Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use

Transcription

1 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use Cari Covell Thesis of 60 ETCS credits Master of Science in Energy Engineering - Iceland School of Energy January 2016

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3 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use Cari Covell Thesis of 60 ECTS credits submitted to the School of Science and Engineering at Reykjavík University in partial fulfillment of the requirements for the degree of Master of Science in Energy Engineering - Iceland School of Energy January 2016 Supervisors: Dr. María Sigríður Guðjónsdóttir, Supervisor Adjunct Professor, Reykjavík University Mr. Sverrir Þórhallsson, Co-Supervisor Drilling Engineer, Iceland GeoSurvey (ISOR) Examiner: Dr. Ágúst Valfells, Examiner Department Head, Mechanical & Electrical Engineering, School of Science and Engineering, Reykjavík University

4 Copyright Cari Covell January 2016

5 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use Cari Covell 60 ECTS thesis submitted to the School of Science and Engineering at Reykjavík University in partial fulfillment of the requirements for the degree of Master of Science in Energy Engineering - Iceland School of Energy. Student: January 2016 Cari Covell Supervisors: Dr. María Sigríður Guðjónsdóttir Mr. Sverrir Þórhallsson Examiner: Dr. Ágúst Valfells

6 The undersigned hereby grants permission to the Reykjavík University Library to reproduce single copies of this project report entitled Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use and to lend or sell such copies for private, scholarly or scientific research purposes only. The author reserves all other publication and other rights in association with the copyright in the project report, and except as herein before provided, neither the project report nor any substantial portion thereof may be printed or otherwise reproduced in any material form whatsoever without the author s prior written permission. Date Cari Covell Master of Science

7 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use Cari Covell January 2016 Abstract Direct use of hot water through renewable energy resources is globally in demand. Thermal energy stored in fractures and pores within geothermal reservoirs contains natural fluids. At times, extracting natural fluids, or hot water in low-temperature areas, can be a challenge. Hydraulic stimulation is one technique to overcome this challenge. Research about hydraulic stimulation methods was done based on theory, fluid treatment, and well testing; in order to see unique trends for low-temperature geothermal applications. Furthermore, a literature review of all hydraulic stimulation applications was conducted to understand reasons for success or failure. In order to predict the effects of hydraulic stimulation before an actual operation, a case study was performed on well HF-1 in Hoffell, Iceland. First, a preliminary production flow model was performed using updated data at the completion of testing in After evaluating the need for stimulation, a fracture model using MFrac was done in two scenarios with an open-hole packer; injection below the packer and injection above the packer. The packer was placed in a conservative interval of m depth to isolate the main fracture at 1093 m depth. Injection below the packer failed, therefore results from injection above the packer were only suitable moving forward. Subsequently, MProd software was used to find an improvement ratio after simulating stimulation above the packer. The improvement ratio of was then applied to the original production data of well HF-1 and a LPM was performed yet again. Reservoir properties of S, T, II, and PI were calculated and compared to original production data. Results indicated the lumpfit model to be very optimistic and improvement of only 4 l/s flow over a 10 year well lifetime was observed. Therefore, the well is not a good candidate for stimulation. However, improvement was seen which proves the potential for this methodology to be implemented in other low-temperature geothermal areas. Keywords: hydraulic stimulation, packer, direct use, low-temperature, production.

8 Örvun Borholna á Lághitasvæðum Fyrir Beina Nýtingu Jarðhita Cari Covell Janúar 2016 Útdráttur Þörf er á aukinni beinni nýtingu heits vatns frá endurnýjanlegum orkugjöfum. Varmaorka finnst í vökva sem finna má í sprungum og holum í jarðhitakerfum og getur verið mikil áskorun að nýta þennan vökva úr lághita jarðhitakerfum. Örvun borholna með vökva og ádælingu (e. hydraulic stimulation) er ein leið til að auðvelda þessa nýtingu. Rannsóknir um örvunaraðferðir, vökvameðferð og borholuprófanir voru teknar saman til þess að fá yfirlit yfir örvunaraðgerðir fyrir lághitaborholur. Ennfremur var tekið saman efni úr heimildum fyrir þær örvunaraðgerðir með vökva sem gerðar hafa verið til að fá yfirlit yfir reynslu af þeim. Til þess að spá fyrir um áhrif örvunaraðgerða með vökva eftir borun var rannsókn gerð á holu HF-1 á svæði Hoffells á Íslandi. Fyrst var einfalt rennslislíkan framkvæmt út frá mæligögnum frá Eftir að þörfin á örvun var metin, var sprunguhermunarlíkanið MFrac notað fyrir tvö tilvik með pakkara (e.packer) fyrir opna holu, annars vegar þar sem svæðið ofan við pakkarann var örvað og hins vegar svæðið neðan við pakkarann. Pakkarinn var staðsettur á m dýpi til að einangra aðalæðina sem er á 1093 m dýpi. Ádæling neðan við pakkarann gaf ekki góða raun og því voru niðurstöður fyrir ádælingu ofan við pakkarann eingöngu nýttar í framhaldinu. MProd forritið var notað til að reikna út breytingu á rennsli eftir örvun fyrir ofan pakkarann. Hlutfall rennslis fyrir og eftir örvun var 1,096 fyrir holuna HF-1 og var forðafræðilíkan (LPM) notað til að spá fyrir um framleiðslugetu örvaðrar holu. Forðafræðieiginleikar S, T, II og PI voru reiknaðir og bornir saman við upphaflegu gildin. Niðurstöður úr líkaninu sýna framleiðsluaukningu um einungis 4 l/s yfir 10 ára líftíma holunnar. Því er ályktað að holan henti ekki vel til örvunar. Sú aðferðafræði sem þróuð var við gerð þessa verkefnis er nýtt framlag til rannsókna á lághitasvæðum. Lykilorð: Örvun jarðhitaholna, pakkari, bein nýting, lághitasvæði, framleiðsla

9 v Acknowledgements I would like to thank my supervisor María Guðjónsdóttir for her moral support, encouragement, and guidance in this thesis; and for being a great mentor throughout the duration of my masters studies. I would also like to thank my co-supervisor Sverrir Þórhallsson for providing useful knowledge and assistance with the MFrac suite; as well as my examiner Ágúst Valfells for reviewing the thesis. I would like to acknowledge the following Iceland GeoSurvey (ISOR) staff: Guðni Axelsson for guidance regarding the initial stages of finding a case study; Sigurður Kristinsson for providing references to Hoffell drilling reports; and Helga Tulinius for her help with Lumpfit beta. Furthermore, I would like to acknowledge Magnús Ólafsson from RARIK (Iceland State Electricity) for allowing the use of production data for the case study; and Baker Hughes Inc. for allowing academic use of MFrac suite software. Additionally, I would like to recognize the Geothermal Resources Council (GRC) Graduate Scholarship and the Iceland School of Energy Sustainable Future Scholarship for funding throughout my masters studies. I express my sincerest gratitude to Halla Hrund Logadóttir, Director of the Iceland School of Energy, for being an incredible mentor and a truly inspiring person. Her unconditional support related to my academic, professional, and personal growth is greatly valued. I am also very grateful to The GREEN Program as they initiated my passion for a career in geothermal energy on an international scale, and have continuously motivated me throughout my masters studies. Finally, I would like to thank my friends Jenn and Angelica for their support from home; my classmates whom have become friends through spending quality time at Miklabraut 64 and Ú214; and my family for allowing me to pursue all of my crazy ambitions.

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11 vii Contents List of Figures List of Tables List of Abbreviations xi xiv xvii 1 Introduction Objectives Structure of the thesis Background Well stimulation theory Hydraulic stimulation Mechanics Frac fluid treatment Hydraulic well testing Thermal stimulation Chemical stimulation Types of hydraulic stimulation Air-lift pumping Open-hole with a packer Before deploying the packer Installing the packer Setting the packer Opening the bottom plug Stimulation Releasing the packer Zonal isolation Use of a liner

12 viii Use of a liner with inflatable or swellable packers Plug and go Multilateral wellbores and sidetracks Environmental impacts and seismicity Literature review Hydraulic stimulation applications Oil and gas industry Low temperature geothermal areas Reykir hydrothermal system Seltjarnarnes well SN Other low-temperature fields in Iceland High temperature geothermal areas Baca, New Mexico (USA) Latera, Italy Salak, Indonesia Mt. Apo, Philippines Enhanced geothermal systems (EGS) History of stimulation fracture modeling Methods Case study: Hoffell well HF Lumpfit parameter model (LPM) LPM solution methodology Initial production modeling of Hoffell HF MFrac model MFrac governing equations Mass conservation Mass continuity Momentum conservation Width-opening pressure elasticity condition Fracture propagation criteria MFrac solution methodology Stimulation set-up Governing model parameters Wellbore hydraulics Rock properties Zones data

13 ix Treatment schedule Fluid loss Proppant criteria Heat transfer MProd model MProd governing equations Dimensionless parameters Pseudopressure Trilinear solution Pseudosteady-state pressure and resistivity solutions Wellbore choked skin effect Pseudo-radial flow solution Productivity increase Desuperposition Stimulation set-up Formation data Single case fracture characteristics Well data Results MFrac Fracture propagation solution Proppant design summary Total fluid loss and leakoff rate output Heat transfer solution MProd Lumpfit parameter model Summary Discussion Conclusions Future work Recommendations A Open hole packer 109 B Thermal Stimulation in Iceland 111 C EGS Applications 121

14 x D Fluid and proppant type properties 135 E MFrac report 137 F MProd report 139

15 xi List of Figures 1 Fracture propagation as a result of Hydraulic Proppant Fracturing [14] Fracture propagation as a result of Water Fracturing [14] Schematic illustration of the setup for air-lift pumping [19] Diagram for design of air-lift pumping, based on water well experience [26] 17 5 Schematic picture of injection via a packer [22] Results of production testing of well SN-12, where symbols show observed data one hour into each step and lines show calculated output characteristics [41] Stimulation methods applied to EGS projects worldwide as of 2013 [56] Rock type and well depth of EGS projects worldwide as of 2013 [56] Locations of geothermal areas in Iceland based on reservoir temperature and geology [19] Map showing the location of the Hoffell case study area [63] Location of well HF-1 and some exploration wells [64] A general lumped parameter model used to simulate water level or pressure changes in a geothermal system. The three tank scenario is shown here [70] Monitored and calculated water level of Well HF-1 from April 9, 2013 to September 8, 2013 of the long-term production test. Calculated values are those of the LPM, where the left shows the two-tank closed model and the right shows the two-tank open model. Time t = 0 corresponds to April 9, 2013 [61] Monitored and calculated water level of Well HF-1 from May 9, 2013 to May 8, 2014 of the long-term production test. Calculated values are those of the LPM, where the left shows the two-tank closed model and the right shows the two-tank open model. Time t = 0 corresponds to May 9,

16 xii 15 Long-term production test for a one year period of well HF-1. Time t = 0 corresponds to May 9, Predicted water levels in well HF-1 for the next 10 years for different production rates using the five month period long-term production test data. Conservative predictions using two-tank closed model are on the left. Optimistic predictions using two-tank open model are on the right [61] Predicted water levels in well HF-1 for the next 10 years for different production rates using the year-long period of long-term production test data. The optimistic two-tank open model is shown MFrac Pipe Friction Empirical Correlations [72] Wellbore cross section for Hoffell well HF Velocity of cuttings in mm/s [58] Upper and lower fracture zone height when stimulated below the packer Upper and lower fracture zone height when stimulated above the packer Frac width as a function of frac length for stimulation below the packer Frac width as a function of frac length for stimulation above the packer Net pressure measured after stimulation below and above the packer Frac fluid efficiency after stimulation below and above the packer Leakoff rate after stimulation below and above the packer Temperature as a function of fracture length after stimulation below and above the packer Flow rate of Hoffell well HF-1 before and after stimulation Measured and calculated water level of a long-term production test after stimulation of Hoffell well HF Long-term production test before and after stimulation for a one year period of well HF Predicted water levels in well HF-1 for the next 10 years for different production rates using the simulated year-long period of production test data after stimulation. The optimistic two-tank approach is shown Cross section of Baker Hughes packer " OD ISP for formation test [19] Pressure, temperature, and injection rates during step-rate test of well KJ- 38 [18] Temperature logs throughout stimulation of well HE-8, where the November logs were performed after a 3 month cooling period following drill completion [92]

17 xiii 36 Calculated injectivity index for each cycle of stimulation in well HG-1 as a function of volume of injected fluid into the well [18] Fluid type parameters for WG lb/mgal low viscous gel [72] Proppant type parameters for 20/40 mesh Jordan sand [72]

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19 xv List of Tables 1 Improvement ratios in MG-27 [43] Improvement ratios in MG-35 (based on [43]) Well Baca 23 hydraulic stimulation treatment schedule [49] Predicted water levels in well HF-1 after 10 years production [m] Fanning friction factors Casing Dimensions for Hoffell well HF Hoffell well HF-1 deviation Rock properties of Hoffell well HF Treatment schedule for Hoffell well HF Pressure dependent fluid loss for well HF Proppant criteria for well HF Heat transfer properties for Hoffell geothermal field Formation data for well HF Well data for Hoffell well HF Fracture propagation solution. Calculated values are at the end of treatment Proppant design summary for stimulation below and above the packer Summary of fluid loss below and above the packer. Calculated values are at the end of treatment MProd single case fracture characteristics dialog box MProd production solution for Hoffell well HF Improvement ratios for well test data after stimulation above the packer Predicted water levels after stimulation in well HF-1 after 10 years production based on year-long production data

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21 xvii List of Abbreviations BMU BHTP CA DOE ECP EGS ENEL EOJ EPDM FLA GDY GRWSP HDR HEGF HF HPF HWR ID IDH ISOR LPM MD NEDO The Federal Ministry for the Environment (Bundesmin für Umwelt, Germany) Bottom Hole Treating Pressure California Department of Energy External Casing Packer Enhanced Geothermal System National Entity for Electricity (Ente nazionale per l energia elettrica, Italy) End of Job Ethylene Propylene Diene Monomer Fluid Loss Additive Geodynamics Ltd. Geothermal Reservoir and Well Stimulation Program Hot Dry Rock High Energy Gas Fracturing Hybrid Fracturing Hydraulic Proppant Fracturing Hot Wet Rock Inside Diameter Idaho Iceland GeoSurvey Lumped Parameter Modeling Measured Depth New Energy and Industrial Technology Development Organization

22 xviii NM NV OD OFEN OR PRB RSF TVD USA WF WHP New Mexico Nevada Outside Diameter Federal Office of Energy (Switzerland) Oregon Permeable Reactive Barriers Reactant Sand Fracking Total Vertical Depth United States of America Water Fracturing Wellhead Pressure Nomenclature A C C 1 C D C D f C f D C t c tf E F G(θ) H H p H w h J k Leakoff area (one face of the fracture) Total leakoff coefficient Dimensionless inverse fracture diffusivity Dimensionless wellbore storage coefficient Dimensionless fracture storage coefficient Dimensionless fracture conductivity Total reservoir compressibility Fracture compressibility Young s modulus Reservoir aspect ratio Fluid loss function Fracture half-height Pay zone height Total wellbore height Pay zone height Productivity index Permeability

23 xix k Consistency index k f w f Fracture conductivity k f k h k l k v L l h Propped fracture permeability Horizontal reservoir permeability Fracture damaged zone permeability Vertical reservoir permeability Fracture half-length length of horizontal lateral n Flow behavior index NaCl Sodium Chloride Na 2 CO 3 Sodium Carbonate P Pressure P w D Dimensionless wellbore pressure P w f Bottomhole flowing pressure p i q q D r w r wa R w S S ch S p S f s T t t D t DA t Df Initial reservoir pressure Injection flow rate Dimensionless flow rate Wellbore radius Apparent wellbore radius Dimensionless apparent wellbore radius Wellbore skin factor Chocked fracture skin Spurt loss coefficient Fracture skin factor Laplace space variable Reservoir temperature Time Dimensionless Nolte time Dimensionless time based on drainage area Dimensionless time based on fracture length

24 xx t Dw V f V l V sp W W(0,t) W(ζ,t) w f x x f y y s z Dimensionless time based on wellbore radius Fracture volume Fluid loss volume (no spurt loss) Volume loss by spurt Fracture width Average wellbore fracture width Fracture width as a function of position Propped fracture width Lateral coordinate along the fracture length Propped fracture half-length Coordinate perpendicular to the frac face Damaged zone adjacent to fracture Vertical coordinate Greek α a α c α L α p α w γ f,γ f γ w,γ w P η ζ θ Leakoff area parameter Leakoff parameter during pumping Length propagation parameter Pressure parameter Width propagation parameter Friction coefficients Width profile coefficients Net fracturing pressure Fracture efficiency Dimensionless lateral coordinate Dimensionless time µ Equivalent reservoir viscosity τ Time of fracture leakoff area creation Φ Fluid loss parameter φ Equivalent reservoir porosity σ Minimum horizontal stress

25 1 Chapter 1 Introduction Direct use of geothermal energy is the oldest and most common form of geothermal utilization [1]. Traditionally, direct use of geothermal energy has been small scale applications by individuals, but more recent developments involve large scale projects in commercial industry. Direct application of geothermal energy involves a wide variety of end uses, such as space heating and cooling, greenhouses, fish farming, and health spas. Flexibility in direct application by use of geothermal energy makes a more attractive option over other means of resource exploitation; such as coal, oil, gas, or electricity. Geothermal energy consists of thermal energy stored in the earth s crust [1]. Thermal energy in the earth is distributed between constituent host rock and natural fluids that are contained in fractures and pores at temperatures above some specified reference temperature [2]. In direct use, natural fluid is usually associated with hot water. Sometimes however, extraction of hot water presents several challenges due to possible obstructions in fractures or poor fracture connectivity to the reservoir. Hydraulic stimulation is one technique to overcome challenges of fluid extraction, which is similar to the more well-known term of hydraulic fracturing. Hydraulic stimulation is the process of injecting fluid into a rock mass at or below the fracture opening pressure, and seeks to induce shear deformation on naturally oriented fractures to increase permeability within the rock mass [3]. Hydraulic fracturing is the process of injecting fluid into a rock mass at a rate and pressure sufficient to form and propagate new fractures [3]. For the purposes of this thesis, the two terms are used interchangeably because applications presented later in this thesis, specific to Chapters 2 and 3, possess qualities of both definitions. However, hydraulic stimulation is the more politically correct term to entitle this thesis, as most theories and applications will be derived from this mechanism. For clarity moving forward, the definition of hydraulic stimulation is used but not for the purpose of

26 2 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use increasing permeability; rather it is for the purpose of propagating new fractures. This is mostly applicable for the case study performed later in this thesis throughout Chapters 4 and 5. Hydraulic stimulation can be performed in several types of geothermal areas, including low-temperature, high-temperature, and enhanced geothermal systems (EGS). Lowtemperature geothermal areas are defined as having reservoir temperatures below 150 C, while high-temperature geothermal areas are defined as having reservoir temperatures above 200 C [4]. For the purposes of this thesis, EGS areas are defined as having reservoir temperatures less than 200 C, but with very low permeability in the rock mass [5]. Low-temperature geothermal fields, by nature, compose of direct use resources almost entirely for purposes of hot water production; contrary to high-temperature and EGS fields that are capable of co-producing steam for electricity. Therefore, hydraulic stimulation in low-temperature geothermal areas for direct use is a topic of interest, as there is more potential to access natural fluids for a better way to create an almost exclusive network to meet local demand. The knowledge gap lies in predicting the amount of production potential from natural fluids after a hydraulic stimulation operation. 1.1 Objectives The thesis will focus on geothermal resource extraction for direct use by means of hydraulic stimulation in low temperature geothermal areas. One objective is to research all types of hydraulic stimulation methods available in order to see if a particular guideline is necessary for low-temperature geothermal applications. These methods include air-lift pumping, open-hole packers, and zonal isolation. Furthermore, hydraulic stimulation can be performed using different types of fracturing fluids ("frac fluids") to aid in stimulation; including hydraulic proppants, water fracs, and hybrid fracs. The next objective is to review the literature available for each type of geothermal area in order to understand reasons for success (or failure). Another objective is to evaluate the methods most suitable for a case study in Hoffell, Iceland, in order to predict the effects of hydraulic stimulation before the actual operation. This is done by conducting a fracture model using MFrac and a subsequent production model using a combination of MProd and Lumpfit beta. Through modeling an optimal hydraulic stimulation, an evaluation of productivity improvement is performed to compare to the literature review.

27 Cari Covell 3 The last objective is to assess a potential need for technological developments within the chosen methods. This includes analyses of improving modeling methodology in order to recommend procedures applicable to low-temperature geothermal environments. 1.2 Structure of the thesis Chapter 2 discusses background information about three major types of stimulation: hydraulic, thermal, and chemical. Furthermore, hydraulic stimulation is discussed in detail as this is the focus topic of the thesis. Theory of hydraulic stimulation includes several mechanisms of mechanics, frac fluid treatment, and well testing. Methods of hydraulic stimulation are described in three categories: air-lift pumping, open-hole stimulation with a packer, and zonal isolation. Each method includes a guide for conducting stimulation; some of which have multiple options to consider. Lastly, environmental impacts and seismicity are addressed in this chapter. Environmental challenges include the use of chemicals in the fracking fluid, drilling noise, damage to flora, and changes in thermal manifestations. Induced seismicity from stimulation practices has been the topic of many studies throughout Australia and Europe. Chapter 3 is the literature review for hydraulic stimulation applications. Hydraulic stimulation practices originate from the oil and gas industry, where technologies other than those described in Chapter 2 are discussed regarding potential use in the geothermal industry. Low temperature geothermal areas that have experienced hydraulic stimulation only include sites in Iceland, where emphasis is on the Reykir hydrothermal field and Seltjarnarnes well SN-12. The first experiments of hydraulic stimulation in high temperature geothermal areas were in Japan, but open source information is limited on stimulation programs conducted. Earliest forms of packer and proppant technology in high temperature geothermal areas were initiated by the United States Department of Energy (DOE) in the early 1980s where the Baca site of New Mexico was the first stimulation practice of its kind. Other sites included in the literature review are in Italy, Indonesia, and the Philippines. Enhanced geothermal systems (EGS) are the most common fields for hydraulic stimulation research and application. All EGS sites that have experienced hydraulic stimulation are reviewed in this chapter of the thesis. In addition to performing a literature review of hydraulic stimulation applications, a section is dedicated to the review of fracture simulation modeling through the use of different types of software. Chapter 4 describes the methods used for various hydraulic stimulation analyses for a case study in the Hoffell low temperature geothermal field of Iceland. Well HF-1 was used to

28 4 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use target a fracture of 1093 m depth, via two scenarios of hydraulic stimulation below and above a packer. Prior to modeling stimulation, a lumpfit parameter model (LPM) for well production analysis was used to compare more detailed data obtained over a yearlong period to a previous study done over five months of data. After obtaining a basis motivation for stimulation in the well, MFrac software was used to model the effects of fracture design and treatment analysis. The well was built in the software based on casing and deviation data, rock properties, and zones of stimulation. Additionally, the treatment schedule, fluid loss, proppant criteria, and heat transfer properties were defined. The MProd software was then used to model production flow after hydraulic stimulation. Formation data, single phase fracture characteristics, and well data were all defined as parameters before simulation. Pressure boundary conditions were also defined from the MFrac output to compare to original production test data of Hoffell well HF-1. Chapter 5 indicates results after hydraulic stimulation was modeled in MFrac, MProd, and Lumpfit beta software. In MFrac, solutions are included for fracture propagation, proppant design, total fluid loss due to leakoff rate, and heat transfer effects. In MProd, flow rate was analyzed before and after stimulation in order to determine an improvement ratio for the simulated production test. In Lumpfit beta, the improvement ratio was applied to the original year-long production test data of Hoffell well HF-1 in order to determine the success, or failure, of the stimulation. Production over a 10 year lifetime was also included in the analyses of this thesis. Chapter 6 provides a summary as a means of guided discussion, as well as important conclusions, means of future work, and author recommendations. The summary describes the basis for conducting background and literature reviews of hydraulic stimulation, as well as findings within MFrac, MProd, and Lumpfit beta unique to the case study. Conclusions about the margin of production improvement with regards to the sensitivity of each software is also provided in this chapter. Future work includes the use of other tools within MFrac and MProd, as well as additional software within the MFrac suite. Finally, recommendations from the author include studies within Iceland and other geothermal fields around the world.

29 5 Chapter 2 Background The stimulation of geothermal reservoirs involves the opening up of existing fractures by injecting fluid into a rock mass at optimal high pressures, traditionally performed using hydraulic, thermal, or chemical procedures. Most geothermal stimulations occur as part of well drilling completion programs primarily for three reasons: 1) to get more water flow out of the well for improved economics, 2) clean out drill cuttings that may have caused blockage, as well as or alternatively to 3) increase permeability for connecting fractures between wellbores together to the main reservoir. Depending on the objective of a particular stimulation operation, different hydraulic stimulation methods are available. Each method has a certain form of design and implementation in the geothermal field. With stimulation comes environmental impacts, which are usually associated with negative connotation. However research has shown that several measures can be taken to mitigate environmental impacts related to reservoir exploitation. Seismic history is also discussed in this chapter as microseismic events in Australia and Europe have been the subject of many recent studies, where seismic events are analyzed to understand the underlying mechanisms influenced by stimulation. 2.1 Well stimulation theory Generally, there are three types of geothermal well stimulation. Hydraulic stimulation is the process of injecting fluid into a rock mass at or below the fracture opening pressure, and seeks to induce shear deformation on favorably oriented natural fractures [3]. In thermal stimulation, injectivity increases with injection time and with temperature contrast between the reservoir and cold injection temperature [6]. Chemical stimulation involves a mixture of acids that are injected into a well in order to dissolve material clogging the

30 6 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use fracture system of the reservoir, and aims to improve near- well permeability similar to that of hydraulic stimulation. In addition to the three methods described, other methods such as explosives are used in the oil and gas industry and are further explained in the oil and gas applications section Hydraulic stimulation Hydraulic stimulation involves several mechanisms that are contributing factors to shear deformation due to the injection of fluid into a rock mass. The types of mechanisms described in this thesis are fluid mechanics, solid mechanics, fracture mechanics, and thermal mechanics. The composition of frac fluid also plays an important role in the type of fracture created, but each option possesses several advantages and disadvantages. To measure the effects of hydraulic stimulation, well tests are performed before, during, and/or after stimulation operations. Well tests include measurements of injectivity and productivity improvement ratios within a particular well Mechanics The mechanics of hydraulic stimulation is divided into four categories. In stimulation (or fracturing), fluid mechanics describes the flow of one, two, or three phases within the fracture. Solid mechanics describes the deformation or opening of the rock because of the fluid pressure. Fracture mechanics describes all aspects of the failure and parting that occur near the tip of the hydraulic fracture. Thermal mechanics describes the exchange of heat between the fracturing fluid and the formation. Each case is governed by different factors that all play a role in hydraulic stimulation Fluid mechanics Fluid mechanics of a geothermal reservoir play an important role in well stimulation. Factors that are associated with fluid mechanics in a geothermal reservoir include porosity, permeability, reservoir pressure, and skin effect. Porosity (φ) is the fraction of total formation volume that is not occupied by solid rock (i.e., filled with formation fluid), measured as volume fraction (range from 0 to 1) or percent (from 0 to 100). Porosity is used in many correlations to develop a first estimate of other properties, such as rock strength or permeability, and relies mostly on the space present within particles at the time of deposition [7]. A distinction between total porosity (φ total ) and effective porosity (φ eff ) is noted as each governs assumptions for different types of flow. The total porosity is the volume not occupied by solid rock, but part of

31 Cari Covell 7 the volume is occupied by bounded fluid that cannot move. The effective porosity is the volume occupied by moveable fluids, and it is the porosity of interest for most oilfield applications [7]. A notable exception is the use of φ total for all reservoir calculations involving transient flow, or flow affected by changes in velocity and pressure [7]. In addition, no open or cased hole log measures porosity directly, but rather a property related to porosity is measured, such as density or resistivity. This is why a combination of porosity measurements is preferred for estimating φ eff [7]. The most exact porosity measurements are made on cores, should they be available. Density tools are used to measure the electron density of a formation, which is extremely close to its bulk density ρ b [8]. If the density of the matrix components ρ ma and that of the pore fluid ρ f are known, the total porosity from density can be found by volume balance: φ D = ρ ma ρ b ρ ma ρf (1) where ρ ma is determined from the lithology and ρ f is taken as that of the mud filtrate, which is obtained from charts as a function of temperature, pressure and salinity [7]. Permeability is a measure of the ease with which fluids can flow through a formation, and the value of permeability depends on the orientation of flow. In the absence of natural fractures, the permeability k h parallel to the bedding of the formation is considered isotropic, or identical in all directions. However when natural fractures are present, k h varies and have a preferred direction. The permeability perpendicular to the bedding k v relates to the dominant geological nature of the reservoir and is usually only accounted for in horizontal wells [7]. Relative permeability accounts for more than one fluid type, and is sparsely considered in low temperature geothermal well stimulation [7]. Direct measurement of permeability can be obtained from well tests or sampling cores. Reservoir pressure, or pore pressure, is the pressure of the fluid in a geological formation. Pore pressure is an input for designing stimulation treatments of multiple layers in the reservoir, in order to account for crossflow between zones. After production, its value can differ significantly from one layer to the next within a formation [7]. Reservoir pressure is obtained by a point measurement from well tests and the gaps between the measurements are filled by building pressure profiles. Skin effect is a measure of the damage inflicted to the formation permeability in the vicinity of the wellbore. Damage may result from drill cuttings and mud cake from completion processes or from the production of formation fluids, and skin effect can therefore vary during the lifetime of a well [7]. For the design and execution of a stimulation treatment, the skin effect of interest is that related to the injection of treatment fluids into the for-

32 8 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use mation. The injection skin effect is obtained after conducting an injection test, explained further in section Solid mechanics Solid mechanics theory is associated with rock stress properties in an active geothermal area. Elastic and failure parameters are used in stress models to obtain a stress profile as a function of depth and rock properties. These profiles are important for estimating the stress variation between layers, and consequently the geometry of hydraulically induced fractures [7]. The parameters involved are Young s modulus, Poisson s ratio, and the poroelastic coefficient. Young s modulus (E) defines the elastic relationship between stress and strain in a material. Poisson s ratio (ν) is the fraction of rock expansion in the transverse direction divided by the fraction of rock compression in the axial direction. The poroelastic stress coefficient (η) controls the value of stress changes induced by pore pressure changes that result from depletion, injection or fracture fluid loss. All of these values are accounted for when designing well stimulation treatments, as they are associated with the rock type constructed in the applicable stimulation modeling software. Note that in stimulation (or fracturing) practices, seismicity is an effect of rock stress changes, which is discussed further in the Environmental impacts and seismicity section Fracture mechanics Fracture mechanics are important to analyze when modeling a stimulation treatment. Factors that are associated with fracture mechanics include tip effects and fluid losses. Fracture tip effects are governed by some net pressure in the fracture that controls fracture width. Net pressure and fracture height are directly related, and net pressure is dependent on fluid viscosity and pump rate. However in some cases, field observations have shown net pressure, and presumably fracture width, to be greater than predicted [9]. In such cases the fluid viscosity has a small effect on fracture width [9]. At a constant pump rate, it can be assumed that there is no net pressure at the fracture tip; i.e. fracture tip effects are ignored and is therefore a valid assumption to make when modeling a pre-stimulation treatment [7]. Fluid loss is a major fracture design variable characterized by a fluid loss coefficient C and a spurt loss coefficient S p. The total fluid loss from the fracture (volume loss) is controlled by the total fluid loss coefficient C, where the volume lost while a hydraulic fracture treatment is being pumped can be approximated by [10] [11]: V Lp = 6ChL L t p + 4Lh L S p (2)

33 Cari Covell 9 where h L = permeable or fluid loss height, L = fracture penetration length, and t p = pumping time for a treatment. The magnitude of C is typically from to 0.05 ft/min 1/2 [7]. Spurt loss is the instantaneous volume loss of fluid per unit area that occurs prior to the development of a filter cake, and occurs only for wall-building fluids [7]. After stimulation, the fluid losses can be measured through field tests Thermal mechanics The properties of fracturing fluids show some dependence on temperature. In a typical fracturing treatment, the fluid is pumped at a temperature significantly below the reservoir temperature. As the fluid penetrates farther into the fracture, heat transfer occurs between the fracturing fluid and the rock, resulting in an increase in fluid temperature. The temperature gradient in the direction perpendicular to the fracture wall is significantly larger than those in other directions, so the temperature gradients in the other directions can be neglected [7]. In addition, heat conduction in the fluid can be ignored because it is small relative to both conduction in the rock and transport of heat with the moving fluid [7]. These assumptions reduce the heat transfer problem to a 1D problem perpendicular to the fracture wall, with conduction through the rock to the fracture face and convection from the rock face into the fluid Frac fluid treatment Hydraulic stimulation is usually conducted in two stages of fluid injection [12]. First, the pad stage is where only the hydraulic fracturing fluid, mainly water, is injected into the well to either clean out drill cuttings or breakdown the geological formation. Second, the slurry stage is where a mixture of fracturing fluid and propping solid material called a "proppant" is injected into the well and into the fractures. There are mainly three types of proppant injection fluid methods used during hydraulic stimulation within a pay zone. A pay zone is the portion of rock in a reservoir that contains economically producible hydrocarbons, or hot water in geothermal applications [13]. Hydraulic Proppant Fracturing (HPF) is the most conventional method in use for hydraulic stimulation [12]. HPF uses highly viscous gel as fracturing fluid, usually in the form of a polymer. A high proppant concentration creates conductive yet relatively short

34 10 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use fractures in porous media suitable in reducing permeability impairments (i.e. "skin") in the wellbore, as illustrated in Figure 1. The well is shut after the fracturing process to allow proppant transport through the fractures. However, HPF is prone to leave gel residues and may result in the precipitation of minerals, which affects well performance [12] [14]. Water Fracturing (WF), or "Water Fracs", is essentially water containing friction-reducing agents added with a low proppant concentration. The WF method creates long and narrow fractures from the wellbore to the natural fracture network, which is at some distance from the main reservoir, as illustrated in Figure 2. The fracture conductivity induced by WF is maintained by the self-propping ability of the reservoir rock. Since WF is dependent on the self-propping ability of the reservoir formation, fracture closure is likely to occur rapidly as a result of pressure solution processes in regions of high stress [12] [14]. In addition, the low viscosity of water makes it difficult to effectively transport proppants into the newly created hydraulic fractures [12]. Hybrid Fracturing (HF), or "Hybrid Fracs", is a combination of different gels used in the HPF method and slick water fluids used in the WF method, or otherwise known as a cross-linked gel proppant. The concept is to utilize the advantages of the HPF and WF methods in creating the fracture geometry as well as effectively placing the proppant into the induced fracture. In the HF method, the fractures are considerably longer compared to HPF and the effective propped fracture length is higher compared to WF [14]. The HF method usually inherits the same problems as the parent frac methods [12].

35 Cari Covell 11 Figure 1: Fracture propagation as a result of Hydraulic Proppant Fracturing [14] Figure 2: Fracture propagation as a result of Water Fracturing [14]

36 12 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use Hydraulic well testing A series of hydraulic tests are performed before, during, and/or after a stimulation treatment. These include short or long term injection tests to measure reservoir characteristics, and production step tests for measuring well output. Well testing is performed to compare well behavior before and after a stimulation, and is typically used as a point of reference during stimulation between cycles. The injection well test is a field test method where fresh water is injected into the well to raise the water level until a steady height is attained, and the pressure or water level change in the well is recorded. When a well is subjected to injection in order to monitor the pressure response in a reservoir (i.e. pressure transient), it is used to evaluate the properties that govern flow characteristics in the well. These properties include permeability, wellbore skin, storativity, transmissivity, initial pressure, and reservoir boundaries. Permeability and wellbore skin have been previously described in the Fluid mechanics section The storativity describes pressure movement within the reservoir, and is defined as: S = c t h (3) where S = storativity [m 3 /Pa m 2 ], c t = compressibility of the fluid [Pa 1 ], and h = effective reservoir thickness [m]. The transmissivity describes the ability of the reservoir to transmit fluid, which mainly effects the pressure gradient between the well and the reservoir, and is defined as: T = kh µ (4) where T = transmissivity [m 3 /Pa s], k = permeability of the rock [m 2 ], h = effective reservoir thickness [m], and µ = dynamic viscosity of the fluid [Pa s].

37 Cari Covell 13 During an injection test, the injectivity index is often used as an estimate of the connectivity of the well to the surrounding reservoir and is defined as: II = Q P (5) where II = injectivity index [(L/s)/bar], Q = change in flow rate [L/s], and P = change in pressure [bar]. In the case of low-temperature wells tested through production step testing a comparable index is defined, termed productivity index (P I). The productivity index is a measure of well potential, or ability to produce, and is defined as the total mass flow rate per unit pressure drawdown, as explained further in the MProd governing equations section of Chapter 4: Methods. The injectivity index (as well as the productivity index) is a simple relationship, approximately reflecting the capacity of a well, which is useful for determining whether a well is sufficiently open to be a successful producer and for comparison with other wells [15]. This neglects, however, transient changes and turbulence pressure drop at high flow-rates Thermal stimulation Thermal stimulation relies on the thermal contraction induced by a significant temperature difference between the cold injection fluid against the hot rock formation (to create new fractures) and the enhancement of near wellbore permeability. Thermal cracking is attained by alternately injecting cold fluid and allowing the well to heat up the formation as thermal recovery ensues. Cold fluids may include cooling tower condensate, fresh water, seawater, or cold waste brine [12] [16]. Several mechanisms that may enhance reservoir permeability include: 1) the reopening of pre-existing fractures due to thermally induced rock contraction, 2) the shearing of pre-existing fractures, 3) the creation of new fractures due to thermally induced stress changes, or 4) the development of secondary fractures due to the contrast in the thermo-elastic properties of rocks mineral components. Cleaning out of drilling cuttings that clog feed zones can also contribute to the effective permeability of the well, particularly in the initial cycles.

38 14 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use To date, a standard procedure for conducting thermal stimulation operations has not been established as the mechanism of cold water stimulation is still poorly understood [16] [17] [18]. Such practices include cold fluid injection through the drill string when the drilling rig is still on site, through an open ended drill pipe left in the well, or at a closed wellhead after the drill rig is removed [16] [19]. In addition, thermal stimulation pumping pressures are usually kept relatively low so as to not cause hydraulic stimulation, yet productivity improvements have been achieved even if the warming stage has been excluded [12]. For the purposes of this thesis, thermal stimulation will not be discussed in great detail Chemical stimulation Chemical stimulation, or more commonly known as acid stimulation, began as far back as 1895 when hydrochloric acid (HCl) was used to treat oil wells [20]. Despite success with HCl, it did not gain popularity due to corrosion problems affecting wellbore casings [12]. The use of acid was again attempted in 1932 when Grebe and Stoesser of Dow Chemical Co. discovered arsenic as a corrosion inhibitor. Acidizing technology has since advanced with the development of additives, methods, and systems to improve zone coverage during the acidizing process [7]. Chemical stimulation in the geothermal industry began in 1977 with the application of sodium carbonate (Na 2 CO 3 ) in the Fenton Hill Hot Dry Rock (HDR) project in New Mexico, USA in attempts to reduce flow impedance [21]. Further programs throughout the 1980s in the Geysers geothermal field of California were designed to create new conductive flow paths to the main reservoir. Shortly afterwards, acid stimulation gained popularity in places such as Central America, Philippines, and Italy with improvements in injectivity ranging from 40% to over 300% increase from original values [12]. Throughout the geothermal industry, there are two main methods of acid stimulation that are in practice today. Matrix acidizing involves acid treatment injected at pressures below the formation fracturing pressure and is designed to remove skin or other formations of damage that may occur during well operation [20]. Acid fracturing or "fracture acidizing" is designed to stimulate an undamaged formation and is conducted above the formation fracturing pressure [12]. While chemical stimulation treatments are of great value to the geothermal industry, they are not of direct concern for the purposes of this thesis and therefore will not be discussed in more detail.

39 Cari Covell Types of hydraulic stimulation The methods of hydraulic stimulation are described in three categories, as applied on geothermal wells. Air-lift aided drilling (also referred to as pressure balanced drilling, under-balanced drilling (UBD), or aerated drilling) has proven to be successful in preventing the clogging up of feed zones during drilling, but is not necessarily considered a stimulation operation per se [19]. However air-lift pumping that is followed by water circulation helps to restore feed zone permeability that was possibly reduced during drilling [19]. The water circulation phase could be classified as an open-hole stimulation via injection at the wellhead, and is performed in a similar matter. Another method of stimulation is the isolation of intervals in the borehole through the use of a packer in particular to an open hole section. After the packer is set, water may be injected either below the packer, through the drill pipe, or into the annulus above the packer [22]. By using a packer for zonal isolation, a larger effective fracture area can be obtained rather than one massive stimulation over a long open hole section. The packer method is also favorable to reduce the risk of creating larger seismic events [23]. Double packers are also considered to be a method of hydraulic stimulation, but the method is not discussed in this thesis. This is because double packers have hardly been used in geothermal stimulation operations; even though they are potentially more powerful than a single packer due to injected water being focused within a shorter interval [19]. Lastly, zonal isolation is a method used to target one fracture at a time within the wellbore. Several other options are available to achieve zonal isolation, where each technique must be integrated into drilling and well construction [24] Air-lift pumping Air-lift testing aids in maximizing well output and is therefore defined as a valid stimulation technique for the basis of this thesis. Typically air-lift testing is done with compressed air or nitrogen gas, although other gases are known to have been used in geothermal applications that work better with natural gas production of the reservoir [25]. During injection, lift gas is compressed to a pressure equal to or greater than reservoir pressure at the depth of the lower end of the air line (drill pipe). A schematic diagram for air-lift drilling (pressure balance) stimulation is shown in Figure 3. The design for air-lift pumping is based on rules of thumb and graphs that have been developed for air lifting freshwater wells. The main parameters are the submergence of the airline (the coiled tubing) and the air volume and pressure required. The design basis

40 16 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use can be found in the book Groundwater and Wells by Driscol [26] and the Australian training manual "Drilling: The Manual of Methods, Applications and Management" [27]. Figure 4 shows the basis for designing the air lifting program. Figure 3: Schematic illustration of the setup for air-lift pumping [19]

41 Cari Covell 17 Figure 4: Diagram for design of air-lift pumping, based on water well experience [26] Open-hole with a packer The procedure to run an open-hole packer stimulation is based on the full Icelandic paper from Axelsson et al. [19]. The paper explains the open-hole packer procedure using a Baker Hughes - Baker Oil Tools packer of " OD SS OH ISP Bridge Plug for a well of approximately 2,000 m depth. A more detailed cross section of the packer can be seen in Appendix A. Figure 5 shows the general schematic of the open-hole packer procedure. Note that injection is done either below the packer or above the packer, typically one after the other, for any given stimulation. The step-by-step procedure for implementation, stimulation, and removal of the packer is described in the following sections.

42 18 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use Figure 5: Schematic picture of injection via a packer [22] Before deploying the packer The well is first filled to the brim with water in order to measure fluid loss by monitoring the pump rate. Once a steady pump rate has been determined, hold constant for about 1.5 hours and monitor the pressure on the wellhead ("kill line"). A logger is then attached to the mandrel below the packer, where temperature and pressure data will be measured in 3 second intervals. For the logger, it is important to keep the well cooled by constant pumping of cold water. The Icelandic report indicates that pumping should not be stopped for more than 15 minutes due to temperature rise in the well while there is no circulation. The packer is then lifted upright and oriented so that the bleeding cap is facing upwards. The bleeding cap is opened to release any air trapped or excess water. Should water not come out of the bleed valve, the packer will need to be completely filled with water. Air should not enter the packer after this procedure. Pressure tests are then run on all surface

43 Cari Covell 19 piping from the pumps to the rig floor. Lastly, the packer is connected to the drill pipe and prepared to run into the hole Installing the packer As the packer is installed, water injection via the kill line is maintained until the packer reaches approximately 690 m depth inside the production casing. There is no need to pump through the drill string until 1000 m depth is reached because formation of the geothermal field is typically not very hot above this depth. The logger will show depth in meters with respect to the top of the packer, therefore it is necessary to account for the depth of each joint on the drill pipe in order to measure the true depth. The running speed of the packer is about 30 seconds for every 12.5 m; or the length between each drill pipe joint. Assuming a water level of 150 m depth, the pressure on the drill string should not exceed 15 bar in order to avoid premature inflation of the packer. The pressure on the drill string should not exceed 40 bar if the hole is assumed to be full of water Setting the packer A single-set packer can only be set one time per stimulation treatment interval and therefore must be pulled out after each test. Multi-set packers with different setting valves are also available. Typically, the packer is set at the deepest interval first and subsequently moved up to shallower intervals. For setting in directional wells, the packer is normally placed within a 10 m range of the desired interval for stimulation, where there is slight tension once the setting depth is reached. A chalk mark on the drill pipe is made above the rig floor to mark the exact depth setting position and the hook load weight is subsequently determined. The drill pipe connection is then opened to drop the 1.5" ball, where the ball will reach the shear plug at the falling speed of about 300 meters in 5 minutes. To check for any leaks on the surface, the drill string is filled by injecting water slowly until a bar pressure is reached for a water level of 150 m; or about 34 bar if the hole is filled. The pump pressure is then increased in increments of 20 bar until a pressure of 80 bar is reached for the 150 m water level scenario; or 95 bar if filled with water. The pressure is maintained for approximately 15 minutes to ensure that the packer is fully inflated, then released rapidly in order to get the swift closure of the check valve that maintains the inflation of the packer. Assuming a 12 1/4" diameter hole, a weight of 4.5 tons is applied to the drill string to check that the packer is firmly anchored in the well.

44 20 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use Opening the bottom plug The opening of the bottom plug allows water to flow through the packer. Pressure is then increased to about 107 bar for water depth of 150 m, or 122 bar for the filled hole, in order to break the shear pin and release the bottom plug and ball. Subsequently, the plug falls to the bottom of the well. The well is then filled via the kill line at a rate of about 15 L/s to measure the natural fluid loss in the open hole section above the packer Stimulation Stimulation begins by slowly increasing the pump rate to reach the capacity of three rig pumps, and is maintained for about 30 minutes. The pressure should remain steady during this period. Pumping should then be stopped for 15 minutes after 1.5 hours of continuous injection to observe the pressure falloff. The intermittent no-pumping time is considered beneficial to the stimulation process [23]. In addition, the water supply system and rig mud tank capacity may not be great enough to keep up with the large amount of water being pumped into the well and injection will need to stop to refill the tanks. Information about pressure and flow should be hand recorded as backup to the down-hole and on surface digital data records. The method of increasing pressure and stopping the pumping process in the specified intervals is usually maintained for a period of hours Releasing the packer The packer is first deflated by a slight clockwise torque applied to the drill string. A 2.25 ton weight is placed over the string for about 10 minutes to allow for the rubber to deflate completely. The packer should then be free to pull out of the hole. Final steps include circulating cold water for logger retrieval Zonal isolation The zonal isolation discussion in this thesis will be guided under four categories. A simple approach is to use a liner made out of cement or sand that is perforated to distribute fluid across the reservoir. The addition of an inflatable or swellable packer creates a seal to isolate the desired stimulation interval and is an option available for use in the field. The plug and go method involves drilling until a fracture is reached, stimulating the fracture, and then isolating the interval to be repeated over the entire depth of the wellbore. Finally, the use of multilateral wellbores and sidetracks involves first drilling a pilot hole, then

45 Cari Covell 21 drilling either multiple holes to intersect individual fractures or drilling a deviation hole to more accurately target the upper fractures of the reservoir Use of a liner In order to provide zonal isolation between fracture zones, one option is to run a liner that is placed with cement. A cement liner is typically used as this option does not disrupt drilling operations during well construction and does not compromise the wellbore shape and geometry [24]. The liner is initially set above the bottom fracture, perforated to provide hydraulic access to the reservoir, and then stimulated in open hole [24]. A plug or isolation packer is then set in the liner and another stimulation is performed to target the fracture. To access the next fracture, the plug or isolation packer is pulled and reset above the stimulated fracture. The liner is perforated and the fracture is stimulated at the desired interval, and the process is repeated until the final interval is reached. Note that experience proves the use of a cement liner to significantly impair the permeability of the fractures, as it may be difficult to achieve sufficient injectivity from the well [24]. However, viable solutions for extreme high temperatures, lost circulation, CO 2 attack, and cement/casing integrity have been tested for safe geothermal operation [28]. As an addition to the cemented liner, stage cementing collars are optional materials to implement in stimulation practices. The collars are staged based on previously logged spacing between the target fracture zones. A wiper plug is pumped to land at the shoe of the liner, followed by a dart that lands in the lowermost stage cement collar located above the second fracture zone, and an open sleeve is observed after application of pressure from surface shifts [24]. The collar displaces the next volume of cement to form an annular seal above the second fracture zone. The process is then repeated for the next stage collar. Careful observation of the pumping pressures and displacement volumes is necessary as the parameters are sensitive relative to the cement used in particular to high temperature geothermal systems [24]. A sanded liner is also an option for zonal isolation, where sand is pumped into the annular space so that the liner is supported [24]. Stimulation is performed in the same manner as a cement liner. However, the sand liner has a number of disadvantages. Given the anticipated nature and scale of the fracture openings, the size of sand particles will not adequately bridge off across the fracture. Effects include some sand being lost in the fractures, losses in permeability and injectivity, and an increased risk of stimulating pressures to areas not in the target zone [24].

46 22 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use Use of a liner with inflatable or swellable packers External Casing Packers (ECPs) are located for zonal isolation between multiple fracture zones. ECPs are a type of packer on the outside of the casing or liner that is inflated with drilling mud or cement. The packer inflates to conform to the wellbore by forming a seal to the liner and subsequently isolates the zone. The stimulation may then be completed using several options including: sliding sleeves, plugs and perforating tools, stage collars above the ECP, or straddle packer assemblies across the required intervals [24]. Swellable packers are comprised of an elastomer element that swells naturally when exposed to the appropriate swelling agent that is either water or oil based fluid [24]. The packer is bonded to the outside of the base pipe and is assembled for inclusion in the liner. Once the desired depth is located, the well is displaced to a water based fluid, and then time is required to allow the packers to swell to ensure a seal against the wellbore wall [24]. As a note, the packer is recommended for use when there is good control of wellbore geometry as swellable elements are limited in the extent of expansion, and as a result the differential pressure that can be applied is limited [24] Plug and go In the plug and go method, drilling is first done to the uppermost fracture and stimulation is performed by setting a packer in the production casing. For the isolation phase, two methods are known to be effective. One option is to install an expandable liner across the fracture zone and tie back to the production casing. A seal is made by either using cement or swellable packers on the outside of the expandable liner [24]. Drilling then continues to the next fracture zone, where stimulation and placement of a liner is repeated. In this case, the liner can be tied back to the pre-existing liner or be simply set across the target fracture zone [24]. The process is repeated until the entire wellbore section is drilled and stimulated. While this method has been proven to be effective, it may be desirable to limit the number of well re-entries for operational purposes [24]. Another option for isolation is to install a conventional liner with swellable packers. The elastomer in the packer absorbs the formation water over a period of time and swells to form a seal between the liner and the wellbore [24]. Currently the technology is being developed to handle high temperatures of around 300 C [24].

47 Cari Covell Multilateral wellbores and sidetracks The multilateral wellbore method comes about after the bottom fracture zone has been stimulated, isolated with a packer, and cased off above that fracture. The depths of the upper fractures measured during the drilling of the pilot hole are used as target locations for drilling additional wells laterally. All lateral wells are plugged prior to drilling the next to ensure isolation for drilling and stimulation purposes [24]. Multilateral wellbores are efficient in accessing each leg separately, but costs add up for each wellbore and the multilateral technology relies heavily on the ability of elastomer seals to handle high temperatures [24]. The use of sidetracks is considered another option for better targeting the upper fracture zones. A down-hole tool with an inclined plane called a whipstock is placed in the wellbore to exit the original hole and to drill a new well to the next intersected fracture. The fracture is stimulated and isolated, and the process continues until all desired fracture zones have been targeted. The use of sidetracks as an option for zonal isolation is also effective, but it relies almost exclusively on the ability to drill successfully to each interval [24]. 2.3 Environmental impacts and seismicity Besides the technical challenges to stimulate fractures along a fault system, there are other environmental challenges to consider. These include the use of chemicals in the fracking fluid, drilling noise, damage to flora, and changes in thermal manifestations. Induced seismicity has also received much attention after seismic events following hydraulic stimulation in Australia, France, and Switzerland have been the topic of many studies. In some low enthalpy geothermal fields, impact from long-term utilization of water may include the dropping water level of near surface aquifers. In addition, flow reduction or dry-up of nearby springs and shallow water wells may occur. All these problems can be avoided by reinjecting the cooled liquid via stimulation practices [23]. The chemistry of fracking fluid is also of environmental concern, as acid behavior in a reservoir during chemical stimulation can cause scaling due to an improper mixture of tracers. Some proppants within the injection fluid consist of ceramic or glass beads and could be coated or constructed using reactive metals, although this is rare in geothermal applications [29]. To address these environmental concerns, there are groundwater treatment solutions that can be implemented after fracking fluids have been injected; such as reactant sand-fracking (RSF) to decrease metal contamination in aquifers and permeable reactive barriers (PRB) to decrease the amount of volatile organic compounds [29].

48 24 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use Noise can be severe and a nuisance to local residents who live close to the geothermal plant, but is countered by proper plant engineering (e.g. avoiding noisy equipment) and by placing noise barriers if necessary [23]. Damage to local flora occurs every time steam or hot geothermal fluids are released on local plants, which happens due to the high temperature and salinity of the geothermal fluids, but is usually not a problem when fluids are reinjected [23]. Some changes in thermal manifestations are possible during exploitation, where hot spring and fumarole intensity depend on the pressure drawdown of the reservoir. Hydrothermal eruptions could also be correlated with exploitation, but only one such case in New Zealand has occurred [23]. The most problematic side-effect of enhancing geothermal reservoirs by hydraulic stimulation is the potential to generate earthquakes, which may become detrimental for further development of project [23]. During hydraulic stimulation, stress patterns in the rock change to potentially cause microseismic events, but most events are of very low magnitude and are short in duration. However some EGS sites have recorded significant seismic events arising from short-term stimulation operations. In Cooper Basin, Australia, more than 32,000 seismic events occurred in well Habanero-1 after stimulation via large volume injection of 20,000 m 3 of water [30]. The largest seismic event recorded was of a 3.7 magnitude. Similarly, the Soultz-sous-Forêts project involved several stimulations that averaged 23,000 m 3 of water injected and thousands of microseismic events were induced each time, where the largest event reached 2.9 magnitude [31]. The stimulation program had to be changed due to complaints from local residents [23] [30]. In Basil, Switzerland, rupture processes for seismic events with a magnitude greater than 2.2 appear to have occurred in cascades either on a single continuous fracture or nearly synchronously on several closely adjacent structures [32]. Due to this, stimulation operations were put on preliminary halt [23]. The size and frequency of seismic events are therefore primarily controlled by the rate and amount of fluid injected, but are also controlled by the orientation of the stress field [30] [33] [34] [35] [36].

49 25 Chapter 3 Literature review Stimulation practices originated, and are still in use, in the oil and gas industry and have translated to geothermal applications beginning in the early 1970s. When comparing well stimulation applications between the oil and gas industry and the geothermal industry quantitatively, geothermal well stimulation only accounts for a small fraction of all cases. This is mainly due to the fact that geothermal exploration is a younger industry, and most stimulations are ones that include specialized experiments for research rather than for commercial use. The literature review conducted in this chapter will discuss several cases of hydraulic stimulation for each field type in order to evaluate potential correlation. 3.1 Hydraulic stimulation applications The earliest form of hydraulic stimulation in the oil and gas industry is approximately around the late 1800s-early 1900s [25]. This section will focus on hydraulic stimulation applications because more commercial work has been performed in the oil and gas industry that has translated well to the geothermal industry regarding experiences and lessons learned. Thermal and chemical stimulation are still relatively new in the geothermal industry and most projects are research oriented within high-temperature geothermal fields. EGS is important to discuss as they have been the center of study in hydraulic stimulation since the late 1970s.

50 26 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use Oil and gas industry Stimulation techniques to improve well permeability have been in practice within the oil and gas industry since the late 1800s. Examples of stimulation techniques include casing perforation, explosive propellant solution, acoustic stimulation, and electric stimulation. Casing perforation is designed to access cased-off permeable horizons in production wells that still have high commercial temperatures and pressures, and is one of the most common methods used in the oil and gas industry [37]. Horizons are typically found at the shallow depths of the reservoir, where further evaluation is performed based on drilling circulation losses, geology, and petrology of the formation prior to the conduct of a perforation operation [12]. High energy gas fracturing (HEGF), or explosive stimulation, creates a breakdown of the formation and at the same time improves clean up of the perforations [38]. High gas waves generated from the vaporizing propellant (termed deflagration) crushes the formation damage to create small fractures near the perforation channel. When pressure disperses, the gas creates a flooding effect and carries back the fine particles from the formation. Acoustic stimulation uses a simple ultrasonic wave source between the acoustic field and the saturated porous rock. In geothermal applications, this interaction changes permeability or removes plugging materials in the formation [12]. Electric stimulation uses electric current either through electrothermal or electrodynamic type effects. Electrothermal effect is evident in the near wellbore zone during heating with infared or high frequency microwaves, while electrodynamic effect creates a cleaning of the bottom hole formation zone from clay particles restoring or improving the well permeability [39]. While some of these techniques have translated to the geothermal industry, most of these techniques are in the novel stages of development and require more research before being tested on a wider scale [12] Low temperature geothermal areas Hydraulic stimulation by use of open-hole packers and large flow of water has had success in low temperature geothermal areas, specifically in Iceland starting in the early 1970s. The Reykir hydrothermal system was an ambitious stimulation program, when each of the 39 wells drilled during redevelopment of the field were stimulated after drilling. Seltjarnarnes well SN-12 was drilled in 1994 after five previously drilled wells were used for exploration [40]. The decision to stimulate the well resulted from a measured flow yielding almost no production after drilling [41]. Each field and their corresponding stimulation programs are discussed in more detail in the subsequent sections.

51 Cari Covell 27 Other low-temperature geothermal fields that have experienced well stimulation in Iceland include Hlídardalur and surrounding fields in SW-Iceland, Laugarland and Leirá in N-Iceland, and Urridavatn in E-Iceland. Information is limited on these subjects, but reported findings are discussed in section Reykir hydrothermal system The Reykir hydrothermal system has been exploited since 1944 for space heating of Reykjavik, Iceland. Prior to 1970, production amounted to 300 l/s at 86 C by free flow from 69 wells [42]. In the early 1970 s, the Reykir field was redeveloped with the addition of 39 wells to be hydraulically stimulated, by injection above and below inflatable packers, as part of a drill completion program. In general, air-lift pumping was done to clean the hole of drill cuttings and lost circulation materials. A packer was then set a certain depth, between two or more producing horizons, where water was injected beneath or above the packer. Pumping rate varied from 15 to 100 l/s for each well due to the resistance of the producing horizons. Pressure increases at the feed zones ranged from a few bars up to as high as 150 bars at the lowest permeability feed zones treated [42] [4]. Tomasson [22] and Tomasson and Thorsteinsson [43] describe wells MG-25, MG-27, MG-35, and MG-39 in more detail in order to better illustrate the hydraulic stimulation method, discussed in the subsequent sections. The outcomes described in the following are an average of all wells stimulated. Comparing the injectivity before the stimulation and after indicated as much as fold increase; so in total more than 1500 l/s was produced. The drastic improvement is mostly attributed to the reopening of feed-zones clogged by drill cuttings during drilling operation [4]. However, when comparing production over the cumulative loss of circulation during drilling, the wells showed a three-fold increase in production. This is attributed to increased feed-zone permeability, most likely due to the removal of zeolite and calcite vein deposits and partly to increased permeability of near-well fractures in hydroclastic rocks [4] [43]. Specific results per well are referred to by [42] Well MG-25 The well was drilled to a depth of 2025 m with a flow of about 3 l/s in Circulation losses after drilling amounted to Q 1 = 2 l/s and total circulation losses amounted to Q 2 = 13 l/s given the static water level at 20 m [22]. The first packer setting was at 758 m depth in dolerite intrusions with the biggest aquifer above the packer and many small aquifers beneath the packer as seen from lithologic logs of the well [22]. Dolerite tends to be more permeable than basalt and hyaloclastic rocks, therefore it is an

52 28 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use ideal location for stimulation in typical Icelandic geological environments. One run was done below the packer from m depth, and two runs were done above the packer from m depth. The first run had pressure increasing step-wise, while the two runs above the packer at different injection rates had constant pressure of 20 kg/cm 2 and no pressure fall off [22]. After a short break, the first interval of m was run three more times at constant injection rates of l/s. A new packer setting at 552 m depth was then implemented with injection below the packer to the bottom of the drillhole in two runs at constant injection of l/s. Both intervals experienced a drop in pressure, and gradually the pressure built up again meaning an opening of an aquifer most likely occurred [22]. The step draw-down test conducted after stimulation indicated a flow of 40 l/s with a 40 m drawdown [22]. The results show a 14 fold increase compared to fluid losses after drilling, and a 2.2 fold increase including fluid losses during during. This shows a great improvement in production and proves that drilling deeper drillholes can be beneficial for good producing horizons within the geothermal system [22] Well MG-27 In September 1974, well MG-27 was air-lift pumped with compressed air for 12 hours with an estimated yield of 15 l/s. An injection test was run thereafter where total circulation losses were computed. These values were then used to calculate improvement ratios, of which the square roots indicate increase in productivity [43]. The injection packer was sequentially set at 1217 m, 951 m, and 835 m. Water was injected above and below the packer and multiple injection tests were made after each setting. The coefficient of turbulent loss C was calculated for each setting, which is a factor associated with natural fluid loss in the well due to turbulence [43]. Subsequently the improvement ratios were tabulated using values of C 1 and C 2 ; coefficients of turbulent losses during and after drilling. The tabulations are presented in Table 1, along with the volumes withdrawn by the compressed air pumping and injections above and below the packer.

53 Cari Covell 29 Table 1: Improvement ratios in MG-27 [43] Depth [m] Volume injected [m 3 ] C I 1/2 1 I 1/2 2 beneath above total [m/(l/s) 1/2 ] [C 1 /C] [C 2 /C] Compr. air The high value of C = computed after the 951 m setting is probably due to a tight spot and a partial cave-in at a depth of m during the setting [43]. To avoid problems for subsequent stimulation at 835 m depth, the section was widened and the well was cleaned to the bottom with a drillbit. The most successful stimulation, in terms of increase in productivity, is at the 835 m depth with a 2.6 fold increase and a 1.06 fold increase taking into account circulation losses at the end of drilling and during drilling, respectively Well MG-35 In August 1976, well MG-35 was air-lift pumped with compressed air at a rate of l/s with the static water level remaining at a depth of 80 m. The increase in temperature was measured with time to see how cooling points coincide with increases in turbidity; meaning that new and deeper zones of lost circulation are being cleaned out. The packer was then set at a depth of 560 m and water was injected below the packer. The coefficient of turbulent well losses after injection was computed as C = m/(l/s) 1/2 from the initial build-up pressure beneath the packer by the air pumping; because only one small loss of circulation occurred above the setting depth [43]. At the end of the stimulation, C had reduced to m/(l/s) 1/2 (see Table 2). Two additional packer settings were made at 1153 m and 1359 m where water was injected above and beneath the packer. The total losses of circulation at the end of drilling and during drilling were Q 1 = 85 l/s and Q 2 = 7 l/s, respectfully. The turbulent well loss coefficients are subsequently C 1 = 1.63 m/(l/s) 1/2 and C 2 = m/(l/s) 1/2. By using the coefficient of turbulent well loss values, the improvement ratios were calculated and the end of drilling and during drilling and are presented in Table 2.

54 30 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use Table 2: Improvement ratios in MG-35 (based on [43]) Depth [m] Injection rate [l/s] C I 1/2 1 I 1/2 2 above below [m/(l/s) 1/2 ] [C 1 /C] [C 2 /C] Compr. air At the end of stimulation, the productivity of the well increased by 32.9 fold after drilling, but only by 2.7 fold compared to total productivity from circulation losses during drilling (numbers are the square root of I 1 and I 2 ). Well MG-35 is considered to be one of the best producing wells after stimulation, however such a large margin of productivity improvements may be due to other perpetuating factors of the geothermal field that have an effect on circulation losses Well MG-39 In June 1977, well MG-39 was stimulated by injection above packers for two different depths at 1138 m and 1001 m. Injection rates were between l/s with a known static water level of 93 m, but continuous injection was limited due to insufficient water supply. Therefore, injection periods were limited to min [43]. At the first setting of 1138 m, pressure fell gradually from 10 kg/cm 2 to 0 in two days, but at the 1001 m setting the pressure drop was from 7.5 to 3.0 kg/cm 2 in 30 hours [43]. The total loss of circulation was 287 l/s, of which 49% occurred above the first packer setting at 1138 m and 35% occurred above the second packer setting at 1001 m [43]. The total increase in productivity for well MG-39 was estimated to be 3.9 fold, not including circulation losses during drilling. After computing all turbulent losses, the increase in productivity was estimated to be 1.5 fold for the 1138 m packer depth and 1.2 fold for the 1001 m packer depth [43]. Hence, there was a 0.3 fold increase from stimulating 137 m deeper, so there may be a correlation of productivity with stimulation depth Seltjarnarnes well SN-12 The Seltjarnarnes geothermal field has been exploited for hot water since 1970 to serve the town of Seltjarnarnes in SW-Iceland. Seltjarnarnes is a typical low temperature geothermal field with reservoir temperatures ranging from 80 to over 140 C at 2700 m depth [44].

55 Cari Covell 31 The system consists of 3-4 different aquifers, with different temperatures and salinity. Supersaturation of calcium carbonate, due to mixing of water from different feed-zones within a well, has increased with time but no scaling has yet to occur. Although, calcium carbonate is now at a level where scaling is known to have occurred in other geothermal areas of Iceland [41]. Well SN-12 was drilled to a depth of 2714 m in the fall of 1994 and appeared to be almost non-productive after drilling; yielding flow less than 1.5 l/s with a 150 m draw down after a one hour air-lift pumping test. Therefore, it was decided to stimulate the well with a packer in two phases over a ten day period [41]. Prior to stimulation, the average yearly production of the Seltjarnarnes geothermal field was around 30 l/s since 1991 [41] High-pressure wellhead injection The first stimulation phase involved highpressure wellhead injection of cold water. Water was injected at 60 l/s in one hour periods, because not enough water was available at the drill site and storage tanks were refilled during 30 min breaks. At the end of the twelve hour pumping period, the wellhead pressure dropped suddenly from 76 bars to about 18 bars, indicating that the well had in fact been stimulated. The wellhead injection continued for 12 hours and additional pressure drops were observed. At about 8 a.m. the pressure dropped suddenly by about 18 bars and at about 10 a.m. the wellhead pressure was down to 23 bars [41]. This indicated that the well had been stimulated even further, but the pressure started to increase towards the end of the injection phase and it became evident that the well had collapsed [41]. Based on water level monitoring of well SN-6, the transmissivity was estimated to equal T = m 3 /Pa s, and the storage coefficient to be S = m 3 /Pa, which correspond to a permeability of 15 md [41]. The transmissivity may be compared to older estimates which are in the range of m 3 /Pa s to m 3 /Pa s [44]. The storage coefficient is small, indicating that permeability is limited to a thin fracturezone, perhaps on the order of m [41] High-pressure injection below packer The second stimulation phase involved high-pressure injection below a packer at 1412 m depth, in order to stimulate the lower part of the well further and to clean out feed-zones clogged by drill-cuttings [41]. The depth of the packer was chosen on the basis of temperature logs, caliper logs, and borehole lithology, which indicate the existence of feed-zones.

56 32 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use Similar to the first stimulation phase, l/s were injected below the packer during four one hour intervals, each followed by a 20 min break. Accounting for pressure loss in the drill string, the pressure below the packer decreased gradually from 85 bars at the beginning down to 40 bars. Therefore, it is believed that the stimulation was due to the removal of drill cuttings clogging feed-zones [41] Production testing Several production tests were performed throughout the stimulation program. A step-rate injection test was performed on the 13th of October 1994 after the first phase of stimulation, and an air-lift test was performed after the second phase of stimulation from the 18th-19th of October 1994 (see Figure 6). In addition, an air-lift test was performed at the end of drilling on the 20th of October The air-lift test after the second stimulation was done in four steps with flow rate varying from 12 l/s to almost 30 l/s [41]. As seen in Figure 6, the pressure drawdown varied from about 1.5 bars to almost 6 bars, making clear that the productivity of the well had improved. Figure 6: Results of production testing of well SN-12, where symbols show observed data one hour into each step and lines show calculated output characteristics [41] Comparing results from the air-lift tests indicate an increase in flow to about 35 l/s with a draw down of roughly 60 m, and the stimulation had increased the yield of the well by a factor of 60. Thus well SN-12, which appeared to be almost non-productive at the completion of drilling, had turned into a good production well [4].

57 Cari Covell Other low-temperature fields in Iceland Several other low-temperature fields were stimulated in Iceland throughout the 1970s. The first packer experiment took place at Hlídardalur 50 km Southeast of Reykjavik, where production of a 1220 m deep narrow gage drillhole was increased from 1 l/s, 60 C, with a drawdown of 100 m, to 2-3 l/s, 100 C, by free flow [22]. While 2-3 l/s is not much flow for a typical low-temperature geothermal well, the increase in temperature shows that the well was enhanced and was sufficient for the boarding school, swimming pool and adjacent buildings. Good results were achieved in three other drillholes ranging from m depth, located in Selfoss, Midsandur, and Thoroddstadir, SW-Iceland [43]. However at Litlaland near Hlídardalur, a 2187 m deep well collapsed after a packer set at 576 m depth experienced pressures of kg/cm 2 below the packer [43]. In Laugarland, N-Iceland, there were no improvements detected in stimulation of wells LJ-6 and LJ-8 because pressures as high as kg/cm 2 were experienced due to multiple collapses of the drillhole at depths below 940 m [43] [45]. Flows were less than 1 l/s and came mostly from shallow veins around 250 m depth, even after injection at rates between l/s [45]. Some improvements were seen in Tertiary rock, such as in Leirá (SW-Iceland) in the uppermost 500 m section of a 2019 m well, and in Siglufjördur (N-Iceland) the productivity of a 1100 m deep well increased about 50% after several packer settings [43]. While improvements were shown in these areas, the margin of success seems small compared to the time spent stimulating the well at multiple packer depths, therefore drillhole geology and the effects of fluid losses may be underlying mechanisms that directly influence production output. At Urridavatn only small improvements were seen below 250 m while 2-3 fold improvements were seen between m [43]. The results from Urridavatn show high sensitivity regarding the interval at which stimulation succeeds; which questions the specific geological environment required for stimulation location High temperature geothermal areas The first hydraulic stimulation experiments in high temperature geothermal areas were performed from at the Nigorikawa and Kakkonda geothermal fields in Japan, but detailed information on the stimulation programs is not available at this time [46]. The

58 34 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use earliest form of packer and proppant technology in high temperature geothermal areas was when the Department of Energy (DOE) implemented a stimulation program in the United States throughout the early 1980s. Around the same time, hydraulic stimulation through wellhead injection occurred in Italy as part of a different stimulation program set up by the National Entity for Electricity (ENEL). Due to the other thermal and chemical stimulation research occurring throughout these programs, as well as other EGS programs occurring simultaneously, one could say there was a gap in time of no hydraulic stimulation in high temperature geothermal areas, at least according to the definitions of high temperature and EGS fields previously discussed in the introduction of this thesis. Hydraulic stimulation via wellhead injection then resumed in the late 2000s with the Salak field of Indonesia and the Mt. Apo area of the Philippines in order to increase the permeability of these regions. From , the Salak field did a zonal isolation experiment in order to prove the viability of such a stimulation experiment [47]. However, hydraulic stimulation in high temperature areas can be difficult due to several factors of the high temperature nature of geothermal areas effecting the potential for production improvements. Therefore, stimulation in high temperature geothermal wells is more common through thermal injection of cold water and allowing the well to heat up. Several examples of thermal stimulation in high temperature areas around Iceland are available for review. Each case of thermal stimulation in Iceland is discussed further in Appendix B in order to analyze effects based on the unique geology and how these effects influence production outcomes of particular wells Baca, New Mexico (USA) Hydraulic stimulation in the Baca geothermal field of New Mexico, USA was done in 1981 on wells Baca 23 and Baca 20 as part of the DOE-sponsored Geothermal Reservoir Well Stimulation Program (GRWSP) [48] [49]. The liquid dominated reservoir is composed of volcanic tuffs with low permeability and temperatures as high as 500 F (260 C) [49] Well Baca 23 The well was originally completed with a cemented liner at 3057 feet and open hole to 5700 feet with an interval from 3300 feet to 3500 feet selected for hydraulic stimulation. The section was isolated using an experimental high temperature Otis packer with ethylene propylene diene monomer (EDPM) elastomer elements and was treated using a combination of frac fluid water with a fluid loss additive (FLA) and polymer gel proppants [48]. Since the top of the interval was deeper than the existing

59 Cari Covell 35 liner, a new liner was cemented to 3300 feet depth. The lower portion of the hole was sanded back to 3800 feet and plugged with cement to 3531 feet to contain the treatment in the desired interval. The frac string was to isolate the liner laps in the well from the treating pressure [49]. For well completion, a pre-perforated liner was installed in the treatment interval. The hydraulic fracture treatment schedule is shown in Table 3. Due to the high temperature of the geothermal system, special treatment design and materials were required for the stimulation. From a total of 7641 bbl frac fluid, half was dedicated to wellbore and fracture pre-cooling; pumped at high rates in order to minimize its degradation [49]. Table 3: Well Baca 23 hydraulic stimulation treatment schedule [49]. Planned size Actual size Proppant Stage no. [bbl] [bbl] [lb/gal] [size] Fluid Water with fluid loss additive (FLA) Polymer gel with FLA mesh Polymer gel with FLA Polymer gel with FLA /40-mesh Polymer gel /40-mesh Polymer gel /40-mesh Polymer gel Water A long term flow test showed a static temperature profile with a low bottom-hole temperature of 401 F (205 C), while a separate temperature survey showed a maximum temperature of 344 F (173 C) [49]. Therefore, two-phase flow was occurring and the temperature drop was associated with flashing in the formation [49]. In addition, a productivity test showed well recovery after each shut-in period followed by a decrease in mass flow and wellhead pressure. This concludes that permeability reduction associated with two-phase flow effects is most likely occurring due to partial closing of the fracture [49]. Microseismics were also monitored where a single fracture 100 m high and 160 m long might have been created, which is considered success as this fulfills the initial goals of the stimulation [48]. However it is concluded that the well is present in an impermeable formation and is unsuccessful in producing fluids for power generation [48].

60 36 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use Well Baca 20 Shortly after the stimulation in well Baca 23, well Baca 20 was hydraulically stimulated. The hydraulic stimulation interval in the well was from feet and the total depth of the well is 5827 feet with the packer set at 2412 feet [49]. At a temperature of 540 F (282 C), this was the hottest well to be stimulated in the DOE GRWSP [48]. The eleven stage treatment schedule was also similar to well Baca 23 with some minor adjustments. The proppant only consisted of sintered bauxite in equal quantities of 16/20-mesh and 12/20-mesh type. To stop leakage into the small natural fractures, 100-mesh calcium carbonate was pumped in stages 2-5 [49]. Temperature surveys showed a zone cooled by the natural frac fluids less than 100 feet in height near the bottom of the open interval of the well [49]. There was also a zone around 4720 feet depth that indicated some cooling most likely due to the workover fluids (brine) injected in stage 1, but could also be due to the frac fluids present in the lower part of the open interval [49]. Pressure build-up data indicated that a highly conductive fracture with a length of over 100 m was created, but productivity was poor and did not meet the needs for a commercial well [48] Latera, Italy The Latera geothermal field is a water dominated hydrothermal system with temperatures of C and was hydraulically and chemically stimulated in late 1983 as part of a geothermal well stimulation program set up by ENEL [50]. Hydraulic stimulation was performed on wells L1 and L6 as they proved to be dry after drilling [46] [50]. Well L1 experienced several injection tests on the entire open hole section. The first three tests involved injection at rates between m 3 /h but results indicated a relatively small fracture area [50]. Subsequent injection tests with increasing flow rates of 110, 220, and 340 m 3 /h were conducted for short intervals over 1-4 hours, and opened only about half the fracture area created by previous injection [50]. Finally a massive injection test at a rate of 310 m 3 /h over 17.5 hours increased the fracture area by a factor of 4 [50]. The main fracture did not completely close after injection, so short-term injectivity (in days) was improved [50]. However, a long term (1 month) injection test indicated no increase in fracture area [50]. The reason could be due to lack of connection between artificial fractures and the natural fracture network of the geothermal reservoir [46]. Clearly the main fractures in the well had potential to remain open for longer periods of time, but would have required inconceivable amounts of water to be injected. In addition, the transmissivity remained low but the skin factor went from positive to negative. No explanation is provided for the discrepancy of the results or whether they were measured after short-

61 Cari Covell 37 term or long-term tests. Well L6 was stimulated in a similar matter as well L1, but the stimulation continued to require pressures too high for industrial injection rates and the operation was terminated early [50] Salak, Indonesia The Salak high temperature geothermal field of Indonesia ( C) has several wells that have experienced either hydraulic, thermal, or chemical (acid) stimulation. Only hydraulic stimulation is described in order to evaluate successes and failures of particular wells. Hydraulic stimulation was performed from in wells Awi 18-1 and Awi 20-1 as they had low permeability west of the Cianten Caldera production area [51]. In addition, one of the first zonal isolation modeling experiments took place from in well Awi-3 as there was low injectivity after drilling [47]. Through injection of a large volume of water at high pressure, well Awi 18-1 showed decreasing wellhead pressure. The observation indicates conductivity improvements of existing fractures and/or newly developed fractures around the wellbore [51]. A phase of reinjection followed using condensate from the power plant. Although not directly considered a hydraulic stimulation, the reinjection had an effect on the 180% increase in injectivity index of the well. This suggests that not only was permeability improved, but a connection between the well and a low pressure system also occurred [51]. Well Awi 20-1 also experienced a decrease in wellhead pressure by 370 psi after the second injection stimulation period [51]. The decrease in wellhead pressure also corresponded to an increase in injectivity index as well Awi However a final injectivity test at the end of stimulation operations showed no improvement in injectivity index. This indicated that improvement in injection performance was mostly attributed to the establishment of connectivity between the well and a lower pressure fracture network, rather than permeability improvement of existing fractures [51]. For well Awi-3, a conceptual model was built to study the benefits of zonal isolation to improve well injectivity, then the actual stimulation was performed to compare results. The well was designed with a combined pre-perforated and blank 10-3/4 and 8-5/8 liner. The blank part was then cemented about 300 ft high to create zonal isolation. Furthermore, the main injection casing 13-3/8 was successfully installed in one string, which eliminated tie-back (common in geothermal well), improving its long term reliability [47]. This combination of long string injection casing and zonal isolated liner would then allow the model to simulate injection at specific zones. The effects of injection were modeled in the lower zone and in the upper zone of the well (details regarding the location of each

62 38 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use zone are unavailable). The stimulation in the lower zone experienced some plugging and therefore no fracturing happened [47]. However, the upper zone stimulation improved early during injection and showed that the isolation method worked as intended [47]. Therefore the conceptual model for zonal isolation does not guarantee an improvement in injectivity, as the results are different in the lower and upper zones. During actual stimulation in the upper zone, initial injection capacity was around 150 kph at 500 psi wellhead pressure (WHP). After the stimulation, the well injectivity was tested to be 600 kph at 500 psi WHP. This huge improvement shows that large injection plays an important role in stimulating the reservoir, and has helped to eliminate the necessity of drilling another injection well [47]. However more work needs to be done to understand the vast difference between the simulation results of the lower and upper zone Mt. Apo, Philippines Mt. Apo and other geothermal fields in the Philippines have experienced both hydraulic and acid stimulation, but only hydraulic stimulation will be discussed in this thesis. The geothermal field averages reservoir temperatures greater than 300 C [52]. Hydraulic stimulation occurred in well K6 in November 2012 with the goal to increase well permeability [53]. At the end of drilling completion, the injectivity and transmissivity were low and high positive wellhead pressure was observed in addition to the low permeability of the well. River water and power plant condensates were injected continuously at 6 BPM and a controlled maximum pressure of 9.0 MPag over a period of one and a half months[53]. Based on injection flow rate and wellhead pressure monitoring, no indication of permeability enhancement was achieved and no increase in injectivity index was observed [53]. Another well was hydraulically stimulated over five days from September-October 2013, but the literature does not indicate which well in particular. A decreasing trend in wellhead pressure was observed directly with increasing pump rates, signifying an enhancement of well permeability [54] [55]. This was further supported by observing the changes in temperature gradient, where a decrease in temperature indicated a zone of cold water infiltration. The permeable zones noted before hydraulic stimulation were located between mmd and at the bottom of the well [55]. After hydraulic stimulation, additional permeable zones were found between mmd, mmd, and mmd [55]. The injectivity index increased from L/s-MPag to L/s-MPag which also infers improvement in permeability [55].

63 Cari Covell Enhanced geothermal systems (EGS) The definition of EGS has been interpreted in several ways over time regarding rock types, depth, temperature, reservoir permeability, or type of stimulation technique involved. For the purposes of this thesis, the best definition is from the Bundesmin für Umwelt (BMU - The Federal Ministry for the Environment, Germany). The BMU defines enhanced geothermal systems as creating or enhancing a heat exchanger in deep and low permeable rocks of temperatures less than 200 C using stimulation methods [5]. Following BMU s definition, Breede [56] further defines EGS as embracing hot dry rock, deep heat mining, hot wet rock, hot fractured rock, stimulated geothermal systems, and stimulated hydrothermal systems. Stimulation methods that have been applied in EGS developments are summarized in Figure 7, which shows that hydraulic stimulation is the most common method independent of rock type. Due to the relatively few cases where chemical or thermal stimulation technologies are applied, the definition of EGS is interpreted as only applying to hydraulically fractured systems [56]. Figure 8 further shows the rock type and well depth of all the worldwide studied EGS projects as of According to both Figures 7 and 8, all fifteen igneous rock EGS fields have experienced hydraulic stimulation. However with further examination, the Bouillante EGS field of Guadeloupe has experienced thermal cracking; not hydraulic stimulation by definition of this thesis. The five sedimentary fields that have experienced hydraulic stimulation or have hydraulic stimulation programs planned are Mauerstetten, St. Gallen, Genesys Hannover, Genesys Horstberg, and Altheim. The two EGS fields of mixed igneous and sedimentary composition that have experienced hydraulic stimulation are Groß Schönebeck and Paralana. In addition, the metamorphic EGS field Bad Urach and the mixed igneous and metamorphic EGS field Desert Peak have both experienced hydraulic stimulation. A discrepancy is noted in the metamorphic category, where Larderello is stated as a thermal stimulation site. Larderello has actually experienced multiple acid stimulations since the 1980s, some of which are also based on the injection of water and could be interpreted as hydraulic stimulation [57]. These hydraulic stimulations are interpreted as being a part of a larger acid stimulation, therefore the Larderello field will not be discussed in this thesis. The Altheim site in Austria was too small of a project to have any significant record of stimulation. Lastly, the Raft River site in the United States will also be included in this discussion as preliminary results of hydraulic stimulation have been available for review as of Each EGS field, with substantial literature to review, that has experienced hydraulic stimulation as an independent method is discussed based on the specific parameters used either in research or commercial applications, as seen in Appendix C. Essentially, each case is

64 40 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use unique and no conclusion is made about specific methods or procedures as suitable options for particular areas. Every project and location has characteristics that, at this time, are difficult to understand for application in low-temperature geothermal areas. Figure 7: Stimulation methods applied to EGS projects worldwide as of 2013 [56]. Figure 8: Rock type and well depth of EGS projects worldwide as of 2013 [56].

65 Cari Covell History of stimulation fracture modeling Fracture modeling is important to determine the success (or failure) of a stimulation operation and is usually performed before stimulation commences. Two known cases in Germany and Canada are pointed out for fracture modeling using FRACPRO and MShale software. FRACPRO is typically used to address the prediction of pressure response in the well for planned stimulation treatments and the selection of appropriate equipment to handle expected wellhead pressures, friction, and near wellbore tortuosity [58]. Well GrSk4/05 at the Groß Schönebeck EGS site in Germany was first modeled in FRACPRO, then used as a real-time simulation tool. While fracture propagation was the goal of stimulation, the main purpose of FRACPRO was to model a treatment schedule [58]. In the Ft. McMurray area of Canada, research was performed with MShale to extract hot water from natural oil sands. A sensitivity analysis of estimating reservoir properties using prior knowledge about fracture location was done in order to determine the potential for an HDR project, and subsequently to determine optimal areas for stimulation [59]. Both cases were primarily concerned with modeling the effects of stimulation on fracture geometry. However, these software do not account for any potential production flow improvements after stimulation. A number of other fracture modeling software is available [60], but most model seismic activity with the goal to minimize environmental impact. Historically, the importance of fracture modeling was about the emphasis in fracturing low-permeability reservoirs in order to model the productive fracture length and the dimensionless fracture conductivity; i.e. the ratio of the ability of the fracture to carry flow divided by the ability of the formation to feed the fracture [7]. There is a need to derive a solution methodology from the oil and gas industry in order to take the effects of stimulation on fracture geometry and apply them to model production potential. This is the motivation for modeling in the MFrac suite for direct use purposes using geothermal resources, discussed further in the next chapter.

66 42

67 43 Chapter 4 Methods This chapter will discuss the methods used regarding a case study for well HF-1 in Hoffell, Iceland. A lumpfit parameter model (LPM) was analyzed in order to measure the initial production potential of the well. This was done once before by Shengtao [61], but only across 5 months of data out of a 13 month long production test. The LPM compared the two data sets in order to more accurately provide a frame of reference for conducting a hydraulic stimulation model. After determining that well HF-1 should be stimulated, a fracture model is done in MFrac software. This is to see the fracture effects after stimulation using two scenarios; via injection below a packer and above a packer. A third scenario of an open-hole was briefly considered, but ultimately rejected as the MFrac software cannot accommodate a stimulation interval as the same or similar size of the drillhole. The "frac fluid" used is a combination of a low concentration viscous gel to essentially mimic water, and a large grain size proppant of sand. The model also includes parameters for the treatment schedule, as well as initial conditions for modeling fluid loss and heat transfer effects. MProd is then used to model the production flow rate after the stimulation has been performed. This is done by using certain outputs from MFrac as inputs for MProd, along with known characteristics of the reservoir where the well is located. The MProd solution is based on a boundary condition for the pump rate used and net pressure measured after stimulation. An improvement ratio is then calibrated, where another LPM was modeled for a 10 year lifetime to see the well production improvement after stimulation.

68 44 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use 4.1 Case study: Hoffell well HF-1 Iceland is a geologically young country (< 16 Myrs, [19]) lying on the Mid-Atlantic Ridge, which is the boundary between the North American and Eurasian tectonic plates. As a result of its location, Iceland is tectonically and volcanically very active with abundant geothermal resources associated with this activity. A map of the country is presented in Figure 9, which shows the volcanic zone along the Mid-Atlantic Ridge and subsequently the geothermal areas classified into high temperature and low temperature areas. By definition, low temperature areas have a reservoir temperature below 150 C and high temperature areas have a reservoir temperature above 200 C [19]. Stimulation operations are commonly an integral part of the completion programs of geothermal wells drilled in Iceland, and are usually conducted at the end of drilling in order to enhance the output of the wells [19] [62]. Figure 9: Locations of geothermal areas in Iceland based on reservoir temperature and geology [19]. The Hoffell case study area is located in SE-Iceland about 15 km outside the city of Hofn (pop. 1700), as shown in Figure 10. Hoffell is a low temperature geothermal field about 400 km east of Reykjavik, the capital city of Iceland, and is located at N N and E E. Within the region the extinct central volcano of Geitafell is found, but was active five million years ago [63]. Geothermal exploration in Hoffell began in 1992 with research done on surface geology, magnetic measurements, chemical analysis of the water, and geothermal gradient drilling [64]. The results

69 Cari Covell 45 showed that there is potential of exploitable low temperature geothermal resources, as temperature gradients of up to 186 C/km were observed and chemical composition of the water indicated a C temperature deep in the water system [64] [65]. Figure 10: Map showing the location of the Hoffell case study area [63]. RARIK (Iceland State Electricity) drilled Well HF-1, but before the well was drilled in 2012 there were already 33 boreholes in the area with a cumulative total drilling depth of 3,594 meters [66]. The drilling of well HF-1 at Hoffell started in early November 2012 and lasted until January 11, The hole was first drilled down to 1,208 m depth, but was later deepened in February 2013, first to 1,404 m and finally to 1,608 m depth [66]. Figure 11 shows the location of well HF-1 with respect to the other boreholes in the Hoffell geothermal area. Most of the exploration wells were drilled N-S as surface manifestations indicated the main fault line to be in this direction. However when well HF-1 was drilled and tested, the free flow rate was very low at about 7 l/s. Recently, data loggers placed in the exploration boreholes on the east side of the geothermal field indicated that the main fault line is most likely oriented NE-SW, which may explain the low flow of well HF-1 [66].

70 46 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use Figure 11: Location of well HF-1 and some exploration wells [64]. After drilling was completed, long term production testing was performed to understand the reservoir behavior and to estimate its production potential [61]. The test started April 9, Water-level drawdown, production flow rate and temperature were monitored and recorded continuously. The test concluded 13 months later on May 9, Data collected during this time was used as the basis for developing this thesis. 4.2 Lumpfit parameter model (LPM) Lumped parameter modeling (LPM) is a simplified form of numerically modeling the hydrological properties of a low temperature geothermal reservoir. The observed changes in reservoir pressure (or water level) and the fluid production/injection rates can be matched using lumped parameter models, and consequently the fluid and/or energy production potential of a given field can be predicted [67]. For the software, Lumpfit beta was used, which was programmed by and obtained from Iceland GeoSurvey (ISOR) in The software is an update from PyLumpfit, programmed by ISOR in 2014.

71 Cari Covell LPM solution methodology The theoretical foundation of lumped parameter modeling is the concept of dividing the geothermal system into two or more individual data blocks. LPM contrasts other numerical modeling softwares that use a range of modeling blocks. Typically one block represents the production zone of a system, while the other blocks represent recharge zones. Within each block the properties are uniform, hence no internal differences exist. While assuming uniform tanks might seem disadvantageous in terms of simulation accuracy, LPMs actually provide a good result for modeling low temperature geothermal reservoirs [68]. No major drawbacks are seen from assuming uniformity because low temperature geothermal reservoirs are considered nearly isothermal and have almost uniform fluid chemistry [67]. Lumped parameter modeling has been proven to quite accurately simulate various low temperature systems in Iceland [67] [69] [70]. An illustration of the representative tanks in LPM is shown in Figure 12, where a few tanks (capacitors) are connected by flow resistors (conductors). The tanks simulate the storage capacity of different parts of the reservoir and the resistors simulate the permeability. A tank in a lumped model has a storage coefficient κ when it responds to a load of liquid mass m with a pressure increase p = m/κ. The mass conductance (inverse of resistance) of a resistor is σ when it transfers Q = σ p units of liquid mass per unit time at the pressure difference p. Withdrawal from the production tank will influence all connected tanks, according to set properties for individual tanks and connectors [69]. Figure 12: A general lumped parameter model used to simulate water level or pressure changes in a geothermal system. The three tank scenario is shown here [70]. Lumped models can either be open or closed. Open models are connected by a resistor to an infinitely large imaginary reservoir, which maintains a constant pressure. When closed, lumped models are isolated from any external reservoirs. Actual reservoirs can most generally be represented and simulated by two- or three-tank closed or open lumped parameter models [69].

72 48 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use The pressure response p(t) of a single-tank open model for production Q, assuming a step response since time = 0, is given by the following equation [71]: ( Q p(t) = σ 1 ) ( 1 e σ 1 t i κ 1 ) (6) The pressure response p(t) of a more general open model with N tanks to a more constant production Q from time = 0 is given by: p(t) = N Q j=1 ( Aj L j ) (1 e L j t ) (7) The pressure response of a general closed model with N tanks is given by: N 1 p(t) = Q j=1 ( Aj L j ) (1 e L j t ) QBt (8) Coefficients A j, L j and B are functions of the storage coefficients of the tanks (κ j ) and the conductance coefficients of resistors (σ j ) of the model, and can be estimated by the LUMPFIT program which uses an iterative non-linear inversion technique to fit a corresponding solution to the observed pressure or water level [69] Initial production modeling of Hoffell HF-1 While the 13 month production test was being conducted, LPM work by Shengtao (United Nations University) was done for the first five months of production testing from April 9, 2013 to September 8, 2013 [61]. The LPM conducted in this thesis is based on data from the 13 month production test, but starting one month later from May 9, 2013 as data for the first month was deemed invalid. Pre-stimulation LPM results are then compared to the Shengtao analysis. Data was provided by ISOR with permission to use from RARIK. The purpose of performing a pre-stimulation production analysis with the additional production test data is to foresee a more accurate prediction of the required flow for sustaining production over a certain period of time. The required flow calculated in Lumpfit beta will be used as a guideline for determining the effects of the post-stimulation treatment. In Shengtao s analysis, two lumped parameter models, a two-tank closed model and a two-tank open model, were used to simulate the five month production data from well HF-1. During the 152 day production process, production started with a flow rate of 20

73 Cari Covell 49 l/s, and was later changed to 15 l/s by August 2, The water level in the well varied from -80 m to -140 m depth (below surface level). An average reservoir temperature of 72 C was assumed based on the measured data [61]. The two models were chosen as they provided a good fit between the measured and calculated water level in the well, which can be seen in Figure 13. In the analysis for this thesis, only the two-tank open model was considered, as the two-tank closed model did not provide a good fit of the measured and calculated water level in the well, as shown in Figure 14. This may be a result of the uncertainty of LPM within the Lumpfit beta software [68]. In addition to the five month data, production continued with a change in flow rate to 5 l/s by November 13, 2013, 3 l/s by December 3, 2013, and 1 l/s by April 30, 2014 as seen in Figure 15. The water level in the well varied from -5 m to -140 m depth (below the surface level). An average reservoir temperature of 69 C was assumed based on the measured data. Figure 13: Monitored and calculated water level of Well HF-1 from April 9, 2013 to September 8, 2013 of the long-term production test. Calculated values are those of the LPM, where the left shows the two-tank closed model and the right shows the two-tank open model. Time t = 0 corresponds to April 9, 2013 [61].

74 50 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use Figure 14: Monitored and calculated water level of Well HF-1 from May 9, 2013 to May 8, 2014 of the long-term production test. Calculated values are those of the LPM, where the left shows the two-tank closed model and the right shows the two-tank open model. Time t = 0 corresponds to May 9, Figure 15: Long-term production test for a one year period of well HF-1. Time t = 0 corresponds to May 9, Based on the lumped parameter models established above, future predictions could be calculated to estimate the response of the water level (reservoir pressure) to exploitation. Ten year predictions were calculated to help gain an understanding of the general water level changes for different production flow rates [61]. A Monte Carlo simulation performed by Shengtao shows that if the geothermal heating system will be used for 50 years with average thermal power of 6.0 MW th, a thermal water flow rate of 28.6 l/s is needed; and if the geothermal heating system will be used for 100 years with a thermal power of 3.0 MW th, a thermal water flow rate of 14.3 l/s is needed [61]. The Monte Carlo simulation results form the basis for the prediction production scenarios; therefore the production rates were set to 28.6 l/s, 21.4 l/s, 14.3 l/s and 7.15 l/s [61].

75 Cari Covell 51 As seen in Figure 16, the set of data over the five month period shows that the water level behaves quite differently in the two models. Over the next 10 years, the water level is predicted to decline very sharply in the closed system while in the open system it reaches equilibrium. As seen in Figure 17, the year-long analysis for this thesis also shows the open system as reaching equilibrium. Figure 16: Predicted water levels in well HF-1 for the next 10 years for different production rates using the five month period long-term production test data. Conservative predictions using two-tank closed model are on the left. Optimistic predictions using two-tank open model are on the right [61]. Figure 17: Predicted water levels in well HF-1 for the next 10 years for different production rates using the year-long period of long-term production test data. The optimistic two-tank open model is shown. As seen in Table 4, the water level behaves quite differently between the closed system and the open system. With an increasing production rate, the difference between the closed tank system and the open tank system becomes more obvious [61]. The water level in a closed system had a greater response to large production rates than that in an open

76 52 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use system. With the pump at a depth of 175 m, Shengtao s LPM model shows the closed tank system requiring a sustained production rate of 6.7 l/s and the open tank system requiring a sustained production rate of 26.8 l/s. The LPM model used in this thesis shows the open tank system requiring a sustained production rate of about 28.6 l/s with the pump at a depth of 175 m. Table 4: Predicted water levels in well HF-1 after 10 years production [m] Based on five months data [61] Based on year-long data Production flow rate Conservative model Optimistic model Optimistic model [L/s] (closed system) (open system) (open system) A production rate as high as 28.6 l/s would lead to a very great water level decline if the geothermal system was a closed system; and a rate this large would cause the water level to drop down to -841 m after 10 years, which is not realistic [61]. However, it is also very unlikely that the system is completely closed. Furthermore, the difference in production rate for each of the optimistic approaches is very small (about 2 l/s), so it is shown that with more production data the results of the 10 year prediction are relatively the same in this case. Although the conservative approach was unable to be modeled with the yearlong production data, it can be assumed that the production rate would be relatively close if a better fit were to be made. From these results, the behavior of well HF-1 is most likely to be between the l/s production range. However, to reduce negative influence, reinjection or stimulation will be necessary, especially for large production rates if the system turns out to be relatively closed [61]. This is the underlying reason for creating a stimulation treatment program for well HF MFrac model MFrac Suite Hydraulic Fracturing Software is a comprehensive design and evaluation simulator containing a variety of options including three-dimensional fracture geometry, auto design features, and integrated acid fracturing solutions; originally designed for the oil and gas industry. Fully coupled proppant transport and heat transfer routines permit use of the program for fracture design, as well as treatment analysis [60]. MFrac is

77 Cari Covell 53 not a fully 3-D model, but rather is formulated between a pseudo-3d and full 3-D type model with an applicable half-length to half-height aspect ratio greater than about 1/3 [60]. MFrac also has options for 2-D type fracture models in the form of Geertsma & de Klerk (GDK) and Perkins & Kern (PKN). MFrac is the calculation engine for real-time and replay fracture simulation and works in conjunction with the real-time data acquisition and display program MView. The MFrac suite also includes MPwri, MinFrac, MFast, MProd, MNpv, MLite, MWell, MShale, MACQ, and MDBE. For the purposes of this thesis, only MProd was used as an additional software for analysis to MFrac, discussed further in section 4.4. The MFrac suite was obtained from Baker Hughes Incorporated with a full academic license, and is programmed by several third parties [72] MFrac governing equations The fracture propagation solution is obtained numerically by satisfying mass conservation, continuity, momentum, width-opening pressure elasticity condition, and the fracture propagation criteria; where a detailed description of these equations and the solution methodology is provided by Meyer et. al [60] [73] [74] [75] [76]. All nomenclature is listed in the preamble of this thesis Mass conservation The governing mass conservation equation for an incompressible slurry in a fracture is defined by: where t 0 q(τ)dτ V f (t) V l (t) V sp (t) = 0 (9) V l (t) = 2 t A 0 0 C(A, t) dadt αc [t τ(a)] V sp (t) = 2S p A(t) τ(a) = t[a/a(t)] αa. The above mass conservation equations are solved numerically in MFrac by elementally descritizing a fracture grid and then integrating over each element. The above equations for performing minifrac analysis (i.e. from a previous fracture) can be simplified for 2-D

78 54 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use type models for fluid loss due to leakoff during and after pumping: During Pumping V l (t) = πc(t)a(t) tφ(α a α c ) After Pumping V l (θ) = 2C(t p )A(t p ) t p G(α a α c, θ) where θ = t/t p Mass continuity The mass continuity equation in terms of the flow rate per unit length q = vw is: q + 2q L + W t = 0 (10) where q = q L / x + z / z and L is the leakoff rate per unit leakoff area (i.e. leakoff velocity) Momentum conservation The momentum equation (equation of motion) for steady flow is: P = (1/2)fρ q 2 /w 3 (11) where f = 24/R e ; laminar flow, f = fr(e, ɛ) ; turbulent flow, and f is further defined as the Darcy friction factor, R e as the Reynolds number, and ɛ as the relative wall roughness.

79 Cari Covell Width-opening pressure elasticity condition The crack-opening and opening pressure relationship is of the form: 2(1 v) W (x, z, t) = Γ W (x, y, z, t) G H ζ P (x, 0, t) (12) where Γ W is a generalized influence function, H ζ is a characteristic half-height, and P is the net fracture pressure P σ Fracture propagation criteria The criteria for fracture propagation is based on the concept of a stress intensity factor κ I. The fracture will propagate when the stress intensity factor equals the fracture toughness κ IC or critical stress intensity of the rock (κ I = κ IC or σ I = σ IC, whichever is greater) MFrac solution methodology The governing differential equations for fracture propagation are differentiated with respect to time and then simplified by the transformations: α w α L α P t dl(t) ; α a t da(t) L(t) dt A(t) dt t dw w (t) ; α H t dh w (t) W w (t) dt H w (t) dt t d P (t) ; α c t dc(t) P (t) dt C(t) dt to form a set of equations in terms of the alpha parameters (α ζ = t/ζdζ/dt). The length propagation parameter is of the form: α L = 1 (α ca + 1/2)(1 η) + α term 1 + η(1+β H(3+n )) (n +1)(1 β γ) (13) where α ζ accounts for the time dependent gamma parameters, non-steady injection rates and fluid rheology, spurt loss, fracture toughness, etc. The fracture efficiency is given by η and β H = α H /α L. The geometric factor β γ is equal to unity for the PKN and 3-D type fracture models and equal to zero for the GDK model. Additional alpha parameters

80 56 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use for 2-D type fractures are also given by [60]. The previous equation and the formulated constitutive relationships control the time dependent length propagation solution: L(t) = L(t n ) (t/t n )) α L(t). (14) Stimulation set-up For Hoffell well HF-1, a 3-D fracture simulation model along with a complete proppant transport and fluid treatment schedule were constructed in MFrac. The goal was to create a stimulation program based on the characteristics of the well and the geothermal area in order to analyze the effects of fracture propagation. The target area was a fracture located at 1093 m depth as televiewer logs indicate good cracking and is therefore the best candidate for stimulation [77]. Therefore, it was decided to place the packer in a conservative interval of 1070 m depth to 1110 m depth; allowing for a 40 m range of placement. Injection down the casing will be done through a 12 hour stimulation in order to show one cycle of a typical stimulation program. Proppant type used was a 20/40 mesh Jordan sand and fluid type was a low concentration water based gel, where each of their properties can be seen further in Appendix D. The idea of creating a water frac (WF) that has low concentrations of sand and gel will aid in creating a long fracture to intersect the main fault line. Two scenarios are created: 1) injection below a packer and 2) injection above a packer Governing model parameters The first step in MFrac is to indicate the type of stimulation desired. This is designated in three stages: 1)general, 2) fracture, and 3) proppant. General conditions include the assumption of linear reservoir coupling as a one-dimensional analysis, as this option is the most common fluid loss model used for propagating fractures. Subsequently, fluid loss is to remain constant. The treatment design schedule is in auto design in order to optimize injection time. Wellbore hydraulics will be tabulated using an empirical model, where the wellbore friction factor is used to determine the energy dissipation (pressure loss) in the wellbore [73]. With this, three distinct types of behavior are possible with the combined correlation used in MFrac, and are summarized in the expressions for the Fanning friction factor in Table 5. Through an iterative process, MFrac determines which correlation is most applicable in determining the friction factor. The criteria are based on the argument that 1/ f will always be greater than the Prandtl-Karman Law (lower bound) and less

81 Cari Covell 57 than Virk s maximum drag reduction asymptote (upper bound). Therefore, when the transitional correlation developed by Keck et al. [78] reaches either the upper or lower bound, it is automatically adjusted to meet the above criteria, as seen in Figure 18. Table 5: Fanning friction factors Maximum Drag Reduction [79] 1 f = 19log(Re s f) 32.4 Transitional flow [78] 1 f = Alog(Re s f + B No Drag Reduction [80] 1 f = 4log(Re s f) 0.4 Figure 18: MFrac Pipe Friction Empirical Correlations [72]. For the fracture dialog box, no flowback is assumed as no negative flow rate is present. The model will not simulate to closure after pumping, therefore it is assumed that the fracture remains open after treatment. The fracture fluid gradient option is turned on to tabulate hydrostatic pressure changes as a function of depth. Default growth of the fracture is assumed (i.e. in the positive and negative direction) as this will measure pressure decline even after/during pump shut down. This tends to happen in stimulation treatments where not enough fluid is available on site and re-filling of tanks is necessary. The fracture initiation interval will be calculated using the minimum stress interval, which is 10% of the initial fracture height [72]. This option calculates effective closure pressure to keep the fracture open over the interval. Creating a fracture friction model will not be necessary as laminar flow normally exists in the fracture. For this case, the classical solution for fluid flow is used and the Darcy friction factor is f D = 24/R e [72]. The inclusion

82 58 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use of wall roughness is turned off, as the Darcy friction factor inside the fracture is used without modification. This selection assumes that the fracture surface is a smooth planar feature without roughness [72]. Tip effects will not be analyzed, as a constant pump rate was used and it can be assumed that there is no net pressure at the fracture tip (see section for further information on this theory). For the proppant dialog box, the proppant ramp (i.e. changes in proppant concentration as a function of time) is turned off because a uniform proppant concentration will be used throughout the stimulation. Perforation erosion will not be considered as the stimulation will model as close to an open hole as possible. The model will use a conventional (link proppant) transport methodology because this couples the proppant solution with fracture propagation and is the optimal solution of proppant transport when using the Auto Design treatment schedule feature. The proppant settling option will be user specified as the size of the particles used is typically much smaller than for oil and gas applications. Fractureproppant effects control the effect of proppant concentration on frictional pressure losses in the fracture, and will use an empirical solution. The procedure involves a correction to the base viscosity to produce a relative viscosity term. Once this is done, the friction factor is calculated based on the fracture friction model selected (in this case, the classical Darcy friction factor solution). The general correlation as a function of proppant void fraction is: µ r = (1 φ) αµ where µ r = relative slurry velocity µ r = relative slurry velocity α µ = exponent coefficient φ = proppant void or particle volume fraction Wellbore hydraulics The wellbore hydraulics are defined to essentially build the well in order to calculate its total volume. First, the casing depths and dimensions are set for Hoffell well HF-1 based on drilling reports as seen in Table 6 [66]. The outside diameter (OD) is specified using the MFrac internal database, where the subsequent weight and inside diameter (ID) are calculated. The lightest weight for each OD was then chosen. Although the wellbore is actually open hole after the production casing of 400 m depth, it is necessary to include the corresponding depths where additional drilling was performed in order to construct a

83 Cari Covell 59 complete well in MFrac. Drilling depths to 1404 m and 1608 m were reached using a drill bit. Up to 1404 m depth a drill bit size of 9 7/8" was used, however casings are not made in this dimension and a 9 5/8" was assumed. A drill bit size of 8 5/8" was used for the remaining 202 m to 1608 m depth. The difference in measured length and section length are not applicable for this geothermal well, as the study does not account for the use of a liner where section length is different than measured depth. Table 6: Casing Dimensions for Hoffell well HF-1 Measured depth Section length OD Weight ID [m] [m] [in] [lbf/ft] [in] Next, the deviation of the well is built in MFrac. The wellbore survey method for determining deviation will use the average angle method, where well path between 2 stations is along a straight line; and whose length is the measured depth difference between the 2 stations and whose inclination and azimuth angles are the average of the station s values. Since the ISOR drilling report only gives a graph representing horizontal deviation, the inclination angle was calculated in different iterations as a slope of the line of horizontal deviation versus measured depth [77]. All values were entered as measured depth (MD) and total vertical depth (TVD) was internally calculated in MFrac, as seen in Table 7. Total deviation in the well is approximately 8. Once the casing dimensions and well deviation are set, a cross section of the well is created as seen in Figure 19. Table 7: Hoffell well HF-1 deviation Measured depth Inclination angle TVD [m] [ ] [m]

84 60 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use Figure 19: Wellbore cross section for Hoffell well HF-1. Bottom-hole treating pressure (BHTP) was specified by MD and 3 entries are allotted in MFrac. This will essentially create an output that measures BHTP from these 3 points in the well. The three points chosen were depth of production casing (400 m), depth of packer placement (1100 m), and the bottom of the well (1608 m). Lastly, the total volume of the well is calculated based on wellbore configuration, surface line volume, and the wellbore volume reference depth using the governing equations for mass conservation. Surface line volume is the volume of fluid/slurry in the service line(s) upstream of the well entrance, and is assumed as zero because all treatment parameters are referenced at the well entrance. The wellbore volume reference was entered as MD and TVD is subsequently calculated, but this value has to be above the bottom of the casing and is therefore defined at approximately 1600 m depth Rock properties Rock type is described in the drilling reports from ISOR [66]. For simplification purposes, rock type was defined in three layers based on MD, as in reality there are only slight differences in the properties of various rock types within the major governing layers of the well. The three layers of gravel, dolomite, and intrusive volcanics along with their

85 Cari Covell 61 governing properties are shown in Table 8. Stress and stress gradient were calculated based on internal calculations in MFrac (see [73]). Young s modulus, poisson s ratio, and fracture toughness vary in range for different rock types, where typical values can be seen in the Baker Hughes MFrac manual [72]. The critical stress, defined as the minimum critical stress for the fracture to propagate in the vicinity of a constant stress field, is set to zero via the database option; i.e. only fracture toughness will be considered. Critical stress may also be thought of as the apparent tensile strength since it is the critical stress that must be over come for the crack to propagate (in a uniform stress field) [72]. Table 8: Rock properties of Hoffell well HF-1 Zone name TVD at bottom MD at bottom Stress gradient Stress Young s modulus Poisson s ratio Fracture toughness Critical stress [m] [m] [psi/ft] [psi] [psi] [psi-in 1/2 ] [psi] Gravel e Dolomite e Int. volcanic e Zones data The zone of stimulation for each case below and above the packer must be specified. Typically a packer is placed where the fracture can be isolated within a m interval. As the main fracture for well HF-1 is located at 1093 m depth, the packer would be isolated somewhere between m depth. Therefore, stimulation below the packer is defined within a zone that starts at 1110 m depth and goes to the bottom of the hole at 1608 m depth. The zone of stimulation above the packer starts at the end of the production casing at 400 m depth and goes to 1070 m depth. Within the zones module of MFrac, perforation data is necessary to enter as MFrac caters to oil and gas wells. In essence, the number of perforations is set to 2000 at 0.75 in diameter in order to mimic an open hole geothermal well. The pay zone (length of stimulation interval) has an associated permeability for each case below and above the packer. The permeability used below the packer in the intrusive volcanic zone is low at around 10 4 darcy, while the permeability above the packer in the dolomite zone is higher at around 10 1 darcy [81].

86 62 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use Treatment schedule The total slurry volume injected was calculated assuming a constant 60 l/s flow for 12 hours and a total of 15 tons of proppant. The proppant distribution style was set using the maximum proppant concentration because a constant proppant concentration is assumed throughout the stimulation, therefore MFrac will design treatments with the last propped stage at the final proppant concentration specified. This option also creates a treatment schedule (when in auto design mode) where stages do not screen or bridge out and the maximum proppant concentration in the fracture will not exceed the maximum value specified. The proppant settling rate was obtained using Figure 20, assuming 0.8 mm diameter sphere/grain size [58], at 20 C injection fluid temperature. Table 9 shows each of the properties defined in the treatment schedule. Figure 20: Velocity of cuttings in mm/s [58]. Table 9: Treatment schedule for Hoffell well HF-1. Property Value Unit Slurry volume 2606 m 3 Pump rate 3600 L/min Initial and incremental proppant concentration lbm/gal Final proppant concentration lbm/gal Maximum proppant concentration (at tip) lbm/gal Proppant settling rate 10 cm/s

87 Cari Covell Fluid loss To model fluid loss from the fracture into the reservoir and surrounding layers, additional information characterizing the formation and in-situ diffusivity parameters is necessary. The leakoff coefficient needs to be specified for each rock layer and the Baker Hughes MFrac manual provides a range of values for any given formation. Since the Hoffell geothermal area is dominated by dolomite and intrusive volcanics, a range of to ft/min 1/2 is acceptable and a value of ft/min 1/2 was therefore assumed. Spurt loss are assumed to be zero as this is only present for wall-building fluids [7]. Fluid loss is also pressure dependent and is based off of Table 10. Pressure was calculated at zones of BHTP measurements located at 400 m, 1100 m, and 1608 m depth via production test data. Arbitrary leakoff multipliers are assumed for the three zones and gradually decrease as depth increases, where zones are cooled and gradually take longer to heat up. The leakoff coefficient throughout the stimulation therefore changes and is calculated as a function of pressure. This is helpful for modeling leakoff in naturally fractured reservoirs. While fracturing a naturally fractured formation, the pressure in the fracture may approach the critical pressure. When the critical pressure of the formation is reached, natural fractures open and accelerated leakoff occurs. Table 10: Pressure dependent fluid loss for well HF-1. Pressure Leakoff coef. Spurt loss coef. [bar] multiplier multiplier Proppant criteria The minimum number of proppant layers to prevent bridging is the minimum number of layers in the fracture at which bridging occurs. In MFrac, a bridge-out is assumed to occur if the average fracture width integrated over the fracture height is less than the minimum number of proppant layers to prevent bridging. This makes sure that the fracture width is greater than the bridging criteria in order for the proppant to pass through. Typically, a value of 1.5 to 3 is used [72]. The minimum concentration/area for propped fracture means that anything below this concentration after embedment is included and the fracture will not be reported as being propped. A typical value ranges from 0 to 0.2 lbm/ft 2 (1.0

88 64 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use kg/m 2 ) [72]. The amount of embedment depends upon the proppant and formation type, and MFrac assumes this embedment is in the fracture at closure, therefore a value of zero is used. Finally, closure pressure on the proppant is calculated using the bottomhole fluid pressure subtracted from the horizontal stress of the area. The horizontal stress of a geothermal area similar to Hoffell in Iceland was assumed as 500 bar [81]. The bottomhole fluid pressure of 154 bar was taken from the production data of well HF-1. Therefore, the closure pressure on the proppant is approximately 344 bar. This is used to determine the proppant permeability which is interpolated from the proppant database. As the closure pressure (stress) increases, the proppant pack permeability decreases. Table 11 further illustrates the required proppant criteria. Table 11: Proppant criteria for well HF-1. Property Value Unit Min. number of proppant layers to prevent bridging 2 Min. concentration/area for propped fracture 0.1 [lbm/ft 2 ] Embedment concentration/area 0 [lbm/ft 2 ] Closure pressure on proppant 344 bar [psi] Heat transfer An analytical heat transfer model is included in MFrac that combines thermal convection in the fracture, with transient conduction and convection in the reservoir. MFrac predicts the heat-up of the fracturing fluid within the wellbore and/or the exchange of heat between the fluid and the reservoir during fracture propagation. MFrac couples the heat transfer, fluid flow, and fracture propagation expressions to characterize the time dependent fracture temperature profiles. The fluid inlet is to be at the surface as MFrac will calculate heat transfer in the wellbore and in the fracture using this option. The reservoir lithology must be selected from the MFrac database, and the closest option to the Hoffell field is dolomite, where average porosity is subsequently applied within the MFrac program. The mean formation temperature of the area is 69 C as measured from production test data, and the injection fluid temperature is assumed to be 20 C. Table 12 further lists heat transfer properties.

89 Cari Covell 65 Table 12: Heat transfer properties for Hoffell geothermal field. Property Value Unit Fluid inlet Surface Base fluid type Water Reservoir lithology Dolomite In-situ fluid type Water Average porosity 0.15 fraction Mean formation temperature 69 C Injection fluid temperature 20 C 4.4 MProd model MProd is a single phase analytical production simulator. Although the program was designed primarily for hydraulic fracturing applications, it can also be used to explore the production potential of unfractured reservoirs. MProd has options for Production Simulation, History Match Production Simulation, and Fracture Design Optimization. Production Simulation will be used in this thesis which allows the user to input typical production data to simulate well performance for fractured and unfractured wells. The capability to compare the output (numerical simulated results) with measured data is also provided. MProd is integrated and fully compatible with MFrac to provide full feature optimization, where the output produced by MFrac can be used by MProd. The numerical results of MProd, in turn, can be imported by MNpv to perform economic analyses, but will not be done in this thesis MProd governing equations The governing equations for simulating production from fractured and unfractured wells in closed and infinite reservoirs are based on the Baker Hughes manual solution methodology [72] presented in the following sections. The production solution is obtained numerically by satisfying conditions related to pre-defined dimensionless parameters, pseudopressure, the trilinear solution, pseudosteady-state pressure and resistivity solutions, wellbore choked skin effect, the pseudo-radial flow solution, productivity increase, and desuperposition. When appropriate, the solution methodology is also given. All nomenclature is listed in the preamble of this thesis.

90 66 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use Dimensionless parameters The dimensionless pressure p D for a constant production rate q is defined as: p D = 2πkh p (15) qµ where k is the formation permeability, h is the formation height, µ is the reservoir viscosity, and p = p i p wf is the differential pressure (the initial reservoir pressure p i minus the flowing pressure p wf ). The dimensionless times based on the drainage area A, wellbore radius r w, and fracture half-length x f are defined as: t DA = kt c t φµa, t D = kt c t φµr 2 w, and t Dxf = kt c t φµx 2 f where φ is the formation porosity and c t is the formation compressibility. The dimensionless rate q D for a constant flowing pressure p wf is defined as: q D = and the flow rate as a function of the dimensionless rate is: where p = p i p wf is the constant drawdown pressure. The productivity index J is defined as: J = µ 2πkh p q (t) (16) q (t) = 2πkh p q D (17) µ q = 2πkh p p wf µ J D (18) where q is the flow rate, p is the average reservoir pressure, and p wf is the flowing pressure. The dimensionless productivity index J D is defined as: J D = 2πkh J µ = 2πkh µ q (19) p p wf

91 Cari Covell 67 The dimensionless and Laplace parameters used in the production model are: C fd = k fw f C C, C D =, C kx f 2πφc t hrw 2 Df =, 2πφc t hx 2 f C 1 = η/η f, η = k/(φµc t ), η f = k f /(φµc t f, s f = π ( ) y s k 1, 2 x f k s a = 2, b = π. C fd C fd The Laplacian operator used in the production models is given by s. The fracture skin is given by s f Pseudopressure The real gas potential or pseudopressure is defined as: p p m(p) = 2 dp (20) p b µ(p)z(p) where p b is an arbitrary base pressure and Z is the real gas deviation factor. The real gas pseudopressure equation can be simplified for certain pressure ranges. At low pressures µz is essentially constant, while at higher pressures it is directly proportional to pressure [82]. At low pressure (p < 2000 psi), the real gas pseudopressure based on a constant µz product is: m(p) = (p2 p 2 b ) µz or m(p i ) = (p2 i p 2 wf ) µ i Z i where µ i and Z i are initial condition gas properties at p i. At high pressures (p > 3000 psi), the real gas pseudopressure based on a constant p/(µz) product is: m(p) = 2p(p p b) µz or m(p i ) = 2p i(p i p wf ) µ i Z i. When the fluid type is gas and the Internal PVT correlations are not used, the model requires that a table of µ and Z be entered as a function of pressure. The pseudopressure function is then automatically used to calculate the dimensionless pressure.

92 68 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use Trilinear solution The trilinear solution for a finite-conductivity fracture in Laplace space is for [83] [84]: p D (s) = Constant flow rate b, or for s(sbc Df (ΨtanhΨ) q D (s) = Constant pressure 1 s 2 p D (s) = Ψ sb tanhψ. The Ψ parameter used in the above equations is defined by: a(s + s Ψ = 1/2 ) 1/2 + C 1 + (s + s 1/2 ) 1/2 1 s (21) S f This analytical solution is based on transforming the equations above from Laplace space to real time using the Stehfest inversion algorithm [85] Pseudosteady-state pressure and resistivity solutions The pseudosteady-state dimensionless pressure solution in a closed system can be written as [86]: where the inverse productivity index is given by p D = 2πt DA + 1/J D (22) ( ) 4A 1/J D = 1/2ln e γ C A r w 2. (23) The pseudosteady-state resistivity solution for a finite-conductivity fracture in a closed system in terms of the inverse productivity index is [87]: where the pseudo-skin function f is ( ) 1 x e = ln β xe + f (24) J D x f ( ) π f = ln C fd g(λ) + ζ. (25)

93 Cari Covell 69 The pseudosteady-state resistivity equations are solved to generate the production solution for a single fracture in a closed rectangular reservoir for all times (i.e., linear, bilinear, trilinear, and pseudosteady-state). These generated fundamental solutions for constant rate and constant pressure boundary conditions are then used to calculate the composite multiple transverse fracture solution Wellbore choked skin effect Mukherjee and Economides [88] identified that the inadequate contact between a vertical transverse fracture and the horizontal well resulted in a restriction that can be quantified by a choked skin effect as given by: s ch = kh k f w f [ ln h π ] 2r w 2 in terms of the dimensionless fracture conductivity. This illustrates that as the height interval to wellbore radius ratio or height to propped length ratio decreases (i.e., radial to linear flow in the fracture) or the dimensionless fracture conductivity increases, the skin due to convergence becomes smaller. Soliman et al. [89] concluded that a high conductivity tail-in could be incorporated to reduce the additional pressure drop because of flow convergence around the wellbore. (26) Pseudo-radial flow solution The non-dimensional pressure drop at the wellbore, for an unfractured well, is [82]: p d = 1 2 E i ( 1 ) 4t Dw (27) where the exponential integral E i is defined as E i ( x) = x e µ µ dµ. (28) This solution is also used for the pseudo-radial solution of the fractured well by matching the pseudo-radial and trilinear solutions.

94 70 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use Productivity increase The productivity increase as defined by the ratio of the productivity indices for the fractured and unfractured wells as given by [73] below Constant flow rate The instantaneous (current rate) and average (volume) productivity indices are: Instantaneous J/J 0 t = p Dw /p Df Average J/J 0 V = p D0 dt/ p Df dt Constant pressure The instantaneous (rate) and average (volume) productivity indices are: Instantaneous J/J 0 t = q Df /q D0 Average J/J 0 V = q Df dt/ q D0 dt where f refers to the fractured well and 0 to the unfractured case. For unfractured reservoirs the subscript f refers to the well with no skin. When considering a series of constant rate or pressure changes, the productivity parameters outlined above are equal to the equivalent values calculated by superposition Desuperposition The concept of desuperposition has been illustrated by Gringarten, Ramey and Raghavan [90] for modifying known values of p D to dimensionless pressures describing somewhat different systems. This method is used to calculate the effect of skin and fractures in closed systems. For closed systems, the dimensionless pressure p d is found from the following relationship: p d (C D, S) = p D (C D = 0, S = 0) p D (C D = 0, S = 0) p D (C D, S). (29)

95 Cari Covell 71 In the above equation p D is the dimensionless pressure for a closed system and p D is the dimensionless pressure for an infinite (unbounded) reservoir. The first term on the right side of the equation is for the closed system with zero skin and zero wellbore storage. Dimensionless pressure p D for a single well in an infinite system with zero skin and wellbore storage is subtracted from this dimensionless pressure term. This dimensionless pressure p D for a single well in an infinite system with the desired wellbore storage and skin factor is then added Stimulation set-up The goal of MProd is to take the output from MFrac in order to simulate a production test performed after two scenarios of stimulation; below and above a packer. The solution is for the case of a single fracture in an infinite reservoir (i.e. open tank) where the production boundary condition is based on the net flowing pressure output of MFrac. The original production data based on flow rate from HF-1 is then overlayed for comparison in order to obtain a productivity index Formation data The formation data module provides a location for entering the reservoir properties needed to perform a simulation. The total pay zone height is entered based on the scenario being analyzed, followed by all reservoir properties that were obtained via a Monte Carlo simulation performed by Shengtao [61]. Table 13 shows the input dialog box. Table 13: Formation data for well HF-1. Property Value Unit Total pay zone height 498 (below) or 670 (above) [m] Equivalent reservoir permeability [md] Initial reservoir pressure 38.5 [bar] Total reservoir compressibility 6.665e-08 [1/kPa] Equivalent reservoir porosity 10 % Equivalent reservoir viscosity Pa s

96 72 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use Single case fracture characteristics A calculated radial option is available for single case fracture characteristics in order to calculate either the fracture permeability, fracture width, or fracture conductivity. This allows flexibility to input two of the variables and have the third calculated, where the calculated value will then be dimmed. The calculate option may not be available depending on the fracture options selected (i.e., if input conductivity or calculate fracture permeability is selected). In this case, fracture width and average fracture conductivity were the input, and fracture permeability was subsequently calculated. Effective dimensionless conductivity in the pay zone is then calculated from: C fd = k fw f kl h p (30) h p The parameters from MFrac include: Total pay zone height [m], Effective propped pay zone height [m], Propped fracture length [m], Fracture width [in], and Average fracture conductivity [md-ft]. In addition, the inverse fracture diffusivity is a parameter to consider as the conductivity of a fracture approaches the conductivity of the reservoir, which may significantly influence the early time production behavior of a well [72]. The definition of the inverse fracture diffusivity is: where c f = kφc t k f φ f c tf (31) k = Equivalent reservoir permeability k f = Equivalent fracture permeability c t = Total reservoir compressbility c tf = Total fracture compressibility φ = Equivalent reservoir porosity φ f = Equivalent fracture porosity

97 Cari Covell 73 The calculation results in a small ratio of 10/1100 for permeability and porosity, while compressibility remains fairly constant. Therefore, the inverse fracture diffusivity is of the order 8e-05. Lastly, the fracture skin factor is assumed to be negligible (zero) Well data Production forecasting typically requires a minimum of data describing certain features of the well in order to perform a simulation. For MProd, these features include the wellbore radius and the permeability damage due to skin. The well radius defines the contact area between the well and the reservoir. The skin damage (well skin) characterizes the additional pressure drop associated with the near wellbore effects. This parameter may have a significant effect on calculating the increase in productivity index. For the purposes of this thesis, the skin factor before stimulation was assumed to be 0.67 and after stimulation to be small and negative at approximately as indicated by Shengtao s reservoir analysis [61]. C D = C 2πc t h(r w2 ) (32) where C D = dimensionless wellbore storage C = wellbore storage coefficient [61] c t = total reservoir compressibility [61] h = pay zone height [MFrac] r w = wellbore radius [61] φ = equivalent reservoir porosity [61] Table 14 summarizes the input parameters of well data for MProd. Table 14: Well data for Hoffell well HF-1. Property Value Unit Wellbore radius 0.14 [m] Wellbore skin factor (base - prefrac) 0.67 Wellbore skin factor (stimulated) Wellbore storage factor 1.302

98 74

99 75 Chapter 5 Results This chapter will discuss the results from MFrac and MProd, followed by a Lumpfit parameter model showing production potential after stimulation. 5.1 MFrac The packer was assumed to be placed between m depth to be conservative with a placement interval, with stimulation below the packer from m depth in the intrusive volcanic region (total interval length 498 m), and stimulation above the packer from m depth in the dolomite region (total interval length 670 m). For full reports see Appendix E. Results from proppant design tabulations indicated no need to continue modeling stimulation below the packer, however all results continue to be analyzed for further discussion in Chapter Fracture propagation solution The fracture propagation solution displays the fracture (frac) length, height, and width characteristics. Fracture length is measured as a half-length, i.e. for one wing of the fracture. The fracture length created after stimulation below the packer (122 m) is significantly shorter than the fracture length created after stimulation above the packer (925 m), which is due to permeability of the rock type defined for each stimulation zone. Permeability for the intrusive volcanic zone below the packer is defined as 10 4 darcy, which is significantly less than the permeability for the dolomite zone above the packer defined as

100 76 Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use 10 1 darcy [81]. Each permeability value is based on geological surveys in other areas of Iceland similar to the Hoffell geothermal field [81]. Frac height is calculated above and below the target fracture zone (i.e. where the packer is isolated between m depth). When comparing upper frac height and lower frac height, the one that is greater is the one where injection is dominant, as seen in Figures 21 and 22. Lower frac height is greater than upper frac height when injection is below the packer, and upper frac height is greater than lower frac height when injection is above the packer. Figure 21: Upper and lower fracture zone height when stimulated below the packer. Figure 22: Upper and lower fracture zone height when stimulated above the packer. Frac width is illustrated in Figures 23 and 24 as a percentage of frac length, where frac width decreases as frac length increases. The proportion that governs each value related to fracture length, height, and width is unknown; which will be addressed in Chapter 6: Discussion.

101 Cari Covell 77 Figure 23: Frac width as a function of frac length for stimulation below the packer. Figure 24: Frac width as a function of frac length for stimulation above the packer. Net frac pressure is total pressure measured over the 12 hour stimulation, subtracted by pressure loss in the wellbore due to friction. Effects of net frac pressure over time are illustrated in Figure 25. Net frac pressure remains fairly constant at later stages of stimulation after about 30 minutes time, but is very low at about 0.5 bar. Net frac pressure increases with time when stimulation is done above the packer, which seems abnormal upon first glance. However this observation is consistent with pressure measured in the initial production test of Hoffell HF-1, as pressure is assumed to stabilize when measured over a longer period of time. The net frac pressure tabulated in MFrac will later be used as input for MProd, as these calculations represent pressure measured from a production test conducted after stimulation.