Enhancement of productivity after reservoir stimulation of the hydro- - - PowerPoint PPT Presentation

Enhancement of productivity after reservoir stimulation of the hydro- thermal reservoir Gross Schönebeck with different fracturing concepts Günter Zimmermann & Geothermics Group GeoForschungsZentrum Potsdam

Operations overview

• pen hole proppant frac

Jan/Feb 2002

• production test / logging
• 4130-4190m (frac 1)
• 4080-4118m (frac 2)
• production test / logging
• pen hole waterfrac

start Jan/Feb 2003

• 3874-4294m, borehole instability
• production test
• cont. Nov/Dec 2003
• 4135-4309m
• production test / logging

Dec 2004

• injection test

drilling 2. well

hydraulic stimulation of sandstones (Feb 2002)

qi

pwh pat

Open Hole Packer 7“ Liner 3 ½“ Fracstring 9 5/8“ Casing 5“ Fracstring p,TMemory Fracinterval 5 7/8“ OH-Interval 3874 m 4294 m 2309 m Sand Plug Expansion Joints dz dpRRf dz dpslurry

concept:

• pen-hole stimulation
• high-viscous fluid

(HTU-Gel + citric acid)

• proppant

result:

• increase of productivity
• FOI = 2
• not sufficient for economics

Legarth et al., Geothermics, 2003

flowmeter-log after gel-proppant treatment

4294 m 3874 m 7“ Liner 32# 7“ Liner- Hanger 9 5/8“ Casing 2309 m 2350 m 5 7/8“ borehole 13 3/8“ Casing 18 5/8“ stand pipe 205,3 m

• pen hole waterfrac (Jan/Feb 2003)

Siltstone Vulkanites Sandstone

max. 25 l/s 250 bar

well Groß Schönebeck / casing profile

flow back test march 2003

5 10 15 20 25 30 5000 10000 15000 20000 25000 time [sec] flow [l/s] 20 40 60 80 100 120 140 160 180 head pressure [bar] head pressure flow

productivity index PI = 3-4 m³/(h MPa) FOI = 4

FMI measurements after 1. waterfrac treatment

Holl et al. EAGE, 2004

depth [ m ]

4127 4128

waterfrac cont. (Nov/Dec 2003)

4309 m 4134 m 3820,6 m 3874 m 5“ Liner 15#, N80 7“ Liner 32# 5“ Liner Hanger (15#, mech.) + integr. packer 7“ treatm. packer (IDmin 56 mm) 7“ Liner- Hanger 5“x3 ½“ G105 IF-drillpipe (TK34); 3 slip joints, ID 57 mm 9 5/8“ Casing 2309 m 2350 m 5 7/8“ borehole 5“, 15#, N80 pre- perforated Liner (93 holes/m, Ø1,5cm

Cup-Packer, OD 140 mm

2331,8 m 2300,6 m 13 3/8“ Casing 18 5/8“ stand pipe 4305,7 m 205,3 m

max. 80 l/s 500 bar

pre-perforated liner

well Groß Schönebeck / casing profile

massive waterfrac treatment nov. 2003

fracture dimensions

50 40 30 20 10 10 20 30 40 50 199 160 120 80 40 0.80 0.64 0.48 0.32 0.16 10 20 30 40 50 120 96 72 48 24

Rate (l/s) Fracture Length (m) Total Fracture Height (m) Average Width (cm) time (h)

productivity development

1 2 3 4 5 6 7 8

PI [m³/(h MPa)] CLT Jan2001 CLT Feb2002 PT Aug2002 IT Jan2003 FB Feb2003 FB Dec2003 167 m³ 12,3 hours 13,5 m³/h 307 m³ 14 hours 22,4 m³/h 580 m³ 37 days 1 m³/h 720 m³ 8,3 days 3,6 m³/h 250 m³ 5 hours 50 m³/h 859 m³ 24 hours 50 m³/h gel-proppant treatment

• 1. waterfrac

treatment

• 2. waterfrac

treatment volume time flow rate

FOI = 2 FOI = 4 FOI = 8

Injection experiment 2004/2005

aim: transmissibility and flow profile Q = 2 l/s Injection time = 18 days Shut-in = 76 days Remaining head pressure = 4.5 MPa Flow back & temperature log Q = 2 l/s

Injection experiment 2004/2005

8.0 - 4.0 - 2.0 -

time [days]

0 10 20 30 40 50 60 70 80 90

flowrate [l/s]

0.0 -

pressure [MPa]

6.0 -

Injection experiment 2004/2005 Transmissibility T = k h = 4.1 x 10-14 m³ = 0.041 Dm Fracture half length xf = 255 m Fracture conductivity Fc = 9.6 x 10-13 m³ = 0.96 Dm

temperature logs during flow back 2005

4130 4140 4150 4160 4170 4180 4190 4200 4210 4220 4230 4240 4250 4260 138 139 140 141 142 143 144 145 146 147 temperature [°C] depth [m] stat down stat up dyn down dyn up dynamic temperture log static temperature log

Flowrate q = 2 l/s

results & conclusion

• gel & proppant treatment in sandstones => FOI = 2

problem: ⇒ generation of tensile fractures ⇒ no self propping effect ⇒ number of proppant layers to low ⇒ closure of fractures at low differential pressure

• 1. massive waterfrac treatment => FOI = 4
• 2. massive waterfrac treatment => FOI = 8

problem: ⇒ only impact in volcanic rocks ⇒ closure of sandstone layers at low differential pressure recommendation:

• separate treatments for sediments & volcanic rocks
• waterfrac treatment in volcanic rock (with optional tie-back)
• gel & proppant treatment in sediments

(with increasing number of proppant layers)

Quo vadis Groß Schönebeck 4?

Thermal-hydraulic modelling

Injection temperature T = 70°C Reservoir temperature T = 150 °C Q = 75 m³/h Simulation time = 30 years Frac conductivity = 1Dm Transmissibility = 1Dm Frac half length GrSk3/90 = 150 m Frac half lengths GrSk4/05 = 250 m GrSk3/90 GrSk4/05

Injection experiment 2004/2005

Injection experiment 2004/2005 Transmissibility T = k h = 4.1 x 10-14 m³ = 0.041 Dm Fracture half length xf = 309 m Fracture conductivity Fc = 7.8 x 10-13 m³ = 0.78 Dm

Reservoir conditions (applied in FracPro) 10 mD 0.145 bar/m 59.3 MPa upper Dethlingen 10 mD 0.125 bar/m 52.2 MPa lower Dethlingen 1 mD 0.16 bar/m 68.4 MPa volcanics pore fluid permeability closure stress gradient frac pressure

Reservoir conditions (applied in FracPro) 0.59 MPa m1/2 0.18 55 GPa upper Dethlingen 0.59 MPa m1/2 0.18 55 GPa lower Dethlingen 1.72 MPa m1/2 0.2 55 GPa volcanics fracture toughness Poisson‘s ratio Youngs modulus

productivity development 2-3 10 3-5 upper Dethlingen 3-5 30 6-10 lower Dethlingen 3-5 10 2-4 Volcanics

FOI = PI(stim)/PI(initial) productivity index after stimulation [m³/h MPa] initial productivity index [m³/h MPa]

waterfrac stimulation in volcanics

waterfrac stimulation in volcanics

Time (min)

1600 3200 4800 6400 8000 160 240 320 480 480 720 640 960 800 1200 40 80 120 160 200

Surface Pressure (bar) (698.93) BHP from Frac Model (bar) (968.68) Total Friction (bar) (155.30)

Time (min)

1600 3200 4800 6400 8000 2 4 6 8 10 5000 10000 15000 20000 25000

Slurry Rate (m3/min) (9.00) Slurry Total (m3) (19776.83)

waterfrac stimulation in volcanics

Time (min)

1600 3200 4800 6400 8000 40 0.40 80 0.80 120 1.20 160 1.60 199 2 30 60 90 120 150

Fracture Length (m) (184.68) A verage Width (cm) (1.73) Total Fracture Height (m) (127.89)

Time (min)

1600 3200 4800 6400 8000 24 48 72 96 120 6 12 18 24 30

Fracture Upper Height (m) (101.53) Fracture Lower Height (m) (26.35)

Time (min)

30 60 90 120 150 200 100 400 200 600 300 800 400 1000 500 120 16 240 32 360 48 480 64 600 80

BHP from WB Model and/or Data (bar) Model Net Pressure (bar) (153.42) Surface Pressure (bar) (274.50) Total Friction (bar) (10.09) Time (min)

30 60 90 120 150 30000 0.80 100 60000 1.60 200 90000 2.40 300 1.2e+05 3.20 400 1.5e+05 4 500 300 4 600 8 900 12 1200 16 1500 20

Proppant Total (kg) (118012.44) Slurry Rate (m3/min) (3.00) Slurry Total (m3) (421.63) Proppant Concentration (g/L) (0.00) Proppant conc. in fracture (kg/m2) (18

gel-proppant treatment in sandstones

(kg/m2)(18,38)

gel-proppant fracture dimensions

Time (min)

30 60 90 120 150 12 0.40 24 0.80 36 1.20 48 1.60 60 2 20 40 60 80 99

Fracture Length (m) (49.97) A verage Width (cm) (1.24) Total Fracture Height (m) (82.61)

Time (min)

30 60 90 120 150 10 20 30 40 50.00 10 20 30 40 50.00

Fracture Upper Height (m) (43.22) Fracture Lower Height (m) (39.39)

proppant concentration

proppant concentration

Proppants

Expectations: High conductive fracture, CfD ≥ 1 High long term permeability Controlling movement of fines Good placing of appropriate concentration CarboHSP 20/40 83 % Al2O3, 5 % SiO2 ρ= 2.0 g/cm3 Crushtest 0.7 % fines at 67 MPa