Monitoring CO 2 injection at Cranfield field, Mississippi Jiemin Lu Bureau of Economic Geology University of Teas 3,000 m depth Gas cap, oil ring, downdip water leg Shut in since 1965 Strong water drive Returned to near initial pressure
Cranfield Field Test Collaboration Gulf Coast Carbon Center Industrial Associates QEA BP Univ. Mississippi Miss State UTPGE UT DoG Univ. Tennessee Princeton Univ. Stanford Univ. Univ. Edinburgh Gulf Coast Carbon Center Staff Susan Hovorka Ramon Trevino Tip Meckel Changbing Yang Jiemin Lu Katherine Romanak Rebecca Smyth Sigrid Clift Masoumeh Kordi Stuart Coleman Yihua Cai Hamid Lashgari BEG staff Tongwei Zhang Jeff Paine Bob Reedy Robert Reed Kitty Millikan
Talk outline Field Geology Reservoir architecture stacked fluvial deposits Reservoir property Phase 2 Pressure Monitoring Phase 3 Detail Area study ERT (electric resistivity tomography) RST (reservoir saturation tool) CASSM (Continuous active-source seismic monitoring) U-tube tracer monitoring
Reservoir Characterization
A Characterization of the Reservoir B Tuscaloosa Fm Phase II Tuscaloosa confining system Phase III DAS Tuscaloosa D-E reservoir Oil-water contact Based on log annotation and recent side-walls 3D Denbury - interpretation Tip Meckel BEG
Reservoir heterogeneity from surface seismic Stratal slicing for facies 90-degree phase AVF for thickness/fluid AVO for fluid/owc Chann el erosio n Point bar Channel erosion Point bar Channel erosion Channel erosion Denbury 3-D survey interpretation by Hongliu Zeng, BEG
CFU 31F-2 CFU 31F-2 XRD Mineralogy % XRD mineral % 0 5 10 15 20 25 30 35 10420 10430 10440 Chlorite Carbonates Kaolinite Illite MD 10450 10460 10470 10480 10490 10500 Sandstone and conglomerate: Quartz ~ 60-80% Feldspar < 1% Average Φ H: 20.5 % V: 20.7 % Average K H: 283 md V: 47 md
Cranfield Project Progress 2006 Phase II Site selection Characterization 2007 First cored well, brine samples baseline seismic 2008 2009 Soil gas baseline Phase II Site development Phase III NEPA Drill Phase III 3 DAS wells Monitoring 2010 2011 2012 Phase III injection Phase II injection Commercial injection End SECARB Early Phase II 1 million tones injected December 20 P II + III Phase III Last well for 1 million tones/year rate Projected 1.5 million tons phase III
5km HiVIT Psite Five Study Areas Phase II Pipeline head& Separation facility GMT DAS Injector Producer Observation Well GIS base Tip Meckel
Talk outline Field Geology Reservoir architecture stacked fluvial deposits Reservoir property Phase 2 Pressure Monitoring Phase 3 Detail Area study ERT (electric resistivity tomography) RST (reservoir saturation tool) CASSM (Continuous active-source seismic monitoring) U-tube tracer monitoring
sppressure monitoring SECARB Phase II mv Ohm-m 16" casing set @ 222' SP RES -150-100 -50 0 5 10 15 10-3/4" casing set @ 1,825' 9,700 Dedicated observation well 5km 9,800 Monitoring Zone DEPTH (ft) 9,900 10,000 10,100 Marine mudstone (Tip Meckel) 10,200 Injection Zone 10,300 Tuscaloosa perforation
BHP (psia) Daily mscf 8 6 4 2 6000 5500 5000 4500 Continuous field data from dedicated monitoring well 10 104 0 Jul.01 Jul.15 Jul.29 Aug.12Aug.26Sep.09Sep.23Oct.07 Oct.21 Nov.04 Nov.18Dec.02Dec.16Dec.30Jan.13 Dec.30 Jan.27 Feb.10 Feb.24Mar.10Mar.24 Mar.24 Apr.07 Apr.21May.05May.19Jun.02 Jun.16 Jun.30 Jul.14 Jul.28 Aug.11 0 Injection Zone Pressure INJECTION DATA 2008 2009 Bottom Hole Pressures (psia) Rate of Observed Pressure Change in Injection Zone at Monitor Well Above-zone Pressure (Tip Meckel) Jul.01 Jul.15 Jul.29 Aug.12Aug.26Sep.09Sep.23Oct.07 Oct.21 Nov.04 Nov.18Dec.02Dec.16Dec.30Jan.13 Jan.27 Feb.10 Feb.24Mar.10Mar.24 Apr.07 Apr.21May.05May.19Jun.02 Jun.16 Jun.30 Jul.14 Jul.28 Aug.11 10 5 10 8 6 4 2 Cumulative Metric Tons Injection Rate (mscfd) Injection Rate (mscfd) Delta BHP injection zone (psia) 0.1 0-0.1 15000 10000 5000 10000 5000 Incremental Delta Pressure - injection zone (psi) Jul.01 Jul.15 Jul.29 Aug.12Aug.26Sep.09Sep.23Oct.07 Oct.21 Nov.04 Nov.18Dec.02Dec.16Dec.30Jan.13 Jan.27 Feb.10 Feb.24Mar.10Mar.24 Apr.07 Apr.21May.05May.19Jun.02 Jun.16 Jun.30 Jul.14 Jul.28 Aug.11 Injection Rates East of fault Individual well injection rates 0 Jul.01 Jul.15 Jul.29 Aug.12Aug.26Sep.09Sep.23Oct.07 Oct.21 Nov.04 Nov.18Dec.02Dec.16Dec.30Jan.13 Jan.27 Feb.10 Feb.24Mar.10Mar.24 Apr.07 Apr.21May.05May.19Jun.02 Jun.16 Jun.30 Jul.14 Jul.28 Aug.11 Injection Rates West of fault Individual well injection rates 0 Jul.01 Jul.15 Jul.29 Aug.12Aug.26Sep.09Sep.23Oct.07 Oct.21 Nov.04 Nov.18Dec.02Dec.16Dec.30Jan.13 Jan.27 Feb.10 Feb.24Mar.10Mar.24 Apr.07 Apr.21May.05May.19Jun.02 Jun.16 Jun.30 Jul.14 Jul.28 Aug.11 29-10 29-12 25-2 24-2 29-2 48-1 29-7 26-1 27-1 28-1 29-4 * 1000 psi = 68.9 bar
Monitored rate of pressure change from field-wide shut-in for hurricane -19.3 MMSCFD, -6,214 M3/D, -39,087 BBL/D, -1,140 GAL/min ~1,000 metric tons/day at reservoir conditions 0.15 Incremental Delta Pressure - injection zone (psi) Delta BHP injection zone (psia) 0.1 0.05 0-0.05-0.1 Aug.12 Aug.26 Sep.09 Sep.23 Injection Rate (mscfd) 15000 10000 5000 29-10 29-12 25-2 24-2 29-2 48-1 29-7 29-11 Individual well injection rates 0 Aug.12 Aug.26 Sep.09 Sep.23
Delta BHP injection zone (psia) Monitored rate of pressure change from one injector 3,680 ft (1120 m) away -4.0 MMSCFD, -1,320 M 3 /D, -8,300 BBL/D, -242 GAL/min ~215 metric tons/day at reservoir conditions 0.15 0.14 0.13 0.12 0.11 0.1 0.09 0.08 0.07 0.06 0.05 0.04 0.03 0.02 0.01 0-0.01-0.02-0.03-0.04-0.05 /10 min 15000-4.0 MMSCFD 1,120 m ~215 tons/day Incremental Delta Pressure - injection zone (psi) Jul.01 Jul.15 Jul.29 Individual well injection rates 3,680 ft 1,120 m 0.01-1.1 MMSCFD 940 m ~56 tons/day Injection Rate (mscfd) 10000 5000 No significant response 29-10 29-12 25-2 24-2 29-2 48-1 29-7 29-11 3,080 ft 940 m 0 Jul.01 Jul.15 Jul.29 Avg. 3.9 MMSCFD Avg. 0.8 MMSCFD 5,270 ft 1,720 ft 1,600 m 525 m Avg. 0.8 MMSCFD 1,720 ft 525 m
Talk outline Field Geology Reservoir architecture stacked fluvial deposits Reservoir property Phase 2 Pressure Monitoring Phase 3 Detail Area study ERT (electric resistivity tomography) RST (reservoir saturation tool) CASSM (Continuous active-source seismic monitoring) U-tube tracer monitoring
SECARB Phase III Detail Aare Study Injector CFU31 F1 Obs CFU31 F2 Obs CFU31 F3 U-Tube System Distributed Temperature System Press/Temp 10,500 feet BSL F1 F2 F3 Above-zone monitoring Above Zone Monitoring CASSM P/T Injection Zone ERT DTS System
Phase III Observation Smart Well Construction 2 7/8 tubing U-tube sampler 1/4 SS Continuous seismic sources/receivers INJ OBS1 OBS2 BHP+ T Casing-conveyed pressure sensor Electrical resistance tomography 20 electrodes 200 Fiberglass non-conductive casing 100 Tuscaloosa DE Distributed temperature Cross well array in two wells High injection volumes Far-field monitoring tilt, microseismic, P&T, chemistry, surface seismic BEG, LBNL, LLNL, USGS, ORNL, Pinnacle, QEA, Sandia Technologies
Crosswell ERT (Electric Resistance Tomography) (Charles Carrigan et al., 2010)
Nulled Background at Initiation Of Injection (1 Dec 2009) Direction of CO 2 plume Injector Multi-Phase Technologies, LLC
Injector Workover Fluids? (4 Dec 2009) Direction of CO 2 plume Injector
Arrival of CO 2 Plume? (9 Dec 2009) X Direction of CO 2 plume X X X Injector X X CO 2 arrival?
Growth Of CO 2 Plume? (21 Dec 2009) X Direction of CO 2 plume X X X Injector X X
Growth Of CO 2 Plume? (11 Jan 2010) X Direction of CO 2 plume X X X Injector X X
Growth Of CO 2 Plume? (13 Jan 2010) Direction of CO 2 plume Injector
Growth Of CO 2 Plume? (5 Feb 2010) Direction of CO 2 plume Injector
Growth Of CO 2 Plume? (23 Feb 2010) Direction of CO 2 plume Injector
Cross Well ERT clues to how flow occurred Two CO 2 flow pathways? Injector Direction of CO 2 plume Observation well F2 electrodes Observation well F3 electrodes 50ft Resistive plume = CO 2 in reservoir Conductive plume = workover fluids? Charles Carrigan, LLNL
Wireline Formation Evaluation ELAN RST (Reservoir Saturation Tool) (Bob Butch) GR Washouts Resistivity OH Porosity Sigma RST Porosity Perm CO2 Volume CO2 Saturation RST 12/12/09 RST 12/15/09 RST 12/31/09 Measures gamma rays emitted from inelastic neutron scattering to determine C/O
What happened at the wells? packer packer Injection Well F1 Dec 1 CO2 flows into formation Observation well F2 Observation well F3 Dec 1 pressure changes right away, but no CO 2
Day 9 packer packer Injection Well F1 Dec 1 CO2 flows into formation Observation well F2 Observation well F3 Dec 9 CO detected 2 in top of well interval
Day 13 packer packer Injection Well F1 Dec 1 CO2 flows into formation Observation well F2 Observation well F3 Dec 13 still minor amounts of CO detected 2 in top of well interval and maybe some thin zones Dec 13 CO detected 2 in top of well interval and maybe some thin zones
Day 31 packer packer Injection Well F1 may injection log large flow in upper part well F2 well F3 Dec 30 large amounts of CO detected 2 in well interval and some thick zones in lower part of formation Dec 31 large amounts of CO detected 2 in well interval upper part of formation
Crosswell Continuous Active-Source Seismic Monitoring 2 sources, 10 Sensors deployed at 3.2 km, 130 C Monitor F3 Monitor F2 Injector F1 3150 Depth (m) CO 2 Plumes Hydrophones 3200 41 m 70 m Source Sensor Packer Perforations (Tom Daley, Jonathan Ajo-Franklin) CASSM Source
Continuous Active-Source Seismic Monitoring Baseline Data Nov 2009: Proved use of dual source Upper Source Lower Source Three Pump Tests 1 2 Days 3 4 5 Oct 2009: Installed, used for monitoring microseismic and well pump tests; Sensors failed just before CO 2 injection (Dec 1, 2009) (Tom Daley, Jonathan Ajo-Franklin) CASSM Data Pressure Data
U-tube Monitoring (SF6, PFTs, noble gases) Above-zone Inj Obs1 Obs2monitoring Above Zone Monitoring 10,500 feet BSL Injection Zone U-Tube surface control system
Injection started at 12/1 8:40 am 175kg/min ~ 12d ~ 15d Arrival at F2 on ~ 12/12 Arrival at F3 on ~12/15 CO 2 -F2 CO 2 -F3 CH 4 -F3 CH 4 -F2 12/1/09 12/5/09 12/9/09 12/13/ 09 12/17/09 12/21/09 12/25/09 12/ 29/09 1/2/10
CO 2 injection rate = 275kg/min Flow rate (F1 F2) / (F1 F3) = 0.66 Injection rate increase to 488 kg/min (77% increase) Flow rate increase (F1 F3): 117% Flow rate increase (F1 F2): 59% Fluvial Depositional System vertically stacked fluvial point bar and channel deposits Galloway 1983 SF6 detected/injected: 0.03 Ky detected/injected= 0.3 SF6 lost? Meander fluvial model Channel erosion Channel erosion Channel erosion Channel erosion Point bar Point bar (Hongliu Zeng)
Distributed Temperature CFU31 F3 Depth (1000 ft) Perforation zone: 10,450 to 10,520 ft 12/01/09 01/01/10 02/01/10 03/01/10 04/01/10 05/01/10 Produce well Start injection
Change in Distributed Temperature CFU31 F3 Depth (1000 ft) Perforation zone: 10,450 to 10,520 ft 12/01/09 01/01/10 02/01/10 03/01/10 04/01/10 05/01/10 Produce well Start injection
Interim Conclusions of Cranfield Test Phase III 1 million ton/year rate achieved Dec 20, 2009; 2.2 Million tones monitored since July 2008 Rate to be maintained >15 months Monitored with standard and novel approaches Above-Zone pressure monitoring Fluid flow measured/monitored with multiple tools in comple flow field First US application of Electrical Resistance Tomography (ERT) for CS Quantification of fluid flow Eport to commercial EOR/CCS projects