Drill and complete wells faster with clear formate brines
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Transcript of Drill and complete wells faster with clear formate brines
DRILL AND COMPLETE FASTER WITH CLEAR FORMATE BRINES
Reducing drilling and completion times by weeks
John Downs Formate Brine Ltd
www.formatebrine.com
Clear formate brines drill wells much faster than conventional drilling muds
Solids-free formate brines drill much faster than conventional drilling muds like OBM (Inverts)
Drilling fluids - Performance Requirements
Wellbore stabilization*
Well pressure control*Lubrication
Hole cleaning
Fluid loss control
Non-damaging to reservoir
Safe
Power transmission
Low environmental impact
Allow formation evaluation
Compatible with metalsand elastomers
Aids rock cutting Scavenges acid gases
• Typically want to keep wellbore pressure @ steady 500 psi above pore pressure
Drilling fluids have many essential functions
Completion fluids - Performance Requirements
Wellbore stabilization*
Well pressure control*
Lubrication
Clay stabilization
Fluid loss control
Non-damaging to reservoir and sand control completions
Safe Low environmental impact
Long-term compatibility with metals
Compatible with elastomers
Similar function to drilling fluids
Compatible with drilling fluid filtrate
Scavenges acid gases (CO2/H2S)
Need correct fluid weight in wellbore at all times - for well control and well stabilisation
For optimal wellbore stability and safety the fluid weight in the wellbore should be higher than the rock pore pressure and lower than the rock fracture pressure
Making a weighted drilling fluid – Some options
• Suspend mineral particles in a fluid ( water, oil, etc) to make a heavy slurry or “mud”
Barite powder
• Dissolve salts in a fluid (water, glycol) to make a clear heavy “brine”
• Emulsify a heavy brine in an immiscible fluid like oil
• Use molten salts or liquid metals
Making a weighted drilling fluid – in 1924 the oil industry chose the wrong option ! Unfortunately the oil industry adopted Benjamin Stroud’s invention
filed in 1924 : Micronised barite – a bad mistake !
Barite-weighted drilling muds increase well costs and reduce production revenues
The high solids content of barite-weighted drilling muds : - Slows everything down, - Creates operational costs/risk - Damages the reservoirSome of the problems created by barite :
•Well control problems caused by high ECD and barite sag •Reduced drilling penetration rate and bit life•Differential sticking from thick mud cakes •Slow pipe and casing running speeds•Long mud conditioning and flow-check times •Failures/plugging of completion tools, seals and screens •Formation damage reduced production •Mud maintenance problems : barite same size as drilled
solids
The clear solution – Make a weighted drilling fluid using clear heavy brine with no barite In 1979 Oxy Petroleum in USA drilled 4 wells with SG 1.62 calcium
chloride/bromide brine - see SPE 8223
The clear solution – Make a weighted drilling fluid using clear heavy brine with no barite Oxy Petroleum found big advantages to drilling with heavy solids-
free brine - see Conclusions of SPE 8223
The clear solution – Make a weighted drilling fluid using clear heavy brine with no barite In 1986 Dow Chemical tested the ROP of SG 1.56 calcium
chloride/bromide brine in a drilling machine - see SPE 13441
The clear solution – Make a weighted drilling fluid using clear heavy brine with no barite Dow found that heavy clear brines could drill sandstone up to 10
times faster than barite-weighted muds
But ... Many chloride and bromide brines are not safe to handle
The brines are hazardous for rig crew and for the environment
But.. chloride and bromide brines can ruin production from oil and gas reservoirs
Bromide brines can block oil and gas production completely
In the latest problem to solve, zinc bromide standardly used in well completions for years became the culprit. It turns out that in a high pressure, high temperature environment as found at Davy Jones, the zinc bromide acts differently than it usually does and becomes like putty. When it comes into contact with drilling mud, it sets up like cement. That’s just what you don’t need in a small ultra deep well that you need to flow.”
“McMoRan's Davy Jones #1 Well Close But Still No Banana
McMoran have spent $ 1 billion on Davy Jones so far……
Forbes magazine article – 14 June 2012 :
But .... chloride and bromide brines can destroy metals and elastomers
The brines can destroy well metals and elastomers - Failures of structural elastomers and metals - Stress corrosion cracking of Corrosion Resistant Alloys (CRA)
Cracking of CRA after exposure to calcium bromide and oxygen at 160oC
Super 13Cr, 1 month 22Cr, 2 months 25Cr, 2 months
Downs et al, Royal Society of Chemistry – Chemistry in the Oil Industry Conference, Manchester, UK, 1st November 2005
The Perfect Clear Solution - 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/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 – Properties
•Density up to 2.3 g/cm3
•pH 9-10
• Safe, non-toxic and readily biodegradable
• Low corrosion
•Protect polymers at high temperature
•Good lubricity
•Compatible with reservoirs - no formation damage
Formate brines make excellent drilling and completion fluids
The clear solution – Make a weighted drilling fluid using low-solids heavy formate brine In 2008 TerraTek tested the ROP in shale of low-solids 16 ppg K/Cs
formate brine in a drilling machine - see SPE 112731
The clear solution – Make a weighted drilling fluid using heavy low-solids formate brine Terratek found that the heavy low-solids formate brine drilled shale
2-4 times faster than oil-based muds of the same weight
The clear solution – Make a weighted drilling fluid using clear heavy formate brine Field trials ( 140 wells) in Canada confirm that clear potassium
formate brines drill shale much faster than barite-weighted oil-based mud
And much fewer bits needed : 2 versus 8
Formate brines – Discovery and qualification by Shell
1987 1988 1989 1990 1991 1992
Shell patent the use of formates as
drilling polymer stabilisers
Shell discover cesium formate
brine
Shell R&D in UK study the effect of sodium and potassium formates on the thermal stability of drilling polymers
Shell R&D in The Netherlands carry out qualification work on formate brines as HPHT drilling fluids
Shell publish first SPE papers on formate brines
Start of Shell’s formate drilling fluid
development for HPHT wells
Formate brines – Production and first field use - Milestones
1993 1994 1995 1996 1997 1998
First field use of sodium formate: Shell drills and completes first
Draugen oil wells
Start of deep HPHT gas well
drilling with formates in Germany
(Mobil, RWE, BEB)
Sodium formate powder available from the start, but no anti-caking additive. Draugen wells each produce 48,000 bbl oil /day
1995 - Potassium formate brine becomes available from Hydro Chemicals (now Addcon) in Norway
Potassium formate brines used in USA, Canada,
Mexico, Venezuela,
Brazil, Ecuador
First field use of potassium formate (with Micromax) : Statoil drills and
completes Gullfaks oil well
1997 - Cesium formate brine becomes available from Cabot
First use of formate brine
as packer fluid: Shell Dunlin
A-14
Historically the main application for formate brines has been in HPHT gas wells
Low-solids heavy fluids for deep HPHT gas well constructions
• Reservoir drill-in • Completion • Workover • Packer fluids • Well suspension • Fracking
Formate brines reduce HPHT well construction times by weeks
Used in hundreds of HPHT wells since 1995, including some of Europe’s deepest, hottest and highly-pressured gas reservoirs
The economic benefits provided by formate brines in HPHT gas field developments
Formate brines improve the economics of HPHT gas field developments by :
• Reducing well delivery time by several weeks
• Improving operational safety and reducing risk
• Delivering production rates that exceed expectations
• Providing more precise reservoir definition
More than 50 deep HPHT gas fields developed using formate brines since 1995
Country Fields* Reservoir Description
Matrix type
Depth, TVD (metres)
Permeability (mD)
Temperature (oC)
Germany Walsrode,SohlingenVoelkersen, Idsingen,Kalle, Weissenmoor, Simonswolde
Sandstone 4,450-6,500 0.1-150 150-165
Hungary Mako , Vetyem Sandstone 5,692 - 235Kazakhstan Kashagan Carbonate 4,595-5,088 - 100
Norway Huldra ,NjordKristin,Kvitebjoern Tune, ValemonVictoria, 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,ShedgumUthmaniyah Hawiyah,Haradh Tinat, Midrikah
Sandstone and carbonate
3,963-4,572 0.1-40 132-154
UK Braemar,DevenickDunbar,ElginFranklin,GlenelgJudy, Jura, KessogRhum, ShearwaterWest Franklin
Sandstone 4,500-7,353 0.01-1,000 123-207
USA High Island Sandstone 4,833 - 177
* More HPHT fields developed with formates in Kuwait, India and Malaysia
Potassium formate brine has been produced at Porsgrunn in Norway 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 % KOH4,500 m3
6,300 MT
94 % Formic acid5,000 m3
Feedstock storage tanks in Norway
Cesium formate produced by Cabot in Canada from pollucite ore
Pollucite ore Cs0.7Na0.2Rb0.04Al0.9Si2.1O6·(H20)
• Mined at Bernic Lake, Manitoba • Processed on site to Cs formate brine• Cs formate brine production 700
bbl/month
W-Cluster
15000'
14800'
Z2Z6
Z5Z7
Z4
5000'
10000'
15000'
18000'
Germany : Potassium formate brine has been used to drill deep HPHT gas wells since 1995 First use : ExxonMobil’s Walsrode field, onshore northern Germany - high-angle deep HPHT slim hole low perm gas wells
TVD : 4,450-5,547 metres Reservoir: Sandstone 0.1-125 mDBHST : 157o C Section length: 345-650 mDrilling fluid: SG 1.45-1.55 K formate brine
Potassium formate from Norway used in 15 deep HPHT gas well constructions in Germany ,1995-99
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
Further wells drilled for BEB and RWE-DEA in Germany with Porsgrunn’s potassium formate brines via Baroid (1997 onwards)
Summary of potassium formate brine use in HPHT gas wells in Germany,1995-99 – SPE 59191
Formate brines – Some further important milestones : 1999-2004
1999 2000 2001 2002 2003 2004
First production of non-caking
crystalline K formate at Porsgrunn
First drilling jobs with
K/Cs formate brine:
Huldra and Devenick
Formate brines used as packer fluids for HPHT wells in GOM. First well : ExxonMobil’s MO 822#7 (215oC BHST) in 2001
Use of Cs-weighted oil-based completion fluids for oil reservoirs : Visund, Statfjord, Njord, Gullfaks, Snorre , Oseberg, Rimfaks 2001 – present
First use of Cs-weighted LSOBM as perforating completion
fluid (Visund)
First use of K/Cs formate
brine : Completion
job in Shearwater well (Shell
UK)
Cs-weighted LSOBM used as OH screen completion
fluid (Statfjord)
First use of K/Cs
formate brine as
HPHT well suspension
fluid (Elgin G-3)
Individual Draugen oil wells (1993) and Visund oil wells (2003) have similar flow rates of around 50,000 bbl oil/day
First of 14 Kvitebjørn HPHT wells drilled and completed with K/Cs formate brines
The first sustained use of K/Cs formate brine was in the world’s largest HPHT gas field development
190oC1100bar
5300m
Water Depth 90m
SIWHPFWHT
830bar180oC
::
GASCONDENSATE
3-4% C0230-40 ppm H2S
320barDEWPOINT
30% O1 Darcy K
K/Cs formate brine used by TOTAL in 34 well construction operations in 8 deep gas fields in period 1999-2010
Elgin/Franklin field – UK North Sea
Formate brines – Some published milestones 2005 -2010
2005 2006 2007 2008 2009 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
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
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
Pakistan - OMV use potassium formate brine for HPHT deep gas well drilling and completions
Extracts from OMV’s SPE papers and SPE presentations – note 1,700 psi overbalance, and 350oF
North Sea - Heavy 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
Tune field – HP/HT gas condensate reservoir drilled and completed with potassium 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
Tune wells - Initial Clean-up – Operator’s view (direct copy of slide) June 2003
• 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 512A-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
TVD
MSL
]
A-11AHA-12HT2A-13HA-14HA-11 AH plugged back
Tune field – 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
• 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 heavy formate brine, 2001
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
• 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 heavy formate brine, 2004-2013
Kvitebjoern well
Completion time
(days)
A-4 17.5
A-5 17.8
A-15 14.8
A-10 15.9
A-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
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
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”
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”
Economic benefits from using formate brines - Latest paper
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)
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
Formate Brines : Allow fast solids-free drilling
Solids-free formate brines drill deep horizontal well sections much faster than muds like OBM – and cause less formation damage
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
- 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
• 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
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
Economic benefits from using formate brines - Good reservoir imaging
• Highly conductive fluid
• Clear resistivity images
• Information provided: - structural dip - depositional environment - geological correlations
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
Latest formate success : Shale drilling in Canada
Formates brines reduce shale drilling time by up to 50%
Latest formate success : Shale drilling in Canada
Formates brines reduce shale drilling time by up to 50%
Shale drilling success in Canada with potassium formate brine
140 shale wells drilled with potassium formate drilling fluid since mid-2013 The cost of drilling long horizontals in shale has been reduced by 27% (Chevron/Encana data)
New explanation for shale drilling success with potassium formate – Osmosis