Characterization and Modeling to Examine the Potential for CO 2 Storage and Enhanced Oil Recovery in the Bakken Petroleum System

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Characterization and Modeling to Examine the Potential for CO 2 Storage and Enhanced Oil Recovery in the Bakken Petroleum System Williston Basin Petroleum

1 Characterization and Modeling to Examine the Potential for CO 2 Storage and Enhanced Oil Recovery in the Bakken Petroleum System Williston Basin Petroleum Conference Regina, Saskatchewan April 29, 2015 James Sorensen Senior Research Manager 2015 University of North Dakota Energy & Environmental Research Center.

2 Bakken CO 2 Storage and Enhanced Recovery Program Sponsoring Partners

3 Thank You!

4 Bakken Petroleum System Lithology Upper Bakken Shale: Brown to black, organic-rich. Bakken source rock Middle Bakken: Variable lithology (up to nine lithofacies), ranging from silty sands to siltstones and tight carbonates. Bakken tight reservoir rock (horizontal drilling target) Lower Bakken Shale: Brown to black, organic-rich. Bakken source rock Pronghorn Member: Mixed sandstone, siltstone, dolomite, and shale. Three Forks Formation: Interbedded dolostone/limestone, siltstone/mudstone, shale, evaporites.

5 Bakken Pore Throat Sizes (Dunn County, ND) Lower Bakken Shale Middle Bakken 5

6 Bakken and Three Forks Production Production (January 2015) Over 9000 wells in North Dakota. Over 1.1 Mbbl/day of oil. Over 1.4 Bcf/day of gas.

7 How Much Bigger Can Bakken Get? Currently, only a 3% 10% recovery factor. Small improvements in recovery could yield over a billion barrels of oil. Can CO 2 be a game changer in the Bakken? 7

8 Challenges of Enhanced Oil Recovery (EOR) in Tight Oil Formations Mobility and effectiveness of fluids through fractures relative to very low matrix permeability. How will clays react to CO 2? High vertical heterogeneity of the lithofacies complicates our understanding of flow regimes (fractures and matrix). Multiphase fluid flow behavior varies substantially depending on the size of the pore throats. Fluid viscosity and density are much different in nanoscale pores than in macroscale pores. How does the sorptive capacity of the organic carbon materials affect CO 2 mobility, EOR, and storage?

9 Pore Size Affects Fluid Phase Behavior Conceptual pore network model showing different phase behavior in different pore sizes for a bubble point system with phase behavior shift. Source: Alharthy, Nguyen, Teklu, Kazemi, and Graves, 2013, SPE , Colorado School of Mines and Computer Modelling Group Ltd. 9

$We need to understand: Rock matrix. Nature of fractures (macro and micro).$

10 How Does CO 2 Interact with a Tight Oil Reservoir? We need to understand: Rock matrix. Nature of fractures (macro and micro). Effects of CO 2 on oil. 10

11 Research Program Well Locations 11

$Reservoir Characterization Is Key Microfractures accounted for most of the porosity in the most productive zones of the Bakken.$

12 Reservoir Characterization Is Key Microfractures accounted for most of the porosity in the most productive zones of the Bakken. Scanning Electron Microscopy (SEM) Mineral Map of a Middle Bakken Sample (colors represent minerals; black represents porosity) Movement of fluids (CO 2 in and oil out) relies on fractures. Generating macrofracture and microfracture data and integrating those data into modeling are essential to develop effective EOR strategies. 12

$closed Utilize macrofracture$ $and microfracture data to help$

13 Analysis of Fractures Macro-, micro, and nano-scales Fracture properties Measure aperture, length, and orientation Open vs. closed Utilize macrofracture and microfracture data to help populate fracture properties in the static geologic model. 13

Characterization Informs Static Model to Support

$X-Ray Diffraction (XRD) and X- Ray Fluorescence$ Core Description to Log Breaks Core Permeability

Modeling Matrix Modeling Petrophysical Model

Simulation Clip Drill Spacing Unit (DSU) Model

14 Characterization Informs Static Model to Support Simulations of EOR Scenarios Core Description, X-Ray Diffraction (XRD) and X- Ray Fluorescence (XRF) Analysis Routine Core Analysis, XRD Results Core Description to Log Breaks Core Permeability and Porosity Petrophysical Modeling Structural Modeling Matrix Modeling Petrophysical Model Quality Control (QC) Prepare for Dynamic Simulation Clip Drill Spacing Unit (DSU) Model from Larger Study Area Model Fracture Modeling 14 Core and SEM Fracture Analysis

15 Drill Spacing Unit (DSU) Scale Model Simulation model DSU Cells 537,000 Grid Size ft (25 25 m) Zones six

16 Dual-Porosity Dual-Permeability Model of a DSU in Dunn County, ND 16

54-inch width 600-ft half-length 17 Local

17 Triple-Porosity Triple-Permeability Simulation Model Hydraulic Fractures Perpendicular to wellbore 30 stages with 300-ft distance between 0.54-inch width 600-ft half-length 17 Local grid refinement used to capture near-wellbore, nearfracture effects

Production response is delayed compared to CO 2 EOR in a conventional

18 DSU Simulation Results Highlights Best cases showed significant improvement in total recovery factor (some over 100%). Production response is delayed compared to CO 2 EOR in a conventional reservoir, which is in line with what we see in the lab. From NW McGregor (Mission Canyon) DFN From NW McGregor (Mission Canyon) 18

19 Next Steps for Modeling Hurley et. al Multiscale models: understand porescale processes and upscale to reservoir. Understand various mechanisms related to adsorption, diffusion, gravity, Darcy flow, etc.

20 Estimation of Bakken CO 2 Storage Capacity and EOR Potential The U.S. Department of Energy (DOE) methodology for estimating CO 2 EOR and storage capacity (2007) was applied to the Bakken in North Dakota: The approach that uses cumulative production/estimated recovery factor to calculate original oil in place (OOIP) yields a storage capacity ranging from 121 to 194 million tons of CO 2. This could yield 420 to 670 million barrels of incremental oil. The reservoir properties approach to calculate OOIP yields a storage capacity ranging from 1.9 to 3.2 billion tons of CO 2. This could yield 4 to 7 billion barrels of incremental oil.

$Use unfracced$ wells as

$fracture$ slower

21 Take Home Thoughts Unconventional resource will take unconventional approach to EOR. Diffusion is more important than displacement. Patience required, but reward may be substantial. Innovative injection and production schemes. Use unfracced wells as injectors; rely on natural fracture system for slower movement of CO 2 through the reservoir and improved matrix contact time. Injectors in the shale paired with producers in the Middle Bakken and/or Three Forks. 21

$Microfracture characterization to improve the accuracy of dual-porosity dual-permeability reservoir models.$ Hydrocarbon extraction data from the various lithofacies to derive a realistic range of diffusion rates.

Hydrocarbon extraction data from the various lithofacies to derive a realistic range of diffusion rates.

$properties of tight oil formations: Microfractures High organic content Combined diffusion, adsorption, and$

22 Take Home Thoughts Detailed reservoir characterization will be key. Microfracture characterization to improve the accuracy of dual-porosity dual-permeability reservoir models. Hydrocarbon extraction data from the various lithofacies to derive a realistic range of diffusion rates. Knowledge of CO 2 oil multiphase behavior to improve modeling and scheme designs. Existing modeling and simulation software packages do not adequately address or incorporate the unique properties of tight oil formations: Microfractures High organic content Combined diffusion, adsorption, and Darcy flow mechanisms Physical interactions between CO 2 and formation fluids 22

Pilot-Scale Field Test of CO 2 Injection into a Tight Oil Reservoir EERC activities will include: Conducting MMP and hydrocarbon extraction studies on site-specific samples.

23 Pilot-Scale Field Test of CO 2 Injection into a Tight Oil Reservoir EERC activities will include: Conducting MMP and hydrocarbon extraction studies on site-specific samples. Providing site-specific characterization and modeling support to the hosting company. Working with the hosting operator to design and implement an effective monitoring scheme to determine the fate of the injected CO 2 and its impact on the reservoir. Site host will obtain the CO 2, conduct the injection and production activities, and provide relevant data to the project team. 23

24 Thanks!

25 Contact Information Energy & Environmental Research Center University of North Dakota 15 North 23rd Street, Stop 9018 Grand Forks, ND World Wide Web: Telephone No. (701) Fax No. (701) James Sorensen, Senior Research Manager

26 Acknowledgment This material is based upon work supported by the U.S. Department of Energy National Energy Technology Laboratory under Award No. DE-FC26-05NT42592 and Award No. DE-FE Disclaimer This presentation was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government, nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof.

Latest Developments at the EERC and CO 2 Enhanced Oil Recovery (EOR) in Bakken Shale

Latest Developments at the EERC and CO 2 Enhanced Oil Recovery (EOR) in Bakken Shale 12th Annual EOR Carbon Management Workshop, Session I Midland, Texas December 9, 2014 John Harju Associate Director