time - Isolation and treatment of produced water - Production delays - Production handover delays - Liabilities and legal fees arising from splashes, spills, releases

Factors in damage caused to company reputation by incidents

BrineWise tool calculates all fluid ownership costs

So.. do conventional WCF influence the economics of deep gas field developments ?

Undoubtedly YES – conventional WCF have problems and influence economics by increasing overall development costs of deep gas fields

• Lengthening the time taken to drill and complete

• Creating well control and safety risks

• Degrading well integrity/durability

• Raising waste management costs and liabilities – i.e. high cost of

ownership

...And if they are damaging to the formation they may

reduce the rate of revenue generation 2010 SPE Deep Gas Conference, Bahrain, 24-26 January

How do you make a WCF that performs better under extreme conditions in deep gas wells ?

Remove the source of the problems -Remove the solid-weighting agents

-Remove any halide salts (chlorides and bromides)

-Preferably remove any hydrocarbons too (well control risk and logging issues)

Formate brines developed by Shell Research, 1985-95


Density to SG 2.3 /19.2 ppg/143 pcf

No solids No halides No hydrocarbons Anti-oxidant

Drilling, completion, workover and suspension fluids for deep gas wells



W-Cluster

Z2

Z6

Z5Z7

Z4

5000'

10000'

15000'

18000'

1995 – Formate brines used for first time by Mobil to drill and work over deep gas wells, onshore, northern Germany

Walsrode field – onshore, high-angle slim hole wells Z1, Z5, Z6 and Z7

TVD : 4,450-5,547 metres Reservoir: Sandstone 0.1-125 mDBHST : 315oF (157o C) Section length: 345-650 metres

Outcome of Mobil’s first drilling trials with formate brines in

onshore deep gas wells - 1995/96

Absence of weighting solids has a clear impact on efficiency and

economics 1,2

“Use of formate drilling fluid ….eliminated most of the previous hole problems

...resulted in a dramatic increase in drilling performance and hydraulics…

and significantly reduced well costs”

Low-solids drilling fluid concept appears to be validated

1) Sundermann, R. and Bungert, D.: “Potassium-Formate-Based Fluid Solves High Temperature Drill-In

Problem,” Journal of Petroleum Technology (November 1996) 1042

2) Bungert, D., Maikranz, S., Sundermann, R., Downs, J., Benton, W. and Dick, M.A.: “The Evolution and

Application of Formate Brines in High-Temperature/High-Pressure Operations”, IADC/SPE 59191, IADC/SPE

Drilling Conference, New Orleans, 23-25 February 2000.


Formate brines used by Mobil in 15 deep gas well

constructions in northern Germany 1995-1999 (SPE

59191)


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-In Na Formate/Formix 1.35 (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

Huldra field, HP/HT gas condensate -BHST: 297oF-TVD : 3,900 metres/12,795 ft - Fluid density: 15.75 ppg/118 pcf - 6 wells – 600 ft reservoir sections 5-7/8” at 45-55o

- 1–2,000 mD sandstone-Open hole, wire wrapped screens

Justification for using formate - Improve well control ! - Lower ECD- Run completion in same fluid - Low risk of screen plugging - Shale stabilisation - Lubricating- Safe for crews - Environmentally benign


2001 - Formate brines used for first time by Statoil to drill and complete 6 deep HPHT gas wells, offshore, Norway

Operator had experienced kicks when using barite-weighted fluids

Outcome of Statoil’s first drilling trials with formate brines in

offshore deep gas wells - 2001/02

Efficiencies and economies provided by drilling at depth with low-

solids brine 1

“Stable hole, low ECD, good hole cleaning and stable fluid has led to rig time savings due to:

•Fast tripping speed

•Fast casing running speeds

•Less mud conditioning and wiper trips than with conventional drilling fluids”

Low-solids fluid enables faster well constructions at depth

1) Saasen, A., Jordal, O.H., Burkhead, D., Berg, P.C., Løklingholm, G., Pedersen, E.S., Turner, J. and Harris, M.J.:

“Drilling HT/HP Wells Using a Cesium Formate Based Drilling Fluid,” IADC/SPE 74541, IADC/SPE Drilling

Conference, Dallas, 26-28 February 2002.


Deep and/or HPHT gas fields developed using formate brines as WCF 1995-2009

Author has good information on 35 fields


Some deep and/or HPHT gas fields developed using formate brines

Country Fields Reservoir Description

Matrix

type

Depth, TVD

(metres)

Permeability

(mD)

Temperature

(oC)

Germany Walsrode,Sohlingen

Voelkersen,Idsingen

Sandstone 4,450-6,500 0.1-150 150-165

Hungary Mako Sandstone 5,692 - 235

Kazakhstan Kashagan Carbonate 4,595-5,088 - 100

Norway Huldra ,Njord

Kristin,Kvitebjoern

Tune, Valemon

Victoria

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

Formate brine used in > 140* deep and/or HPHT gas wells , 1995- present

Drilling, completion, workover, suspension and packer fluids

•At densities up to SG 2.25 (18.7 ppg or 140.2 pcf)

•At BHST up to 235oC (450oF)

• For periods of > 10 years dowhole (packer fluid applications)

•In sandstone and carbonate reservoirs, 0.01 mD up to 4 Darcy

•Wide variety of completions – barefoot open hole, cased and

perforated, with sand screens and gravel packs

* Actual field/well numbers will be greater – but some are not documented


Deep gas fields where formate brines have been used as WCF – segmented by operator


Formate brines used in the world’s largest HPHT gas field development – Elgin/Franklin


Also the deepest HPHT gas field in North Sea

B

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 1999-2009

Gaining an economic perspective – Scope of review

•Only examined Cs formate brine applications (more extreme conditions)

•128 user observations extracted from 5 published field case histories

•8-year production figures found for two HPHT gas fields drilled and

completed entirely with potassium/cesium formate brines

•Observations on well construction efficiencies tend to be qualitative

rather than quantitative


1) Collect and analyse user observations on operational well construction efficiencies

2) Look for examples of long-term production rates, for evidence of production efficiencies

Economic benefits from use of formate brines in deep gas

field developments – Results of review

“ a remarkable record of zero well control incidents in all 15

HPHT drilling operations and 20 HPHT completion operations”

Operational efficiencies provide well construction cost reductions

1.Better drilling environment gives rig-time savings - 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





2. Allowing faster and easier movements of tubulars and fluids - Pipe and casing running speeds are faster

- Mud conditioning and flow-check times shorter - Displacements simplified, and sometimes eliminated (i.e. formate drilling fluid = formate completion fluid)

Quote by operator : “ Improved well economics by increasing trip speed”





3. Faster completions

HPHT gas well completion timesfrom the Rushmore database

-Wells drilled with OBM vs cesium formate brine

Quote by operator : “ fastest HPHT completion operation ever performed in North Sea (12.7 days)”


Efficient delivery of gas reserves (revenues)

Tune and Huldra fields – drilled and completed with formate brines

90% recovery of reserves (16-18 billion m3) produced in 7 to 8 years


Source : Norwegian Petroleum Directorate- Fact Pages - November 2009

Efficient delivery of condensate reserves (revenues)

Tune and Huldra fields – drilled and completed with formate brines

90% recovery of reserves (3-5 million m3) produced in 4 to 6 years


Source : Norwegian Petroleum Directorate- Fact Pages - November 2009

Conclusion

Results of this review suggests that the use of formate brines in deep gas field developments has reduced well construction times and costs by :

- Providing a better drilling environment - Allowing faster/easier movements of WCF and hardware - Allowing faster completions

The non-damaging nature of formate brines may have contributed to the efficient production of recoverable hydrocarbon reserves from two HPHT gas/condensate fields examined in this study.


Footnote 1

Results of independent Eco-efficiency study by BASF show thatcesium formate brine is the most sustainable high-density completion fluid


Leasing of cesium formate brine encourages a sustainable approach

Footnote 2


“Using photoelectric factor and bulk density data, combined with resistivity measurements from both the LWD drill pass and the ream pass, produces a very reliable and consistent net reservoir definition.”

Good reservoir definition in cesium formate brine

Footnote 3


“Applying a conductive drilling fluid in all production wells drilled in a field also provides the possibility of running high quality resistivity image logs (FMI). Extensive use of such logs provides the geo-modelers with detailed information regarding structural dip, depositional environment, sedimentary features, facies, and geological correlations.”

Good reservoir definition in cesium formate brine

SPE 130376 A Review of the Impact of the Use of Formate Brines on the Economics of Deep Gas Field...

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