Thesis Final Draft Kara Bennett

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  • POWER GENERATION POTENTIAL

    FROM COPRODUCED FLUIDS IN

    THE LOS ANGELES BASIN

    A REPORT SUBMITTED TO THE DEPARTMENT OF ENERGY

    RESOURCES ENGINEERING

    OF STANFORD UNIVERSITY

    IN PARTIAL FULFILLMENT OF THE REQUIREMENTS FOR THE

    DEGREE OF MASTER OF SCIENCE

    By

    Kara Bennett

    June 2012

  • iii

    I certify that I have read this report and that in my opinion it is fully

    adequate, in scope and in quality, as partial fulfillment of the degree

    of Master of Science in Energy Resources Engineering.

    __________________________________

    Roland N. Horne

    (Principal Advisor)

  • v

    Abstract

    There is potential to utilize oilfield infrastructure to produce geothermal electricity

    profitably, in a process called coproduction. Although many oil reservoirs represent only

    a low-to-mid temperature resource, utilizing oil infrastructure sidesteps the initial capital

    investment for exploration and development making these low temperature resourced

    profitable. Power generation from coproduced fluids using binary-cycle power plants has

    been demonstrated at the Rocky Mountain Oilfield Testing Center in Wyoming, and at

    Huabei Oilfield near Beijing, China. This research investigated the feasibility and

    profitability of implementing coproduction at the oilfields of the Los Angeles Basin. The

    Los Angeles Basin was selected because of the regions promising combination of giant

    oilfields, including Wilmington Oilfield, high water cut, 97% water in 2011, and elevated

    geothermal gradient, over 2.0F/100ft. The feasibility and profitability of coproduction in

    the Los Angeles Basin was evaluated in three steps. First, a STARS simulation model for

    each promising oilfield in the Los Angeles Basin forecasted reservoir and production

    conditions over the lifetime of the coproduction project. Second, the produced fluid flow

    rate and temperature, as predicted by the STARS model, was converted to an electricity

    output by a specific power correlation curve created by consulting the literature on

    current and past coproduction pilot test and low-temperature geothermal projects. Third,

    economic analysis was performed to determine the net present value of these

    coproduction projects considering the profits from avoided electricity purchase, initial

    capital cost of the power plant and gathering system, continued costs for operation and

    maintenance, and lost profits from the decrease in oil production due to increases in oil

    viscosity with decreasing reservoir temperature. From the nine oilfields in the Los

    Angeles Basin with sufficient production rates and reservoir temperatures for

    coproduction, four coproduction projects were found to be both feasible and profitable,

    one was deemed feasible but uneconomic due to lost oil production, and four were not

    feasible due to wellbore heat losses. The four successful projects represented a combined

    power generation potential of over 3 MW and a net present value exceeding $14 million.

  • vii

    Acknowledgments

    First and foremost I would like to acknowledge the phenomenal support and guidance of

    my advisor, Professor Roland Horne and thank him for the opportunity to work in the

    Stanford Geothermal Program and for greatly enriching my Stanford experience.

    I would also like to thank my colleagues in the Stanford Geothermal Group, Mohammed

    Alaskar, Morgan Ames, Carla Co, Egill Juliusson, Lilga Magnusdottir, Mark McClure,

    Lawrence Valverde, and past member Sarah Pistone, for research advice and camaraderie

    both in and outside the classroom. A particular thank you goes out to Kewen Li for his

    expert advice on coproduction and instrumental help in building my STARS model.

    I would like to thank Jeff Adams from the Department of Oil, Gas, and Geothermal

    Resources for his guidance in navigating the DOGGR database. Also thank you to Jeff

    Stewart and Franois Florence at Occidental Petroleum for sharing details of oil

    operations in the Los Angeles Basin.

    Lastly I would like to thank my fantastic officemates Carla Co, Chanya Thirawarapan,

    and Whitney Sargent for a truly unforgettable year.

  • ix

    Contents

    Abstract ............................................................................................................................... v

    Acknowledgments............................................................................................................. vii

    Contents ............................................................................................................................. ix

    List of Tables ................................................................................................................... xiii

    List of Figures ................................................................................................................... xv

    1. Introduction ............................................................................................................... 19

    1.1. Current Coproduction Projects ........................................................................... 19

    1.2. US Coproduction Potential................................................................................. 20 1.2.1. Gulf Coast States......................................................................................... 20

    1.2.2. California .................................................................................................... 20 1.3. Research Objective ............................................................................................. 21

    2. Los Angeles Basin Data ............................................................................................ 23

    2.1. Background ........................................................................................................ 23 2.1.1. Geology ....................................................................................................... 23

    2.1.2. History of Oil Production............................................................................ 23 2.2. Data .................................................................................................................... 25

    2.2.1. Temperature ................................................................................................ 25 2.2.2. Production and Injection Rates ................................................................... 26

    2.2.3. Viscosity ..................................................................................................... 27 2.2.4. Relative Permeability .................................................................................. 27 2.2.5. Other Data ................................................................................................... 28

    3. STARS Simulation.................................................................................................... 29

    3.1. Model Overview ................................................................................................. 29 3.2. Sensitivity Analysis ............................................................................................ 29

    3.2.1. Initial Water Saturation ............................................................................... 30

    3.2.2. Porosity ....................................................................................................... 31

    3.2.3. Reservoir Pressure ...................................................................................... 31

    3.2.4. Permeability ................................................................................................ 32 3.2.5. Oil Molecular Weight ................................................................................. 33 3.2.6. Liquid Compressibility ............................................................................... 33 3.2.7. Coefficient of Thermal Expansion .............................................................. 34

    3.3. Inputs .................................................................................................................. 37

    3.4. Outputs ............................................................................................................... 38 3.4.1. Wellbore Heat Loss Analytical Model ....................................................... 38

    4. Power Generation...................................................................................................... 41

  • x

    4.1. Binary Power Plants ........................................................................................... 41

    4.2. Net Thermal Efficiency as a Function of Geofluid Inlet Temperature .............. 42 4.3. Specific Power.................................................................................................... 43 4.4. Lower limits of power generation ...................................................................... 44

    4.4.1. Geofluid Temperature ................................................................................. 44 4.4.2. Power Plant Size ......................................................................................... 45 4.4.3. Reinjection Temperature ............................................................................. 45

    5. Economic Analysis ................................................................................................... 47

    5.1. Methodology .................................................................................