Karine C. Schepers-Cheng Advanced Resources International, Inc.

Transcription

1 Southwest Partnership on Carbon Sequestration (SWP) Pump Canyon CO 2 Enhanced Coalbed Methane (ECBM) / CO 2 Sequestration Demonstration Test Site Karine C. Schepers-Cheng Advanced Resources International, Inc. Southwest Regional Partnership on Carbon Sequestration Phase II Final Annual Meeting September 21 22, 2010 Albuquerque, NM

2 Outline Introduction Site Preparation and Injection Operations Enhanced Coal Bed Methane and CO 2 Sequestration: Reservoir Modeling Lessons Learned 2

3 INTRODUCTION

4 Project Objectives The Pump Canyon CO 2-enhanced coalbed methane (CO 2 /ECBM) sequestration project planned to demonstrate the effectiveness of CO 2 sequestration in deep, unmineable coal seams via a small-scale geologic sequestration project 4

5 Site Location Located in San Juan County, northern New Mexico, just within the limits of the highpermeability fairway LA PLATA CO. ARCHULETA CO. Durango Pagosa Springs COLORADO NEW MEXICO F A I R W A Y Pump Canyon Dulce Aztec Farmington Bloomfield JAF02041.CDR 5

6 SITE PREPARATION

7 Field Operations Pipeline Pipeline 4-inch diameter Indirectly tied to the Cortez pipeline Trenching started in January 2008 Halted during Section 106 Completed by end of April 2008 Was moved to water line when injection stopped 7

8 Field Operations Injection Well Well drilled to 3,000 ft Kirtland shale cored First logging suite conducted Casing set Fruitland coal drilled Coal cuttings collected Second logging Perforated liner installed Second logging suite run Flow computer setup WHP 1,110 psig 8

9 Reservoir Characterization: Logging and Seismic i 9 Upper part of the well logged on May 10, 2008 (224 to 2,933 ft): eventual fractures in Kirtland Shale Platform Express FMI log Sonic Scanner Lower part logged (2,846 to 3,158 ft): Fruitland Coal reservoir characterization Gamma Ray Density Photo Electric (PEF) Sonic Scanner Baseline VSP run on June 3 rd and 4 th, 2008: reservoir characterization and CO 2 migration Seismic attribute analysis and surface EM characterization to detect eventual fractures in seal and reservoir

10 Seal Characterization Kirtland shale was cored in May 2008 Variety of analyses conducted to assess seal integrity Mercury injection capillary pressure used to determine seal capacity Petrographic, petrophysical and geologic characterization through X-ray diffraction, total organic carbon content analysis, thin sections, scanning electron microscopy as well as laser scanning confocal microscopy, porosity, permeability, density and fluid saturation ti measurements, Analysis of noble gases to determine the natural helium concentrations, helium gradients, and 3He/4He ratios, which are being used to determine transport properties of the Kirtland and concomitant sealing behavior, Geomechanical analysis, and CO 2 sorption tests. 10

11 MVA Plan: Ground Deformation 36 tiltmeters installed 2 GPS stations InSar Used to determine the subsurface CO 2 movement and eventual CO 2 leakage 11

12 MVA: Surface CO 2 Flux Soil-gas surveys for Perfluorocarbon (PFC) tracers added to the injected CO 2 (36 stations) Direct CO 2 flux monitoring at the surface in the atmosphere (46 stations) Three mounted closed to CO 2 sensors to detect breakthrough of injected gas (tracers precede CO 2 ) 12

13 CO 2 Monitoring at Offset Production Wells CO 2 sensors installed at the 3 immediate offset wells Gas samples taken from production gas stream as well (14 wells) Gas vent tubing Antenna Solar panel Satellite Dish Antenna Data logging box Data-shock house CO 2 sensor 13

14 MVA: Water Sampling Focused on the investigation of the chemical composition of produced water from offset wells as an indicator of CO 2 migration and potential breakthrough Address CO 2 sequestration by dissolution and mineralization 14

15 Injection Operations Injection started on July 30 th 2008, ended on August 12 th, 2009 Injection stream: 98.5% CO 2, 1.5% N 2 Continuous measurements of surface rate,,p pressure, temperature and downhole pressure and temperature 4, ,500 18,400 tons injected 4,000 3,500 Injection Rate, Mscfd 3,000 2, ,000 1,500 1,000 Coal Swelling 3,000 2,500 2,000 1,500 1,000 Injection Pre essure, psig /1/08 12/30/08 7/1/ Injection Rate Injection Pressure

16 ECBM and CO 2 SEQUESTRATION: RESERVOIR MODELING

17 Reservoir Modeling Model focused on Section 32 (injector and 3 immediate offset wells) 3-layer model (Upper, Middle and Basal coals) Included all available information elevation and thickness, Isotherms: CO2/CH4 storage capacity ratio of ~2 Initial pressure measurements: 0.5 psia/ft cleat orientation, N35 for face cleats Production and injection data. 17

18 Permeability and Porosity Based on experience in the area and review of available logs, basal coal of better quality (ConocoPhillips) Flow profile survey supports above (83% of CO 2 going into bottom coal) Permeability allowed to be higher in basal coal during optimization process Porosity assumed to be correlated with permeability k k i n a * k i n typically 3, factor a varied during optimization 18

19 Model Construction COMET3 model (binary isotherm, CH 4 and CO 2 2) Structure and isopach maps included Simulation grid oriented along face cleat orientation to simulate preferential flow path Focus on Section 32 19

20 Model Views Top View 3D View 20

21 History-Match Variables and Ranges Parameters Units Min Max Formation Properties Porosity Layer Initial Water Saturation fraction Absolute Permeability Layer 3 md Permeability Anisotropy fraction 1 5 Pore Compressibility 1/psi 5.00E E-04 Matrix Compressibility 1/psi 5.00E E-06 Permeability Exponent Differential Swelling Factor Initial CO 2 Content fraction Relative Permeability Relationships Irreducible Water Saturation Maximum Krg Krw Exponent Krg Exponent Well Parameters Producer Initial Skin Producer Stimulated Skin

22 Producers History-Match Well running on gas rate while matching Gas rate BHP when available CO 2 content N 2 content from gas samples Unreliable water rate not matched 22

23 Injector History-Match Skin varied with time Positive at the beginning to reflect plugging/damage caused during drilling Improving as the well is being cleaned-up during injection Well running on wellhead pressure, matching injection rate Higher permeability in bottom coal A 4:1 ratio was applied between the basal layer and the upper/ middle layers 23

24 EPNG Com A 300 History-Match Gas Rate 5,000 12,000 4,000 10,000 Gas Ra ate, Mscfd 3,000 2,000 8,000 6,000 4,000 Water Rate, Bbld 1, , /1/1990 1/1/1995 1/1/ /31/ /1/2010 Date Actual Gas Sim Gas Actual Water Sim Water 24

25 EPNG Com A 300 History-Match Methane Mole Fraction Methane e Mole Fractio on /1/1990 1/1/1995 1/1/ /31/2004 1/1/2010 Date Actual Data Sim Data 25

26 EPNG Com A 300 History-Match Nitrogen Content t ogen Conte ent Nitr Jan-07 Apr-07 Jul-07 Oct-07 Feb-08 May-08 Aug-08 Dec-08 Mar-09 Jun-09 Sep-09 Actual Data Simulated Data 26

27 EPNG Com A 300 History-Match BHP BHP, psi /1/1990 1/1/1995 1/1/ /31/2004 1/1/2010 Date Actual Data Sim Data 27

28 EPNG Com A 300S History-Match Gas Rate Gas Ra ate, Mscfd Water Rate, Bbld /1/1990 1/1/1995 1/1/ /31/2004 1/1/2010 Date Actual Gas Sim Gas Actual Water Sim Water 0 28

29 EPNG Com A 300S History-Match Methane Mole Fraction e Mole Fractio on Methan /1/1990 1/1/1995 1/1/ /31/2004 1/1/2010 1/1/2015 Date Actual Data Sim Data 29

30 EPNG Com A 300S History-Match Nitrogen Content t Nit trogen Co ontent May-06 Nov-06 Jun-07 Jan-08 Jul-08 Feb-09 Aug-09 Mar-10 Actual Data Simulation Data 30

31 EPNG Com A 300S History-Match BHP BHP, psi /1/1990 1/1/1995 1/1/ /31/2004 1/1/2010 Date Actual Data Sim Data 31

32 FC State Com 1 History-Match Gas Rate 7, , Gas Rat te, Mscfd 5,000 4,000 3,000 2,000 1, Water Rate, Bbld 0 0 1/1/1990 1/1/1995 1/1/ /31/2004 1/1/2010 Date Actual Gas Sim Gas Actual water Sim Water 32

33 FC State Com 1 History-Match Methane Mole Fraction Methan ne Mole Fractio on /1/1990 1/1/1995 1/1/ /31/2004 1/1/2010 Date Actual Data Sim Data 33

34 FC State Com 1 History-Match Nitrogen Content t Nitr rogen Con ntent Jan-07 Apr-07 Jul-07 Oct-07 Feb-08 May-08 Aug-08 Dec-08 Mar-09 Jun-09 Sep-09 Actual Data Simulated Data 34

35 Injector Results 6,000 5,000 Injection n Rate, Mscfd 4,000 3,000 2,000 1, /1/2008 9/30/ /30/2008 3/31/2009 7/1/2009 9/30/2009 Actual Gas Sim Gas Actual Pressure Sim Pressure 35

36 Optimized Parameters Parameters Units Min Max Optimized Formation Properties Porosity Layer Initial Water Saturation fraction Absolute Permeability Layer 3 md Permeability Anisotropy fraction Pore Compressibility 1/psi 5.00E E E-04 Matrix Compressibility 1/psi 5.00E E E-06 Permeability Exponent Differential Swelling Factor Initial CO 2 Content fraction Relative Permeability Relationships Irreducible Water Saturation Maximum Krg Krw Exponent Krg Exponent Well Parameters Producer Initial Skin Producer Stimulated Skin Note: Permeability was altered around the injector to replicate flow profile survey (reduced to 10 md in the upper and middle coals) 36

37 Enhanced Coalbed Methane To assess if additional production was recovered due to the CO 2 injection, a no injection case was modeled Cumulative CH 4 Production (MMcf) No Injection Injection ECBM (MMcf) EPNG Com A 300 8,592 8, EPNG Com A 300S FC State Com 9,527 9, Totals 18,364 18,

38 Enhanced Coalbed Methane EPNG Com A 300S FC State Com 1 Methane Production Rate, Mscfd, Mscfd 0 Jan-08 Apr-08 Jul-08 Oct-08 Feb-09 May-09 Aug-09 Dec-09 Injection No Injection ne Production Rate, Jan-08 Apr-08 Jul-08 Oct-08 Feb-09 May-09 Aug-09 Dec thane Production Rate, Mscfd Metha 50 0 EPNG Com A 300 Injection No Injection Jan-08 Apr-08 Jul-08 Oct-08 Feb-09 May-09 Aug-09 Dec-09 Met 38 Injection No Injection

39 History-Match Results Discussion i Offset producers Simulated CO 2 breakthrough occurs at wells EPNG Com A 300 and FC State Com 1 Consistent with gas samples results and tracers data However breakthrough hasn t occurred at the site yet Overestimated permeability? Too much CO 2 injected? But breakthrough h might be imminenti Injector Match quite good Except peak in February 2009 overestimates injected CO 2 But some pressure/ rate actual data are inconsistent, could not be replicated 39

40 LESSONS LEARNED

41 Lessons Learned Injection was a success 319MMcf injected (18,407 tons) 26MMcf ECBM Simulation work was able to replicate production/injection profile Indication of enhanced production MVA results well replicated Breakthrough might be imminent at FC State Com 1 (increase in CO 2 and N 2, PFC breakthrough) No significant ground deformation observed Very high sealing quality of the upper Kirtland shale 41

42 Lessons Learned (cont d) Injection rate can be high Providing depleted reservoir and high initial permeability Injection rate will decline Due to re-pressurization and swelling of the coal reservoir N 2 may be a strong indicator of pending breakthrough An order of magnitude N 2 increase at two offset wells No leakage detected No tracer (water or gas detected) No bank of CH 4 or CO 2 detected Still processing time-lapse seismic 42

43 Questions? Pipeline Termination Point CPU and Telemetry Station Flow Control Valve CO 2 Line Heater Tracer Injection Point 43 Pressure and Temperature Sensors Wellhead NETL s Perfluoroocarbon Tracer Trailer