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 open hole proppant frac Jan/Feb 2002 � production test / logging � 4130-4190m (frac 1) � 4080-4118m (frac 2) � production test / logging open 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) p wh p at concept: q i • open-hole stimulation dp slurry • high-viscous fluid dz (HTU-Gel + citric acid) 5“ Fracstring dp RRf • proppant dz 9 5/8“ Casing result: 2309 m • increase of productivity 3 ½“ Fracstring • FOI = 2 7“ Liner 3874 m • not sufficient for economics Expansion Joints Open Hole Packer 5 7/8“ Fracinterval p,TMemory OH-Interval Sand Plug 4294 m Legarth et al., Geothermics, 2003

flowmeter-log after gel-proppant treatment

open hole waterfrac (Jan/Feb 2003) well Groß Schönebeck / casing profile 18 5/8“ stand pipe 13 3/8“ Casing 205,3 m 9 5/8“ Casing max. 25 l/s 250 bar 7“ Liner- 2309 m Hanger 2350 m 7“ Liner 32# 3874 m Siltstone Sandstone Vulkanites 5 7/8“ borehole 4294 m

flow back test march 2003 30 180 productivity index 160 PI = 3-4 m³/(h MPa) 25 FOI = 4 140 head pressure [bar] 20 120 flow flow [l/s] 100 15 80 10 60 40 5 head 20 pressure 0 0 0 5000 10000 15000 20000 25000 time [sec]

FMI measurements after 1. waterfrac treatment 4127 depth [ m ] 4128 Holl et al. EAGE, 2004

waterfrac cont. (Nov/Dec 2003) well Groß Schönebeck / casing profile pre-perforated 18 5/8“ stand pipe 13 3/8“ Casing liner 205,3 m 9 5/8“ Casing max. 5“x3 ½“ G105 80 l/s IF-drillpipe (TK34); 3 slip joints, ID 57 mm 500 bar 2300,6 m 7“ Liner- 2309 m Hanger 2331,8 m 2350 m 7“ treatm. packer (ID min 56 mm) 7“ Liner 32# 5“ Liner Hanger (15#, mech.) 3820,6 m + integr. packer 3874 m 5“ Liner 15#, N80 4134 m Cup-Packer, OD 140 mm 5“, 15#, N80 pre- perforated Liner (93 holes/m, Ø1,5cm 4305,7 m 5 7/8“ borehole 4309 m

massive waterfrac treatment nov. 2003

fracture dimensions Rate (l/s) Fracture Length (m) 50 199 40 160 30 120 20 80 10 40 0 0 0 10 20 30 40 50 Average Width (cm) Total Fracture Height (m) 0.80 120 0.64 96 0.48 72 0.32 48 0.16 24 0 0 0 10 20 30 40 50 time (h)

productivity development 8 7 FOI = 8 6 2. waterfrac PI [m³/(h MPa)] FOI = 4 treatment 5 1. waterfrac FOI = 2 treatment 4 gel-proppant treatment 3 2 1 0 CLT Jan2001 CLT Feb2002 PT Aug2002 IT Jan2003 FB Feb2003 FB Dec2003 307 m³ 250 m³ 859 m³ volume 167 m³ 580 m³ 720 m³ 14 hours 5 hours 24 hours time 12,3 hours 37 days 8,3 days 22,4 m³/h 50 m³/h 50 m³/h flow rate 13,5 m³/h 1 m³/h 3,6 m³/h

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 - pressure [MPa] 6.0 - 4.0 - 0.0 - flowrate [l/s] 2.0 - 0 10 20 30 40 50 60 70 80 90 time [days]

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 temperature [°C] 138 139 140 141 142 143 144 145 146 147 4130 Flowrate q = 2 l/s 4140 4150 4160 4170 4180 depth [m] 4190 4200 4210 4220 dynamic temperture log 4230 4240 4250 static temperature log 4260 stat down stat up dyn down dyn up

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

Reservoir conditions (applied in FracPro) Youngs Poisson‘s fracture modulus ratio toughness volcanics 55 GPa 0.2 1.72 MPa m 1/2 lower 55 GPa 0.18 0.59 MPa m 1/2 Dethlingen upper 55 GPa 0.18 0.59 MPa m 1/2 Dethlingen

productivity development initial productivity productivity index FOI = index after stimulation PI(stim)/PI(initial) [m³/h MPa] [m³/h MPa] Volcanics 2-4 10 3-5 lower 6-10 30 3-5 Dethlingen upper 3-5 10 2-3 Dethlingen

waterfrac stimulation in volcanics

waterfrac stimulation in volcanics Surface Pressure (bar) (698.93) Total Friction (bar) (155.30) BHP from Frac Model (bar) (968.68) 800 200 1200 640 160 960 480 120 720 320 80 480 160 40 240 0 0 0 0 1600 3200 4800 6400 8000 Time (min) Slurry Rate (m3/min) (9.00) Slurry Total (m3) (19776.83) 10 25000 8 20000 6 15000 4 10000 2 5000 0 0 0 1600 3200 4800 6400 8000 Time (min)

waterfrac stimulation in volcanics Fracture Length (m) (184.68) Total Fracture Height (m) (127.89) A verage Width (cm) (1.73) 199 150 2 160 120 1.60 120 90 1.20 80 60 0.80 40 30 0.40 0 0 0 0 1600 3200 4800 6400 8000 Time (min) Fracture Upper Height (m) (101.53) Fracture Lower Height (m) (26.35) 120 30 96 24 72 18 48 12 24 6 0 0 0 1600 3200 4800 6400 8000 Time (min)

gel-proppant treatment in sandstones BHP from WB Model and/or Data (bar) Surface Pressure (bar) (274.50) Model Net Pressure (bar) (153.42) Total Friction (bar) (10.09) 1000 600 500 80 800 480 400 64 600 360 300 48 400 240 200 32 200 120 100 16 0 0 0 0 0 30 60 90 120 150 Time (min) Proppant Total (kg) (118012.44) Proppant Concentration (g/L) (0.00) Slurry Rate (m3/min) (3.00) Proppant conc. in fracture (kg/m2) (18 (kg/m2)(18,38) Slurry Total (m3) (421.63) 1.5e+05 1500 4 20 1.2e+05 1200 500 3.20 16 90000 400 900 2.40 12 60000 600 300 1.60 8 30000 200 300 0.80 4 100 0 0 0 0 0 0 30 60 90 120 150 Time (min)

gel-proppant fracture dimensions Fracture Length (m) (49.97) Total Fracture Height (m) (82.61) A verage Width (cm) (1.24) 60 99 2 48 80 1.60 36 60 1.20 24 40 0.80 12 20 0.40 0 0 0 0 30 60 90 120 150 Time (min) Fracture Upper Height (m) (43.22) Fracture Lower Height (m) (39.39) 50.00 50.00 40 40 30 30 20 20 10 10 0 0 0 30 60 90 120 150 Time (min)

proppant concentration

proppant concentration

Proppants Expectations: � High conductive fracture, C fD ≥ 1 � High long term permeability � Controlling movement of fines � Good placing of appropriate concentration CarboHSP 20/40 83 % Al 2 O 3 , 5 % SiO 2 ρ = 2.0 g/cm 3 Crushtest 0.7 % fines at 67 MPa