for mate fluids
TRANSCRIPT
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Specialty Fluids
Update on Formate Fluids and Field Update on Formate Fluids and Field ApplicationsApplications
AADE Houston Chapter Fluids Management Group MeetingAADE Houston Chapter Fluids Management Group Meeting
October 11, 2006October 11, 2006
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Aerial Photo of TANCO Mine Pollucite:-Originally discovered: 1846 - San Piero, Campo, Elba, Livorno Province, Tuscany, ItalyNamed after Pollux, a figure from Greek mythology, brother of Castor, for its common association with “Castorite”(petalite)Chemical makeup: Cs0.7Na0.2Rb0.04Al0.9Si2.1O6·(H20)
Found in many places including:
– Bikita, Masvingo, Zimbabwe
– Shigar Mine, Skardu, Pakistan
– Varuträsk, Västerbotten, Sweden
– Kunar Province, Afghanistan
– Oxford, Maine, USA
– Ray Mica Mine, North Carolina, USA
Most abundant source ofMost abundant source of PollucitePollucite, , containing around 15 containing around 15 –– 22%22%CesiumCesium Oxide is found at Bernic Lake, Manitoba, CanadaOxide is found at Bernic Lake, Manitoba, Canada
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keV109876543210
Cou
nts
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
0
C
O
Na
Al
Si
CsCs
Cs
Cs
CsCs
Converting Converting CesiumCesium Oxide to Oxide to CesiumCesium FormateFormate
Pollucite mineral is classified as a Pegmatite, a class of old volcanic hard rock where specialized machinery is used in the mining process.Pollucite is first mined by blasting and crushing. The crushed pollucite is then milled at surface.Cesium oxide is then extracted by digestion in sulphuric acid to form a cesium alum.
The GiraffeThe Giraffe
The BreakerThe BreakerThe JumboThe Jumbo
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Converting Converting CesiumCesium Oxide to Oxide to CesiumCesium FormateFormate
Cesium Alum is used as the base to manufacture the alkali metal salt - Cesium Formate - which has a saturation density of 2.3Cesium Formate is a high density, thermally stable, environmentally friendly heavy fluid used for:
– Drilling, completing and workovers of high pressure high temperature (HPHT) oil and gas wells
– Safely overcoming the hydrostatic pressure while drilling, completing, suspending or workovers
– Minimizing formation damage while drilling to optimize productivity of hydrocarbons
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Monovalent Monovalent Ion SeriesIon Series
Li = LithiumNa = SodiumK = PotassiumRb = RubidiumCs = CesiumFr = Francium
= Hydration layer around ionN.B. hydration layer decreases with increasing atomic number of ion
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Monovalent Ion Organic Alkali Metal Salts (Formate)Monovalent Ion Organic Alkali Metal Salts (Formate)
NaCOOH KCOOH CsCOOH1.0 S.G.8.3 ppg
1.3 S.G.10.8 ppg
1.57 S.G.13.1 ppg
2.3 S.G.19.2 ppg
O Cs+ / K+ / Na+
OH-C
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Basic Properties and Attributes of Formate Fluids
Saturated formate fluids:– Na Formate 45% 10.8 ppg– K Formate 75% 13.1 ppg– Cs Formate 80% 19.2 ppg
Saturated formate fluids are polar ionic fluids
– Inherently low viscosity– Biodegradable– Environmentally benign– Non-Toxic– Non-Corrosive– Non-Damaging– Safe to handle, pH 9.0 – 10.5– Protect polymers– Reclaimable and recyclable
O Cs/K/Na
OH-C
Formate fluids and Cabot Specialty Fluids have an excellent HS&E record
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Differences in basic properties between Formates and HalidesDifferences in basic properties between Formates and Halides
Formates– Monovalent– Organic– Bufferable– More alkaline (pH 8 – 11)– Densities up to 19.2 ppg– Applicable to higher
temperatures – Solubility of polymers– Biodegradable– Less corrosive (wider AOE)– Simple drill-in fluids
Halides– Divalent– Inorganic– Unbufferable– More acidic (pH 3 – 6)– Densities up to 19.2 ppg– Less applicable at higher
temperatures– Polymers less soluble– Non-biodegradable– More corrosive (Lesser AOE)– Difficult to formulate drill-in fluids
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Typical formulation of Base Formate Fluid (1.52 s.g.)Typical formulation of Base Formate Fluid (1.52 s.g.)with Optimization of Crystallization Temperature and Pressurewith Optimization of Crystallization Temperature and Pressure
0
0.1
0.2
0.3
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0.7
0.8
0.9
1
1 2 3 4 5 6 7 8
wt% CsFwt% KFwt% DI water
Cs Formate = 2.2 s.g, K Formate = 1.57 s.g., H20 = 1.0 s.g
TCT = -20 °C
TCT = -1.1 °C
{RULE-of-THUMB for PCT: 1.0 °F per 1000 psi}
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Rheology of Formate Base FluidsRheology of Formate Base Fluids
Density and Viscosity vs Temperature12 ppg (1.44 s.g.) Na/K Formate Blend
0.7
2.7
4.7
6.7
8.7
10.7
12.7
14.7
16.7
18.7
20.7
0 50 100 150 200 250Temperature (°F)
Visc
osity
(mm
2/s)
1.37
1.38
1.39
1.40
1.41
1.42
1.43
1.44
1.45
Den
sity
(g/c
m3)
cP g/cm3
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Viscosity & Density, s.g. (73°F) for Blends of Saturated Potassium and Cesium Formate
y = -3E-05x2 - 0.0344x + 10.52R2 = 0.9954
y = 3E-05x2 + 0.0055x + 1.6032R2 = 0.9998
7.00
7.50
8.00
8.50
9.00
9.50
10.00
10.50
11.00
0.00 10.00 20.00 30.00 40.00 50.00 60.00 70.00 80.00 90.00
% Cesium Formate (2.286 s.g.)
Visc
osity
(cps
)
1.50
1.60
1.70
1.80
1.90
2.00
2.10
2.20
2.30
2.40
Den
sity
(s.g
.)
Viscosity (cps)Density S.G.Poly. (Viscosity (cps))Poly. (Density S.G.)
Rheology of Formate Base FluidsRheology of Formate Base Fluids
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Cesium Acetate applicable as XHPHT Fluid ?Cesium Acetate applicable as XHPHT Fluid ?
Cesium Acetate behaves similarly to Cesium Formate but stable tohigher temperatures.
– Cesium Acetate tested to 600°F in titanium cell with no degradation observed– Eutectic blending with K Acetate for saturated fluid over similar density
range– Buffered pH for control and maintenance with carbonate/bicarbonate– Low solids drill-in fluids formulated with synthetic high temperature stable
polymers for rheology and fluid loss– Non-damaging as completion fluid– Non-corrosive to C-276 type and titanium tubulars– Resistant to CO2 and H2S in similar manner as formate based fluids– Passivating film formation with carbon steel and CO2– High productivity as with Cesium Formate based fluids
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Autoclave pressure buildAutoclave pressure build--up of Cesium acetate up of Cesium acetate compared to steam pressurecompared to steam pressure
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Improved well control:
Reduced Risk of Stuck Pipe - Differential and Mechanical
Barite Sag Eliminated - i.e. very low solids content
Excellent Shale Inhibition/Stabilization
Reduced Risk of Tool/ Pump Failures
Thermal Equilibrium Reached Quickly - Reduces Flow-Check Time
Easier Kick Detection and Well Kill
High Dissociation Constant gives Excellent Hydrate Inhibition
Cleaner Completions
All of the above result in Reduced Rig Spread Costs
Reduced Risk of Common Drilling HazardsReduced Risk of Common Drilling Hazards
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Formulating a FormateFormulating a Formate--Based Reservoir DrillBased Reservoir Drill--In FluidIn Fluid
Particle Diameter (µm.)
Volume (%)
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80
90
100
0.1 1.0 10.0 100.0 1000.0
Na/K Formate Drilling/Drill-In FormulationDensity 10.8 ppg (Na + K Formate)Viscosifier - 1.0 lb/bblFL-1 0.5 lb/bblFL-2 1.5 lb/bblSoluble Carbonate/Bicarbonate * as pH buffer (4 - 10 lb/bbl)CaCO3 - 15 lb/bbl (PSD is pore throat matched to porosity)
Very stable fluids can be made using commonly available oilfield additives
*Monovalent formate fluids are alkaline buffered pH 10.0 – 10.5 to enhance fluid stability, mitigate influx of acid gases and to minimize corrosion
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Drilling and Coring with Formate FluidsDrilling and Coring with Formate Fluids
Drilling Operational Behavior - PV, YP and 100 rpm
0.00
5.00
10.00
15.00
20.00
25.00
30.00
35.00
11/2
3/20
03
11/2
5/20
03
11/2
7/20
03
11/2
9/20
03
12/1
/200
3
12/3
/200
3
12/5
/200
3
12/7
/200
3
12/9
/200
3
12/1
1/20
03
12/1
3/20
03
12/1
5/20
03
12/1
7/20
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12/1
9/20
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12/2
1/20
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12/2
3/20
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12/2
5/20
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12/2
7/20
03
12/2
9/20
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12/3
1/20
03
1/2/
2004
1/4/
2004
1/6/
2004
1/8/
2004
1/10
/200
4
1/12
/200
4
1/14
/200
4
1/16
/200
4
1/18
/200
4
1/20
/200
4
1/22
/200
4
1/24
/200
4
PVYP100 RPM
Typical Fluid Properties (Kristin)
Density s.g./ppg 2.09/17.4MD, m. 5249Temp. °C/°F 162/324600 rpm 36300 rpm 21200 rpm 16100 rpm 106 rpm 43 rpm 3Gels 10s/10m 2/4Plastic Viscosity 15Yield Pt. 6pH (9:1) 10.4HPHT, ml 15.8
Formate fluids are easily maintained and show consistency with only small additions necessary over a drill-in campaign
65 day drilling operation
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Minimize Differential Sticking and Lower Formation DamageMinimize Differential Sticking and Lower Formation Damage
Low Solids significantly reduces the risk of pore plugging
Monovalent base fluid enables drilling of calcium sensitive reservoirs without the risk of precipitation induced impairment.
Extremely low permeability filter cakes minimize filtrate invasion once formed
Extremely thin filter cakes are easily removed during back-flow
LCM pills formulated of more robust drill-in formulation on-the-fly, i.e. increase PSD of CaCO3 and polymer fluid loss additives. Also weighted solids free ‘wall building’ LCM pill
All Case Histories have reported substantial gains (up to 300 %) in well productivity compared to previous wells drilled with other fluids.
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Improved Hydraulics with Formate FluidsImproved Hydraulics with Formate Fluids
Lower Surge and Swab Pressures– Faster tripping times
Lower Transient Pressure Changes– Reduced risk of hole instability or well control incidents
Lower System Pressure Losses– More available power for motor - higher ROP
Lower ECDs’– Drill in narrower window between pore and fracture pressure gradients– Less chance of fracturing well and causing lost circulation
Low Coefficient of Friction of Base Formate Fluid Higher Flow Rates
– Higher annular velocities give better hole cleaning
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Coefficient of Friction and Inherent Lubricity of Saturated Coefficient of Friction and Inherent Lubricity of Saturated Formate FluidsFormate Fluids
The more saturated a formate fluid the lower the coefficient of friction and the better the lubricityIf a more lubricious fluid is needed, such as for ER and horizontal wells, formate compatible, non-formation damaging lubricants with COF as low as 0.04 are available
0.00
0.10
0.20
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0.50
0.60
Coe
ffici
ent o
f Fri
ctio
n
Metal-to-Metal Metal-to-Sandstone Metal-to-Shale
Coefficient of Friction for Various Densities of Formate Fluids compared to Water at 200°F
Water 200
CsFormate 2.3 S.G. 200
KFormate 1.57 S.G. 200
Cs/K Formate 1.9 S.G. 200
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Green Canyon Shale Swelling with Formate FluidsGreen Canyon Shale Swelling with Formate FluidsShale Swellmeter Testing
GC 782 No 1 ST3 Shale Exposed toDeionized Water, 10.8, 11.5, and 12.0 lb/gal
Sodium Formate/Potassium Formate Fluids
-5
0
5
10
15
20
25
30
35
40
45
50
55
60
0 4 8 12 16 20 24 28 32 36 40 44 48 52 56 60 64 68 72 76 80 84 88 92 96 100
Time, Hours
Shal
e Sw
ellin
g, %
D.I. Water (58.6% at 96 hrs)
10.8 lb/gal NaF/KF (1.53% at 96 hrs)
11.5 lb/gal NaF/KF (-0.31% at 96 hrs)
12.0 lb/gal NaF/KF (1.19% at 96 hrs)
Reconstituted Shale Plug
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Diffusion of methane into wellbore => trip gas, kick, degradation of mud properties, increased sagDiffusion of methane into wellbore much reduced with formates compared to OBM
– Reduced diffusion rate– Reduced concentration of methane– Particularly important for horizontal and high angle HPHT wells
Solubility of methane in drilling fluids: T = 300°F (149°C), P = 10,000 psi (690 bar)
Fluid Solubility (kg/m3) Diffusion Coefficient (m2/sec x 108)
Diffusion Flux** (kg/m2s x 106)
Oil Based Mud 164 1.1500 53.3000
Water Based Mud 4.8 2.9260 3.9800
Formate Fluid 1.0926 0.8072 0.2494
** Diffusion fluxes vary more than diffusion coefficients becaus** Diffusion fluxes vary more than diffusion coefficients because they are affected by the increase in e they are affected by the increase in solubility solubility –– formate > water > oilformate > water > oil
Well Control during DrillWell Control during Drill--In Phase In Phase -- DiffusionDiffusion
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No SwappingNo Swapping--Out of Base Fluid with Formate FluidsOut of Base Fluid with Formate Fluids
Much simpler completion operationVery simple displacement operationCleanout/Sweep pills are also formate based and hence same density and compatibility between drilling/drill-in fluid and completion fluidRun screens in fluid (fluid run over 300 – 400 mesh)Expandable screens have been run in formate fluidVery limited, if any, UB exposure (no UB fluids, pills needed) High heat transfer rate extends life of tools in HT wellsLess tripping = rig-time saved = less $$$$$
Formate FluidFormate FluidFormate FluidWell Control Well Control
during during CompletionCompletion
Drilling/Reservoir Drilling/Reservoir
DrillDrill--In FluidIn Fluid
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Formation Evaluation - Return Permeability
Difference in clean-up behavior between OBM and Formate MudParticle Size Distribution (PSD) optimized to permeability and pore throat sizeFiltrate invasion can be higher than OBM –needed for thin filtercake depositionWeak Acid wash can provide improved return perm (even > than 100%)
100 %
50 %
12 2416 2084Time (hrs)
% ReturnPermeability
(S)OBMFormate FluidFormate Fluid + Weak Acid
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Selected Field Experience with Formate Based FluidsSelected Field Experience with Formate Based Fluids
Statoil Kvitebjørn
Statoil Kristin
BP High Island
A-5
Devon West
Cameron 165 A-7, A-8
Devon West
Cameron 165 A-7, A-
8
Walter O&G Mobile Bay
862
No. of wells 7 to date 6 to date 1 1 1 1
Hydrocarbon Gas condensate
Gas condensate Gas Gas
condensate Gas Gas
°C 150 171 163 149 163 216 Max. temp
°F 302 340 325 300 325 420 Completion material CRA S13Cr S13Cr S13Cr 13Cr 13Cr G-3
Liner material CRA 13Cr S13Cr S13Cr 13Cr 13Cr G-3
Brine density g/cm2 2.00 - 2.06 2.09 - 2.13 2.11 1.03 1.14 2.06
CO2 % 2-3 3.5 5 3 3 10
H2S ppm Max 10 12 - 17 12 5 5 100
Exposure time days 57 57 4 3 yrs packer 240 and 270 120 16
325 packer
Application
Drilling Completion /
Screens / Liners
Drilling Completion
Well kill Completion
Packer Packer Packer
Well kill Completion
Packer
HPHT Field Experience with formate fluids over the past twelve years. No corrosion problems have been reported in buffered formate fluids without added corrosion inhibitor.
References:•SPE 98391 “Taking Nondamaging Fluids to New extremes: Formate Based Drilling Fluids for High-Temperature Reservoirs in Pakistan” R.J. Oswald, Petrom SA and D.A. Knox and M.R. Monem, M-I Swaco•IADC/SPE 99068 “Drilling and Completing HP/HT Wells with the Aid of Cesium Formate Brines – A Performance Review” J.D. Downs, M. Blaszczynski, J. Turner, M. Harris, Cabot Specialty Fluids
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Selected Field Experience with Formate Based FluidsSelected Field Experience with Formate Based Fluids
BP Rhum 3/29a
Shell Shearwater
Marathon Braemar
BP Devenick
Total Elgin/Franklin
Statoil Huldra
No. of wells 3 6 1 1 10 6
Hydrocarbon Gas condensate
Gas condensate
Gas condensate
Gas condensate
Gas Condensate
Gas Condensate
°C 149 182 135 146 204 149 Max. temp
°F 300 360 275 295 400 300 Completion material CRA S13Cr 25Cr 13Cr 13Cr 25Cr S13Cr Liner material CRA S13Cr 25Cr 22Cr VM110 P110 S13Cr Brine density g/cm2 2.00-2.20 2.05-2.20 1.80-1.85 1.60-1.65 2.10-2.20 1.85-1.95
CO2 % 5 3 6.5 3.5 4 4
H2S ppm 5 - 10 20 2.5 5 20 – 50 10 - 14
Exposure time Days 250 65 7 90 450 45
Application PerforationCompletion Workover
Well kill CT
Workover Perforation
Workover Perforation
Drill Completion
Workover Completion CT / Well kill Perforation
Drilling / Completion
Screens
HPHT Field Experience with formate fluids over the past twelve years. No corrosion problems have been reported in buffered formate fluids without added corrosion inhibitor.
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Workover – Total Elgin/Franklin F7 well has been suspended with 2.15 s.g. (17.92 ppg) Cesium Formate open hole at full temperature (400 °F) for 18 months – awaiting rig availability, possibly Jan 2007
– Well is being continuously monitored for gases, changes in fluid properties, none detected to-date
– Plan thorough inspection and analysis of metals for corrosion and fluid for changes after project is complete (and this will be published)
March 2006 Total E&P UK plc – Development well Glenelg 22/30c-G10Y Satellite from Elgin/Franklin, drilled 24,229’ Highly Deviated Inclination 16.34° -> 64°
– Brought on production after completion and UB perforation through 7” liner with 1.78 s.g.(14.84 ppg) Cesium/Potassium formate
– Reservoir Temperature – 195 °F (383 °F) @ 5,859 m TVDPressure – 1,126 bar (16,331 psi) @ 5,539 m TVD
– Total Depth – 7,383 m MD, TVD – 5,815 m TVD, Gas Condensate– Perforation Losses – 2.0 m3 (12.58 bbl)– Production potential – 30,000 boe per day – Well test has been performed - Actual
production – n/a
Selected 2006 Field Experience with Formate Based FluidsSelected 2006 Field Experience with Formate Based Fluids
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Petrobras Petrobras EnergiaEnergia –– El El CampamentoCampamento, , Santa Cruz, ArgentinaSanta Cruz, Argentina
Exploratory/Appraisal well - drilling with Cs/K formate Drilled a ‘gage’ hole to 3000 mFound gas in section above target zone – 575 bar (8340 psi), 1.93 s.g. (16 ppg)No indication of gas from offset P&A’d wellWell being cased and cemented and then perforated through formate fluid
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Thank You for your attention
Specialty Fluids