Search and Discovery Article # (2009) Posted July 25, Abstract

Transcription

1 AV Fracture Imaging Pilot esigned to Compare Various Microseismic Monitoring Techniques* idier rapeau 1, Francis Cerda 1, Laszlo Maurel 2, Pablo Ferguson 2, Raul Sanchez 2, Christophe Maisons 3, Emmanuel Auger 3, Regis Agut 2, and Philippe Matheron 2 Search and iscovery Article # (2009) Posted July 25, 2009 *Adapted from oral presentation at AAPG Annual Convention, enver, Colorado, June 7-10, GEP/SCR/R/PJ, TOTAL SA, Pau Cedex, France (didier-hubert.drapeau@total.com) 2 Total Austral, Buenos Aires, Argentina 3 Magnitude, Sainte Tulle, France Abstract Hydraulic Fracturing is an economic necessity for low permeability reservoirs. The production potential is evaluated as a function of fracture penetration and conductivity. Highly conductive flow paths generated by fracturing some distance away from the wellbore needs to be imaged. Fracture mapping is considered as one of the key challenges for tight gas reservoir development. Microseismic monitoring is known as a technique able to provide fracture imaging. Indeed, changes in pressure and stress induced in the formation by the hydraulic fracturing process cause small slippages to occur along preexisting fractures. These shear failures generate P- and S-waves, which can be recorded at seismic receivers. Microseismic amplitudes are small; therefore, the common technique is to run sensitive downhole tools in an offset well at small recording distances. However, availability of existing wells and the small well spacing is often a strong limiting factor to the application of this technique. Alternative solutions exist but results are as yet unclear. For this reason, TOTAL has completed in 2008 a unique pilot experiment on the Aguada Pichana Field (Neuquen Basin, Argentina) to develop, test, and validate alternative microseismic designs which can be applied to hydraulic fracture mapping for tight gas reservoir developments. The pilot program includes microseismic monitoring from the treatment well (wire-line design), from the observation well (as reference), from dedicated shallow wells, and from dense surface networks. The pilot results are going to be compared for various stages of fracs with and without proppant. Copyright AAPG. Serial rights given by author. For all other rights contact author directly.

2 The two pilot objectives are to validate an alternative fracture imaging technique and to evaluate the potential benefits of various fracturing programs. This article on this unique pilot will present (1) the challenge and the objectives, (2) the monitoring networks tested, (3) the program and the frac stages performed, and (4) the results

3 Fracture Imaging Pilot esigned to Compare Various Microseismic Monitoring Techniques AAPG ENVER, 2009 June 8-10 th idier rapeau(1); Francis Cerda(1); Laszlo Maurel(2); Pablo Ferguson(2); Raul Sanchez(2); Christophe Maisons (4); Emmanuel Auger(3); Regis Agut (2); Philippe Matheron(2) 1. GEP/SCR/R/PJ, TOTAL SA, Pau Cedex, France. 2. Total Austral, Buenos Aires, Argentina. 3. Magnitude, Sainte Tulle, France 4. Consultant Business evelopment SCR/R AAPG 2009, June 8_10th H

4 AGENA Regional Setting Pilot Objectives & program Main operational results based on massive frac From observation well : REFERENCE From Surface Network From Near-Surface Network Conclusions 2 - AAPG enver 2009, June 8_10th H

5 Regional Setting 3 - AAPG enver 2009, June June 8_10th H H

6 Regional Setting (1/2) Total Austral has undertaken to develop the southwestern fringe of the Aguada Pichana gas field (Neuquen Basin), which is characterized by lower permeability (0.1 1 m in reservoir conditions) Top Top Reservoir Upper (mss) Mulichinco ( mss ) Aguada Pichana 4 - AAPG enver 2009, June 8_10th H

7 Regional Setting (2/2) Main Reservoir : Mulichinco sandstone Neuquen Basin Sedimentary column Mulichinco Sequence Stratigraphy Moderate size hydraulic fracturing performed up until now on AP Main No longer suitable for the new development phase «Massive» hydraulic fracturing test programme launched to obtain the hydraulic fracturation propagation mode and geometry using the microseismic technique. Rayoso + Huitrin Agrio Mulichinco Quintuco + Vaca Muerta Tordillo Auquilco + Lotena Lajas Molles Precuyo CRETACEOUS JURASSIC edicated Pilot to reach this goal was set up 5 - AAPG enver 2009, June 8_10th H

8 Pilot Objectives & Program 6 - AAPG enver 2009, June June 8_10th H H

9 Pilot Objectives & Configurations evelop, test and validate alternative µ-seismic techniques avoiding an observation well Minimizing delays and costs of acquisition and processing Three alternate configurations tested: Wire line sensor antenna in the treated well (without proppant in well1) Sensor antenna in dedicated shallow wells with beam forming processing: new application Surface sensor network Reference configuration Antenna in dedicated deep observation well Surface network:20 lines of 26 traces (6 geophones per trace) Geophones in 5 Well separation = 250 m shallow wells Well1 Well2 epth 1600 m 3C-sensors in the treated well 4 monitoring networks 663 sensors Reference network: 3C-sensors in the observation well 7 - AAPG enver 2009, June 8_10th H

10 Pilot Program Well1 AP210 3 Well2 AP The pilot program included: Three stages of frac jobs: with and without proppant in Well1, propped frac in Well2 Monitoring in both treated and observation well, in dedicated shallow wells ( near-surface network) and from a surface network eliverables: 4 mapping of hydraulic fracture (azimuth, length, height, growth) Recommendations for the more accurate deployment option Monitoring from: Treated well Obs well Shallow Surface Frac Well1: AP210: Water Frac Inj. Rate 30 bpm Fluid : 296 m3 Pmax : 2760 psi Monitoring from: Obs well Shallow Surface Frac Well1: AP210: Proppant Frac Inj. Rate 35 bpm Fluid : 531 m3 Up to 4196 psi Monitoring from: Obs well Shallow Surface UMZ MMZ LMZ T ~1775,00 m 20 1, AP210 Well UMZ MMZ LMZ T ~1775,00 m 20 1, AP210 Well1 Well2 AP213 AP213 Well Operations Perfo in AP210 Well1 Orientation Survey (Vibrotruck) before Frac Continuous Recording from beginning of injection to 2 hours after shut-in. FRAC 1 FRAC 2 (massive) FRAC AAPG enver 2009, June 8_10th H Frac Well2: AP210: Proppant Frac Inj. Rate 24 bpm Fluid : 196 m3 Pmax : 4736 psi T ~1775,00 m UMZ MMZ LMZ 1,

11 Main Operational Results based on Massive Frac 9 AAPG enver 2009, June 8_10th H

12 Key points for the interpretation Seismicity of expected magnitude: -2.8 to -1.9 for frac 2, -2.8 to -2.3 for frac 3 (US Rockies standard of -3 to -2) Wide majority of the detected and located microseismic events during the injection phase : very few or no events during the fall-off. Moderate number of recorded seismic events (max of 200 during frac 2, standard processing), may be in relation with the intensity of frac jobs (comparison frac 2 / frac 3) 10 - AAPG enver 2009, June 8_10th H

13 Obs. Well: Chronograms & Location Maps Slurry Proppant / 30BPM Proppant / 35BPM 50 minutes 55 minutes 35 minutes Frac#2 Seismicity Location Threshold -2.8 Max Magnitude -1.9 AP/AS from 0.1 to 1 B 100 m A Local time Injection rate Net Pressure Cumulative number of seismic events (detected) Cumulative number of located events Located events (10 minutes step) Epicenter Map 100 m A 100 m B Perforation Cross Section (Easting ( Easting) 11 - AAPG enver 2009, June 8_10th H Cross Section (Northing ( Northing)

14 Observation Well: global geometry X Az=284 ist -85m / +125m Az=270 ist - 55m / +55m Fracture orientation NE 275 +/- 10 Y Well Azimuth of events view from Perf zone AP 210 Microseismic Phase 1(50 events minutes) AP210 Phase First 2 60 (55minutes) 60 Phase to minutes (35 minutes) Fracture half length = maximum 125 m Fracture height about +60m to -25m epth (m) versus Time from beginning of injection (minutes) istance to perf zone (m) m Pressure epth with respect to Perfo depth (m) m -25m Outliers Seismicity associated to the fracture Outliers Pressure Ellapse Time (sec) Horizontal distance (m) 0.26 Pressure Time (min) 12 - AAPG enver 2009, June 8_10th H

15 Observation Well: epth distribution High seismicity in Upper Mulichinco, at the end of frac job 100 istance Velocity model UM epth 0 MM -25 LM Phase 1(50 minutes) Microseismic events Phase First 2 (55minutes) Phase to 105 minutes 3 (35 minutes) 13 - AAPG enver 2009, June 8_10th H

16 Maximum distance from Observation to treated well (Aguada Pichana setting) Frac #2 Frac #3-1.6 Moment magnitude istance to source (m) Maximum distance between microseismic events and geophones ~ 425 m (Max offset 340 m for dz around 270 m) Improvement by increasing the number of levels and by applying beam forming technique Processing can be applied remotely and in near real time 14 - AAPG enver 2009, June 8_10th H

17 Observation well Results (standard method) Microseismic events: Slurry Proppant / 30BPM Proppant / 35BPM 50 minutes 55 minutes 35 minutes Magnitude range of [-2.8, -1.9] for located events 204 microseismic events detected, of which 67 located These numbers could be dramatically increased using alternative picking methods (from 67 to more than 580 located events) X Injection rate Net Pressure Local time Cumulative number of seismic events (detected) Cumulative number of located events Az=284 ist -85m / +125m Az=270 ist - 55m / +55m Located events (10 minutes step) Frac geometry: Y Azimuth 284 NE in reservoir Frac Extension: Asymmetry Growth, at least AP 210 Microseismic Phase 1(50 events minutes) AP210 Phase First 2 60 (55minutes) 60 Phase to minutes (35 minutes) Azimuth of events view from Perf zone 125 m Eastward and 85 m Westward Frac Height +60 m -25 m from perf zone High seismicity in Upper Mulichinco -1 Consistency with frac simulations Frac #2 Frac #3 estabilized zone extends up to 225 m Maximal distance for observation well: 350 m Moment magnitude AAPG enver 2009, June 8_10th H istance to source (m)

18 Surface and Near Surface networks Both networks effective since being able to detect AN locate: The perforation shot (explosive event) with a S/N ratio of 1:20 The "bridge plug" anchoring shot ("simulacra") in well2 (frac 3) which has a magnitude of ~ -2 equivalent to that of microseismic events High noise level in surface geophones and near the shallow wells : Only 40% of the sensors on each line efficient for processing red curve indicates the variations in noise level along the line with a retained threshold of mv AAPG enver 2009, June 8_10th H

19 Surface network main results 67 events with magnitudes down to -2.5 detected (must be improved). Beam forming processing allows to increase the detected and located microseismic events BUT unsatisfactory level of uncertainty in locating the events: the focal mechanism should be taken into account in the processing "weighted barycentre" technique provides a better map of the fracture, but only in the x-y plane Processing capability requirements could be a limiting factor for use in "near real time". Semblance at constant depth for one event Intermediate imaging step up to 4 responses for 1 microseismic event typical of the signature of a strike-slip fault mechanism AAPG enver 2009, June 8_10th H

20 Surface Net. Location with standard approach Results from observation well Results from surface network Weighted barycenter provides a better image but still an unsatisfactory resolution Artifact not solved Sensitivity not improved Source mechanism issue hidden 18 - AAPG enver 2009, June 8_10th H

21 Near Surface Network (shallow wells) Network is effective since it was able to detect AN to locate: The perforation shot (explosive event) with a S/N ratio of 1:20 The bridge plug anchoring shot at the same level as the microseismic events but no usable results during frac jobs! Possible explanation: radiation pattern of the focal mechanism 19 - AAPG enver 2009, June 8_10th H

22 SCR/R AAPG 2009, June 8_10th H Conclusions

23 Conclusions (1/2) Overall operational success especially for the more integrated operations involving many contractors. A unique data set to compare various approaches isappointment concerning 2 networks: -Monitoring in the treated well Possible only if no proppant used Can detect events during fall-off only -Shallow wells Not conclusive More work on lay-out design: emergence angle & multi-component recordings! 21 - AAPG enver 2009, June 8_10th H

24 Conclusions (2/2) Fruitful results for the remaining two networks: - Monitoring in an observation well Good results; however, the well should be located within 350m from the treated well Further processing possible to increase the number of located events - Surface network Best alternative to the observation well More work needed on reliability of detected events; S/N; accuracy of location Need to take the focal mechanism into account in the beam-forming process Processing capability requirements for use in near real time 22 - AAPG enver 2009, June 8_10th H

25 THANK YOU FOR YOUR ATTENTION The authors would like to thank - the Management of Total Austral - the Management of Repsol-YPF Argentina, Wintershall Argentina & Panamerican Argentina - the R& management of TOTAL SA - the Management of Magnitude for their authorization to present this paper 23 - AAPG enver 2009, June 8_10th H