Hydraulic Well Stimulation in Low-Temperature Geothermal ... · Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use Cari Covell January 2016 Abstract Direct

Hydraulic Well Stimulation inLow-Temperature Geothermal Areas for

Direct Use

Cari Covell

Thesis of 60 ETCS creditsMaster of Science in Energy Engineering -

Iceland School of Energy

January 2016

Hydraulic Well Stimulation in Low-TemperatureGeothermal Areas for Direct Use

Cari Covell

Thesis of 60 ECTS credits submitted to the School of Science and Engineeringat Reykjavík University in partial fulfillment of

the requirements for the degree ofMaster of Science in Energy Engineering - Iceland School of Energy

January 2016

Supervisors:

Dr. María Sigríður Guðjónsdóttir, SupervisorAdjunct Professor, Reykjavík University

Mr. Sverrir Þórhallsson, Co-SupervisorDrilling Engineer, Iceland GeoSurvey (ISOR)

Examiner:

Dr. Ágúst Valfells, ExaminerDepartment Head, Mechanical & Electrical Engineering, Schoolof Science and Engineering, Reykjavík University

CopyrightCari Covell

January 2016

Student:

Cari Covell

Supervisors:

Dr. María Sigríður Guðjónsdóttir

Mr. Sverrir Þórhallsson

Examiner:

Dr. Ágúst Valfells

Hydraulic Well Stimulation in Low-TemperatureGeothermal Areas for Direct Use

Cari Covell

60 ECTS thesis submitted to the School of Science and Engineeringat Reykjavík University in partial fulfillment

of the requirements for the degree ofMaster of Science in Energy Engineering - Iceland School of Energy.

January 2016

Date

Cari CovellMaster of Science

The undersigned hereby grants permission to the Reykjavík University Li-brary to reproduce single copies of this project report entitled HydraulicWell Stimulation in Low-Temperature Geothermal Areas for Direct Useand to lend or sell such copies for private, scholarly or scientific researchpurposes only.

The author reserves all other publication and other rights in association withthe copyright in the project report, and except as herein before provided, nei-ther the project report nor any substantial portion thereof may be printed orotherwise reproduced in any material form whatsoever without the author’sprior written permission.

Hydraulic Well Stimulation in Low-Temperature GeothermalAreas for Direct Use

Cari Covell

January 2016

Abstract

Direct use of hot water through renewable energy resources is globally indemand. Thermal energy stored in fractures and pores within geothermalreservoirs contains natural fluids. At times, extracting natural fluids, or hotwater in low-temperature areas, can be a challenge. Hydraulic stimulation isone technique to overcome this challenge. Research about hydraulic stimu-lation 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 wasconducted to understand reasons for success or failure. In order to predictthe effects of hydraulic stimulation before an actual operation, a case studywas performed on well HF-1 in Hoffell, Iceland. First, a preliminary pro-duction flow model was performed using updated data at the completion oftesting in 2014. After evaluating the need for stimulation, a fracture modelusing MFrac was done in two scenarios with an open-hole packer; injectionbelow the packer and injection above the packer. The packer was placed ina conservative interval of 1070-1110 m depth to isolate the main fracture at1093 m depth. Injection below the packer failed, therefore results from in-jection above the packer were only suitable moving forward. Subsequently,MProd software was used to find an improvement ratio after simulating stim-ulation above the packer. The improvement ratio of 1.096 was then appliedto the original production data of well HF-1 and a LPM was performed yetagain. Reservoir properties of S, T, II, and PI were calculated and comparedto original production data. Results indicated the lumpfit model to be veryoptimistic and improvement of only 4 l/s flow over a 10 year well lifetimewas observed. Therefore, the well is not a good candidate for stimulation.However, improvement was seen which proves the potential for this method-ology to be implemented in other low-temperature geothermal areas.

Keywords: hydraulic stimulation, packer, direct use, low-temperature, pro-duction.

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 jarðhitaker-fum og getur verið mikil áskorun að nýta þennan vökva úr lághita jarðhitak-erfum. 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 yfirörvunaraðgerðir fyrir lághitaborholur. Ennfremur var tekið saman efni úrheimildum fyrir þær örvunaraðgerðir með vökva sem gerðar hafa verið til aðfá yfirlit yfir reynslu af þeim. Til þess að spá fyrir um áhrif örvunaraðgerðameð vökva eftir borun var rannsókn gerð á holu HF-1 á svæði Hoffells áÍslandi. Fyrst var einfalt rennslislíkan framkvæmt út frá mæligögnum frá2014. Eftir að þörfin á örvun var metin, var sprunguhermunarlíkanið MFracnotað fyrir tvö tilvik með pakkara (e.packer) fyrir opna holu, annars vegarþar sem svæðið ofan við pakkarann var örvað og hins vegar svæðið neðanvið pakkarann. Pakkarinn var staðsettur á 1070-1100 m dýpi til að einangraaðalæðina sem er á 1093 m dýpi. Ádæling neðan við pakkarann gaf ekki góðaraun og því voru niðurstöður fyrir ádælingu ofan við pakkarann eingöngunýttar í framhaldinu. MProd forritið var notað til að reikna út breytingu árennsli eftir örvun fyrir ofan pakkarann. Hlutfall rennslis fyrir og eftir örvunvar 1,096 fyrir holuna HF-1 og var forðafræðilíkan (LPM) notað til að spáfyrir um framleiðslugetu örvaðrar holu. Forðafræðieiginleikar S, T, II og PIvoru reiknaðir og bornir saman við upphaflegu gildin. Niðurstöður úr líkan-inu 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 þróuðvar við gerð þessa verkefnis er nýtt framlag til rannsókna á lághitasvæðum.

Lykilorð: Örvun jarðhitaholna, pakkari, bein nýting, lághitasvæði, fram-leiðsla

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Acknowledgements

I would like to thank my supervisor María Guðjónsdóttir for her moral support, encour-agement, and guidance in this thesis; and for being a great mentor throughout the durationof my masters studies. I would also like to thank my co-supervisor Sverrir Þórhallsson forproviding useful knowledge and assistance with the MFrac suite; as well as my examinerÁgúst Valfells for reviewing the thesis.

I would like to acknowledge the following Iceland GeoSurvey (ISOR) staff: Guðni Axels-son for guidance regarding the initial stages of finding a case study; Sigurður Kristinssonfor providing references to Hoffell drilling reports; and Helga Tulinius for her help withLumpfit beta.

Furthermore, I would like to acknowledge Magnús Ólafsson from RARIK (Iceland StateElectricity) for allowing the use of production data for the case study; and Baker HughesInc. for allowing academic use of MFrac suite software.

Additionally, I would like to recognize the Geothermal Resources Council (GRC) Grad-uate Scholarship and the Iceland School of Energy Sustainable Future Scholarship forfunding throughout my masters studies.

I express my sincerest gratitude to Halla Hrund Logadóttir, Director of the Iceland Schoolof Energy, for being an incredible mentor and a truly inspiring person. Her unconditionalsupport 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 ca-reer in geothermal energy on an international scale, and have continuously motivated methroughout 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 Miklabraut64 and Ú214; and my family for allowing me to pursue all of my crazy ambitions.

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Contents

List of Figures xi

List of Tables xiv

List of Abbreviations xvii

1 Introduction 11.1 Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21.2 Structure of the thesis . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

2 Background 52.1 Well stimulation theory . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

2.1.1 Hydraulic stimulation . . . . . . . . . . . . . . . . . . . . . . . 62.1.1.1 Mechanics . . . . . . . . . . . . . . . . . . . . . . . . 62.1.1.2 Frac fluid treatment . . . . . . . . . . . . . . . . . . . 92.1.1.3 Hydraulic well testing . . . . . . . . . . . . . . . . . . 12

2.1.2 Thermal stimulation . . . . . . . . . . . . . . . . . . . . . . . . 132.1.3 Chemical stimulation . . . . . . . . . . . . . . . . . . . . . . . . 14

2.2 Types of hydraulic stimulation . . . . . . . . . . . . . . . . . . . . . . . 152.2.1 Air-lift pumping . . . . . . . . . . . . . . . . . . . . . . . . . . 152.2.2 Open-hole with a packer . . . . . . . . . . . . . . . . . . . . . . 17

2.2.2.1 Before deploying the packer . . . . . . . . . . . . . . . 182.2.2.2 Installing the packer . . . . . . . . . . . . . . . . . . . 192.2.2.3 Setting the packer . . . . . . . . . . . . . . . . . . . . 192.2.2.4 Opening the bottom plug . . . . . . . . . . . . . . . . 202.2.2.5 Stimulation . . . . . . . . . . . . . . . . . . . . . . . 202.2.2.6 Releasing the packer . . . . . . . . . . . . . . . . . . . 20

2.2.3 Zonal isolation . . . . . . . . . . . . . . . . . . . . . . . . . . . 202.2.3.1 Use of a liner . . . . . . . . . . . . . . . . . . . . . . 21

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2.2.3.2 Use of a liner with inflatable or swellable packers . . . 222.2.3.3 Plug and go . . . . . . . . . . . . . . . . . . . . . . . 222.2.3.4 Multilateral wellbores and sidetracks . . . . . . . . . . 23

2.3 Environmental impacts and seismicity . . . . . . . . . . . . . . . . . . . 23

3 Literature review 253.1 Hydraulic stimulation applications . . . . . . . . . . . . . . . . . . . . . 25

3.1.1 Oil and gas industry . . . . . . . . . . . . . . . . . . . . . . . . 263.1.2 Low temperature geothermal areas . . . . . . . . . . . . . . . . . 26

3.1.2.1 Reykir hydrothermal system . . . . . . . . . . . . . . . 273.1.2.2 Seltjarnarnes well SN-12 . . . . . . . . . . . . . . . . 303.1.2.3 Other low-temperature fields in Iceland . . . . . . . . . 33

3.1.3 High temperature geothermal areas . . . . . . . . . . . . . . . . 333.1.3.1 Baca, New Mexico (USA) . . . . . . . . . . . . . . . . 343.1.3.2 Latera, Italy . . . . . . . . . . . . . . . . . . . . . . . 363.1.3.3 Salak, Indonesia . . . . . . . . . . . . . . . . . . . . . 373.1.3.4 Mt. Apo, Philippines . . . . . . . . . . . . . . . . . . 38

3.1.4 Enhanced geothermal systems (EGS) . . . . . . . . . . . . . . . 393.2 History of stimulation fracture modeling . . . . . . . . . . . . . . . . . . 41

4 Methods 434.1 Case study: Hoffell well HF-1 . . . . . . . . . . . . . . . . . . . . . . . 444.2 Lumpfit parameter model (LPM) . . . . . . . . . . . . . . . . . . . . . . 46

4.2.1 LPM solution methodology . . . . . . . . . . . . . . . . . . . . 474.2.2 Initial production modeling of Hoffell HF-1 . . . . . . . . . . . . 48

4.3 MFrac model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 524.3.1 MFrac governing equations . . . . . . . . . . . . . . . . . . . . 53

4.3.1.1 Mass conservation . . . . . . . . . . . . . . . . . . . . 534.3.1.2 Mass continuity . . . . . . . . . . . . . . . . . . . . . 544.3.1.3 Momentum conservation . . . . . . . . . . . . . . . . 544.3.1.4 Width-opening pressure elasticity condition . . . . . . 554.3.1.5 Fracture propagation criteria . . . . . . . . . . . . . . 55

4.3.2 MFrac solution methodology . . . . . . . . . . . . . . . . . . . . 554.3.3 Stimulation set-up . . . . . . . . . . . . . . . . . . . . . . . . . 564.3.4 Governing model parameters . . . . . . . . . . . . . . . . . . . . 564.3.5 Wellbore hydraulics . . . . . . . . . . . . . . . . . . . . . . . . 584.3.6 Rock properties . . . . . . . . . . . . . . . . . . . . . . . . . . . 604.3.7 Zones data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

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4.3.8 Treatment schedule . . . . . . . . . . . . . . . . . . . . . . . . . 624.3.9 Fluid loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 634.3.10 Proppant criteria . . . . . . . . . . . . . . . . . . . . . . . . . . 634.3.11 Heat transfer . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64

4.4 MProd model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 654.4.1 MProd governing equations . . . . . . . . . . . . . . . . . . . . 65

4.4.1.1 Dimensionless parameters . . . . . . . . . . . . . . . . 664.4.1.2 Pseudopressure . . . . . . . . . . . . . . . . . . . . . 674.4.1.3 Trilinear solution . . . . . . . . . . . . . . . . . . . . 684.4.1.4 Pseudosteady-state pressure and resistivity solutions . . 684.4.1.5 Wellbore choked skin effect . . . . . . . . . . . . . . . 694.4.1.6 Pseudo-radial flow solution . . . . . . . . . . . . . . . 694.4.1.7 Productivity increase . . . . . . . . . . . . . . . . . . 704.4.1.8 Desuperposition . . . . . . . . . . . . . . . . . . . . . 70

4.4.2 Stimulation set-up . . . . . . . . . . . . . . . . . . . . . . . . . 714.4.3 Formation data . . . . . . . . . . . . . . . . . . . . . . . . . . . 714.4.4 Single case fracture characteristics . . . . . . . . . . . . . . . . . 724.4.5 Well data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73

5 Results 755.1 MFrac . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75

5.1.1 Fracture propagation solution . . . . . . . . . . . . . . . . . . . 755.1.2 Proppant design summary . . . . . . . . . . . . . . . . . . . . . 785.1.3 Total fluid loss and leakoff rate output . . . . . . . . . . . . . . . 795.1.4 Heat transfer solution . . . . . . . . . . . . . . . . . . . . . . . . 81

5.2 MProd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 825.3 Lumpfit parameter model . . . . . . . . . . . . . . . . . . . . . . . . . . 84

6 Summary 896.1 Discussion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 896.2 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 916.3 Future work . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 926.4 Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93

A Open hole packer 109

B Thermal Stimulation in Iceland 111

C EGS Applications 121

x

D Fluid and proppant type properties 135

E MFrac report 137

F MProd report 139

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List of Figures

1 Fracture propagation as a result of Hydraulic Proppant Fracturing [14] . . 112 Fracture propagation as a result of Water Fracturing [14] . . . . . . . . . 113 Schematic illustration of the setup for air-lift pumping [19] . . . . . . . . 164 Diagram for design of air-lift pumping, based on water well experience [26] 175 Schematic picture of injection via a packer [22] . . . . . . . . . . . . . . 18

6 Results of production testing of well SN-12, where symbols show ob-served data one hour into each step and lines show calculated output char-acteristics [41] . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

7 Stimulation methods applied to EGS projects worldwide as of 2013 [56]. . 408 Rock type and well depth of EGS projects worldwide as of 2013 [56]. . . 40

9 Locations of geothermal areas in Iceland based on reservoir temperatureand geology [19]. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

10 Map showing the location of the Hoffell case study area [63]. . . . . . . . 4511 Location of well HF-1 and some exploration wells [64]. . . . . . . . . . . 4612 A general lumped parameter model used to simulate water level or pres-

sure changes in a geothermal system. The three tank scenario is shownhere [70]. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

13 Monitored and calculated water level of Well HF-1 from April 9, 2013to September 8, 2013 of the long-term production test. Calculated valuesare those of the LPM, where the left shows the two-tank closed model andthe right shows the two-tank open model. Time t = 0 corresponds to April9, 2013 [61]. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

14 Monitored and calculated water level of Well HF-1 from May 9, 2013 toMay 8, 2014 of the long-term production test. Calculated values are thoseof the LPM, where the left shows the two-tank closed model and the rightshows the two-tank open model. Time t = 0 corresponds to May 9, 2013. . 50

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15 Long-term production test for a one year period of well HF-1. Time t = 0corresponds to May 9, 2013. . . . . . . . . . . . . . . . . . . . . . . . . 50

16 Predicted water levels in well HF-1 for the next 10 years for differentproduction rates using the five month period long-term production testdata. Conservative predictions using two-tank closed model are on theleft. Optimistic predictions using two-tank open model are on the right [61]. 51

17 Predicted water levels in well HF-1 for the next 10 years for differentproduction rates using the year-long period of long-term production testdata. The optimistic two-tank open model is shown. . . . . . . . . . . . . 51

18 MFrac Pipe Friction Empirical Correlations [72]. . . . . . . . . . . . . . 5719 Wellbore cross section for Hoffell well HF-1. . . . . . . . . . . . . . . . 6020 Velocity of cuttings in mm/s [58]. . . . . . . . . . . . . . . . . . . . . . 62

21 Upper and lower fracture zone height when stimulated below the packer. . 7622 Upper and lower fracture zone height when stimulated above the packer. . 7623 Frac width as a function of frac length for stimulation below the packer. . 7724 Frac width as a function of frac length for stimulation above the packer. . 7725 Net pressure measured after stimulation below and above the packer. . . . 7826 Frac fluid efficiency after stimulation below and above the packer. . . . . 8127 Leakoff rate after stimulation below and above the packer. . . . . . . . . 8128 Temperature as a function of fracture length after stimulation below and

above the packer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8229 Flow rate of Hoffell well HF-1 before and after stimulation. . . . . . . . . 8430 Measured and calculated water level of a long-term production test after

stimulation of Hoffell well HF-1. . . . . . . . . . . . . . . . . . . . . . 8531 Long-term production test before and after stimulation for a one year pe-

riod of well HF-1. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8532 Predicted water levels in well HF-1 for the next 10 years for different

production rates using the simulated year-long period of production testdata after stimulation. The optimistic two-tank approach is shown. . . . . 87

33 Cross section of Baker Hughes packer 10.375" OD ISP for formation test[19] . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109

34 Pressure, temperature, and injection rates during step-rate test of well KJ-38 [18] . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 114

35 Temperature logs throughout stimulation of well HE-8, where the Novem-ber logs were performed after a 3 month cooling period following drillcompletion [92] . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116

xiii

36 Calculated injectivity index for each cycle of stimulation in well HG-1 asa function of volume of injected fluid into the well [18] . . . . . . . . . . 118

37 Fluid type parameters for WG-11 20 lb/Mgal low viscous gel [72] . . . . 13538 Proppant type parameters for 20/40 mesh Jordan sand [72] . . . . . . . . 136

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xv

List of Tables

1 Improvement ratios in MG-27 [43] . . . . . . . . . . . . . . . . . . . . . 292 Improvement ratios in MG-35 (based on [43]) . . . . . . . . . . . . . . . 303 Well Baca 23 hydraulic stimulation treatment schedule [49]. . . . . . . . 35

4 Predicted water levels in well HF-1 after 10 years production [m] . . . . . 525 Fanning friction factors . . . . . . . . . . . . . . . . . . . . . . . . . . . 576 Casing Dimensions for Hoffell well HF-1 . . . . . . . . . . . . . . . . . 597 Hoffell well HF-1 deviation . . . . . . . . . . . . . . . . . . . . . . . . . 598 Rock properties of Hoffell well HF-1 . . . . . . . . . . . . . . . . . . . . 619 Treatment schedule for Hoffell well HF-1. . . . . . . . . . . . . . . . . . 6210 Pressure dependent fluid loss for well HF-1. . . . . . . . . . . . . . . . . 6311 Proppant criteria for well HF-1. . . . . . . . . . . . . . . . . . . . . . . . 6412 Heat transfer properties for Hoffell geothermal field. . . . . . . . . . . . 6513 Formation data for well HF-1. . . . . . . . . . . . . . . . . . . . . . . . 7114 Well data for Hoffell well HF-1. . . . . . . . . . . . . . . . . . . . . . . 73

15 Fracture propagation solution. Calculated values are at the end of treatment. 7816 Proppant design summary for stimulation below and above the packer. . . 7917 Summary of fluid loss below and above the packer. Calculated values are

at the end of treatment. . . . . . . . . . . . . . . . . . . . . . . . . . . . 8018 MProd single case fracture characteristics dialog box. . . . . . . . . . . . 8319 MProd production solution for Hoffell well HF-1. . . . . . . . . . . . . . 8420 Improvement ratios for well test data after stimulation above the packer. . 8621 Predicted water levels after stimulation in well HF-1 after 10 years pro-

duction based on year-long production data . . . . . . . . . . . . . . . . 87

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List of Abbreviations

BMU The Federal Ministry for the Environment (Bundesmin für Umwelt, Germany)

BHTP Bottom Hole Treating Pressure

CA California

DOE Department of Energy

ECP External Casing Packer

EGS Enhanced Geothermal System

ENEL National Entity for Electricity (Ente nazionale per l’energia elettrica, Italy)

EOJ End of Job

EPDM Ethylene Propylene Diene Monomer

FLA Fluid Loss Additive

GDY Geodynamics Ltd.

GRWSP Geothermal Reservoir and Well Stimulation Program

HDR Hot Dry Rock

HEGF High Energy Gas Fracturing

HF Hybrid Fracturing

HPF Hydraulic Proppant Fracturing

HWR Hot Wet Rock

ID Inside Diameter

IDH Idaho

ISOR Iceland GeoSurvey

LPM Lumped Parameter Modeling

MD Measured Depth

NEDO New Energy and Industrial Technology Development Organization

xviii

NM New Mexico

NV Nevada

OD Outside Diameter

OFEN Federal Office of Energy (Switzerland)

OR Oregon

PRB Permeable Reactive Barriers

RSF Reactant Sand Fracking

TVD Total Vertical Depth

USA United States of America

WF Water Fracturing

WHP Wellhead Pressure

Nomenclature

A Leakoff area (one face of the fracture)

C Total leakoff coefficient

C1 Dimensionless inverse fracture diffusivity

CD Dimensionless wellbore storage coefficient

CDf Dimensionless fracture storage coefficient

CfD Dimensionless fracture conductivity

Ct Total reservoir compressibility

ctf Fracture compressibility

E Young’s modulus

F Reservoir aspect ratio

G(θ) Fluid loss function

H Fracture half-height

Hp Pay zone height

Hw Total wellbore height

h Pay zone height

J Productivity index

k Permeability

xix

k’ Consistency index

kfwf Fracture conductivity

kf Propped fracture permeability

kh Horizontal reservoir permeability

kl Fracture damaged zone permeability

kv Vertical reservoir permeability

L Fracture half-length

lh length of horizontal lateral

n’ Flow behavior index

NaCl Sodium Chloride

Na2CO3 Sodium Carbonate

P Pressure

PwD Dimensionless wellbore pressure

Pwf Bottomhole flowing pressure

pi Initial reservoir pressure

q Injection flow rate

qD Dimensionless flow rate

rw Wellbore radius

rwa Apparent wellbore radius

Rw Dimensionless apparent wellbore radius

S Wellbore skin factor

Sch Chocked fracture skin

Sp Spurt loss coefficient

Sf Fracture skin factor

s Laplace space variable

T Reservoir temperature

t Time

tD Dimensionless Nolte time

tDA Dimensionless time based on drainage area

tDf Dimensionless time based on fracture length

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tDw Dimensionless time based on wellbore radius

Vf Fracture volume

Vl Fluid loss volume (no spurt loss)

Vsp Volume loss by spurt

W Fracture width

W(0,t) Average wellbore fracture width

W(ζ ,t) Fracture width as a function of position

wf Propped fracture width

x Lateral coordinate along the fracture length

xf Propped fracture half-length

y Coordinate perpendicular to the frac face

ys Damaged zone adjacent to fracture

z Vertical coordinate

Greek

αa Leakoff area parameter

αc Leakoff parameter during pumping

αL Length propagation parameter

αp Pressure parameter

αw Width propagation parameter

γf ,Γf Friction coefficients

γw,Γw Width profile coefficients

∆P Net fracturing pressure

η Fracture efficiency

ζ Dimensionless lateral coordinate

θ 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

1

Chapter 1

Introduction

Direct use of geothermal energy is the oldest and most common form of geothermal uti-lization [1]. Traditionally, direct use of geothermal energy has been small scale applica-tions by individuals, but more recent developments involve large scale projects in com-mercial industry. Direct application of geothermal energy involves a wide variety of enduses, such as space heating and cooling, greenhouses, fish farming, and health spas. Flex-ibility in direct application by use of geothermal energy makes a more attractive optionover 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]. Thermalenergy in the earth is distributed between constituent host rock and natural fluids that arecontained in fractures and pores at temperatures above some specified reference temper-ature [2]. In direct use, natural fluid is usually associated with hot water. Sometimeshowever, extraction of hot water presents several challenges due to possible obstructionsin fractures or poor fracture connectivity to the reservoir.

Hydraulic stimulation is one technique to overcome challenges of fluid extraction, whichis similar to the more well-known term of hydraulic fracturing. Hydraulic stimulation isthe 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 perme-ability within the rock mass [3]. Hydraulic fracturing is the process of injecting fluid intoa rock mass at a rate and pressure sufficient to form and propagate new fractures [3]. Forthe purposes of this thesis, the two terms are used interchangeably because applicationspresented later in this thesis, specific to Chapters 2 and 3, possess qualities of both defi-nitions. However, hydraulic stimulation is the more politically correct term to entitle thisthesis, as most theories and applications will be derived from this mechanism. For claritymoving forward, the definition of hydraulic stimulation is used but not for the purpose of

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 ismostly applicable for the case study performed later in this thesis throughout Chapters 4and 5.

Hydraulic stimulation can be performed in several types of geothermal areas, includ-ing low-temperature, high-temperature, and enhanced geothermal systems (EGS). Low-temperature geothermal areas are defined as having reservoir temperatures below 150°C,while high-temperature geothermal areas are defined as having reservoir temperaturesabove 200°C [4]. For the purposes of this thesis, EGS areas are defined as having reservoirtemperatures 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 almostentirely for purposes of hot water production; contrary to high-temperature and EGS fieldsthat are capable of co-producing steam for electricity. Therefore, hydraulic stimulationin low-temperature geothermal areas for direct use is a topic of interest, as there is morepotential to access natural fluids for a better way to create an almost exclusive networkto meet local demand. The knowledge gap lies in predicting the amount of productionpotential 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 hy-draulic stimulation in low temperature geothermal areas. One objective is to research alltypes of hydraulic stimulation methods available in order to see if a particular guidelineis necessary for low-temperature geothermal applications. These methods include air-liftpumping, open-hole packers, and zonal isolation. Furthermore, hydraulic stimulation canbe 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 inorder 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 productionmodel using a combination of MProd and Lumpfit beta. Through modeling an optimalhydraulic stimulation, an evaluation of productivity improvement is performed to compareto the literature review.

Cari Covell 3

The last objective is to assess a potential need for technological developments within thechosen methods. This includes analyses of improving modeling methodology in order torecommend procedures applicable to low-temperature geothermal environments.

1.2 Structure of the thesis

Chapter 2 discusses background information about three major types of stimulation: hy-draulic, thermal, and chemical. Furthermore, hydraulic stimulation is discussed in detailas this is the focus topic of the thesis. Theory of hydraulic stimulation includes severalmechanisms of mechanics, frac fluid treatment, and well testing. Methods of hydraulicstimulation are described in three categories: air-lift pumping, open-hole stimulation witha packer, and zonal isolation. Each method includes a guide for conducting stimula-tion; some of which have multiple options to consider. Lastly, environmental impactsand seismicity are addressed in this chapter. Environmental challenges include the use ofchemicals in the fracking fluid, drilling noise, damage to flora, and changes in thermalmanifestations. Induced seismicity from stimulation practices has been the topic of manystudies throughout Australia and Europe.

Chapter 3 is the literature review for hydraulic stimulation applications. Hydraulic stim-ulation practices originate from the oil and gas industry, where technologies other thanthose described in Chapter 2 are discussed regarding potential use in the geothermal in-dustry. Low temperature geothermal areas that have experienced hydraulic stimulationonly include sites in Iceland, where emphasis is on the Reykir hydrothermal field andSeltjarnarnes well SN-12. The first experiments of hydraulic stimulation in high tempera-ture geothermal areas were in Japan, but open source information is limited on stimulationprograms conducted. Earliest forms of packer and proppant technology in high temper-ature 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 prac-tice of its kind. Other sites included in the literature review are in Italy, Indonesia, andthe Philippines. Enhanced geothermal systems (EGS) are the most common fields forhydraulic stimulation research and application. All EGS sites that have experienced hy-draulic stimulation are reviewed in this chapter of the thesis. In addition to performing aliterature review of hydraulic stimulation applications, a section is dedicated to the reviewof fracture simulation modeling through the use of different types of software.

Chapter 4 describes the methods used for various hydraulic stimulation analyses for a casestudy in the Hoffell low temperature geothermal field of Iceland. Well HF-1 was used to


target a fracture of 1093 m depth, via two scenarios of hydraulic stimulation below andabove a packer. Prior to modeling stimulation, a lumpfit parameter model (LPM) forwell production analysis was used to compare more detailed data obtained over a year-long period to a previous study done over five months of data. After obtaining a basismotivation for stimulation in the well, MFrac software was used to model the effectsof fracture design and treatment analysis. The well was built in the software based oncasing and deviation data, rock properties, and zones of stimulation. Additionally, thetreatment 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 asparameters before simulation. Pressure boundary conditions were also defined from theMFrac 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 improvementratio for the simulated production test. In Lumpfit beta, the improvement ratio was appliedto the original year-long production test data of Hoffell well HF-1 in order to determinethe success, or failure, of the stimulation. Production over a 10 year lifetime was alsoincluded in the analyses of this thesis.

Chapter 6 provides a summary as a means of guided discussion, as well as important con-clusions, means of future work, and author recommendations. The summary describesthe basis for conducting background and literature reviews of hydraulic stimulation, aswell as findings within MFrac, MProd, and Lumpfit beta unique to the case study. Con-clusions about the margin of production improvement with regards to the sensitivity ofeach software is also provided in this chapter. Future work includes the use of other toolswithin MFrac and MProd, as well as additional software within the MFrac suite. Finally,recommendations from the author include studies within Iceland and other geothermalfields around the world.

5

Chapter 2

Background

The stimulation of geothermal reservoirs involves the opening up of existing fractures byinjecting fluid into a rock mass at optimal high pressures, traditionally performed usinghydraulic, thermal, or chemical procedures. Most geothermal stimulations occur as partof well drilling completion programs primarily for three reasons: 1) to get more waterflow out of the well for improved economics, 2) clean out drill cuttings that may havecaused blockage, as well as or alternatively to 3) increase permeability for connectingfractures between wellbores together to the main reservoir. Depending on the objectiveof a particular stimulation operation, different hydraulic stimulation methods are avail-able. Each method has a certain form of design and implementation in the geothermalfield. With stimulation comes environmental impacts, which are usually associated withnegative connotation. However research has shown that several measures can be takento mitigate environmental impacts related to reservoir exploitation. Seismic history isalso discussed in this chapter as microseismic events in Australia and Europe have beenthe subject of many recent studies, where seismic events are analyzed to understand theunderlying mechanisms influenced by stimulation.

2.1 Well stimulation theory

Generally, there are three types of geothermal well stimulation. Hydraulic stimulation isthe 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 ther-mal stimulation, injectivity increases with injection time and with temperature contrastbetween the reservoir and cold injection temperature [6]. Chemical stimulation involvesa mixture of acids that are injected into a well in order to dissolve material clogging the


fracture system of the reservoir, and aims to improve near- well permeability similar tothat of hydraulic stimulation. In addition to the three methods described, other methodssuch as explosives are used in the oil and gas industry and are further explained in the oiland gas applications section 3.1.1.

2.1.1 Hydraulic stimulation

Hydraulic stimulation involves several mechanisms that are contributing factors to sheardeformation due to the injection of fluid into a rock mass. The types of mechanismsdescribed in this thesis are fluid mechanics, solid mechanics, fracture mechanics, andthermal mechanics. The composition of frac fluid also plays an important role in thetype 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 andproductivity improvement ratios within a particular well.

2.1.1.1 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 thefracture. Solid mechanics describes the deformation or opening of the rock because ofthe fluid pressure. Fracture mechanics describes all aspects of the failure and parting thatoccur near the tip of the hydraulic fracture. Thermal mechanics describes the exchangeof heat between the fracturing fluid and the formation. Each case is governed by differentfactors that all play a role in hydraulic stimulation.

2.1.1.1.1 Fluid mechanics Fluid mechanics of a geothermal reservoir play an impor-tant role in well stimulation. Factors that are associated with fluid mechanics in a geother-mal 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 per-cent (from 0 to 100). Porosity is used in many correlations to develop a first estimateof other properties, such as rock strength or permeability, and relies mostly on the spacepresent within particles at the time of deposition [7]. A distinction between total porosity(φtotal) and effective porosity (φeff ) is noted as each governs assumptions for differenttypes of flow. The total porosity is the volume not occupied by solid rock, but part of

Cari Covell 7

the volume is occupied by bounded fluid that cannot move. The effective porosity is thevolume occupied by moveable fluids, and it is the porosity of interest for most oilfieldapplications [7]. A notable exception is the use of φtotal for all reservoir calculationsinvolving transient flow, or flow affected by changes in velocity and pressure [7]. In addi-tion, no open or cased hole log measures porosity directly, but rather a property related toporosity is measured, such as density or resistivity. This is why a combination of porositymeasurements is preferred for estimating φeff [7]. The most exact porosity measurementsare made on cores, should they be available. Density tools are used to measure the elec-tron density of a formation, which is extremely close to its bulk density ρb [8]. If thedensity of the matrix components ρma and that of the pore fluid ρf are known, the totalporosity from density can be found by volume balance:

φD =ρma − ρbρma − ρf

(1)

where ρma is determined from the lithology and ρf 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 nat-ural fractures, the permeability kh parallel to the bedding of the formation is consideredisotropic, or identical in all directions. However when natural fractures are present, khvaries and have a preferred direction. The permeability perpendicular to the bedding kvrelates to the dominant geological nature of the reservoir and is usually only accountedfor in horizontal wells [7]. Relative permeability accounts for more than one fluid type,and is sparsely considered in low temperature geothermal well stimulation [7]. Directmeasurement 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 thereservoir, in order to account for crossflow between zones. After production, its value candiffer significantly from one layer to the next within a formation [7]. Reservoir pressure isobtained by a point measurement from well tests and the gaps between the measurementsare filled by building pressure profiles.

Skin effect is a measure of the damage inflicted to the formation permeability in the vicin-ity of the wellbore. Damage may result from drill cuttings and mud cake from completionprocesses or from the production of formation fluids, and skin effect can therefore varyduring 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-


mation. The injection skin effect is obtained after conducting an injection test, explainedfurther in section 2.1.1.3.

2.1.1.1.2 Solid mechanics Solid mechanics theory is associated with rock stress prop-erties in an active geothermal area. Elastic and failure parameters are used in stress modelsto obtain a stress profile as a function of depth and rock properties. These profiles are im-portant for estimating the stress variation between layers, and consequently the geometryof hydraulically induced fractures [7]. The parameters involved are Young’s modulus,Poisson’s ratio, and the poroelastic coefficient. Young’s modulus (E) defines the elasticrelationship between stress and strain in a material. Poisson’s ratio (ν) is the fraction ofrock expansion in the transverse direction divided by the fraction of rock compressionin the axial direction. The poroelastic stress coefficient (η) controls the value of stresschanges induced by pore pressure changes that result from depletion, injection or fracturefluid loss. All of these values are accounted for when designing well stimulation treat-ments, as they are associated with the rock type constructed in the applicable stimulationmodeling software. Note that in stimulation (or fracturing) practices, seismicity is an ef-fect of rock stress changes, which is discussed further in the Environmental impacts andseismicity section 2.3.

2.1.1.1.3 Fracture mechanics Fracture mechanics are important to analyze when mod-eling a stimulation treatment. Factors that are associated with fracture mechanics includetip effects and fluid losses.

Fracture tip effects are governed by some net pressure in the fracture that controls fracturewidth. Net pressure and fracture height are directly related, and net pressure is dependenton fluid viscosity and pump rate. However in some cases, field observations have shownnet pressure, and presumably fracture width, to be greater than predicted [9]. In suchcases 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 effectsare ignored and is therefore a valid assumption to make when modeling a pre-stimulationtreatment [7].

Fluid loss is a major fracture design variable characterized by a fluid loss coefficient Cand a spurt loss coefficient Sp. The total fluid loss from the fracture (volume loss) iscontrolled by the total fluid loss coefficient C, where the volume lost while a hydraulicfracture treatment is being pumped can be approximated by [10] [11]:

VLp ∼= 6ChLL√tp + 4LhLSp (2)

Cari Covell 9

where

hL = permeable or fluid loss height,

L = fracture penetration length, and

tp = pumping time for a treatment.

The magnitude of C is typically from 0.0005 to 0.05 ft/min1/2 [7]. Spurt loss is theinstantaneous volume loss of fluid per unit area that occurs prior to the development of afilter cake, and occurs only for wall-building fluids [7]. After stimulation, the fluid lossescan be measured through field tests.

2.1.1.1.4 Thermal mechanics The properties of fracturing fluids show some depen-dence on temperature. In a typical fracturing treatment, the fluid is pumped at a temper-ature significantly below the reservoir temperature. As the fluid penetrates farther intothe fracture, heat transfer occurs between the fracturing fluid and the rock, resulting inan increase in fluid temperature. The temperature gradient in the direction perpendicularto the fracture wall is significantly larger than those in other directions, so the tempera-ture gradients in the other directions can be neglected [7]. In addition, heat conductionin the fluid can be ignored because it is small relative to both conduction in the rock andtransport of heat with the moving fluid [7]. These assumptions reduce the heat transferproblem to a 1D problem perpendicular to the fracture wall, with conduction through therock to the fracture face and convection from the rock face into the fluid.

2.1.1.2 Frac fluid treatment

Hydraulic stimulation is usually conducted in two stages of fluid injection [12]. First, thepad stage is where only the hydraulic fracturing fluid, mainly water, is injected into thewell to either clean out drill cuttings or breakdown the geological formation. Second, theslurry 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 typesof 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 produciblehydrocarbons, or hot water in geothermal applications [13].

Hydraulic Proppant Fracturing (HPF) is the most conventional method in use for hy-draulic stimulation [12]. HPF uses highly viscous gel as fracturing fluid, usually in theform of a polymer. A high proppant concentration creates conductive yet relatively short


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 processto allow proppant transport through the fractures. However, HPF is prone to leave gelresidues 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-reducingagents added with a low proppant concentration. The WF method creates long and narrowfractures from the wellbore to the natural fracture network, which is at some distance fromthe main reservoir, as illustrated in Figure 2. The fracture conductivity induced by WFis maintained by the self-propping ability of the reservoir rock. Since WF is dependenton the self-propping ability of the reservoir formation, fracture closure is likely to occurrapidly as a result of pressure solution processes in regions of high stress [12] [14]. Inaddition, the low viscosity of water makes it difficult to effectively transport proppantsinto the newly created hydraulic fractures [12].

Hybrid Fracturing (HF), or "Hybrid Fracs", is a combination of different gels used inthe HPF method and slick water fluids used in the WF method, or otherwise known as across-linked gel proppant. The concept is to utilize the advantages of the HPF and WFmethods in creating the fracture geometry as well as effectively placing the proppant intothe induced fracture. In the HF method, the fractures are considerably longer comparedto HPF and the effective propped fracture length is higher compared to WF [14]. The HFmethod usually inherits the same problems as the parent frac methods [12].

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]


2.1.1.3 Hydraulic well testing

A series of hydraulic tests are performed before, during, and/or after a stimulation treat-ment. 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 comparewell behavior before and after a stimulation, and is typically used as a point of referenceduring stimulation between cycles.

The injection well test is a field test method where fresh water is injected into the wellto raise the water level until a steady height is attained, and the pressure or water levelchange in the well is recorded. When a well is subjected to injection in order to monitorthe pressure response in a reservoir (i.e. pressure transient), it is used to evaluate the prop-erties that govern flow characteristics in the well. These properties include permeability,wellbore skin, storativity, transmissivity, initial pressure, and reservoir boundaries. Per-meability and wellbore skin have been previously described in the Fluid mechanics sec-tion 2.1.1.1.1. The storativity describes pressure movement within the reservoir, and isdefined as:

S = cth (3)

where

S = storativity [m3/Pa·m2],

ct = compressibility of the fluid [Pa−1], and

h = effective reservoir thickness [m].

The transmissivity describes the ability of the reservoir to transmit fluid, which mainlyeffects the pressure gradient between the well and the reservoir, and is defined as:

T =kh

µ(4)

where

T = transmissivity [m3/Pa·s],

k = permeability of the rock [m2],

h = effective reservoir thickness [m], and

µ = dynamic viscosity of the fluid [Pa·s].

Cari Covell 13

During an injection test, the injectivity index is often used as an estimate of the connec-tivity 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 comparableindex is defined, termed productivity index (PI). The productivity index is a measure ofwell potential, or ability to produce, and is defined as the total mass flow rate per unitpressure drawdown, as explained further in the MProd governing equations section ofChapter 4: Methods.

The injectivity index (as well as the productivity index) is a simple relationship, ap-proximately reflecting the capacity of a well, which is useful for determining whethera well is sufficiently open to be a successful producer and for comparison with otherwells [15]. This neglects, however, transient changes and turbulence pressure drop athigh flow-rates.

2.1.2 Thermal stimulation

Thermal stimulation relies on the thermal contraction induced by a significant tempera-ture difference between the cold injection fluid against the hot rock formation (to createnew fractures) and the enhancement of near wellbore permeability. Thermal cracking isattained by alternately injecting cold fluid and allowing the well to heat up the forma-tion as thermal recovery ensues. Cold fluids may include cooling tower condensate, freshwater, seawater, or cold waste brine [12] [16]. Several mechanisms that may enhancereservoir permeability include: 1) the reopening of pre-existing fractures due to thermallyinduced rock contraction, 2) the shearing of pre-existing fractures, 3) the creation of newfractures due to thermally induced stress changes, or 4) the development of secondaryfractures due to the contrast in the thermo-elastic properties of rocks’ mineral compo-nents. Cleaning out of drilling cuttings that clog feed zones can also contribute to theeffective permeability of the well, particularly in the initial cycles.


To date, a standard procedure for conducting thermal stimulation operations has not beenestablished 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 drillingrig is still on site, through an open ended drill pipe left in the well, or at a closed wellheadafter the drill rig is removed [16] [19]. In addition, thermal stimulation pumping pressuresare usually kept relatively low so as to not cause hydraulic stimulation, yet productivityimprovements have been achieved even if the warming stage has been excluded [12]. Forthe purposes of this thesis, thermal stimulation will not be discussed in great detail.

2.1.3 Chemical stimulation

Chemical stimulation, or more commonly known as acid stimulation, began as far back as1895 when hydrochloric acid (HCl) was used to treat oil wells [20]. Despite success withHCl, 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 ChemicalCo. discovered arsenic as a corrosion inhibitor. Acidizing technology has since advancedwith the development of additives, methods, and systems to improve zone coverage duringthe acidizing process [7].

Chemical stimulation in the geothermal industry began in 1977 with the application ofsodium carbonate (Na2CO3) in the Fenton Hill Hot Dry Rock (HDR) project in NewMexico, USA in attempts to reduce flow impedance [21]. Further programs through-out the 1980s in the Geysers geothermal field of California were designed to create newconductive flow paths to the main reservoir. Shortly afterwards, acid stimulation gainedpopularity in places such as Central America, Philippines, and Italy with improvementsin injectivity ranging from 40% to over 300% increase from original values [12].

Throughout the geothermal industry, there are two main methods of acid stimulation thatare in practice today. Matrix acidizing involves acid treatment injected at pressures belowthe formation fracturing pressure and is designed to remove skin or other formations ofdamage that may occur during well operation [20]. Acid fracturing or "fracture acidizing"is designed to stimulate an undamaged formation and is conducted above the formationfracturing pressure [12]. While chemical stimulation treatments are of great value to thegeothermal industry, they are not of direct concern for the purposes of this thesis andtherefore will not be discussed in more detail.

Cari Covell 15

2.2 Types of hydraulic stimulation

The methods of hydraulic stimulation are described in three categories, as applied ongeothermal 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 pre-venting the clogging up of feed zones during drilling, but is not necessarily considereda stimulation operation per se [19]. However air-lift pumping that is followed by wa-ter circulation helps to restore feed zone permeability that was possibly reduced duringdrilling [19]. The water circulation phase could be classified as an open-hole stimula-tion via injection at the wellhead, and is performed in a similar matter. Another methodof stimulation is the isolation of intervals in the borehole through the use of a packer inparticular to an open hole section. After the packer is set, water may be injected eitherbelow the packer, through the drill pipe, or into the annulus above the packer [22]. Byusing a packer for zonal isolation, a larger effective fracture area can be obtained ratherthan one massive stimulation over a long open hole section. The packer method is alsofavorable to reduce the risk of creating larger seismic events [23]. Double packers are alsoconsidered to be a method of hydraulic stimulation, but the method is not discussed in thisthesis. This is because double packers have hardly been used in geothermal stimulationoperations; even though they are potentially more powerful than a single packer due toinjected water being focused within a shorter interval [19]. Lastly, zonal isolation is amethod used to target one fracture at a time within the wellbore. Several other options areavailable to achieve zonal isolation, where each technique must be integrated into drillingand well construction [24].

2.2.1 Air-lift pumping

Air-lift testing aids in maximizing well output and is therefore defined as a valid stimula-tion technique for the basis of this thesis. Typically air-lift testing is done with compressedair or nitrogen gas, although other gases are known to have been used in geothermal ap-plications that work better with natural gas production of the reservoir [25]. During injec-tion, lift gas is compressed to a pressure equal to or greater than reservoir pressure at thedepth 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 beendeveloped for air lifting freshwater wells. The main parameters are the submergence ofthe airline (the coiled tubing) and the air volume and pressure required. The design basis


can be found in the book “Groundwater and Wells” by Driscol [26] and the Australiantraining 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]

Cari Covell 17

Figure 4: Diagram for design of air-lift pumping, based on water well experience [26]

2.2.2 Open-hole with a packer

The procedure to run an open-hole packer stimulation is based on the full Icelandic paperfrom Axelsson et al. [19]. The paper explains the open-hole packer procedure using aBaker Hughes - Baker Oil Tools packer of 10.375" OD SS OH ISP Bridge Plug for a wellof approximately 2,000 m depth. A more detailed cross section of the packer can be seenin 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 oneafter 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.


Figure 5: Schematic picture of injection via a packer [22]

2.2.2.1 Before deploying the packer

The well is first filled to the brim with water in order to measure fluid loss by monitoringthe pump rate. Once a steady pump rate has been determined, hold constant for about 1.5hours and monitor the pressure on the wellhead ("kill line"). A logger is then attachedto the mandrel below the packer, where temperature and pressure data will be measuredin 3 second intervals. For the logger, it is important to keep the well cooled by constantpumping of cold water. The Icelandic report indicates that pumping should not be stoppedfor 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 notcome out of the bleed valve, the packer will need to be completely filled with water. Airshould not enter the packer after this procedure. Pressure tests are then run on all surface

Cari Covell 19

piping from the pumps to the rig floor. Lastly, the packer is connected to the drill pipeand prepared to run into the hole.

2.2.2.2 Installing the packer

As the packer is installed, water injection via the kill line is maintained until the packerreaches approximately 690 m depth inside the production casing. There is no need topump through the drill string until 1000 m depth is reached because formation of thegeothermal field is typically not very hot above this depth. The logger will show depthin meters with respect to the top of the packer, therefore it is necessary to account for thedepth of each joint on the drill pipe in order to measure the true depth. The running speedof the packer is about 30 seconds for every 12.5 m; or the length between each drill pipejoint. Assuming a water level of 150 m depth, the pressure on the drill string should notexceed 15 bar in order to avoid premature inflation of the packer. The pressure on the drillstring should not exceed 40 bar if the hole is assumed to be full of water.

2.2.2.3 Setting the packer

A single-set packer can only be set one time per stimulation treatment interval and there-fore must be pulled out after each test. Multi-set packers with different setting valves arealso available. Typically, the packer is set at the deepest interval first and subsequentlymoved up to shallower intervals. For setting in directional wells, the packer is normallyplaced within a 10 m range of the desired interval for stimulation, where there is slighttension once the setting depth is reached. A chalk mark on the drill pipe is made above therig floor to mark the exact depth setting position and the hook load weight is subsequentlydetermined. The drill pipe connection is then opened to drop the 1.5" ball, where the ballwill reach the shear plug at the falling speed of about 300 meters in 5 minutes. To checkfor any leaks on the surface, the drill string is filled by injecting water slowly until a 15-20bar 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 isreached for the 150 m water level scenario; or 95 bar if filled with water. The pressure ismaintained for approximately 15 minutes to ensure that the packer is fully inflated, thenreleased rapidly in order to get the swift closure of the check valve that maintains theinflation of the packer. Assuming a 12 1/4" diameter hole, a weight of 4.5 tons is appliedto the drill string to check that the packer is firmly anchored in the well.


2.2.2.4 Opening the bottom plug

The opening of the bottom plug allows water to flow through the packer. Pressure is thenincreased to about 107 bar for water depth of 150 m, or 122 bar for the filled hole, in orderto break the shear pin and release the bottom plug and ball. Subsequently, the plug fallsto the bottom of the well. The well is then filled via the kill line at a rate of about 15 L/sto measure the natural fluid loss in the open hole section above the packer.

2.2.2.5 Stimulation

Stimulation begins by slowly increasing the pump rate to reach the capacity of three rigpumps, and is maintained for about 30 minutes. The pressure should remain steady duringthis period. Pumping should then be stopped for 15 minutes after 1.5 hours of continuousinjection to observe the pressure falloff. The intermittent no-pumping time is consideredbeneficial to the stimulation process [23]. In addition, the water supply system and rigmud tank capacity may not be great enough to keep up with the large amount of waterbeing pumped into the well and injection will need to stop to refill the tanks. Informationabout pressure and flow should be hand recorded as backup to the down-hole and onsurface digital data records. The method of increasing pressure and stopping the pumpingprocess in the specified intervals is usually maintained for a period of 12-24 hours.

2.2.2.6 Releasing the packer

The packer is first deflated by a slight clockwise torque applied to the drill string. A 2.25ton weight is placed over the string for about 10 minutes to allow for the rubber to deflatecompletely. The packer should then be free to pull out of the hole. Final steps includecirculating cold water for logger retrieval.

2.2.3 Zonal isolation

The zonal isolation discussion in this thesis will be guided under four categories. A simpleapproach is to use a liner made out of cement or sand that is perforated to distribute fluidacross the reservoir. The addition of an inflatable or swellable packer creates a seal toisolate the desired stimulation interval and is an option available for use in the field. Theplug 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

Cari Covell 21

drilling either multiple holes to intersect individual fractures or drilling a deviation holeto more accurately target the upper fractures of the reservoir.

2.2.3.1 Use of a liner

In order to provide zonal isolation between fracture zones, one option is to run a liner thatis placed with cement. A cement liner is typically used as this option does not disruptdrilling operations during well construction and does not compromise the wellbore shapeand geometry [24]. The liner is initially set above the bottom fracture, perforated toprovide hydraulic access to the reservoir, and then stimulated in open hole [24]. A plug orisolation packer is then set in the liner and another stimulation is performed to target thefracture. To access the next fracture, the plug or isolation packer is pulled and reset abovethe stimulated fracture. The liner is perforated and the fracture is stimulated at the desiredinterval, and the process is repeated until the final interval is reached. Note that experienceproves 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, viablesolutions for extreme high temperatures, lost circulation, CO2 attack, and cement/casingintegrity have been tested for safe geothermal operation [28].

As an addition to the cemented liner, stage cementing collars are optional materials toimplement in stimulation practices. The collars are staged based on previously loggedspacing between the target fracture zones. A wiper plug is pumped to land at the shoe ofthe liner, followed by a dart that lands in the lowermost stage cement collar located abovethe second fracture zone, and an open sleeve is observed after application of pressure fromsurface shifts [24]. The collar displaces the next volume of cement to form an annularseal 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 asthe parameters are sensitive relative to the cement used in particular to high temperaturegeothermal systems [24].

A sanded liner is also an option for zonal isolation, where sand is pumped into the annu-lar space so that the liner is supported [24]. Stimulation is performed in the same manneras a cement liner. However, the sand liner has a number of disadvantages. Given theanticipated nature and scale of the fracture openings, the size of sand particles will notadequately bridge off across the fracture. Effects include some sand being lost in the frac-tures, losses in permeability and injectivity, and an increased risk of stimulating pressuresto areas not in the target zone [24].


2.2.3.2 Use of a liner with inflatable or swellable packers

External Casing Packers (ECPs) are located for zonal isolation between multiple fracturezones. ECPs are a type of packer on the outside of the casing or liner that is inflated withdrilling mud or cement. The packer inflates to conform to the wellbore by forming a sealto the liner and subsequently isolates the zone. The stimulation may then be completedusing several options including: sliding sleeves, plugs and perforating tools, stage collarsabove the ECP, or straddle packer assemblies across the required intervals [24].

Swellable packers are comprised of an elastomer element that swells naturally when ex-posed to the appropriate swelling agent that is either water or oil based fluid [24]. Thepacker is bonded to the outside of the base pipe and is assembled for inclusion in theliner. Once the desired depth is located, the well is displaced to a water based fluid, andthen time is required to allow the packers to swell to ensure a seal against the wellborewall [24]. As a note, the packer is recommended for use when there is good control ofwellbore geometry as swellable elements are limited in the extent of expansion, and as aresult the differential pressure that can be applied is limited [24].

2.2.3.3 Plug and go

In the plug and go method, drilling is first done to the uppermost fracture and stimulationis performed by setting a packer in the production casing. For the isolation phase, twomethods are known to be effective. One option is to install an expandable liner across thefracture zone and tie back to the production casing. A seal is made by either using cementor swellable packers on the outside of the expandable liner [24]. Drilling then continuesto the next fracture zone, where stimulation and placement of a liner is repeated. In thiscase, the liner can be tied back to the pre-existing liner or be simply set across the targetfracture zone [24]. The process is repeated until the entire wellbore section is drilled andstimulated. While this method has been proven to be effective, it may be desirable to limitthe number of well re-entries for operational purposes [24]. Another option for isolationis to install a conventional liner with swellable packers. The elastomer in the packerabsorbs the formation water over a period of time and swells to form a seal between theliner and the wellbore [24]. Currently the technology is being developed to handle hightemperatures of around 300°C [24].

Cari Covell 23

2.2.3.4 Multilateral wellbores and sidetracks

The multilateral wellbore method comes about after the bottom fracture zone has beenstimulated, isolated with a packer, and cased off above that fracture. The depths of theupper fractures measured during the drilling of the pilot hole are used as target locationsfor drilling additional wells laterally. All lateral wells are plugged prior to drilling thenext to ensure isolation for drilling and stimulation purposes [24]. Multilateral wellboresare efficient in accessing each leg separately, but costs add up for each wellbore andthe multilateral technology relies heavily on the ability of elastomer seals to handle hightemperatures [24]. The use of sidetracks is considered another option for better targetingthe upper fracture zones. A down-hole tool with an inclined plane called a whipstockis placed in the wellbore to exit the original hole and to drill a new well to the nextintersected fracture. The fracture is stimulated and isolated, and the process continuesuntil all desired fracture zones have been targeted. The use of sidetracks as an optionfor zonal isolation is also effective, but it relies almost exclusively on the ability to drillsuccessfully to each interval [24].

2.3 Environmental impacts and seismicity

Besides the technical challenges to stimulate fractures along a fault system, there are otherenvironmental challenges to consider. These include the use of chemicals in the frackingfluid, drilling noise, damage to flora, and changes in thermal manifestations. Inducedseismicity has also received much attention after seismic events following hydraulic stim-ulation 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 mayinclude the dropping water level of near surface aquifers. In addition, flow reduction ordry-up of nearby springs and shallow water wells may occur. All these problems can beavoided by reinjecting the cooled liquid via stimulation practices [23]. The chemistryof fracking fluid is also of environmental concern, as acid behavior in a reservoir duringchemical stimulation can cause scaling due to an improper mixture of tracers. Some prop-pants within the injection fluid consist of ceramic or glass beads and could be coated orconstructed using reactive metals, although this is rare in geothermal applications [29]. Toaddress these environmental concerns, there are groundwater treatment solutions that canbe 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].


Noise can be severe and a nuisance to local residents who live close to the geothermalplant, but is countered by proper plant engineering (e.g. avoiding noisy equipment) andby placing noise barriers if necessary [23]. Damage to local flora occurs every time steamor hot geothermal fluids are released on local plants, which happens due to the high tem-perature and salinity of the geothermal fluids, but is usually not a problem when fluids arereinjected [23]. Some changes in thermal manifestations are possible during exploitation,where hot spring and fumarole intensity depend on the pressure drawdown of the reser-voir. Hydrothermal eruptions could also be correlated with exploitation, but only one suchcase in New Zealand has occurred [23].

The most problematic side-effect of enhancing geothermal reservoirs by hydraulic stimu-lation is the potential to generate earthquakes, which may become detrimental for furtherdevelopment of project [23]. During hydraulic stimulation, stress patterns in the rockchange to potentially cause microseismic events, but most events are of very low magni-tude and are short in duration. However some EGS sites have recorded significant seismicevents arising from short-term stimulation operations. In Cooper Basin, Australia, morethan 32,000 seismic events occurred in well Habanero-1 after stimulation via large vol-ume injection of 20,000 m3 of water [30]. The largest seismic event recorded was of a3.7 magnitude. Similarly, the Soultz-sous-Forêts project involved several stimulations thataveraged 23,000 m3 of water injected and thousands of microseismic events were inducedeach time, where the largest event reached 2.9 magnitude [31]. The stimulation programhad 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 haveoccurred in cascades either on a single continuous fracture or nearly synchronously onseveral closely adjacent structures [32]. Due to this, stimulation operations were put onpreliminary halt [23]. The size and frequency of seismic events are therefore primarilycontrolled by the rate and amount of fluid injected, but are also controlled by the orienta-tion of the stress field [30] [33] [34] [35] [36].

25

Chapter 3

Literature review

Stimulation practices originated, and are still in use, in the oil and gas industry and havetranslated to geothermal applications beginning in the early 1970s. When comparing wellstimulation applications between the oil and gas industry and the geothermal industryquantitatively, 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 moststimulations are ones that include specialized experiments for research rather than forcommercial use. The literature review conducted in this chapter will discuss several casesof 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 approximatelyaround the late 1800s-early 1900s [25]. This section will focus on hydraulic stimulationapplications because more commercial work has been performed in the oil and gas indus-try that has translated well to the geothermal industry regarding experiences and lessonslearned. Thermal and chemical stimulation are still relatively new in the geothermal in-dustry 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 stimulationsince the late 1970s.


3.1.1 Oil and gas industry

Stimulation techniques to improve well permeability have been in practice within theoil and gas industry since the late 1800s. Examples of stimulation techniques includecasing perforation, explosive propellant solution, acoustic stimulation, and electric stim-ulation. Casing perforation is designed to access cased-off permeable horizons in pro-duction wells that still have high commercial temperatures and pressures, and is one ofthe most common methods used in the oil and gas industry [37]. Horizons are typicallyfound at the shallow depths of the reservoir, where further evaluation is performed basedon drilling circulation losses, geology, and petrology of the formation prior to the con-duct of a perforation operation [12]. High energy gas fracturing (HEGF), or explosivestimulation, creates a breakdown of the formation and at the same time improves cleanup of the perforations [38]. High gas waves generated from the vaporizing propellant(termed deflagration) crushes the formation damage to create small fractures near the per-foration channel. When pressure disperses, the gas creates a flooding effect and carriesback the fine particles from the formation. Acoustic stimulation uses a simple ultrasonicwave source between the acoustic field and the saturated porous rock. In geothermalapplications, this interaction changes permeability or removes plugging materials in theformation [12]. Electric stimulation uses electric current either through electrothermal orelectrodynamic type effects. Electrothermal effect is evident in the near wellbore zoneduring heating with infared or high frequency microwaves, while electrodynamic effectcreates a cleaning of the bottom hole formation zone from clay particles restoring or im-proving the well permeability [39]. While some of these techniques have translated to thegeothermal industry, most of these techniques are in the novel stages of development andrequire more research before being tested on a wider scale [12].

3.1.2 Low temperature geothermal areas

Hydraulic stimulation by use of open-hole packers and large flow of water has had successin low temperature geothermal areas, specifically in Iceland starting in the early 1970s.The Reykir hydrothermal system was an ambitious stimulation program, when each ofthe 39 wells drilled during redevelopment of the field were stimulated after drilling. Selt-jarnarnes well SN-12 was drilled in 1994 after five previously drilled wells were usedfor exploration [40]. The decision to stimulate the well resulted from a measured flowyielding almost no production after drilling [41]. Each field and their corresponding stim-ulation programs are discussed in more detail in the subsequent sections.

Cari Covell 27

Other low-temperature geothermal fields that have experienced well stimulation in Ice-land include Hlídardalur and surrounding fields in SW-Iceland, Laugarland and Leirá inN-Iceland, and Urridavatn in E-Iceland. Information is limited on these subjects, butreported findings are discussed in section 3.1.2.3.

3.1.2.1 Reykir hydrothermal system

The Reykir hydrothermal system has been exploited since 1944 for space heating of Reyk-javik, Iceland. Prior to 1970, production amounted to 300 l/s at 86°C by free flow from69 wells [42]. In the early 1970’s, the Reykir field was redeveloped with the addition of39 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 circulationmaterials. 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 to100 l/s for each well due to the resistance of the producing horizons. Pressure increases atthe feed zones ranged from a few bars up to as high as 150 bars at the lowest permeabilityfeed zones treated [42] [4]. Tomasson [22] and Tomasson and Thorsteinsson [43] describewells MG-25, MG-27, MG-35, and MG-39 in more detail in order to better illustrate thehydraulic stimulation method, discussed in the subsequent sections.

The outcomes described in the following are an average of all wells stimulated. Com-paring the injectivity before the stimulation and after indicated as much as 30-40 foldincrease; so in total more than 1500 l/s was produced. The drastic improvement is mostlyattributed to the reopening of feed-zones clogged by drill cuttings during drilling oper-ation [4]. However, when comparing production over the cumulative loss of circulationduring drilling, the wells showed a three-fold increase in production. This is attributedto increased feed-zone permeability, most likely due to the removal of zeolite and calcitevein deposits and partly to increased permeability of near-well fractures in hydroclasticrocks [4] [43]. Specific results per well are referred to by [42].

3.1.2.1.1 Well MG-25 The well was drilled to a depth of 2025 m with a flow of about3 l/s in 1974. Circulation losses after drilling amounted to Q1 = 2 l/s and total circulationlosses amounted to Q2 = 13 l/s given the static water level at 20 m [22]. The first packersetting was at 758 m depth in dolerite intrusions with the biggest aquifer above the packerand 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


ideal location for stimulation in typical Icelandic geological environments. One run wasdone below the packer from 758-2025 m depth, and two runs were done above the packerfrom 204-758 m depth. The first run had pressure increasing step-wise, while the tworuns above the packer at different injection rates had constant pressure of 20 kg/cm2 andno pressure fall off [22].

After a short break, the first interval of 758-2025 m was run three more times at constantinjection rates of 37-38 l/s. A new packer setting at 552 m depth was then implementedwith injection below the packer to the bottom of the drillhole in two runs at constantinjection of 45-46 l/s. Both intervals experienced a drop in pressure, and gradually thepressure 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 40m drawdown [22]. The results show a 14 fold increase compared to fluid losses afterdrilling, and a 2.2 fold increase including fluid losses during during. This shows a greatimprovement in production and proves that drilling deeper drillholes can be beneficial forgood producing horizons within the geothermal system [22].

3.1.2.1.2 Well MG-27 In September 1974, well MG-27 was air-lift pumped with com-pressed air for 12 hours with an estimated yield of 15 l/s. An injection test was runthereafter where total circulation losses were computed. These values were then used tocalculate 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 wasinjected above and below the packer and multiple injection tests were made after eachsetting. The coefficient of turbulent loss C was calculated for each setting, which is afactor associated with natural fluid loss in the well due to turbulence [43]. Subsequentlythe improvement ratios were tabulated using values of C1 and C2; coefficients of turbulentlosses during and after drilling. The tabulations are presented in Table 1, along with thevolumes withdrawn by the compressed air pumping and injections above and below thepacker.

Cari Covell 29

Table 1: Improvement ratios in MG-27 [43]

Depth [m] Volume injected [m3] C I1/21 I1/22

beneath above total [m/(l/s)1/2] [C1/C] [C2/C]

Compr. air 650 0.250 2.16 0.351217 1135 980 2115 0.037 5.62 0.93951 2350 0 2350 0.062 4.34 0.72835 620 2600 3220 0.025 6.84 1.13

The high value of C = 0.062 computed after the 951 m setting is probably due to a tightspot and a partial cave-in at a depth of 270-320 m during the setting [43]. To avoidproblems for subsequent stimulation at 835 m depth, the section was widened and thewell was cleaned to the bottom with a drillbit. The most successful stimulation, in termsof increase in productivity, is at the 835 m depth with a 2.6 fold increase and a 1.06 foldincrease taking into account circulation losses at the end of drilling and during drilling,respectively.

3.1.2.1.3 Well MG-35 In August 1976, well MG-35 was air-lift pumped with com-pressed air at a rate of 50-70 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 coincidewith increases in turbidity; meaning that new and deeper zones of lost circulation arebeing cleaned out.

The packer was then set at a depth of 560 m and water was injected below the packer. Thecoefficient of turbulent well losses after injection was computed as C = 0.022 m/(l/s)1/2

from the initial build-up pressure beneath the packer by the air pumping; because onlyone small loss of circulation occurred above the setting depth [43]. At the end of thestimulation, C had reduced to 0.019 m/(l/s)1/2 (see Table 2).

Two additional packer settings were made at 1153 m and 1359 m where water was injectedabove and beneath the packer. The total losses of circulation at the end of drilling andduring drilling were Q1 = 85 l/s and Q2 = 7 l/s, respectfully. The turbulent well losscoefficients are subsequently C1 = 1.63 m/(l/s)1/2 and C2 = 0.011 m/(l/s)1/2. By using thecoefficient of turbulent well loss values, the improvement ratios were calculated and theend of drilling and during drilling and are presented in Table 2.


Table 2: Improvement ratios in MG-35 (based on [43])

Depth [m]Injection rate [l/s] C I1/21 I1/22

above below [m/(l/s)1/2] [C1/C] [C2/C]

Compr. air50-70

0.022 74.09 0.5560 0.019 85.79 0.581153

6560

0.0015 1896 7.31359 40

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 I1 and I2). Well MG-35 is considered to be one of thebest producing wells after stimulation, however such a large margin of productivity im-provements may be due to other perpetuating factors of the geothermal field that have aneffect on circulation losses.

3.1.2.1.4 Well MG-39 In June 1977, well MG-39 was stimulated by injection abovepackers for two different depths at 1138 m and 1001 m. Injection rates were between83-91 l/s with a known static water level of 93 m, but continuous injection was limiteddue to insufficient water supply. Therefore, injection periods were limited to 15-35 min[43].

At the first setting of 1138 m, pressure fell gradually from 10 kg/cm2 to 0 in two days, butat the 1001 m setting the pressure drop was from 7.5 to 3.0 kg/cm2 in 30 hours [43]. Thetotal loss of circulation was 287 l/s, of which 49% occurred above the first packer settingat 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 includ-ing circulation losses during drilling. After computing all turbulent losses, the increase inproductivity was estimated to be 1.5 fold for the 1138 m packer depth and 1.2 fold for the1001 m packer depth [43]. Hence, there was a 0.3 fold increase from stimulating 137 mdeeper, so there may be a correlation of productivity with stimulation depth.

3.1.2.2 Seltjarnarnes well SN-12

The Seltjarnarnes geothermal field has been exploited for hot water since 1970 to serve thetown of Seltjarnarnes in SW-Iceland. Seltjarnarnes is a typical low temperature geother-mal field with reservoir temperatures ranging from 80 to over 140°C at 2700 m depth [44].

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-zoneswithin a well, has increased with time but no scaling has yet to occur. Although, calciumcarbonate is now at a level where scaling is known to have occurred in other geothermalareas of Iceland [41].

Well SN-12 was drilled to a depth of 2714 m in the fall of 1994 and appeared to be almostnon-productive after drilling; yielding flow less than 1.5 l/s with a 150 m draw down aftera one hour air-lift pumping test. Therefore, it was decided to stimulate the well with apacker in two phases over a ten day period [41]. Prior to stimulation, the average yearlyproduction of the Seltjarnarnes geothermal field was around 30 l/s since 1991 [41].

3.1.2.2.1 High-pressure wellhead injection The first stimulation phase involved high-pressure 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 dur-ing 30 min breaks. At the end of the twelve hour pumping period, the wellhead pressuredropped suddenly from 76 bars to about 18 bars, indicating that the well had in fact beenstimulated.

The wellhead injection continued for 12 hours and additional pressure drops were ob-served. At about 8 a.m. the pressure dropped suddenly by about 18 bars and at about 10a.m. the wellhead pressure was down to 23 bars [41]. This indicated that the well hadbeen stimulated even further, but the pressure started to increase towards the end of theinjection 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 equalT = 6.3×10−8 m3/Pa·s, and the storage coefficient to be S = 3.5×10−9 m3/Pa , whichcorrespond to a permeability of 15 mD [41]. The transmissivity may be compared toolder estimates which are in the range of 3.2×10−8 m3/Pa·s to 40×10−8 m3/Pa·s [44].The storage coefficient is small, indicating that permeability is limited to a thin fracture-zone, perhaps on the order of 50 - 100 m [41].

3.1.2.2.2 High-pressure injection below packer The second stimulation phase in-volved high-pressure injection below a packer at 1412 m depth, in order to stimulate thelower 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, andborehole lithology, which indicate the existence of feed-zones.


Similar to the first stimulation phase, 58-59 l/s were injected below the packer duringfour one hour intervals, each followed by a 20 min break. Accounting for pressure lossin the drill string, the pressure below the packer decreased gradually from 85 bars at thebeginning down to 40 bars. Therefore, it is believed that the stimulation was due to theremoval of drill cuttings clogging feed-zones [41].

3.1.2.2.3 Production testing Several production tests were performed throughout thestimulation program. A step-rate injection test was performed on the 13th of October1994 after the first phase of stimulation, and an air-lift test was performed after the secondphase of stimulation from the 18th-19th of October 1994 (see Figure 6). In addition, anair-lift test was performed at the end of drilling on the 20th of October 1994. The air-lifttest after the second stimulation was done in four steps with flow rate varying from 12 l/sto almost 30 l/s [41]. As seen in Figure 6, the pressure drawdown varied from about 1.5bars 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 dataone 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 witha draw down of roughly 60 m, and the stimulation had increased the yield of the wellby a factor of 60. Thus well SN-12, which appeared to be almost non-productive at thecompletion of drilling, had turned into a good production well [4].

Cari Covell 33

3.1.2.3 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 muchflow for a typical low-temperature geothermal well, the increase in temperature showsthat the well was enhanced and was sufficient for the boarding school, swimming pooland adjacent buildings.

Good results were achieved in three other drillholes ranging from 1097-1733 m depth,located in Selfoss, Midsandur, and Thoroddstadir, SW-Iceland [43]. However at Litla-land near Hlídardalur, a 2187 m deep well collapsed after a packer set at 576 m depthexperienced pressures of 70-80 kg/cm2 below the packer [43].

In Laugarland, N-Iceland, there were no improvements detected in stimulation of wellsLJ-6 and LJ-8 because pressures as high as 130-150 kg/cm2 were experienced due tomultiple collapses of the drillhole at depths below 940 m [43] [45]. Flows were less than1 l/s and came mostly from shallow veins around 250 m depth, even after injection at ratesbetween 30-35 l/s [45].

Some improvements were seen in Tertiary rock, such as in Leirá (SW-Iceland) in the up-permost 500 m section of a 2019 m well, and in Siglufjördur (N-Iceland) the productivityof a 1100 m deep well increased about 50% after several packer settings [43]. Whileimprovements were shown in these areas, the margin of success seems small comparedto the time spent stimulating the well at multiple packer depths, therefore drillhole geol-ogy and the effects of fluid losses may be underlying mechanisms that directly influenceproduction output.

At Urridavatn only small improvements were seen below 250 m while 2-3 fold improve-ments were seen between 172-250 m [43]. The results from Urridavatn show high sensi-tivity regarding the interval at which stimulation succeeds; which questions the specificgeological environment required for stimulation location.

3.1.3 High temperature geothermal areas

The first hydraulic stimulation experiments in high temperature geothermal areas wereperformed from 1978-1983 at the Nigorikawa and Kakkonda geothermal fields in Japan,but detailed information on the stimulation programs is not available at this time [46]. The


earliest form of packer and proppant technology in high temperature geothermal areas waswhen the Department of Energy (DOE) implemented a stimulation program in the UnitedStates throughout the early 1980s. Around the same time, hydraulic stimulation throughwellhead injection occurred in Italy as part of a different stimulation program set up by theNational Entity for Electricity (ENEL). Due to the other thermal and chemical stimulationresearch occurring throughout these programs, as well as other EGS programs occurringsimultaneously, one could say there was a gap in time of no hydraulic stimulation in hightemperature geothermal areas, at least according to the definitions of high temperature andEGS fields previously discussed in the introduction of this thesis. Hydraulic stimulationvia wellhead injection then resumed in the late 2000s with the Salak field of Indonesia andthe Mt. Apo area of the Philippines in order to increase the permeability of these regions.From 2012-2013, the Salak field did a zonal isolation experiment in order to prove theviability of such a stimulation experiment [47].

However, hydraulic stimulation in high temperature areas can be difficult due to severalfactors of the high temperature nature of geothermal areas effecting the potential for pro-duction improvements. Therefore, stimulation in high temperature geothermal wells ismore 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 areavailable for review. Each case of thermal stimulation in Iceland is discussed further inAppendix B in order to analyze effects based on the unique geology and how these effectsinfluence production outcomes of particular wells.

3.1.3.1 Baca, New Mexico (USA)

Hydraulic stimulation in the Baca geothermal field of New Mexico, USA was done in1981 on wells Baca 23 and Baca 20 as part of the DOE-sponsored Geothermal ReservoirWell Stimulation Program (GRWSP) [48] [49]. The liquid dominated reservoir is com-posed of volcanic tuffs with low permeability and temperatures as high as 500°F (260°C)[49].

3.1.3.1.1 Well Baca 23 The well was originally completed with a cemented liner at3057 feet and open hole to 5700 feet with an interval from 3300 feet to 3500 feet selectedfor hydraulic stimulation. The section was isolated using an experimental high temper-ature Otis packer with ethylene propylene diene monomer (EDPM) elastomer elementsand 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

Cari Covell 35

liner, a new liner was cemented to 3300 feet depth. The lower portion of the hole wassanded back to 3800 feet and plugged with cement to 3531 feet to contain the treatmentin the desired interval. The frac string was to isolate the liner laps in the well from thetreating pressure [49]. For well completion, a pre-perforated liner was installed in thetreatment interval.

The hydraulic fracture treatment schedule is shown in Table 3. Due to the high temper-ature of the geothermal system, special treatment design and materials were required forthe stimulation. From a total of 7641 bbl frac fluid, half was dedicated to wellbore andfracture 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 ProppantStage no. [bbl] [bbl] [lb/gal] [size] Fluid

1 4000 3582 8 - Water with fluid loss additive (FLA)2 500 502 8 - Polymer gel with FLA3 500 502 2 100-mesh Polymer gel with FLA4 500 526 6 - Polymer gel with FLA5 900 905 1 20/40-mesh Polymer gel6 1000 1000 2 20/40-mesh Polymer gel7 600 562 3 20/40-mesh Polymer gel8 58 62 6 - Water

8058 7641

A long term flow test showed a static temperature profile with a low bottom-hole tempera-ture of 401°F (205°C), while a separate temperature survey showed a maximum tempera-ture of 344°F (173°C) [49]. Therefore, two-phase flow was occurring and the temperaturedrop was associated with flashing in the formation [49]. In addition, a productivity testshowed well recovery after each shut-in period followed by a decrease in mass flow andwellhead pressure. This concludes that permeability reduction associated with two-phaseflow effects is most likely occurring due to partial closing of the fracture [49]. Microseis-mics were also monitored where a single fracture 100 m high and 160 m long might havebeen 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 isunsuccessful in producing fluids for power generation [48].


3.1.3.1.2 Well Baca 20 Shortly after the stimulation in well Baca 23, well Baca 20was hydraulically stimulated. The hydraulic stimulation interval in the well was from4880-5120 feet and the total depth of the well is 5827 feet with the packer set at 2412feet [49]. At a temperature of 540°F (282°C), this was the hottest well to be stimulatedin the DOE GRWSP [48]. The eleven stage treatment schedule was also similar to wellBaca 23 with some minor adjustments. The proppant only consisted of sintered bauxitein equal quantities of 16/20-mesh and 12/20-mesh type. To stop leakage into the smallnatural 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 inheight near the bottom of the open interval of the well [49]. There was also a zone around4720 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 theopen interval [49]. Pressure build-up data indicated that a highly conductive fracture witha length of over 100 m was created, but productivity was poor and did not meet the needsfor a commercial well [48].

3.1.3.2 Latera, Italy

The Latera geothermal field is a water dominated hydrothermal system with temperaturesof 210-230°C and was hydraulically and chemically stimulated in late 1983 as part of ageothermal well stimulation program set up by ENEL [50]. Hydraulic stimulation wasperformed 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 threetests involved injection at rates between 45-97 m3/h but results indicated a relatively smallfracture area [50]. Subsequent injection tests with increasing flow rates of 110, 220, and340 m3/h were conducted for short intervals over 1-4 hours, and opened only about halfthe fracture area created by previous injection [50]. Finally a massive injection test at arate of 310 m3/h over 17.5 hours increased the fracture area by a factor of 4 [50]. Themain 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 increasein fracture area [50]. The reason could be due to lack of connection between artificialfractures and the natural fracture network of the geothermal reservoir [46]. Clearly themain fractures in the well had potential to remain open for longer periods of time, butwould have required inconceivable amounts of water to be injected. In addition, the trans-missivity remained low but the skin factor went from positive to negative. No explanationis provided for the discrepancy of the results or whether they were measured after short-

Cari Covell 37

term or long-term tests. Well L6 was stimulated in a similar matter as well L1, but thestimulation continued to require pressures too high for industrial injection rates and theoperation was terminated early [50].

3.1.3.3 Salak, Indonesia

The Salak high temperature geothermal field of Indonesia (240-315°C) has several wellsthat have experienced either hydraulic, thermal, or chemical (acid) stimulation. Onlyhydraulic stimulation is described in order to evaluate successes and failures of particularwells. Hydraulic stimulation was performed from 2007-2009 in wells Awi 18-1 and Awi20-1 as they had low permeability west of the Cianten Caldera production area [51]. Inaddition, one of the first zonal isolation modeling experiments took place from 2012-2013in 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 showeddecreasing wellhead pressure. The observation indicates conductivity improvements ofexisting fractures and/or newly developed fractures around the wellbore [51]. A phaseof reinjection followed using condensate from the power plant. Although not directlyconsidered a hydraulic stimulation, the reinjection had an effect on the 180% increase ininjectivity index of the well. This suggests that not only was permeability improved, buta 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 thesecond injection stimulation period [51]. The decrease in wellhead pressure also corre-sponded to an increase in injectivity index as well Awi 18-1. However a final injectivitytest at the end of stimulation operations showed no improvement in injectivity index. Thisindicated that improvement in injection performance was mostly attributed to the estab-lishment of connectivity between the well and a lower pressure fracture network, ratherthan permeability improvement of existing fractures [51].

For well Awi-3, a conceptual model was built to study the benefits of zonal isolation to im-prove well injectivity, then the actual stimulation was performed to compare results. Thewell 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. Further-more, the main injection casing 13-3/8” was successfully installed in one string, whicheliminated 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 allowthe model to simulate injection at specific zones. The effects of injection were modeledin the lower zone and in the upper zone of the well (details regarding the location of each


zone are unavailable). The stimulation in the lower zone experienced some plugging andtherefore no fracturing happened [47]. However, the upper zone stimulation improvedearly during injection and showed that the isolation method worked as intended [47].Therefore the conceptual model for zonal isolation does not guarantee an improvementin injectivity, as the results are different in the lower and upper zones. During actualstimulation in the upper zone, initial injection capacity was around 150 kph at 500 psiwellhead pressure (WHP). After the stimulation, the well injectivity was tested to be 600kph at 500 psi WHP. This huge improvement shows that large injection plays an impor-tant role in stimulating the reservoir, and has helped to eliminate the necessity of drillinganother injection well [47]. However more work needs to be done to understand the vastdifference between the simulation results of the lower and upper zone.

3.1.3.4 Mt. Apo, Philippines

Mt. Apo and other geothermal fields in the Philippines have experienced both hydraulicand acid stimulation, but only hydraulic stimulation will be discussed in this thesis. Thegeothermal field averages reservoir temperatures greater than 300°C [52].

Hydraulic stimulation occurred in well K6 in November 2012 with the goal to increasewell permeability [53]. At the end of drilling completion, the injectivity and transmis-sivity were low and high positive wellhead pressure was observed in addition to the lowpermeability of the well. River water and power plant condensates were injected contin-uously at 6 BPM and a controlled maximum pressure of 9.0 MPag over a period of oneand a half months[53]. Based on injection flow rate and wellhead pressure monitoring, noindication of permeability enhancement was achieved and no increase in injectivity indexwas 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 well-head pressure was observed directly with increasing pump rates, signifying an enhance-ment of well permeability [54] [55]. This was further supported by observing the changesin temperature gradient, where a decrease in temperature indicated a zone of cold waterinfiltration. The permeable zones noted before hydraulic stimulation were located be-tween 2000-2050 mMD and at the bottom of the well [55]. After hydraulic stimulation,additional permeable zones were found between 950-1000 mMD, 1075-1150 mMD, and1875-1950 mMD [55]. The injectivity index increased from 11.27 L/s-MPag to 14.34L/s-MPag which also infers improvement in permeability [55].

Cari Covell 39

3.1.4 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. Forthe purposes of this thesis, the best definition is from the Bundesmin für Umwelt (BMU- The Federal Ministry for the Environment, Germany). The BMU defines enhancedgeothermal systems as creating or enhancing a heat exchanger in deep and low perme-able rocks of temperatures less than 200°C using stimulation methods [5]. FollowingBMU’s definition, Breede [56] further defines EGS as embracing hot dry rock, deep heatmining, hot wet rock, hot fractured rock, stimulated geothermal systems, and stimulatedhydrothermal systems.

Stimulation methods that have been applied in EGS developments are summarized inFigure 7, which shows that hydraulic stimulation is the most common method indepen-dent of rock type. Due to the relatively few cases where chemical or thermal stimulationtechnologies are applied, the definition of EGS is interpreted as only applying to hydrauli-cally fractured systems [56]. Figure 8 further shows the rock type and well depth of all theworldwide studied EGS projects as of 2013. According to both Figures 7 and 8, all fifteenigneous rock EGS fields have experienced hydraulic stimulation. However with furtherexamination, the Bouillante EGS field of Guadeloupe has experienced thermal cracking;not hydraulic stimulation by definition of this thesis. The five sedimentary fields thathave experienced hydraulic stimulation or have hydraulic stimulation programs plannedare Mauerstetten, St. Gallen, Genesys Hannover, Genesys Horstberg, and Altheim. Thetwo EGS fields of mixed igneous and sedimentary composition that have experiencedhydraulic stimulation are Groß Schönebeck and Paralana. In addition, the metamorphicEGS field Bad Urach and the mixed igneous and metamorphic EGS field Desert Peakhave both experienced hydraulic stimulation. A discrepancy is noted in the metamorphiccategory, where Larderello is stated as a thermal stimulation site. Larderello has actuallyexperienced multiple acid stimulations since the 1980s, some of which are also based onthe injection of water and could be interpreted as hydraulic stimulation [57]. These hy-draulic stimulations are interpreted as being a part of a larger acid stimulation, thereforethe Larderello field will not be discussed in this thesis. The Altheim site in Austria wastoo small of a project to have any significant record of stimulation. Lastly, the Raft Riversite in the United States will also be included in this discussion as preliminary results ofhydraulic stimulation have been available for review as of 2014.

Each EGS field, with substantial literature to review, that has experienced hydraulic stim-ulation as an independent method is discussed based on the specific parameters used eitherin research or commercial applications, as seen in Appendix C. Essentially, each case is


unique and no conclusion is made about specific methods or procedures as suitable op-tions 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].

Cari Covell 41

3.2 History of stimulation fracture modeling

Fracture modeling is important to determine the success (or failure) of a stimulation op-eration and is usually performed before stimulation commences. Two known cases inGermany and Canada are pointed out for fracture modeling using FRACPRO and MShalesoftware. FRACPRO is typically used to address the prediction of pressure response inthe well for planned stimulation treatments and the selection of appropriate equipmentto handle expected wellhead pressures, friction, and near wellbore tortuosity [58]. WellGrSk4/05 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 ofstimulation, the main purpose of FRACPRO was to model a treatment schedule [58]. Inthe Ft. McMurray area of Canada, research was performed with MShale to extract hotwater from natural oil sands. A sensitivity analysis of estimating reservoir properties us-ing prior knowledge about fracture location was done in order to determine the potentialfor an HDR project, and subsequently to determine optimal areas for stimulation [59].Both cases were primarily concerned with modeling the effects of stimulation on fracturegeometry. However, these software do not account for any potential production flow im-provements 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 fracturinglow-permeability reservoirs in order to model the productive fracture length and the di-mensionless fracture conductivity; i.e. the ratio of the ability of the fracture to carry flowdivided by the ability of the formation to feed the fracture [7]. There is a need to de-rive a solution methodology from the oil and gas industry in order to take the effects ofstimulation on fracture geometry and apply them to model production potential. This isthe motivation for modeling in the MFrac suite for direct use purposes using geothermalresources, discussed further in the next chapter.

42

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 initialproduction potential of the well. This was done once before by Shengtao [61], but onlyacross 5 months of data out of a 13 month long production test. The LPM compared thetwo data sets in order to more accurately provide a frame of reference for conducting ahydraulic stimulation model.

After determining that well HF-1 should be stimulated, a fracture model is done in MFracsoftware. This is to see the fracture effects after stimulation using two scenarios; via in-jection below a packer and above a packer. A third scenario of an open-hole was brieflyconsidered, but ultimately rejected as the MFrac software cannot accommodate a stim-ulation interval as the same or similar size of the drillhole. The "frac fluid" used is acombination of a low concentration viscous gel to essentially mimic water, and a largegrain size proppant of sand. The model also includes parameters for the treatment sched-ule, 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 per-formed. This is done by using certain outputs from MFrac as inputs for MProd, alongwith known characteristics of the reservoir where the well is located. The MProd solutionis based on a boundary condition for the pump rate used and net pressure measured afterstimulation. An improvement ratio is then calibrated, where another LPM was modeledfor a 10 year lifetime to see the well production improvement after stimulation.


4.1 Case study: Hoffell well HF-1

Iceland is a geologically young country (< 16 Myrs, [19]) lying on the Mid-AtlanticRidge, 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 abun-dant geothermal resources associated with this activity. A map of the country is presentedin Figure 9, which shows the volcanic zone along the Mid-Atlantic Ridge and subse-quently the geothermal areas classified into high temperature and low temperature areas.By definition, low temperature areas have a reservoir temperature below 150°C and hightemperature areas have a reservoir temperature above 200°C [19]. Stimulation operationsare commonly an integral part of the completion programs of geothermal wells drilled inIceland, and are usually conducted at the end of drilling in order to enhance the output ofthe wells [19] [62].

Figure 9: Locations of geothermal areas in Iceland based on reservoir temperature andgeology [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 about400 km east of Reykjavik, the capital city of Iceland, and is located at 64°42´20´Ń –64°44´20´Ń and 15°04´20´É – 15°06´30´É. Within the region the extinct central vol-cano of Geitafell is found, but was active five million years ago [63]. Geothermal explo-ration in Hoffell began in 1992 with research done on surface geology, magnetic measure-ments, chemical analysis of the water, and geothermal gradient drilling [64]. The results

Cari Covell 45

showed that there is potential of exploitable low temperature geothermal resources, astemperature gradients of up to 186°C/km were observed and chemical composition of thewater indicated a 70-80°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 in2012 there were already 33 boreholes in the area with a cumulative total drilling depth of3,594 meters [66]. The drilling of well HF-1 at Hoffell started in early November 2012and lasted until January 11, 2013. 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 inthe Hoffell geothermal area. Most of the exploration wells were drilled N-S as surfacemanifestations indicated the main fault line to be in this direction. However when wellHF-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 fieldindicated that the main fault line is most likely oriented NE-SW, which may explain thelow flow of well HF-1 [66].


Figure 11: Location of well HF-1 and some exploration wells [64].

After drilling was completed, long term production testing was performed to understandthe reservoir behavior and to estimate its production potential [61]. The test started April9, 2013. Water-level drawdown, production flow rate and temperature were monitoredand recorded continuously. The test concluded 13 months later on May 9, 2014. Datacollected 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 hy-drological properties of a low temperature geothermal reservoir. The observed changes inreservoir pressure (or water level) and the fluid production/injection rates can be matchedusing lumped parameter models, and consequently the fluid and/or energy production po-tential 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 2015. Thesoftware is an update from PyLumpfit, programmed by ISOR in 2014.

Cari Covell 47

4.2.1 LPM solution methodology

The theoretical foundation of lumped parameter modeling is the concept of dividing thegeothermal system into two or more individual data blocks. LPM contrasts other numeri-cal modeling softwares that use a range of 100-106 modeling blocks. Typically one blockrepresents the production zone of a system, while the other blocks represent rechargezones. Within each block the properties are uniform, hence no internal differences ex-ist. While assuming uniform tanks might seem disadvantageous in terms of simulationaccuracy, LPMs actually provide a good result for modeling low temperature geothermalreservoirs [68]. No major drawbacks are seen from assuming uniformity because low tem-perature geothermal reservoirs are considered nearly isothermal and have almost uniformfluid chemistry [67]. Lumped parameter modeling has been proven to quite accuratelysimulate 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 storagecapacity of different parts of the reservoir and the resistors simulate the permeability. Atank in a lumped model has a storage coefficient κ when it responds to a load of liquidmass 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 thepressure difference ∆p. Withdrawal from the production tank will influence all connectedtanks, according to set properties for individual tanks and connectors [69].

Figure 12: A general lumped parameter model used to simulate water level or pressurechanges 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 resistorto an infinitely large imaginary reservoir, which maintains a constant pressure. Whenclosed, lumped models are isolated from any external reservoirs. Actual reservoirs canmost generally be represented and simulated by two- or three-tank closed or open lumpedparameter models [69].


The pressure response ∆p(t) of a single-tank open model for production Q, assuming astep response since time = 0, is given by the following equation [71]:

∆p(t) = −(Q

σ1

)(1− e

σ1tiκ1

)(6)

The pressure response ∆p(t) of a more general open model with N tanks to a moreconstant production Q from time = 0 is given by:

∆p(t) = −N∑j=1

Q

(AjLj

)(1− e−Ljt

)(7)

The pressure response of a general closed model with N tanks is given by:

∆p(t) = −N−1∑j=1

Q

(AjLj

)(1− e−Ljt

)−QBt (8)

Coefficients Aj , Lj and B are functions of the storage coefficients of the tanks (κj) andthe conductance coefficients of resistors (σj) of the model, and can be estimated by theLUMPFIT program which uses an iterative non-linear inversion technique to fit a corre-sponding solution to the observed pressure or water level [69].

4.2.2 Initial production modeling of Hoffell HF-1

While the 13 month production test was being conducted, LPM work by Shengtao (UnitedNations 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 fromthe 13 month production test, but starting one month later from May 9, 2013 as data forthe first month was deemed invalid. Pre-stimulation LPM results are then compared to theShengtao analysis. Data was provided by ISOR with permission to use from RARIK. Thepurpose of performing a pre-stimulation production analysis with the additional produc-tion test data is to foresee a more accurate prediction of the required flow for sustainingproduction over a certain period of time. The required flow calculated in Lumpfit beta willbe 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 atwo-tank open model, were used to simulate the five month production data from wellHF-1. During the 152 day production process, production started with a flow rate of 20

Cari Covell 49

l/s, and was later changed to 15 l/s by August 2, 2013. The water level in the well variedfrom -80 m to -140 m depth (below surface level). An average reservoir temperature of72°C was assumed based on the measured data [61]. The two models were chosen as theyprovided a good fit between the measured and calculated water level in the well, whichcan be seen in Figure 13. In the analysis for this thesis, only the two-tank open modelwas considered, as the two-tank closed model did not provide a good fit of the measuredand calculated water level in the well, as shown in Figure 14. This may be a result of theuncertainty of LPM within the Lumpfit beta software [68]. In addition to the five monthdata, production continued with a change in flow rate to 5 l/s by November 13, 2013, 3 l/sby December 3, 2013, and 1 l/s by April 30, 2014 as seen in Figure 15. The water level inthe well varied from -5 m to -140 m depth (below the surface level). An average reservoirtemperature 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 toSeptember 8, 2013 of the long-term production test. Calculated values are those of theLPM, where the left shows the two-tank closed model and the right shows the two-tankopen model. Time t = 0 corresponds to April 9, 2013 [61].


Figure 14: Monitored and calculated water level of Well HF-1 from May 9, 2013 to May8, 2014 of the long-term production test. Calculated values are those of the LPM, wherethe left shows the two-tank closed model and the right shows the two-tank open model.Time t = 0 corresponds to May 9, 2013.

Figure 15: Long-term production test for a one year period of well HF-1. Time t = 0corresponds to May 9, 2013.

Based on the lumped parameter models established above, future predictions could be cal-culated to estimate the response of the water level (reservoir pressure) to exploitation. Tenyear predictions were calculated to help gain an understanding of the general water levelchanges for different production flow rates [61]. A Monte Carlo simulation performedby Shengtao shows that if the geothermal heating system will be used for 50 years withaverage thermal power of 6.0 MWth, a thermal water flow rate of 28.6 l/s is needed; andif the geothermal heating system will be used for 100 years with a thermal power of 3.0MWth, a thermal water flow rate of 14.3 l/s is needed [61]. The Monte Carlo simulationresults form the basis for the prediction production scenarios; therefore the productionrates were set to 28.6 l/s, 21.4 l/s, 14.3 l/s and 7.15 l/s [61].

Cari Covell 51

As seen in Figure 16, the set of data over the five month period shows that the water levelbehaves quite differently in the two models. Over the next 10 years, the water level ispredicted to decline very sharply in the closed system while in the open system it reachesequilibrium. As seen in Figure 17, the year-long analysis for this thesis also shows theopen system as reaching equilibrium.

Figure 16: Predicted water levels in well HF-1 for the next 10 years for different pro-duction rates using the five month period long-term production test data. Conservativepredictions using two-tank closed model are on the left. Optimistic predictions usingtwo-tank open model are on the right [61].

Figure 17: Predicted water levels in well HF-1 for the next 10 years for different pro-duction rates using the year-long period of long-term production test data. The optimistictwo-tank open model is shown.

As seen in Table 4, the water level behaves quite differently between the closed systemand the open system. With an increasing production rate, the difference between theclosed tank system and the open tank system becomes more obvious [61]. The water levelin a closed system had a greater response to large production rates than that in an open


system. With the pump at a depth of 175 m, Shengtao’s LPM model shows the closed tanksystem requiring a sustained production rate of 6.7 l/s and the open tank system requiringa sustained production rate of 26.8 l/s. The LPM model used in this thesis shows the opentank system requiring a sustained production rate of about 28.6 l/s with the pump at adepth 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 dataProduction flow rate Conservative model Optimistic model Optimistic model

[L/s] (closed system) (open system) (open system)7.15 -187 -6.5 -44

14.3 -421 -81.6 -88

21.45 -639 -140 -132

28.6 -841 -183 -176

A production rate as high as 28.6 l/s would lead to a very great water level decline if thegeothermal system was a closed system; and a rate this large would cause the water levelto drop down to -841 m after 10 years, which is not realistic [61]. However, it is also veryunlikely that the system is completely closed. Furthermore, the difference in productionrate for each of the optimistic approaches is very small (about 2 l/s), so it is shown thatwith more production data the results of the 10 year prediction are relatively the same inthis case. Although the conservative approach was unable to be modeled with the year-long production data, it can be assumed that the production rate would be relatively closeif a better fit were to be made. From these results, the behavior of well HF-1 is most likelyto be between the 15-20 l/s production range. However, to reduce negative influence,reinjection or stimulation will be necessary, especially for large production rates if thesystem turns out to be relatively closed [61]. This is the underlying reason for creating astimulation treatment program for well HF-1.

4.3 MFrac model

MFrac Suite Hydraulic Fracturing Software is a comprehensive design and evaluationsimulator containing a variety of options including three-dimensional fracture geometry,auto design features, and integrated acid fracturing solutions; originally designed for theoil and gas industry. Fully coupled proppant transport and heat transfer routines per-mit use of the program for fracture design, as well as treatment analysis [60]. MFrac is

Cari Covell 53

not a fully 3-D model, but rather is formulated between a pseudo-3D and full 3-D typemodel 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 & deKlerk (GDK) and Perkins & Kern (PKN). MFrac is the calculation engine for real-timeand replay fracture simulation and works in conjunction with the real-time data acquisi-tion and display program MView. The MFrac suite also includes MPwri, MinFrac, MFast,MProd, MNpv, MLite, MWell, MShale, MACQ, and MDBE. For the purposes of thisthesis, only MProd was used as an additional software for analysis to MFrac, discussedfurther in section 4.4. The MFrac suite was obtained from Baker Hughes Incorporatedwith a full academic license, and is programmed by several third parties [72].

4.3.1 MFrac governing equations

The fracture propagation solution is obtained numerically by satisfying mass conserva-tion, continuity, momentum, width-opening pressure elasticity condition, and the frac-ture propagation criteria; where a detailed description of these equations and the solutionmethodology is provided by Meyer et. al [60] [73] [74] [75] [76]. All nomenclature islisted in the preamble of this thesis.

4.3.1.1 Mass conservation

The governing mass conservation equation for an incompressible slurry in a fracture isdefined by: ∫ t

0

q(τ)dτ − Vf (t)− Vl(t)− Vsp(t) = 0 (9)

where

Vl(t) = 2

∫ t

0

∫ A

0

C(A, t)

[t− τ(A)]αcdAdt

Vsp(t) = 2SpA(t)

τ(A) = t[A/A(t)]αa .

The above mass conservation equations are solved numerically in MFrac by elementallydescritizing a fracture grid and then integrating over each element. The above equationsfor performing minifrac analysis (i.e. from a previous fracture) can be simplified for 2-D


type models for fluid loss due to leakoff during and after pumping:

During Pumping

Vl(t) = πC(t)A(t)√tΦ(αaαc)

After Pumping

Vl(θ) = 2C(tp)A(tp)√tpG(αaαc, θ)

where θ = t/tp.

4.3.1.2 Mass continuity

The mass continuity equation in terms of the flow rate per unit length q = vW is:

~∇ · ~q + 2qL +∂W

∂t= 0 (10)

where ~∇·~q = ∂qL/∂x+∂z/∂z and ∂L is the leakoff rate per unit leakoff area (i.e. leakoffvelocity).

4.3.1.3 Momentum conservation

The momentum equation (equation of motion) for steady flow is:

~∇P = −(1/2)fρ~q2/w3 (11)

where

f = 24/Re ; laminar flow,

f = fR(e, ε) ; turbulent flow,

and f is further defined as the Darcy friction factor, Re as the Reynolds number, and ε asthe relative wall roughness.

Cari Covell 55

4.3.1.4 Width-opening pressure elasticity condition

The crack-opening and opening pressure relationship is of the form:

W (x, z, t) = ΓW (x, y, z, t)2(1− v)

GHζ∆P (x, 0, t) (12)

where ΓW is a generalized influence function, Hζ is a characteristic half-height, and ∆P

is the net fracture pressure P − σ.

4.3.1.5 Fracture propagation criteria

The criteria for fracture propagation is based on the concept of a stress intensity factorκI . The fracture will propagate when the stress intensity factor equals the fracture tough-ness κIC or critical stress intensity of the rock (κI = κIC or σI = σIC , whichever isgreater).

4.3.2 MFrac solution methodology

The governing differential equations for fracture propagation are differentiated with re-spect to time and then simplified by the transformations:

αL ≡t

L(t)

dL(t)

dt; αa ≡

t

A(t)

dA(t)

dt

αw ≡t

Ww(t)

dWw(t)

dt; αH ≡

t

Hw(t)

dHw(t)

dt

αP ≡t

∆P (t)

d∆P (t)

dt; αc ≡

t

C(t)

dC(t)

dt

to form a set of equations in terms of the alpha parameters (αζ = t/ζdζ/dt). The lengthpropagation parameter is of the form:

αL =1− (αca + 1/2)(1− η) + αterm

1 + η(1+βH(3+n′ ))

(n′+1)(1−βγ)

(13)

where αζ accounts for the time dependent gamma parameters, non-steady injection ratesand fluid rheology, spurt loss, fracture toughness, etc. The fracture efficiency is givenby η and βH = αH/αL. The geometric factor βγ is equal to unity for the PKN and 3-Dtype fracture models and equal to zero for the GDK model. Additional alpha parameters


for 2-D type fractures are also given by [60]. The previous equation and the formulatedconstitutive relationships control the time dependent length propagation solution:

L(t) = L(tn) (t/tn))αL(t) . (14)

4.3.3 Stimulation set-up

For Hoffell well HF-1, a 3-D fracture simulation model along with a complete proppanttransport and fluid treatment schedule were constructed in MFrac. The goal was to createa stimulation program based on the characteristics of the well and the geothermal areain order to analyze the effects of fracture propagation. The target area was a fracturelocated at 1093 m depth as televiewer logs indicate good cracking and is therefore thebest candidate for stimulation [77]. Therefore, it was decided to place the packer in aconservative interval of 1070 m depth to 1110 m depth; allowing for a 40 m range ofplacement. Injection down the casing will be done through a 12 hour stimulation in orderto show one cycle of a typical stimulation program. Proppant type used was a 20/40 meshJordan sand and fluid type was a low concentration water based gel, where each of theirproperties can be seen further in Appendix D. The idea of creating a water frac (WF) thathas low concentrations of sand and gel will aid in creating a long fracture to intersect themain fault line. Two scenarios are created: 1) injection below a packer and 2) injectionabove a packer.

4.3.4 Governing model parameters

The first step in MFrac is to indicate the type of stimulation desired. This is designatedin three stages: 1)general, 2) fracture, and 3) proppant. General conditions include theassumption of linear reservoir coupling as a one-dimensional analysis, as this option is themost common fluid loss model used for propagating fractures. Subsequently, fluid loss isto remain constant. The treatment design schedule is in auto design in order to optimizeinjection time. Wellbore hydraulics will be tabulated using an empirical model, where thewellbore friction factor is used to determine the energy dissipation (pressure loss) in thewellbore [73]. With this, three distinct types of behavior are possible with the combinedcorrelation used in MFrac, and are summarized in the expressions for the Fanning frictionfactor in Table 5. Through an iterative process, MFrac determines which correlation ismost applicable in determining the friction factor. The criteria are based on the argumentthat 1/

√f will always be greater than the Prandtl-Karman Law (lower bound) and less

Cari Covell 57

than Virk’s maximum drag reduction asymptote (upper bound). Therefore, when the tran-sitional 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(Res√f)− 32.4

Transitional flow [78] 1√f

= Alog(Res√f +B

No Drag Reduction [80] 1√f

= 4log(Res√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 thefracture remains open after treatment. The fracture fluid gradient option is turned on totabulate hydrostatic pressure changes as a function of depth. Default growth of the frac-ture is assumed (i.e. in the positive and negative direction) as this will measure pressuredecline even after/during pump shut down. This tends to happen in stimulation treatmentswhere not enough fluid is available on site and re-filling of tanks is necessary. The frac-ture 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 keepthe fracture open over the interval. Creating a fracture friction model will not be neces-sary as laminar flow normally exists in the fracture. For this case, the classical solutionfor fluid flow is used and the Darcy friction factor is fD = 24/Re [72]. The inclusion


of wall roughness is turned off, as the Darcy friction factor inside the fracture is usedwithout modification. This selection assumes that the fracture surface is a smooth planarfeature without roughness [72]. Tip effects will not be analyzed, as a constant pump ratewas used and it can be assumed that there is no net pressure at the fracture tip (see section2.1.1.1.3 for further information on this theory).

For the proppant dialog box, the proppant ramp (i.e. changes in proppant concentrationas a function of time) is turned off because a uniform proppant concentration will be usedthroughout the stimulation. Perforation erosion will not be considered as the stimulationwill model as close to an open hole as possible. The model will use a conventional (linkproppant) transport methodology because this couples the proppant solution with fracturepropagation and is the optimal solution of proppant transport when using the Auto Designtreatment schedule feature. The proppant settling option will be user specified as the sizeof the particles used is typically much smaller than for oil and gas applications. Fracture-proppant effects control the effect of proppant concentration on frictional pressure lossesin the fracture, and will use an empirical solution. The procedure involves a correctionto the base viscosity to produce a relative viscosity term. Once this is done, the frictionfactor is calculated based on the fracture friction model selected (in this case, the classicalDarcy friction factor solution). The general correlation as a function of proppant voidfraction is:

µr = (1− φ)αµ

whereµr = relative slurry velocity

µr = relative slurry velocity

αµ = exponent coefficient

φ = proppant void or particle volume fraction

4.3.5 Wellbore hydraulics

The wellbore hydraulics are defined to essentially build the well in order to calculate itstotal volume. First, the casing depths and dimensions are set for Hoffell well HF-1 basedon drilling reports as seen in Table 6 [66]. The outside diameter (OD) is specified usingthe MFrac internal database, where the subsequent weight and inside diameter (ID) arecalculated. The lightest weight for each OD was then chosen. Although the wellbore isactually open hole after the production casing of 400 m depth, it is necessary to includethe corresponding depths where additional drilling was performed in order to construct a

Cari Covell 59

complete well in MFrac. Drilling depths to 1404 m and 1608 m were reached using a drillbit. Up to 1404 m depth a drill bit size of 9 7/8" was used, however casings are not madein this dimension and a 9 5/8" was assumed. A drill bit size of 8 5/8" was used for theremaining 202 m to 1608 m depth. The difference in measured length and section lengthare not applicable for this geothermal well, as the study does not account for the use of aliner 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]3.9 3.9 20 94 19.124

23.8 23.8 14 50 13.344

400 400 10.75 45.5 9.95

1404 1404 9.625 29.3 9.063

1608 1608 8.625 20 8.191

Next, the deviation of the well is built in MFrac. The wellbore survey method for deter-mining deviation will use the average angle method, where well path between 2 stationsis along a straight line; and whose length is the measured depth difference between the 2stations 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, theinclination angle was calculated in different iterations as a slope of the line of horizontaldeviation 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 welldeviation 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]580 0.796 579.986

720 2.045 719.943

1080 1.989 1079.72

1200 2.386 1199.63

1280 3.576 1279.52

1380 5.711 1379.20

1600 7.765 1597.68


Figure 19: Wellbore cross section for Hoffell well HF-1.

Bottom-hole treating pressure (BHTP) was specified by MD and 3 entries are allotted inMFrac. This will essentially create an output that measures BHTP from these 3 pointsin the well. The three points chosen were depth of production casing (400 m), depth ofpacker placement (1100 m), and the bottom of the well (1608 m).

Lastly, the total volume of the well is calculated based on wellbore configuration, surfaceline volume, and the wellbore volume reference depth using the governing equations formass 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 parametersare referenced at the well entrance. The wellbore volume reference was entered as MDand TVD is subsequently calculated, but this value has to be above the bottom of thecasing and is therefore defined at approximately 1600 m depth.

4.3.6 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 slightdifferences in the properties of various rock types within the major governing layers ofthe well. The three layers of gravel, dolomite, and intrusive volcanics along with their

Cari Covell 61

governing properties are shown in Table 8. Stress and stress gradient were calculatedbased on internal calculations in MFrac (see [73]). Young’s modulus, poisson’s ratio, andfracture toughness vary in range for different rock types, where typical values can be seenin the Baker Hughes MFrac manual [72]. The critical stress, defined as the minimumcritical stress for the fracture to propagate in the vicinity of a constant stress field, is setto zero via the database option; i.e. only fracture toughness will be considered. Criticalstress may also be thought of as the apparent tensile strength since it is the critical stressthat must be over come for the crack to propagate (in a uniform stress field) [72].

Table 8: Rock properties of Hoffell well HF-1

Zonename

TVD atbottom

MD atbottom

Stressgradient

Stress Young’smodulus

Poisson’sratio

Fracturetoughness

Criticalstress

[m] [m] [psi/ft] [psi] [psi] [psi-in1/2] [psi]Gravel 17.999 18 0.6 35.4322 4.5e+06 0.2 1000 0

Dolomite 1099.71 1100 0.83 2994.6 7e+06 0.13 1000 0

Int.volcanic

1605.6 1608 0.7 3687.41 5e+06 0.25 1000 0

4.3.7 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 30-50 m interval.As the main fracture for well HF-1 is located at 1093 m depth, the packer would beisolated somewhere between 1070-1110 m depth. Therefore, stimulation below the packeris defined within a zone that starts at 1110 m depth and goes to the bottom of the hole at1608 m depth. The zone of stimulation above the packer starts at the end of the productioncasing at 400 m depth and goes to 1070 m depth.

Within the zones module of MFrac, perforation data is necessary to enter as MFrac catersto oil and gas wells. In essence, the number of perforations is set to 2000 at 0.75 in diam-eter in order to mimic an open hole geothermal well. The pay zone (length of stimulationinterval) has an associated permeability for each case below and above the packer. Thepermeability 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 around10−1 darcy [81].


4.3.8 Treatment schedule

The total slurry volume injected was calculated assuming a constant 60 l/s flow for 12hours and a total of 15 tons of proppant. The proppant distribution style was set using themaximum proppant concentration because a constant proppant concentration is assumedthroughout the stimulation, therefore MFrac will design treatments with the last proppedstage at the final proppant concentration specified. This option also creates a treatmentschedule (when in auto design mode) where stages do not screen or bridge out and themaximum proppant concentration in the fracture will not exceed the maximum valuespecified. The proppant settling rate was obtained using Figure 20, assuming 0.8 mmdiameter sphere/grain size [58], at 20°C injection fluid temperature. Table 9 shows eachof 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 UnitSlurry volume 2606 m3

Pump rate 3600 L/min

Initial and incremental proppant concentration 0.571429 lbm/gal

Final proppant concentration 0.571429 lbm/gal

Maximum proppant concentration (at tip) 0.571429 lbm/gal

Proppant settling rate 10 cm/s

Cari Covell 63

4.3.9 Fluid loss

To model fluid loss from the fracture into the reservoir and surrounding layers, additionalinformation characterizing the formation and in-situ diffusivity parameters is necessary.The leakoff coefficient needs to be specified for each rock layer and the Baker HughesMFrac manual provides a range of values for any given formation. Since the Hoffellgeothermal area is dominated by dolomite and intrusive volcanics, a range of 0.001 to0.003 ft/min1/2 is acceptable and a value of 0.002 ft/min1/2 was therefore assumed. Spurtloss 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 calculatedat zones of BHTP measurements located at 400 m, 1100 m, and 1608 m depth via produc-tion test data. Arbitrary leakoff multipliers are assumed for the three zones and graduallydecrease 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 asa function of pressure. This is helpful for modeling leakoff in naturally fractured reser-voirs. While fracturing a naturally fractured formation, the pressure in the fracture mayapproach 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

57.5023 0.75 1

109.971 0.15 1

154.029 0.1 1

4.3.10 Proppant criteria

The minimum number of proppant layers to prevent bridging is the minimum number oflayers in the fracture at which bridging occurs. In MFrac, a bridge-out is assumed to occurif the average fracture width integrated over the fracture height is less than the minimumnumber of proppant layers to prevent bridging. This makes sure that the fracture widthis 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 fracturemeans that anything below this concentration after embedment is included and the fracturewill not be reported as being “propped”. A typical value ranges from 0 to 0.2 lbm/ft2 (1.0


kg/m2) [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 ofzero is used. Finally, closure pressure on the proppant is calculated using the bottomholefluid pressure subtracted from the horizontal stress of the area. The horizontal stressof a geothermal area similar to Hoffell in Iceland was assumed as 500 bar [81]. Thebottomhole 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 todetermine the proppant permeability which is interpolated from the proppant database. Asthe closure pressure (stress) increases, the proppant pack permeability decreases. Table11 further illustrates the required proppant criteria.

Table 11: Proppant criteria for well HF-1.

Property Value UnitMin. number of proppant layers to prevent bridging 2

Min. concentration/area for propped fracture 0.1 [lbm/ft2]

Embedment concentration/area 0 [lbm/ft2]

Closure pressure on proppant 344 bar [psi]

4.3.11 Heat transfer

An analytical heat transfer model is included in MFrac that combines thermal convectionin the fracture, with transient conduction and convection in the reservoir. MFrac predictsthe heat-up of the fracturing fluid within the wellbore and/or the exchange of heat betweenthe fluid and the reservoir during fracture propagation. MFrac couples the heat transfer,fluid flow, and fracture propagation expressions to characterize the time dependent frac-ture temperature profiles.

The fluid inlet is to be at the surface as MFrac will calculate heat transfer in the wellboreand in the fracture using this option. The reservoir lithology must be selected from theMFrac database, and the closest option to the Hoffell field is dolomite, where averageporosity is subsequently applied within the MFrac program. The mean formation temper-ature of the area is 69°C as measured from production test data, and the injection fluidtemperature is assumed to be 20°C. Table 12 further lists heat transfer properties.

Cari Covell 65

Table 12: Heat transfer properties for Hoffell geothermal field.

Property Value UnitFluid 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 de-signed primarily for hydraulic fracturing applications, it can also be used to explore theproduction potential of unfractured reservoirs. MProd has options for Production Simu-lation, History Match Production Simulation, and Fracture Design Optimization. Produc-tion Simulation will be used in this thesis which allows the user to input typical productiondata to simulate well performance for fractured and unfractured wells. The capability tocompare the output (numerical simulated results) with measured data is also provided.MProd is integrated and fully compatible with MFrac to provide full feature optimiza-tion, where the output produced by MFrac can be used by MProd. The numerical resultsof MProd, in turn, can be imported by MNpv to perform economic analyses, but will notbe done in this thesis.

4.4.1 MProd governing equations

The governing equations for simulating production from fractured and unfractured wellsin closed and infinite reservoirs are based on the Baker Hughes manual solution method-ology [72] presented in the following sections. The production solution is obtained nu-merically by satisfying conditions related to pre-defined dimensionless parameters, pseu-dopressure, the trilinear solution, pseudosteady-state pressure and resistivity solutions,wellbore choked skin effect, the pseudo-radial flow solution, productivity increase, anddesuperposition. When appropriate, the solution methodology is also given. All nomen-clature is listed in the preamble of this thesis.


4.4.1.1 Dimensionless parameters

The dimensionless pressure pD for a constant production rate q is defined as:

pD =2πkh

qµ∆p (15)

where k is the formation permeability, h is the formation height, µ is the reservoir viscos-ity, and ∆p = pi − pwf is the differential pressure (the initial reservoir pressure pi minusthe flowing pressure pwf ).

The dimensionless times based on the drainage area A, wellbore radius rw, and fracturehalf-length xf are defined as:

tDA =kt

ctφµA, tD =

kt

ctφµr2w, and tDxf =

kt

ctφµx2f

where φ is the formation porosity and ct is the formation compressibility.

The dimensionless rate qD for a constant flowing pressure pwf is defined as:

qD =µ

2πkh∆p·q(t) (16)

and the flow rate as a function of the dimensionless rate is:

q(t) =2πkh∆p

µ·qD (17)

where ∆p = pi − pwf is the constant drawdown pressure.

The productivity index J is defined as:

J =q

p̄− pwf=

2πkh

µJD (18)

where q is the flow rate, p̄ is the average reservoir pressure, and pwf is the flowing pressure.The dimensionless productivity index JD is defined as:

JD =µ

2πkh·J =

µ

2πkh· q

p̄− pwf(19)

Cari Covell 67

The dimensionless and Laplace parameters used in the production model are:

CfD =kfwfkxf

, CD =C

2πφcthr2w, CDf =

C

2πφcthx2f,

C1 = η/ηf , η = k/(φµct), ηf = kf/(φµct)f ,

sf =π

2

ysxf

(k

ks− 1

),

a =2

CfD, b =

−πCfD

.

The Laplacian operator used in the production models is given by s. The fracture skin isgiven by sf .

4.4.1.2 Pseudopressure

The real gas potential or pseudopressure is defined as:

m(p) = 2

∫ p

pb

p

µ(p)Z(p)dp (20)

where pb is an arbitrary base pressure and Z is the real gas deviation factor. The real gaspseudopressure equation can be simplified for certain pressure ranges. At low pressuresµZ 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 µZproduct is:

m(p) =(p2 − p2b)µZ

or m(pi) =(p2i − p2wf )µiZi

where µi and Zi are initial condition gas properties at pi.

At high pressures (p > 3000 psi), the real gas pseudopressure based on a constant p/(µZ)

product is:

m(p) =2p(p− pb)

µZor m(pi) =

2pi(pi − pwf )µiZi

.

When the fluid type is gas and the Internal PVT correlations are not used, the modelrequires that a table of µ and Z be entered as a function of pressure. The pseudopressurefunction is then automatically used to calculate the dimensionless pressure.


4.4.1.3 Trilinear solution

The trilinear solution for a finite-conductivity fracture in Laplace space is for [83] [84]:

Constant flow rate

pD(s) =b

s(sbCDf − (ΨtanhΨ), or for

Constant pressure

qD(s) =1

s2pD(s)= −Ψ

sbtanhΨ.

The Ψ parameter used in the above equations is defined by:

Ψ =

√a(s+ s1/2)1/2

1 + (s+ s1/2)1/2Sf+ C1s (21)

This analytical solution is based on transforming the equations above from Laplace spaceto real time using the Stehfest inversion algorithm [85].

4.4.1.4 Pseudosteady-state pressure and resistivity solutions

The pseudosteady-state dimensionless pressure solution in a closed system can be writtenas [86]:

pD = 2πtDA + 1/JD (22)

where the inverse productivity index is given by

1/JD = 1/2ln

(4A

eγCAr′w2

). (23)

The pseudosteady-state resistivity solution for a finite-conductivity fracture in a closedsystem in terms of the inverse productivity index is [87]:

1

JD= ln

(βxe

xexf

)+ f (24)

where the pseudo-skin function f is

f = ln

(π

CfDg(λ)+ ζ∞

). (25)

Cari Covell 69

The pseudosteady-state resistivity equations are solved to generate the production solutionfor a single fracture in a closed rectangular reservoir for all times (i.e., linear, bilinear,trilinear, and pseudosteady-state). These generated fundamental solutions for constantrate and constant pressure boundary conditions are then used to calculate the compositemultiple transverse fracture solution.

4.4.1.5 Wellbore choked skin effect

Mukherjee and Economides [88] identified that the inadequate contact between a verticaltransverse fracture and the horizontal well resulted in a restriction that can be quantifiedby a choked skin effect as given by:

sch =kh

kfwf

[ln

h

2rw− π

2

](26)

in terms of the dimensionless fracture conductivity. This illustrates that as the heightinterval to wellbore radius ratio or height to propped length ratio decreases (i.e., radialto linear flow in the fracture) or the dimensionless fracture conductivity increases, theskin due to convergence becomes smaller. Soliman et al. [89] concluded that a highconductivity tail-in could be incorporated to reduce the additional pressure drop becauseof flow convergence around the wellbore.

4.4.1.6 Pseudo-radial flow solution

The non-dimensional pressure drop at the wellbore, for an unfractured well, is [82]:

pd = −1

2Ei

(− 1

4tDw

)(27)

where the exponential integral E − i is defined as

Ei(−x) = −∫ ∞x

e−µ

µdµ. (28)

This solution is also used for the pseudo-radial solution of the fractured well by matchingthe pseudo-radial and trilinear solutions.


4.4.1.7 Productivity increase

The productivity increase as defined by the ratio of the productivity indices for the frac-tured and unfractured wells as given by [73] below.

4.4.1.7.1 Constant flow rate The instantaneous (current rate) and average (volume)productivity indices are:

Instantaneous

J/J0t = pDw/pDf

Average

J/J0|V =

∫pD0dt/

∫pDfdt

4.4.1.7.2 Constant pressure The instantaneous (rate) and average (volume) produc-tivity indices are:

Instantaneous

J/J0t = qDf/qD0

Average

J/J0|V =

∫qDfdt/

∫qD0dt

where f refers to the fractured well and 0 to the unfractured case. For unfractured reser-voirs the subscript f refers to the well with no skin. When considering a series of con-stant rate or pressure changes, the productivity parameters outlined above are equal to theequivalent values calculated by superposition.

4.4.1.8 Desuperposition

The concept of desuperposition has been illustrated by Gringarten, Ramey and Raghavan[90] for modifying known values of pD to dimensionless pressures describing somewhatdifferent systems. This method is used to calculate the effect of skin and fractures inclosed systems. For closed systems, the dimensionless pressure pd is found from thefollowing relationship:

pd(CD, S) = pD(CD = 0, S = 0)− pD∞(CD = 0, S = 0)− pD∞(CD, S). (29)

Cari Covell 71

In the above equation pD is the dimensionless pressure for a closed system and pD∞ is thedimensionless pressure for an infinite (unbounded) reservoir. The first term on the rightside of the equation is for the closed system with zero skin and zero wellbore storage.Dimensionless pressure pD∞ for a single well in an infinite system with zero skin andwellbore storage is subtracted from this dimensionless pressure term. This dimensionlesspressure pD∞ for a single well in an infinite system with the desired wellbore storage andskin factor is then added.

4.4.2 Stimulation set-up

The goal of MProd is to take the output from MFrac in order to simulate a productiontest performed after two scenarios of stimulation; below and above a packer. The solutionis for the case of a single fracture in an infinite reservoir (i.e. open tank) where theproduction boundary condition is based on the net flowing pressure output of MFrac. Theoriginal production data based on flow rate from HF-1 is then overlayed for comparisonin order to obtain a productivity index.

4.4.3 Formation data

The formation data module provides a location for entering the reservoir properties neededto perform a simulation. The total pay zone height is entered based on the scenario be-ing analyzed, followed by all reservoir properties that were obtained via a Monte Carlosimulation performed by Shengtao [61]. Table 13 shows the input dialog box.

Table 13: Formation data for well HF-1.

Property Value UnitTotal pay zone height 498 (below) or 670 (above) [m]

Equivalent reservoir permeability 5.686 [mD]

Initial reservoir pressure 38.5 [bar]

Total reservoir compressibility 6.665e-08 [1/kPa]

Equivalent reservoir porosity 10 %

Equivalent reservoir viscosity 0.000399 Pa·s


4.4.4 Single case fracture characteristics

A calculated radial option is available for single case fracture characteristics in order tocalculate either the fracture permeability, fracture width, or fracture conductivity. Thisallows flexibility to input two of the variables and have the third calculated, where thecalculated value will then be dimmed. The calculate option may not be available de-pending on the fracture options selected (i.e., if input conductivity or calculate fracturepermeability is selected). In this case, fracture width and average fracture conductivitywere the input, and fracture permeability was subsequently calculated. Effective dimen-sionless conductivity in the pay zone is then calculated from:

CfD =kfwfkL·h

′p

hp(30)

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 ofa fracture approaches the conductivity of the reservoir, which may significantly influencethe early time production behavior of a well [72]. The definition of the inverse fracturediffusivity is:

cf =kφct

kfφfctf(31)

where

k = Equivalent reservoir permeability

kf = Equivalent fracture permeability

ct = Total reservoir compressbility

ctf = Total fracture compressibility

φ = Equivalent reservoir porosity

φf = Equivalent fracture porosity

Cari Covell 73

The calculation results in a small ratio of 10/1100 for permeability and porosity, whilecompressibility remains fairly constant. Therefore, the inverse fracture diffusivity is ofthe order 8e-05. Lastly, the fracture skin factor is assumed to be negligible (zero).

4.4.5 Well data

Production forecasting typically requires a minimum of data describing certain features ofthe well in order to perform a simulation. For MProd, these features include the wellboreradius and the permeability damage due to skin. The well radius defines the contact areabetween the well and the reservoir. The skin damage (well skin) characterizes the addi-tional pressure drop associated with the near wellbore effects. This parameter may havea significant effect on calculating the increase in productivity index. For the purposes ofthis thesis, the skin factor before stimulation was assumed to be 0.67 and after stimula-tion to be small and negative at approximately -0.06 as indicated by Shengtao’s reservoiranalysis [61].

CD =5.16146C

2πcth(rw2)(32)

where

CD = dimensionless wellbore storage

C = wellbore storage coefficient [61]

ct = total reservoir compressibility [61]

h = pay zone height [MFrac]

rw = 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 UnitWellbore radius 0.14 [m]

Wellbore skin factor (base - prefrac) 0.67

Wellbore skin factor (stimulated) -0.06

Wellbore storage factor 1.302

74

75

Chapter 5

Results

This chapter will discuss the results from MFrac and MProd, followed by a Lumpfit pa-rameter model showing production potential after stimulation.

5.1 MFrac

The packer was assumed to be placed between 1070-1110 m depth to be conservativewith a placement interval, with stimulation below the packer from 1110-1608 m depthin the intrusive volcanic region (total interval length 498 m), and stimulation above thepacker from 400-1070 m depth in the dolomite region (total interval length 670 m). Forfull reports see Appendix E. Results from proppant design tabulations indicated no needto continue modeling stimulation below the packer, however all results continue to beanalyzed for further discussion in Chapter 6.

5.1.1 Fracture propagation solution

The fracture propagation solution displays the fracture (frac) length, height, and widthcharacteristics. Fracture length is measured as a half-length, i.e. for one wing of thefracture. The fracture length created after stimulation below the packer (122 m) is signifi-cantly 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. Perme-ability for the intrusive volcanic zone below the packer is defined as 10−4 darcy, which issignificantly less than the permeability for the dolomite zone above the packer defined as


10−1 darcy [81]. Each permeability value is based on geological surveys in other areas ofIceland similar to the Hoffell geothermal field [81].

Frac height is calculated above and below the target fracture zone (i.e. where the packer isisolated between 1070-1110 m depth). When comparing upper frac height and lower fracheight, the one that is greater is the one where injection is dominant, as seen in Figures21 and 22. Lower frac height is greater than upper frac height when injection is below thepacker, and upper frac height is greater than lower frac height when injection is above thepacker.

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 fracwidth decreases as frac length increases. The proportion that governs each value relatedto fracture length, height, and width is unknown; which will be addressed in Chapter 6:Discussion.

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 bypressure loss in the wellbore due to friction. Effects of net frac pressure over time areillustrated in Figure 25. Net frac pressure remains fairly constant at later stages of stim-ulation after about 30 minutes time, but is very low at about 0.5 bar. Net frac pressureincreases with time when stimulation is done above the packer, which seems abnormalupon first glance. However this observation is consistent with pressure measured in theinitial production test of Hoffell HF-1, as pressure is assumed to stabilize when measuredover a longer period of time. The net frac pressure tabulated in MFrac will later be usedas input for MProd, as these calculations represent pressure measured from a productiontest conducted after stimulation.


Figure 25: Net pressure measured after stimulation below and above the packer.

The fracture propagation solution is summarized in Table 15 for stimulation below andabove the packer.

Table 15: Fracture propagation solution. Calculated values are at the end of treatment.

Parameter Value UnitBelow packer Above packer

Length (one wing) 122.04 924.92 [m]

Upper frac height 42.868 140.13 [m]

Lower frac height 637.1 64.037 [m]

Total frac height 679.97 204.17 [m]

Avg. hydraulic frac width 0.75954 0.12945 [in]

Net frac pressure 0.52949 10.604 [bar]

5.1.2 Proppant design summary

The proppant design summary is shown in Table 16. Proppant concentration is presentat the end of job (EOJ) within the fracture after stimulation below the packer, suggestingthat the proppant aided in creating the fracture. A different result is observed regardingproppant concentration in the pay zone as no proppant concentration is present, thereforeno fracture was propped after stimulation. The proppant failed to create any fracturepropagation that would allow for an increase in fluid production, and the stimulation istherefore deemed unsuccessful. This is possibly due to the low concentration of 0.571429

Cari Covell 79

lbm/gal proppant in the slurry solution of 2,606 m3 (693,480 gal), compared to largeamounts of proppant used in oil and gas applications.

Proppant concentration in the fracture and in the pay zone after stimulation above thepacker are present in very small amounts, but parallel the fracture length created andpropped. The corresponding propped height is calculated to be about 17% of the proppedfracture length. The well and pay zone are also propped due to stimulation above thepacker, and width of propagation is accounted for in MProd production analyses describedin the next section of this chapter. Fracture conductivity in the pay zone is observed to bevery low at about 12 mD-ft, foreshadowing indication that stimulation effects on produc-tion output are minor. Dimensionless frac conductivity is displayed via internal calcula-tions in MFrac. The average fracture permeability increased from 10−1 darcy to 86.526darcy, which indicates that stimulation was successful in terms of improving permeabilityof the formation.

Table 16: Proppant design summary for stimulation below and above the packer.


Frac length - created 122.04 924.92 [m]

Frac length - propped 0 92.946 [m]

Propped height (pay zone) avg. 0 16.445 [m]

Propped width (well) - avg. 0 0.13675 [in]

Propped width (pay zone) - avg. 0 0.0016789 [in]

Conc./area (frac) - avg. at EOJ 0.27101 0.040309 [lbm/ft2]

Conc./area (pay zone) - avg. at closure 0 0.0014565 [lbm/ft2]

Frac conductivity (pay zone) - avg. at closure 0 12.106 [mD-ft]

Dimensionless frac conductivity (pay zone) 0 3.9699e-05

Avg. fracture permeability 0 86.526 [darcy]

5.1.3 Total fluid loss and leakoff rate output

A summary of fluid loss volume and fluid efficiency in the fracture, for stimulation belowand above the packer, is shown in Table 17. The total fluid loss corresponds to frac fluidefficiency, where over 18 times more total fluid loss is observed from stimulation abovethe packer than from stimulation below the packer. To better illustrate the cause of thistrend, Figure 26 shows frac fluid efficiency as a function of time. Frac fluid efficiencydue to stimulation below the packer stays relatively constant at 96%, where slightly more


fluid loss occurs at the initial stages of stimulation at about 86% efficiency. Frac fluidefficiency due to stimulation above the packer sees a steeper decline at the initial stagesof stimulation from 82% to 69% efficiency, followed by more gradual fluid losses overthe duration of the stimulation and ending at about 40% efficiency. Changes in frac fluidefficiency from the initial stages to the later stages of stimulation is dependent on therelationship between slurry volume injected and liquid volume injected, as well as therate of fluid leakoff over the 12 hour stimulation.

Liquid volume injected for each case is rather similar as this represents the real volumeinjected into the wellbore during stimulation. Volume loss occurs during the first stage ofstimulation (about 30 minutes long), and acts as a cleaning (or flushing) of the wellboreperiod before actual stimulation occurs. Fluid loss at the initial stages of stimulationbelow the packer are about twice as great as that above the packer, possibly due to moreobstructions in the lower part of the well. Nevertheless, fluid loss at the initial stages ofstimulation is most likely due to cleaning of drill cuttings blocking the well from furtherstimulation.

When stimulation occurs below the packer, frac fluid efficiency increases from initialstages to later stages by about 10%. The trend simply shows that less fluid loss occursduring stimulation than during well cleaning, although this seems to be a rare occurrenceand is unique behavior compared to other geothermal stimulation operations; especiallysince fluid loss over the later stages of stimulation is only about 4% of fluid volumeinjected into the wellbore. This result is unrealistic because no propped fracture wascreated, and therefore the amount of fluid loss should be much higher. When stimulationoccurs above the packer, frac fluid efficiency decreases from initial stages to later stagesby about 30%. The trend is typical for a geothermal well; and the amount of fluid lossseems logical as Hoffell well HF-1 has a history of large fluid loss, as measured fromleakoff tests performed after drilling. These results are consistent and in agreement withthe leakoff rate illustrated in Figure 27.

Table 17: Summary of fluid loss below and above the packer. Calculated values are at theend of treatment.


Slurry volume injected 2606 2606 [m3]

Liquid volume injected 2540.7 2582.2 [m3]

Fluid loss volume 86.542 1551.6 [m3]

Frac fluid efficiency 0.96679 0.4046

Cari Covell 81

Figure 26: Frac fluid efficiency after stimulation below and above the packer.

Figure 27: Leakoff rate after stimulation below and above the packer.

5.1.4 Heat transfer solution

Heat transfer effects were modeled in MFrac in order to analyze injection fluid temper-ature over the 12 hour stimulation. Figure 28 shows measured temperature of the fracfluid as a function of fracture length created after stimulation. In both instances, the fracfluid heats up to reservoir temperature within the first few meters over the length of thefracture.


Figure 28: Temperature as a function of fracture length after stimulation below and abovethe packer.

5.2 MProd

Due to the case of an unsuccessful fracture propagation when stimulating below thepacker, there is no need for further analysis in Mprod and Lumpfit. Numerical tabula-tions for stimulation above the packer are not validated, in terms of magnitude, becausethere is no prior experience in low temperature geothermal reservoir stimulation model-ing to compare results. However graphical trends are justified for moving forward withanalysis in the case of stimulation above the packer, and will therefore be the only casediscussed for the remainder of this chapter.

In MProd single case fracture characteristics must be entered based on results from MFracsimulation, and as such are listed in Table 18 for stimulation above the packer. Perme-ability was calculated by MProd based on inputs of fracture width and average fractureconductivity. Dimensionless conductivity and inverse fracture diffusivity are internallycalculated as described earlier in section 4.4.4 of the Methods chapter. The fracture skinfactor is assumed to be negligible (zero).

Cari Covell 83

Table 18: MProd single case fracture characteristics dialog box.

Parameter Value Unit

Total pay zone height 670 [m]

Effective propped pay zone height 16.445 [m]

Propped fracture length 92.946 [m]

Fracture permeability, kf 1122.22 [mD]

Fracture width, wf 0.12945 [in]

Average fracture conductivity, kfwf 12.106 [mD-ft]

Dimensionless conductivity Cfd 0.00017137

Fracture skin factor 0

Inverse fracture diffusivity 8e-05

The net pressure data (in bar) obtained from MFrac is then used as a boundary conditionfor MProd simulation, while the initial production data of Hoffell well HF-1 is overlayedfor comparison. The simulated flow rate calculated before and after stimulation over thestimulation time of 12 hours is illustrated in Figure 29. Note that MProd has a maximumcapacity of 500 iterations for the overlay production data, therefore the initial set of pro-duction data measured twice a day was cut to only include measurements taken once aday; where the input was flow rate in L/s over time in days. The production test is a long-term test conducted over one year, while the stimulation is a short-term test conductedover 12 hours, therefore the flow rate calculated in MProd before stimulation has beeninterpolated to accommodate the short-term test. Due to this interpolation the flow rate isslightly skewed, but makes little difference regarding outcomes of the final analyses. Ad-ditionally Figure 29 shows the flow rate before stimulation to be fairly constant at 20 L/stowards the end of the 12 hour cycle, which is consistent with measurements from the firststep of the initial production test. Flow rate after stimulation is then improved by someproductivity index. Therefore an assumption is made that upon a long-term productiontest after stimulation, the flow rate will correspond in similar steps.


Figure 29: Flow rate of Hoffell well HF-1 before and after stimulation.

A production ratio in relation to flow rate and to volume is then calculated for each it-eration, where the results are summarized in Table 19 for approximately every 2 hoursiteration (full report in Appendix F). PI based on volume is slightly higher than PI basedon flow rate because the average volume is used as the initial condition. For simplificationof further analyses the average productivity index of 1.096 (from flow rate) was carriedforward.

Table 19: MProd production solution for Hoffell well HF-1.

Time Flow rate pre-stimulation

Flow ratepost-stimulation

Cumulativeprod.

Avg. reservoirpressure

Flowingpressure

Prod. ratioQ/Qbase

Prod. ratioV/Vbase

[d] [L/min] [L/min] [m3] [bar] [bar] [J/Jo(t)] [J/Jo|avg]

0.0023385 1797.2 2033.3 8.5725 38.5 7.4687 1.1314 1.1501

0.041997 1423.2 1572 105.81 38.5 8.2045 1.1045 1.1148

0.083469 1325.3 1457.1 195.8 38.5 8.9667 1.0995 1.1087

0.17211 1240.8 1358.6 374.69 38.5 9.6243 1.0949 1.1031

0.25468 1196.6 1307.3 532.82 38.5 10.001 1.0926 1.1003

0.33728 1166.6 1272.7 686.06 38.5 10.26 1.0909 1.0983

0.41985 1144.4 1247.1 835.75 38.5 10.452 1.0897 1.0969

0.5027 1126.7 1226.8 983.22 38.5 10.604 1.0888 1.0957

5.3 Lumpfit parameter model

Goals for lumpfit parameter modeling are to evaluate changes in injectivity index, stora-tivity, transmissivity, and productivity index after stimulation of Hoffell well HF-1. Afterthe 12 hour stimulation operation was modeled in MProd, the production flow rate im-

Cari Covell 85

provement ratio of 1.096 was used to scale the initial production data of flow rate versuswater level. Previous analyses indicate a two-tank open model to show good fit betweenmeasured and calculated production data before stimulation, however the same may notbe true for production data after stimulation. To test the fit of post-stimulation data, Figure30 compares lumpfit parameter models for a two-tank closed and a two-tank open reser-voir over a hypothetical time frame of one year (365 days) in order to mimic a long-termproduction test. As anticipated the two-tank closed model fit is poor while the two-tankopen model fit is good, therefore the two-tank open model is used in analyses movingforward. Production flow rate is shown in Figure 31, where increases are observed from20 l/s to 22 l/s in the first step to day 86, and from 15 l/s to 16 l/s in the second step to day189. The remainder of the production flow rate data stays relatively constant with onlyminor increases after stimulation. An average reservoir temperature of 69°C was assumedto remain constant before and after stimulation.

Figure 30: Measured and calculated water level of a long-term production test after stim-ulation of Hoffell well HF-1.

Figure 31: Long-term production test before and after stimulation for a one year periodof well HF-1.


Storativity, transmissivity, injectivity index, and productivity index are expressed in Table20 to compare improvement ratios before and after stimulation. Tabulations were madebased on the equations defined in Chapter 2: Background and the assumptions made inChapter 3: Methods. Improvement ratios are based on year-long production data beforestimulation and production data after stimulation above the packer.

Table 20: Improvement ratios for well test data after stimulation above the packer.

Parameter Value Unit Improvementratio

Before stim. five Before stim. year- After stim.months prod. test

data [61]long prod. test data prod. test data

Storativity(S)

5.65E-08 5.10204E-05 5.10204E-05 [m3/Pa·m2] 1

Transmissivity(T)

1.2E-08 4.59E-07 4.78E-07 [m3/Pa·s] 1.041

Injectivityindex (II)

3.479 1.77 1.942 [(L/s)/bar] 1.097

Productivityindex (PI)

0.4084 0.0378 0.0413 [(L/s)/bar] 1.093

Once again, future predictions of production rate could be calculated to estimate the re-sponse of the water level (reservoir pressure) to exploitation. The same scenario of usingten year predictions were calculated to help gain an understanding of the general waterlevel changes for different production flow rates [61]. Production rates were set to thesame four limits based on Monte Carlo simulation of the Hoffell reservoir; 28.6 l/s, 21.4l/s, 14.3 l/s, and 7.15 l/s [61]. Upon further analysis, an additional boundary conditionof 35.15 l/s was used to better measure well output, determined by adding one more in-crement of 7.15 l/s to the previous upper boundary condition of 28.6 l/s; or essentiallymodeling a sustained flow of 35.15 l/s to have about 7.5 MWth reservoir capacity for alifetime of 25 years. As seen in Figure 32, the year-long analysis after stimulation showsthe open system as reaching equilibrium in a similar fashion to the model made beforestimulation seen in Chapter 4: Methods.

Cari Covell 87

Figure 32: Predicted water levels in well HF-1 for the next 10 years for different produc-tion rates using the simulated year-long period of production test data after stimulation.The optimistic two-tank approach is shown.

Changes in water level are observed based on production flow rate from initial analysesmade using five-month production data before stimulation, as well as analyses made usingyear-long production data before stimulation and after stimulation. Results are tabulatedfor comparison in Table 21. With the pump at a depth of 175 m, a sustained productionincrease is seen from 28.6 l/s to 32.4 l/s.

Table 21: Predicted water levels after stimulation in well HF-1 after 10 years productionbased on year-long production data

Production flow rate Optimistic model Optimistic model[L/s] (before stimulation) [m] (after stimulation) [m]

7.15 -44 -38

14.3 -88 -77

21.45 -132 -115

28.6 -176 -153

35.75 N/A -193

88

89

Chapter 6

Summary

This chapter will provide a basis for discussion regarding hydraulic stimulation in lowtemperature geothermal areas for direct use.

6.1 Discussion

District heating and direct use of hot water through renewable energy resources are glob-ally in demand. Optimal methods of extraction are always under development as resourcesecurity is essential over the lifetime of a reservoir. In the past, stimulation in low tem-perature geothermal areas was done as part of drilling completion, especially for wellsshowing little to no productivity. Within low temperature geothermal areas of Iceland,great success has been seen in the Reykir hydrothermal area and in Seltjarnarnes wellSN-12 on the order of 30-60 fold increases in production flow; however little success wasseen in other areas such as Hlidardalur on the order of only 2-3 l/s increase in produc-tion flow. Ultimately, stimulation after drilling completion stopped due to small benefitsseen given the amount of cost, and production was subsequently not adequate for a givendemand. Therefore stimulation has since been translated to other high temperature andenhanced geothermal fields where more production potential has been proven based onpreliminary studies.

The theory of hydraulic stimulation is associated with several methods in regards to usingdifferent types of proppants and fluids. Most geothermal stimulations have been per-formed using the open hole packer method, while few cases have been performed usingzonal isolation. Motivation for the use of stimulation software is based on the need tocompare several types of hydraulic stimulation methods along with testing different com-


binations of proppant concentration and volume of fluid injected. Currently, FRACPROsoftware is associated with modeling fracture geometry after stimulation, but not produc-tion. Other fracture modeling software is available, but in geothermal applications hasmostly been used to analyze seismic effects from stimulation to moderate environmentalimpact. Based on these findings, a solution software was sought through the oil and gasindustry. Research in Canada on the tight sandstone EGS environment for extracting oilhas led to the use of MFrac suite software. MFrac was used to model a hypothetical stim-ulation, and the sub-program MProd was used to model production after stimulation. TheMFrac suite is designed to model hydraulic stimulation based on geological characteris-tics and proppant fluid (frac fluid), while also including solutions for fluid losses due toleakoff and friction. This is in order to create a production flow rate simulation after ahydraulic stimulation operation.

MFrac was then implemented for the case study of Hoffell well HF-1, via open hole stim-ulation using two scenarios below and above a packer. The auto-design treatment sched-ule was used as not enough information is available to conclude best frac fluid designwithin stimulation practices in low temperature geothermal areas in Iceland. In MFrac,additional assumptions were necessary as the software is designed for oil and gas appli-cations; in order to model well HF-1 as accurately as possible. For example, MFrac isdesigned for stimulation via the use of perforations within a liner similar to a zonal iso-lation technique. Geothermal stimulation in Iceland is typically performed using an openhole packer, therefore modifications in the wellbore hydraulics dialog box were neces-sary to take into consideration. Another factor for consideration was the placement of thepacker, and subsequently the intervals of stimulation below and above the packer. No spe-cific guideline within the MFrac software was provided to accommodate a packer, whichis odd as packers are very common in the oil and gas industry.

Upon MFrac simulation, figures showed very long fractures with very short fractureheights. These results were anticipated because of the water frac fluid used, however theproportion seems unrealistic compared to other fracture simulations done using FRACPROin Gross Schonbeck, Germany. One indication regarding this outcome includes perme-ability influence from the rock type assumed. Basaltic areas in Iceland are more perme-able than the tight sands of EGS sites, such as Soultz and Gross Schonbeck in the UpperRhine Grabbon of Europe. However, typical fracture behavior in Iceland after stimula-tion is unknown, especially in low temperature geothermal areas. When propped fracturelength and height were analyzed, MFrac indicated an inconclusive result for stimulationbelow the packer. The reason for no fracture propagation below the packer could be dueto the low concentration of proppant used. The oil and gas industry typically uses largeamounts of proppant in stimulations, therefore MFrac software is most likely not sensitive

Cari Covell 91

enough to a very water based frac fluid. Stimulation intervals are much larger in geother-mal applications than in oil and gas applications, so this could also be an effect from thesensitivity of MFrac. After some test runs, results showed that increasing concentrationwith respect to defining a shorter interval indicated more fracture propagation, but notnecessarily through the entire length of the created fracture.

For MProd, most of the input parameters are accurately assumed for the case study ofHoffell well HF-1. Therefore MProd is considered a reliable simulation software basedon initial reservoir conditions to show what the improvement ratio would be after stim-ulation. However, MProd created interpolations of the long-term production test data toaccommodate for the short-term stimulation, which produces some minor inaccuracies.The desired result of finding an improvement ratio after stimulation was deemed fairlyaccurate for the case of Hoffell well HF-1. The solution methodology used in MProdto create the final flow rate tabulations needs further analysis, discussed further in theconclusions section 6.2.

For lumpfit parameter modeling (LPM), an increase in flow was observed but only forthe optimistic open tank system, therefore the overall improvement factor for well HF-1is hard to determine accurately. A better fit for the closed tank model would indicate theeffects of stimulation. Perhaps from the assumptions made earlier, a 15-20 l/s rate wouldincrease to somewhere around 20-25 l/s, but this increase would most likely be small ofno more than 5 l/s. Therefore well HF-1 is not considered to be a good candidate for stim-ulation, as improvement ratios on the order of 2-3 fold increase have been seen throughoutsome wells in the Reykir hydrothermal field in Iceland. However, the methodology can beapplied to other geothermal areas around the world, since this thesis is the first to initiatestimulation predictions for low temperature geothermal applications.

6.2 Conclusions

Stimulation above the packer was successfully modeled in MFrac and MProd, while stim-ulation below the packer had inconclusive results for the case study of Hoffell well HF-1.However, this does not mean that stimulation above the packer is a better method for useacross other geothermal areas as there are several uncertainties about the case study. Theproductivity improvement was minor with only a 1.096 improvement ratio, therefore thewell is not a good candidate for realistic stimulation operations. In addition, very opti-mistic production flow rates were measured in the open tank geothermal system model,which further indicates that a different candidate well would have been more appropri-


ate for analyses moving forward. Although the production flow is very optimistic, thereis potential for even more flow improvement if fracture propagation were modeled moreaccurately in MFrac. More research is needed to understand the schematic of fracturepropagation in low temperature geothermal areas of Iceland. Nevertheless, the method-ology used in this thesis will be applicable and beneficial to other case studies with moredata and field history.

Sensitivities were observed within MFrac, MProd, and Lumpfit beta software. These in-clude MFrac’s proppant concentration and stimulation interval, MProd’s solution method-ology for matching short-term and long-term production test data, and Lumpfit beta’scorrelation with closed tank geothermal systems using long-term production test data. In-ternal programming work within MFrac, MProd, and Lumpfit beta software is necessaryto account for varying geothermal circumstances. Specific to Lumpfit beta, the software ismeant to be used when there is limited data available, however it was used in this thesis tocompare original models done by Shengtao for the case study of well HF-1 in the Hoffelllow temperature geothermal field [61]. Perhaps a different program capable of predictingreservoir properties using long-term production data would have been more applicable touse moving forward with this case study. Ultimately, this thesis initiates first attempts inmodeling stimulation for direct use; showing there is proof of concept.

6.3 Future work

Several applications for future work specific to MFrac and MProd are available in additionto working on the software for geothermal applications. For MFrac, a treatment schedulecan be created rather than having one auto-designed in order to look at a more realisticstimulation. Also the stimulation can be modeled over a longer period of time of a day ortwo, as some stimulation operations last this long or longer in order to better improve theproduction flow of the well. In addition experiments can be done using different proppanttypes, although sand is common for geothermal applications, but changing the grain sizemight have an effect on fracture propagation. Use for polymers in fluid solutions mayalso be an area of interest for further studies, in particular to polymers that are effectivein scaling mitigation. Within MFrac, more complex scenarios of stimulation throughmultiple rock layers can be done, as well as stimulation of more than one fracture. Thesescenarios mimic a more realistic zonal isolation for purposes of connecting fractures tothe main fault line of a geothermal area.

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For MProd, history matching can be done similarly to lumpfit parameter modeling, wheremeasured and calculated data simulate to look at optimization of production flow. How-ever in order for this to be useful, prior stimulations must have been performed in orderto establish a proper boundary condition. Lastly, fracture optimization is a separate formof MProd that can be looked into further, but this is more for the distant future.

Additional software within the MFrac suite are very useful for modeling effects of stimu-lation. MView is a data handling system and display module for the real-time and replayanalysis of hydraulic fracture treatments, and is used widely for commercial applicationsin the oil and gas industry [72]. When stimulation is underway, field operators can see thefracture creation and propagation trends as they are happening, and can therefore adjustthe pumping schedule and proppant concentration accordingly. In addition, MNpv is aneconomic analysis software, using treatment advantages or disadvantages that can be de-termined by evaluating predicted cash flow and future return on investment [72]. Althoughthere are many factors which influence the results of a design, the principal objective ofany stimulation operation is to maximize well profitability. Typically, this involves carefuleconomic analysis of the costs and potential benefits of individual well operations. Formany, forecasting net present value (NPV) has become an integral part of the preferredmethodology to optimize hydraulic stimulation treatments [72]. The integrated capabilityof MFrac, MProd, and MNpv provides the ability to optimize the potential propped frac-ture length of a design based on the pumping schedule, fracture geometry, treatment cost,and production revenue. The NPV of various fracture lengths can then be calculated anddisplayed as a function of producing time. Hydraulic stimulation optimization is thereforea basic requirement to maximize economic returns on investment. the economics of priceof hot water versus investment can then be compared to other sources of heating, such ascoal, oil, gas, and electricity.

6.4 Recommendations

As much work can be done, the author has recommendations for moving forward withfuture studies. Starting with a focus in Iceland, first would be to conduct fracture mod-eling of a low temperature geothermal area in order to analyze typical characteristics, ifsuch exist. Next would be to identify better candidates for stimulation, starting with ar-eas where reinjection is a more common practice; as some wells within these areas havealready been classified as having poor production. The way to identify a better candi-date for stimulation is to create a lumpfit model using production test data, and properlycomparing assumptions of a closed geothermal system and an open geothermal system;


in order to provide a better foundation for further stimulation analysis. MFrac and MProdare the best software to use at this time when looking at overall production after stimu-lation, but for fracture modeling it is recommended to use FRACPRO as the software ismore accommodating to geothermal conditions. Although Hoffell well HF-1 did not turnout to be a good candidate for a case study, interests lye in how zonal isolation techniqueswould work in this area, as televiewer logs indicated need to connect to the main faultline. However this requires more knowledge on stimulation of multiple fractures throughmultiple layers of rock.

In a broader schematic, the methodology conducted throughout this thesis is recom-mended for applications in high temperature and EGS areas. While fracture modelinghas been the focus of much research, it is equally as important to evaluate productionflow via a hydraulic stimulation model. Preliminary work regarding economic analysesfor stimulation in high temperature and EGS areas is also recommended; which includesgathering information on best types of proppant to use for particular geothermal areas,and current costs of stimulation equipment and frac fluids. The author plans to continueresearch on hydraulic stimulation in low temperature geothermal areas specific to Iceland,while also considering other low temperature geothermal sites throughout Europe and theUnited States, in order to contribute towards exploring renewable solutions for meetingdirect use demand in local communities around the world.

95

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[117] G. Zimmermann and A. Reinicke, “Hydraulic stimulation of a deep sandstonereservoir to develop an Enhanced Geothermal System: Laboratory and field ex-periments,” Geothermics, vol. 39, no. 1, pp. 70–77, 2010.

[118] Y. Hori, K. Kitano, H. Kaieda, and K. Kiho, “Present status of the Ogachi HDRProject, Japan, and future plans,” Geothermics, vol. 28, no. 4, pp. 637–645, 1999.

[119] D. Swenson, R. Schroeder, N. Shinohara, and T. Okabe, “Analyses of the Hi-jiori long term circulation test,” in Proceedings of the Twenty-Fourth Workshop

on Geothermal Reservoir Engineering, Stanford University, Stanford, California,25-27 January, 1999.


[120] H. Kaieda, H. Ito, K. Kiho, K. Suzuki, H. Suenaga, and K. Shin, “Review of theOgachi HDR project in Japan,” in Proceedings of the World Geothermal Congress,

Antalya, Turkey, 24-29 April, 2005.

[121] K. Kitano, Y. Hori, and H. Kaieda, “Outline of the Ogachi HDR project and charac-ter of the reservoirs,” in Proceedings World Geothermal Congress, Kyushu-Tohoku,

Japan, May 28-June 10, 2000.

[122] J. Norbeck and R. Horne, “Investigation of Injection-Triggered Slip on BasementFaults: Role of Fluid Leakoff on Post Shut-In Seismicity,” in Proceedings World

Geothermal Congress, Melbourne, Australia, 19-24 April, 2015.

[123] I. Moeck, T. Bloch, R. Graf, S. Heuberger, P. Kuhn, H. Naef, M. Sonderegger,S. Uhlig, and M. Wolfgramm, “The St. Gallen Project: Development of Fault Con-trolled Geothermal Systems in Urban Areas,” in Proceedings World Geothermal

Congress, Melbourne, Australia, 19-24 April, 2015.

[124] T. Kraft, S. Wiemer, N. Deichmann, T. Diehl, B. Edwards, A. Guilhem,F. Haslinger, E. Király, E. Kissling, A. Mignan, K. Plenkers, D. Roten, S. Seif,and J. Woessner, “The ML 3.5 earthquake sequence induced by the hydrother-mal energy project in St. Gallen, Switzerland,” American Geophysical Union Fall

Meeting Abstracts, 2013.

[125] F. Ladner and M. O. Häring, “Hydraulic characteristics of the Basel 1 EnhancedGeothermal System,” Geothermal Resources Council Transactions, vol. 33, pp.199–203, 2009.

[126] A. Batchelor, “The stimulation of a hot dry rock geothermal reservoir in the Cornu-bian granite, England,” in Eighth Workshop on Geothermal Reservoir Engineering,

Stanford University, Stanford, California, 1982, pp. 237–248.

[127] A. S. Batchelor, “Reservoir behaviour in a stimulated hot dry rock system,” inEleventh Workshop on Geothermal Reservoir Engineering, Stanford University,

Stanford, California, 1986.

[128] R. H. Parker, Hot dry rock geothermal energy: phase 2B final report of the Cam-

borne School of Mines Project. Pergamon, 1989, vol. 1.

[129] T. Wallroth, T. Eliasson, and U. Sundquist, “Hot dry rock research experiments atFjällbacka, Sweden,” Geothermics, vol. 28, no. 4, pp. 617–625, 1999.

[130] T. Eliasson, U. Sundquist, and T. Wallroth, “Rock mass characteristics at the HDRgeothermal research site in the Bohus granite, SW Sweden,” Department of Geol-

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ogy, Chalmers University of Technology and University of Goteborg, Tech. Rep.,1988.

[131] T. Wallroth, “Hydromechanical breakdown of crystalline rock,” Doktorsavh. vid

Chalmers tekn. hogskola, NS, 1992.

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109

Appendix A

Open hole packer

A description of the open hole packer used to describe the implementation procedure isshown here.

Figure 33: Cross section of Baker Hughes packer 10.375" OD ISP for formation test [19]

110

111

Appendix B

Thermal Stimulation in Iceland

The Krafla geothermal area is well known for thermal injection experiments specific tothe recent activities in connection with the Iceland Deep Drilling Project (IDDP). Wellsin Hellishedi, located in the Hengill volcanic area, have also been thermally stimulatedthroughout the first half of the 21st century. One well is known to have been stimulatedin Nesjavellir (well NJ-24), but no published information is available on the matter andtherefore is not discussed in this thesis. Lastly, one well in Hágöngur was thermallystimulated and a thorough production test was performed afterward.

B.1 Krafla

The Krafla geothermal power plant has been in operation since 1977 and currently hasthe capacity of 60 MWe. Reservoir temperatures in the Krafla system range from 210 to340°C. About 40 production wells have been drilled to date, and most were stimulatedat the end of drilling through cold water injection/circulation with intermittent periods ofthermal recovery [4]. As examples for analysis in this thesis, wells KJ-14, KJ-38, andKJ-39 are discussed as all wells have substantial reports on stimulation directly after thecompletion of drilling.

B.1.1 Well KJ-14

Well KJ-14 was drilled to a depth of 2100 m in 1980 [4] [91]. The main fracture zonelocated at 1050 m is detected to have influence on the productivity of the well after coldwater injection, and was stimulated in three cycles [18].


The first cycle began with cold water injection through the drill string where the initialcirculation losses were 8 l/s but then decreased to 4 l/s over the first 4 hours [4] [18]. After14 hours, the circulation losses were 29 l/s and after 35 hours increased further to 35 l/s.The slight decrease, then rapid increase in losses is due to unclogging of feed zones, whichusually occur at the start of injection [91]. Injection was then switched to the annulus for6 hours, where the circulation losses decreased to 29 l/s. The trend is attributed to thedifference in temperature, where fluid injected down the annulus is colder when it reachesthe feed zone than when injected through the drill string [18]. Colder fluid is more viscousand does not enter the feed zone as easily as warm fluid does [18].

The warming period after the first cycle lasted 12.5 hours before the start of the secondcycle [91]. When injection began again the circulation losses were at a rate of 34 l/s,which is slightly higher than before the warming period [18]. After only 3 hours thecirculation losses increased to 43 l/s. The well was capable of handling more fluid overthe following 16 hours as the water level in the well was far below the ground surface, butwater availability was limited at the site and therefore the injection rate varied between33 and 34 l/s [18]. When injection switched to the annulus, the circulation losses were ata rate of 43 l/s during the last 42 hours [91]. The well was then allowed to heat up beforea step-rate test was performed [18].

The third cycle was a step-rate test after stimulation was complete. The procedure took 18hours and injection rates reached 60 l/s at two stages during the test [18]. A transmissivityof T = 3.1×10−4 m2/s was calculated through a transient pressure analysis, indicating thatthe well would be the most productive well drilled in Krafla up to that time [4] [18] [91].The production test resulted in a 15 kg/s yield of steam, which confirms that the well wasstimulated successfully and is partly attributed to the opening of pre-existing fractures bythermal stresses as well as creation of new fractures by thermal cracking [4] [18]. Hadmore water been available during the second cycle, perhaps the productivity of the wellcould have been further improved as maximum injection was not able to be reached.

B.1.2 WEll KJ-38

Well KJ-38 was drilled to 2700 m depth with 30° inclination below 320 m and measureda static water level of 580 m depth [91]. The well was thermally stimulated in four cy-cles.

The first cycle mostly showed points of interest in the temperature log during the stimu-lation and short step-rate test after the stimulation. The temperature log showed most ofthe injected fluid entering the reservoir through feed zones at 2265 m and 2420 m depth,

Cari Covell 113

with small amounts of flow entering at 2250 m, 2380 m, 2570 m, and 2600 m depth [18].The short step-rate test involved the injection of water at 10 l/s through the drill stringcombined with 10 l/s injected through the ’kill line’ outside of the string for the first 3hours, and then injection through the ’kill line’ increased to 25 l/s for the remaining hourof the test [91] [18]. The 15 l/s increase in injection resulted in a pressure change of about6.3 bar, yielding an injectivity index of 2.4 (l/s)/bar [18].

The second cycle was the cooling period phase of stimulation carried out over 24 hours.Five sub-cycles were done with injection rate held constant at 50 l/s for about 1-1.5 hoursand then decreased to around 20 l/s for the remainder of the stimulation [91] [18]. Thewellhead pressure at the 50 l/s stage ranged from 46-50 bar and was dominated by fric-tional losses in the tubing, but is noted to not reflect downhole pressure in the well [18].However, a reduction in downhole wellbore pressure of about 2.5 bar may be attributed toa reduction in injection pressure of 2-3 bar during the stimulation [18]. The observationof a change in wellbore pressure, possibly influenced from change in injection pressure,shows the importance of monitoring all injection parameters during stimulation as theconsequences may effect the overall productivity of the well. However this could dependon the sensitivity of the well to pressure changes.

Prior to the third stimulation cycle, the well was allowed to warm up for 10 hours beforea slotted liner (1631 m total length) was run to 2660 m depth [91]. Throughout the sev-enteen cooling/warming periods, no significant long-term pressure changes were detectedin the well during injection [91] [18]. The temperature and pressure logs showed that thewell had been cooled below 60°C down to 2500 m, and the water level in the well wasaround 570 m depth [18].

The fourth and final cycle began after a 9 hour warm up period with injection of 45 l/swater to cool down the well for 8 hours [91]. A step-rate test was then performed tomeasure injectivity index and pressure in the well after thermal stimulation (see Figure34). The water level was found to be at 580 m depth unchanged from the initial staticwater level, however the injectivity index was measured to be around 2.6-3.1 (l/s)/bar[91] [18].


Figure 34: Pressure, temperature, and injection rates during step-rate test of well KJ-38[18]

B.1.3 Well KJ-39

Well KJ-39 was drilled to 2865 m depth with 30° inclination and measured a static waterlevel of 580 m depth [91]. The well was stimulated in six phases and a step-rate test wasperformed at the end of stimulation. Discussion for the purposes of this thesis will only in-clude points of interest that may be applicable to hydraulic stimulation procedures.

Phase two is of particular interest as injection down the annulus was performed at 50l/s, but the formation accepted only 30 l/s with the remainder flowing out of a bypass[18]. This could be attributed to the fact that the drill string was stuck in the well fromthe first phase of stimulation, however the formation accepted 56 l/s after a brief warmup period. To aid the thermal stimulation process, polymer pills were then dropped intothe drill string which was then pressured to 210-220 bar, and a pull of 130-140 tons wasapplied [18]. Attempts were then made to loosen and clear blockages around the drillstring. Success was achieved in unclogging the drill string after about 7 hours, but thedrill string was still trapped in the well [91].

In phase four, explosives were used to sever the string at 2808 m depth [18]. The stringwas recovered and a geophysical log suite consisting of caliper, gamma, neutron, resistiv-

Cari Covell 115

ity, and temperature logs was run in the open hole [18]. The recorded temperature at 2815m depth was 385°C indicating the water to be in the supercritical phase [91] [18].

Throughout phases five and six, a slotted liner was inserted and cold water was injectedcontinuously around 56 l/s for two weeks to try to free the drill string, and the effortessentially constitutes a stimulation operation [18]. However, reports are limited on thedetails of flow rates and water levels due to practical difficulties and bad weather [18].The final step-rate test then indicated injectivity rates of approximately 6.5-7 (l/s)/bar afterstimulation [18], showing that the well has good performance even when stimulation wasnot performed as planned.

B.2 Hellisheidi and Hágöngur

The Hellisheidi geothermal power plant is part of the Hengill volcanic zone where thepresent capacity of the electrical power plant is 303 MWe and thermal capacity is 133MWth. The prominent stimulation procedures in Hellisheidi have been performed afterdrill rigs were removed for about a few weeks time by injection of cold water throughthe wellhead. This process results in greater potential of thermal stresses but involveslonger heating and cooling periods [19]. Examples of cold water wellhead injection inHellisheidi include wells HE-8 and HE-21.

The Hágöngur geothermal field is located in the central highlands of Iceland within thecentral volcanic zone. The size of the geothermal field is about 40 km2 with subsurfacetemperatures up to 290°C [18]. Well HG-1 was drilled in 2003 and experienced similarthermal stimulation cycles as the Hellisheidi wells.

B.2.1 Well HE-08

Well He-08 was drilled to a depth of over 2800 m from July-August 2003 [4] [92]. Thewell experienced stimulation through both standard drilling completion procedures andafter drilling ended a few months later.

The injectivity of the well after drilling to 2500 m was around 1-2 (l/s)/bar therefore it wasdecided to initiate stimulation through the "cooling string approach", where drillpipes aresent down to the well bottom allowing the well to cool rapidly [4] [92]. Cold water wasinjected at a rate of 50-60 l/s for 10-20 hours, and then the well was allowed to heatup for 12-24 hours. The cycle repeated until injectivity index became stable betweentwo consecutive cycles [92]. When the well was deepened to 2808 m, circulation losses


increased and stimulation was performed as a standard well completion procedure [92].The well injectivity was estimated between 4-6 (l/s)/bar at completion [18].

A second stimulation attempt occurred a few months later in November 2003. The processbegan by a constant cold water injection of 50 l/s into the well [92]. Points of interestduring injection involve the temperature profiles as seen in Figure 35.

Figure 35: Temperature logs throughout stimulation of well HE-8, where the Novemberlogs were performed after a 3 month cooling period following drill completion [92]

The bottomhole temperature recorded at 2808 m depth shows no increase above 300°C,which is in agreement with the thermal alteration of the formation [92] [93]. Howeverthe temperature is considered low as the well is located only 4 km to the SW of theactive Hengill central volcano [92]. Fluid convection down to 3 km depth is the mostdirect explanation for the phenomena [92]. In addition, the slope changes correlate withlocation of the main feedzones of the well at 1350 and 2200 m depth [92]. Lastly, thetemperature log after the November injection period indicated the well having a minorloss zone when cooling was observed around 2700 m depth [92] [93].

Ultimately, the pressure fall-off test at the end of injection resulted in an injectivity indexof 6-7 (l/s)/bar [18]. This is a great improvement when compared to flow before stimula-tion procedures began, but must be compared to the 4 (l/s)/bar injectivity index after thefirst stimulation phase due to differences in depth when each test was conducted. There-fore, the improvements in the well were only moderate [92]. Through these observations,

Cari Covell 117

it was concluded that the stimulation of the well was partly attributed to reopening offeedzones clogged by drill cuttings and partly to increased near-well permeability result-ing from thermal stresses/cracking [19]. However according to Axelsson [4], the wellturned out to be non-productive during discharge testing. The test assures that the im-provement of the well was mostly attributed to the removal of drill cuttings.

B.2.2 Well HE-21

Well HE-21 was drilled to a depth of 2100 m in early 2006 and was stimulated due tono sign of production after drilling [4] [19]. Initial stimulation occurred over two daysthrough a few cycles of cold water circulation and heating, and then continued after thedrill rig had been removed [19].

The first three cycles of stimulation involved injection at varying rates between 40 and50 l/s, with injection pressures as high as 5 bar [18] [19]. The injectivity index increasedfrom 1.7 (l/s)/bar at the end of well logging to around 2.5 (l/s)/bar by the second cycle, butlater decreased to 1.9 (l/s)/bar by the end of the third cycle due to limited water availabilityat the site [18]. The well was then warmed up for 14.5 hours during which a temperatureand pressure logger was run down the well. The logger was not able to pass beyond2040 m depth, which can be explained by either a breakout in the borehole or sedimentsprecipitated into the well [18].

After a week long warming period, the fourth cooling-warming cycle started with a 70l/s injection rate and indicated a relatively constant injectivity index of 2 (l/s)/bar [18].A fifth cycle was also performed at 65 l/s injection but indicated no change in injectivityindex [18]. Since most of the injected fluid entered the reservoir around 1800 m depth, aborehole acoustic televiewer was then run from 900-1825 m depth to see the fracture net-work. The images revealed many near vertical fractures of variable orientation as well ascontinuous long depth sections attributed to thermal cracking [19]. However, no step-ratetest is known to have been performed [18] [19]. Therefore, the stimulation cannot confirmif thermal cracking would be the main cause of well productivity improvements.

B.2.3 Well HG-01

Well HG-01 in Hágöngur was drilled to a depth of 2360 m in September 2003 and wasstimulated in eleven cooling-warming cycles. Cooling by continuous injection of coldwater varied in periods lasting from 2 hours up to 3 days, and warming periods varied from


1 hour up to 17 hours [94]. Temperature logs indicated the main feed zone at 920 m depth,with smaller feed zones from 1470-1520 m depth and 1980-2020 m depth [94].

For each stimulation cycle, a summary of the injectivity index and measured flow rates asa function of volume injected is illustrated in Figure 36. The overall increase in injectivityis smooth over the entire stimulation operation. The permeability enhancement in cycles1-4 is interpreted to be controlled by a combination of thermal effects and well cleaning,while the later injectivity increase is thought to be caused by thermal effects alone [18].The overall stimulation program shows an increase in injectivity index from 0.6 (l/s)/barto approximately 10 (l/s)/bar indicating a very successful operation [18]. However someinjectivity values are out of place and need further explanation.

Figure 36: Calculated injectivity index for each cycle of stimulation in well HG-1 as afunction of volume of injected fluid into the well [18]

The low injectivity of cycle 4 is highly questionable. Brief injection was performed at137 bar pressure when a packer was deployed to seal the annulus. The overpressure of thewell was not reported because the test was too short in duration to have achieved steadystate conditions [18]. Overpressure was concluded to be the cause of friction losses in thelines, the wellhead, and the tubing through which injection was conducted [18]. Thus, thelow injectivity probably reflects an overestimate of pressure in the wellbore [18].

Cari Covell 119

In cycle 10 the injectivity went from 8.6 (l/s)/bar when stimulation was performed throughthe tubing string, to 5.6 (l/s)/bar when injection was switched to the annulus. Similar towell KJ-14 in Krafla, the difference can be explained by the temperature of the water atthe main feed zone (920 m depth). The water entering the feed zone is cooler and moreviscous when injected down the annulus, compared to when injection is through the longtubing string where water reaches the feed zone by flowing upwards from the hot part ofthe well [18].

The productivity index was then estimated for the well based on varying parameters. Ac-cording to Seifu [94], the transmissivity was calculated to be T = 9.0×10−9 m3/Pa·s usingthe Horner plot of the pressure recovery, and therefore the productivity index ranged from0.83 and 1.25 (l/s)/bar depending on the assumed radius of influence (10 m or 100 m).However, the productivity index derived from the observed flow of 21 l/s and downholedrawdown of 53 bar as steady-state conditions were approached is 0.4 (l/s)/bar [18]. Thediscrepancy can be explained by the existence of positive skin around the well that reducesthe actual productivity [18]. Therefore, the best estimate to use for well productivity is0.4 (l/s)/bar with an implied skin factor ranging from 7.4-9.7, depending on the assumedradius of influence [18].

The injectivity index was then compared to the productivity index calculation for thewell. As discussed in the beginning of the literature review, comparing these two valuesis still considered trivial due to lack of understanding of the potentially affecting under-lying processes, but the typical relationship is 1:3 productivity index to injectivity index.When comparing the productivity index of 0.4 (l/s)/bar to the average injectivity indexof 10.1 (l/s)/bar from cycle eleven, the injetivity index is 25 times higher [18]. This canbe explained by the reversibility of the enhancement of injectivity that was accomplishedduring the stimulation, where feed zones in the well must have cooled down significantly[18]. The conclusion was that reversible mode fracture opening caused the permeabil-ity enhancement, but is not strongly supported from the comparison of productivity andinjectivity indexes.

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Appendix C

EGS Applications

This appendix will discuss each case of hydraulic stimulation in EGS areas. Each case isorganized alphabetically by country, and within each field stimulations are explained bydate of occurrence, if applicable. The section labeled "other sites" includes countries withonly one geothermal field that had experienced hydraulic stimulation.

C.1 Australia

Geothermal exploration in Australia targets EGS sites because no currently active vol-canic terrains exists [95]. Of the 10 geothermal wells that have been drilled in Australiafor resource testing, 6 have been hydraulically stimulated to enhance permeability. Thewells are all located in South Australia either in the Habanero geothermal field at theCooper Basin site, the Olympic Dam site, or the Paralana site.

C.1.1 Cooper Basin - Habanero

Exploration of the Habanero site in the Cooper Basin was first done in 1983 when apetroleum exploration well penetrated granite with a bottom hole temperature of 199°C[95]. EGS exploration began in 2002 by the company Geodynamics Limited (GDY),where the maximum temperature recorded out of the four wells drilled was approximately250°C [95]. All four of the current wells were hydraulically stimulated between 2003-2012. Well Habanero-1 was stimulated from November-December 2003. Some fracturesintersected within granite around a depth of 3668 m indicated overpressure with water at35 MPa above hydrostatic pressure [96]. For stimulation, the drilling fluids were heavily


weighted in order to control the overpressure. Pressures up to about 70 MPa were used topump 20,000 m3 of water into the fractures at flow rates stepped from 13.5 kg/s to a max-imum of 26 kg/s [96]. The first stimulation was successful at creating a fracture volumeof 0.7 km3. Further stimulation through a 7-inch perforated casing at 4136 m depth cre-ated a horizontal fracture area of approximately 3 km2. In 2005, the well was stimulatedagain and the reservoir was extended to an area that covered 4 km2. Well Habanero-2was drilled and stimulated in 2004 with the intent to intersect the fractured reservoir, andsucceeded at 4325 m depth. A flow test was done based on 35 MPa pressure and flowsup to 25 kg/s were measured. However due to a bridge plug stuck in the open hole justabove the main fracture zone, all injection and production tests were affected [97]. WellHabanero-3 was hydraulically stimulated in 2008 but the details of the procedure are notavailable in published literature. Two production tests were performed; one before stim-ulation and one after a small local stimulation. Results indicated a three-fold increase inbottom hole productivity from 1.6 (kg/s)/MPa to 5 (kg/s)/MPa [97]. Well Habanero-4 washydraulically stimulated in 2012 with the intent to expand the existing EGS reservoir andto gain a better understanding of the geothermal system through monitoring seismic re-sponse [98]. A multi-rate test performed before stimulation indicated turbulent flow nearthe wellbore especially at higher flow rates. After stimulation, another multi-rate test wasperformed and indicated an increase in productivity associated with higher flow rates. Thetest confirmed small local stimulations to be effective for reducing near wellbore effectsfrom turbulence [97].

C.1.2 Olympic Dam

The Olympic Dam Project under the Green Rock Energy company (GRK) is located ad-jacent to the Olympic Dam Iron Oxide copper gold uranium mine in the Gawler Cratonof South Australia [95]. In 2005, well Blanche 1 was drilled confirming the presence ofthermally anomalous granite with high heat generation potential and surface heat flow, aswell as a measured maximum downhole temperature of 85.3°C at 1934.2 m depth [95]. Aseries of twelve hydraulic stimulation tests were performed in 2008 within an open holesection section of the Blanche 1 borehole. Objectives of the stimulation were to inducenew fractures, reactivate and extend existing fractures, determine the existing openingpressures, and measure the magnitude and orientation of the in situ stress field [95] [99][100]. Tests were conducted using a 71 mm wireline deployed in an inflatable packersince the open hole section of the borehole was only 76 mm in diameter (see systemdetails in [101]). After measurement of break-down, re-opening, and shut in pressures,no fractures were initiated below 1599 m due to limitations of the packer equipment.

Cari Covell 123

Through further analysis using an acoustic televiewer log, the pressure tests indicatedeither steeply inclined or sub-horizontal fractures striking E-W. A horizontal stress in-crease with depth was later confirmed after comparison of the hydro-frac data with theinitial borehole breakout analysis [95]. However Klee et al. [100] states from the hydro-frac data that the minimum horizontal stress is less than the vertical stress above 1700m which differs from the borehole breakout analysis. Nevertheless both the hydro-fracdata and the borehole breakout analysis show the vertical stress as the minimal princi-pal stress below 1700 m depth [100], and it is at this deeper reverse fault compressionalstress regime that the temperatures needed to power geothermal energy projects would beobtained [95].

C.1.3 Paralana

The Paralana Engineered Geothermal Project was initially tested for viable geothermal re-sources within a sedimentary basin, lying immediately east of known high heat producingMesoproterozoic basement rocks of the Mt. Painter region [102]. According to Reid et al.[102], enough high heat was detected in order to initiate drilling for a commercial powerplant of 7.5 MWe, but no specific temperature is provided. In July 2011, stimulation ofthe injection well Paralana 2 then commenced in two stages for purposes of producingcommercial flow rates. Stage 1 involved an injectivity test, where perforation of the steelcasing was near the bottom of the well and a small volume of water was injected to con-firm fracture initiation and propagation. Stage 2 fracture stimulation involved injection oflarger volumes of water at higher rates in order to create a fracture network and connectto the existing natural fracture network intersected lower in the well. Initial injection rateswere around 3 l/s, but steady improvement occurred over the period with the maximuminjection at 27 l/s [103]. Final injection rates were limited by the number of perforationsand success of the perforation. Bendall et al. [95] notes that the flow was limited by thenumber of perforations, and also dependent on the success of the perforation and hence theconnectivity of the perforation to the rock formation. Microseismics were also recordedwith 98% of the 11000 events detected below 1.0 magnitude, where after 3D modelingsuggested the microseismics not related to a single fault structure but an arrangement ofat least 4 main structures striking predominately northeast to north-northeast [95] [103][104].


C.2 France

EGS stimulation in France began at the Le Mayet site 25 km east-southeast of the town ofVichy, where wells III-8 and III-9 were drilled and stimulated in the late 1980s. Packerswere used to isolate different intervals for multiple stimulations in order to produce alarge surface area link between the two wells [96]. The Soultz-sous-Forêts project thenemerged as a result of interest generated by the Fenton Hill project in the United States[96]. Together with Germany, a study began in the mid 1980s of a potential site in theUpper Rhine Valley bordering the two countries. The goal was to develop a Europeanproject that would eventually lead to a commercially producing site [96]. Four wells wereinitially stimulated using 800 m3 of brine each, followed by several tens of thousands ofliters of fresh water.

C.2.1 Le Mayet

Willis-Richards et al. [105] outlines the stimulation procedures of the Le Mayet site.Stimulation in well III-9 began with small viscous gel treatments and gave a recoveryof 36% at a flow rate of 8.3 l/s. Subsequently 2 m3 of proppant were placed around thewell and an 18% recovery was achieved. Further tests showed about 33% of the injectionwater returned up the annulus, some from a fracture of 550 m depth and some from 160m above the packer. A significant portion (almost 1/5) of total injection flow from thesingle fracture 160 m above the injection zone suggests vertically dominant flow and theexistence of large conductive natural fractures [105]. Recovery dropped to 12% when theflow rate was doubled to 16.6 l/s, and further to 10% when a production well backpressureof 4 MPa was applied. It was then decided to treat well III-8 by using 170 m3 of geland 7 tonnes of proppant in order to try to improve recovery [105]. The recovery wasagain 36%, but this is in addition to some 22% from a shallower well equipped with adownhole pump. A larger stimulation using 400 m3 of gel and 40 tonnes of proppant wasthen performed and injected at high flow rates of 20-30 l/s. The gel proppant treatmentsof each stimulation in well III-8 were compared based on flow rates. Low flow ratesindicated recovery from 68% to 82%, while high flow rates indicated a drop in recoveryto less than 50%. It was concluded that reasonable recoveries were only achieved byrepeated stimulation with large amounts of proppant [105].

Cari Covell 125

C.2.2 Soultz-sous-Forêts

Well GPK1 was stimulated in 1991 in a targeted open hole section from 1420-2002 mdepth, where a natural fracture was possibly intersected that stopped fracture growth andallowed for loss of injected fluid [96]. The well was later deepened and stimulated againthe following year targeting a new zone from 2850-3590 m depth. The stimulation proveda need for large scale injections in order to improve the connection from the well to thefracture network [96] [106]. Initial stimulation of well GPK2 in 1995 showed a continu-ous pressure increase in the main injection phase, which indicated that no constant pres-sure boundary or infinitely conductive structure was connected to the well [107] [108].However well GPK1 showed a significant pressure response to the stimulation, whichshowed a connection between the two wells [96]. Well GPK2 was re-stimulated in 1996where injection and production stabilized with no net fluid losses. Thermal output in-creased from 9 MWth after the first stimulation to 10 MWth after the second stimulation[96]. In 2000, the well was deepened and stimulated again using brine to attempt tostimulate the deeper zones. The majority of the fluid exited the open hole at the bottomduring stimulation, which is encouraging as most of the injected fluid entered the wellwhere initial rock temperatures are about 195–200°C [96]. A simultaneous injection ofwells GPK2 and GPK3 was then performed in 2003 to extend the existing fracture be-tween the two wells, and was successful while improving production of well GPK3 from0.2 (l/s)/bar to 0.3 (l/s)/bar [108]. Following drilling completion in 2004, well GPK4 wasstimulated by injecting brine to encourage development of deep fractures [96], but done atlow injection rates due to many microseismic events from injection into well GPK3 [108].The hydraulic connection between wells GPK3 and GPK4 was still considered poor de-spite small improvements in productivity after a second acid stimulation, suggesting thata linear aseismic zone was present [96] [108]. Currently, research on hydraulic stimula-tions at the Soultz-sous-Forêts site is heavily focused on fracture modeling and seismicityeffects as well as economic optimization of the power plant (see [109] and [110]), and isnot discussed within the scope of this thesis.

C.3 Germany

Stimulation at the Falkenberg test site was done in 1979 with the objective to conductfundamental in situ hydro-mechanical experiments at shallow depths (500 m) in order tounderstand HDR systems [96]. Around the same time, experiments in Bad Urach were de-signed to hydraulically test the reservoir for district heating purposes [111] and to enlarge


this reservoir by a long-term re-stimulation during a second phase [112]. To overcomelimitations in sedimentary formations in the northern German basin, the Genesys Horts-berg stimulation project was established in 2003. The idea was to prove a one well conceptfor supplying 2 MWth power to the nearby complex of buildings of the GEOZENTRUM,Hannover [96]. The gained experiences from Hortsberg were then translated to anotherone well concept fracturing experiment in Genesys Hannover in order to test feasibil-ity of geothermal energy extraction out of low permeable sedimentary rock [113]. TheEGS project at Landau in 2006 aimed at producing hot water from a granitic dominatedgeological system [108]. Two wells were drilled, where well GtLa2 needed massive stim-ulation in order to improve the permeability of the feed zones [108]. Several hydraulicfracturing experiments in the Groß Schönebeck field were performed from 2007-2009,beginning with one stimulation in the low permeability volcanics of well GtGrSk4/05.Another experiment in well EGrSk3/90 was performed to develop concepts for a produc-tivity increase by testing two types of gel proppants in the sandstone section of the well.Two open hole stimulation in the volcanics section of the well through water injectionwere then performed. Stimulation experiments then resumed in well GtGrSk4/05 withtwo tests using gel proppants in the high permeability sandstones. Finally a stimulationproject at the Mauerstetten site was signed on in June 2011, however only initial resultsof reservoir testing have been reviewed at this time (see [114]).

C.3.1 Falkenberg

Well HB4a was stimulated using packers in the 252-255 m depth interval. The stimulationcreated a hydro-fracture that six other boreholes intersected, proving that fresh hydro-fractures can be propagated over significant distances in fractured crystalline rock [96].This was contrary to previous theories that said fluid leak-off into the natural fracturesystem would prevent this from happening [96]. In addition, televiewer logs showedmultiple parallel fractures near well HB4a, although only one extended beyond 20 min length. Several of the wells that intercepted the main fracture indicated that smallamounts of water could be circulated through the fracture, and extensive hydraulic androck mechanical experiments could be conducted [96].

C.3.2 Bad Urach

A series of small scale stimulations with subsequent fluid circulation occurred from May-August 1979 in well Urach III. Seven stimulations occurred over four depth intervals: one

Cari Covell 127

open hole section and three zones accessed through perforated casing by use of viscousgel and proppant. The stimulations were successful in connecting one section to anotherin a single borehole [96]. Fluid circulation was through a loop between the open holesection at around 3326 m depth and the cased hole section around 3295 m depth. Withvertical separation in the perforated sections of only 70 m, circulation was ultimatelyestablished across the section [96].

C.3.3 Genesys Horstberg

To test concepts of extracting geothermal energy from sedimentary geological areas, stim-ulation was performed in abandoned gas well Horstberg Z1 [96]. A large volume stimu-lation using 20,000 m3 of water was injected at 50 l/s and at wellhead pressures of about33 MPa. Post-frac tests showed that the created fracture had a high storage capacity(about 1,000 m3/MPa) and covered a large area on the order of several hundred thousandsquare meters. The results indicated that the fracture not only propagated in the sand-stone layer, but also fractured the adjacent clay-stones [96]. In addition, at least part ofthe fracture stayed opened to allow flow of about 8.3 l/s at fluid pressures well below thefrac-extension pressure [96]. However, long term extrapolation of the test showed that thedesired flow rate of 6.9 l/s cannot be maintained in order to sustain the 2 MWth requiredfor the nearby building complex. This is due to the production and reinjection horizonslocated at around 1,200 m depth do not link together, and therefore the overall yield ofthe fracture formation is too low [96]. In summary, the stimulation of the single boreholewas not sufficient for long-term production.

C.3.4 Genesys Hannover

In 2011, a massive frac operation was performed where about 20,000 m3 of water wereinjected at flow rates up to 90 l/s. The aim of the frac operation was the creation of alarge fracture area of more than 0.5 km2 as based on FIELDPRO modeling [113]. Lowrate injection tests were performed two months after fracturing and provided evidencefor a highly conductive fracture and a fracture area in the range of up to 1 km 2 [113].The injection tests were carried out at a pressure level significantly below the closurepressure of the fracture, hence the fracture retained a high hydraulic conductivity eventhough no proppants were used to keep the fracture conductive [113]. Six months afterthe frac operation, the back flow of the well indicated the possibility of significant waterproduction [113]. However, the recovered water was oversaturated with NaCl at surface


conditions and a salt plug had formed in the well. One year later, the salt plug wasremoved and now further hydraulic tests shall show if the salt problem may be minimized[113].

C.3.5 Landau

Well GtLa2 was hydraulically stimulated via low rate injection pre-tests, followed by highrate injection. The well needed high rate injection in order to increase permeability, giventhere was substantial productivity after drilling [108]. The pre-tests consisted of 4,600m3 of water injected within ten steps over the course of a few hours for each step, at flowrates up to 86 l/s. Initial production increased by a factor of three from 0.2 (l/s)/bar to0.6 (l/s)/bar [108]. The high rate stimulation of flows up to 190 l/s was performed in foursteps of a few hours each with a total volume of 6,600 m3 water injected. Production afterstimulation was 1 (l/s)/bar indicating a five fold increase compared to initial productionafter drilling [108].

C.3.6 Groß Schönebeck

The first fracture treatment was in the volcanic section at the bottom of well GrSk4/05.The goal of this treatment was to obtain a fracture half-length of approximately 150-200 m with a corresponding fracture height of 80-100 m as predicted by the FRACPROsimulation performed prior to the actual stimulation [58]. A constant flow rate of 50 l/swas used, but at times several high flow rate intervals of about 150 l/s were used for ashort duration due to limited water availability at the site [58]. When necessary, flow ratewas reduced to 20 l/s in order to fill the tanks while keeping the fracture open [58]. Aceticacid was added to avoid iron scaling and low concentrations of quartz sand (20/40 meshsize) were added to support a sustainable fracture width [58]. Stimulation results provedsuccess when compared to the FRACPRO model as a 90 m total fracture height and 190m fracture half-length were achieved.

Not much is known about the stimulation procedures of well EGrSk3/90, however resultsindicate a productivity improvement factor of 2.2 from the initial measurement of 0.027(l/s)/bar when the well was stimulated using gel proppants in the sandstone section [58].Additionally, productivity improvement factors of 4.1 and 7.7 were observed from initialmeasurements of 0.112 (l/s)/bar and 0.207 (l/s)/bar respectfully for each stimulation inthe open hole volcanics section of the well [58]. The production data showed that theproduction efficiency of the fractures was strongly dependent on reservoir pressure, as

Cari Covell 129

an increase in reservoir pressure of all stimulated intervals are highly conductive andsubsequently become less conductive during pressure decline [115]. Hence the range ofa suitable reservoir pressure is constrained by this fracture efficiency and limits the usageof the well for geothermal power production [115].

Stimulation experiments then resumed in the sandstone section of well GtGrSk4/05 withthe use of gel proppants. A FRACPRO simulation was performed prior to the actualstimulation and the projected fracture treatment would lead to a fracture height of 80 mand a fracture half-length of 50 m [116] [117]. The targeted interval between 4204-4208m depth was isolated with a bridge plug at 4300 m depth and then perforated. A totalof 95 tons of high strength proppants, including 280 m3 of cross-linked gel was used ata flow rate of 67 l/s. Based on field data collected during well treatment, including flowrate and proppant concentration, a FRACPRO computation was performed and fracturepropagation was compared to the original model. The computations gave a total fractureheight of 115 m and a total half-length of 57 m which suggests that the stimulation wassuccessful [117]. The success of the stimulation was later confirmed by a well productiontest and indicated a five fold productivity index improvement from 0.92 m3/(h MPa) to 5m3/(h MPa) [117].

C.4 Japan

The New Energy and Industrial Technology Development Organization (NEDO) con-ducted studies in Hijiori to determine whether the technology developed at Fenton Hillcould be adapted to the geological conditions found in Japan. Several stimulations wereperformed throughout the 1990s and were followed by short-term and long-term circula-tion tests in order to determine fracture effects based on pressure changes and fluid losses.The Ogachi site near the Kurikoma National Park on Honshu Island in Japan was consid-ered an EGS project because the productivity of the wells was low even though hightemperatures of more than 230°C were observed at 1,000 m depth [96] [118]. Stimula-tions were performed in one injection well and one production well, followed by severalcirculation tests to measure fluid loss and recovery.

C.4.1 Hijiori

Hydraulic fracturing experiments began in 1988 with water injection into well SKG-2. A30-day circulation test showed a good hydraulic connection between the injection well


and the two production wells HDR-2 and HDR-3 as the size of the reservoir continued togrow, even though more than 70% of the injected water was lost to the reservoir [96]. Inaddition, well HDR-1 was hydraulically fractured in 1992 to stimulate the deep fracturesand a 25-day circulation test was conducted in 1995 after wells HDR-2a and HDR-3were deepened. A total of 51,500 m3 of water was injected and 26,000 m3 of water wasrecovered indicating about 50% recovery [96]. In 1996, further stimulation in well HDR-1 was done in an attempt to better connect the main fracture to HDR-3 and reduce theamount of fluid loss to ultimately prepare for a long-term circulation test [96]. While therewas no indication of an improvement in connectivity in short-term circulation testing, thehope was that modifying the pressure in the reservoir could have an effect on the resultsof the stimulation [96]. Based on this theory, a result of the long-term circulation testshowed that while the injection flow remained constant from 15-20 kg/s, the pressurerequired to inject that flow decreased during the course of the test from 84 bar to 70 bar.Ultimately the test was successful in that the flow was used to run a 130 kW binary powerplant and fluid losses amounted to approximately 45% [96] [119]. Overall it was clearthat while stimulation by injecting at high pressures for short periods had some effect onthe naturally fractured reservoir, injecting at low pressures for long periods of time hadan even more beneficial effect [96] [119].

C.4.2 Ogachi

To develop the EGS site, a fracture stimulation was performed in well OGC-1. The lowerreservoir was created through a 10 m open-hole section at the bottom of the well andthe upper reservoir was created through an open-hole milled window in the casing from711-719 m depth. After a reservoir evaluation, production well OGC-2 was drilled topenetrate the two reservoirs [120]. Due to a small water recovery of 3% from well OGC-2 during a circulation test in 1993, it was decided to stimulate the well one year later[120]. In this stimulation, water was injected at a flow rate of 45 ton/hr at a wellheadpressure of 13 MPa for a total of 2,204 tons of water injected. After the stimulation, a 5month circulation test was performed where a total of 140,224 tons of water was injected.The produced water recovery rate increased to 10% of injected water [120]. In 1995,another stimulation was performed in well OGC-2 by injecting a total of 3,400 tons ofwater at a flow rate of 135 ton/hr at a wellhead pressure of 18 MPa. Around the sametime, well OGC-1 was stimulated after re-drilling by also injecting a total of 3,400 tonsof water at a wellhead pressure of 18 MPa, but at a flow rate of 105 ton/hr. A one monthcirculation test was performed to confirm the stimulation effects of the two wells, and atotal of 24,241 tons of water was injected with a water recovery rate of 25% [96] [120]. In

Cari Covell 131

this circulation test the injection pressure decreased by about a half of that of the previouscirculation test in 1994, and the water recovery from OGC-2 increased by more thantwice as much; concluding that the stimulations were very effective [120]. However therate of water recovery was still low, so the upper and lower reservoir of well OGC-1 werefurther analyzed after more circulation tests to determine where the produced fluid camefrom [121]. It was found that 15% of the produced fluid could be attributed to the upperreservoir while 85% came from the lower reservoir; concluding a weak connection of theupper reservoir between wells OGC-1 and OGC-2 [96] [121]. Due to this finding, wellOGC-3 was later drilled and successfully connected the upper reservoir [96].

C.5 Switzerland

The Basel project is partly financed by the Federal Office of Energy (OFEN) and was ini-tiated in 1996 with potential for direct use as well as electrical generation. The geothermalreservoir and power plant were to be located within a seismically active area, thereforeseismic monitoring equipment was installed prior to drilling [96]. Well Basel 1 is theonly stimulated well at this site as multiple seismic events greater than a magnitude ML 3canceled the project in 2009 [122]. The project in St. Gallen started in 2008 with a feasi-bility study considering different target horizons and different concepts of utilization forapplying EGS technology [123]. Drilling through 4 km of sedimentary rocks was done inthe Swiss Molasse Basin order to find and exploit hydrothermal aquifers in the Mesozoicsediments [124].

C.5.1 Basel

Prior to stimulation, an injection test was performed in well Basel 1 in order to charac-terize pre-existing hydraulic properties of the reservoir [32]. Observations showed thatthe formation fluid had progressively diluted the injected freshwater as the well vented,indicating a negligible outflow and suggesting that the well is not naturally fractured [32].Stimulation then commenced in late 2006 with a massive injection of 11,570 m3 of riverwater. Over the first 16 hours the flow rate was increased in steps from 0 to 100 L/minresulting in a wellhead pressure of 110 bar. In the following days the flow rate was in-creased gradually up to a maximum of 3300 L/min resulting in a wellhead pressure of296 bar. A rise in seismic activity was observed with rising pressure and flow rate, andreached magnitudes that required a reduction in flow rate after 6 days of continuous in-jection [32]. Due to the high seismic activity, it was decided to shut-in the well as the


seismic activity remained at an unacceptably high level, but not excessive in magnitude[32]. No conclusive assessment of the efficiency of the stimulation in well Basel 1 can begiven because no hydraulic post-stimulation tests have been conducted [32]. However thewellhead pressure curve showed that as long as the overpressure is kept high, both shearslipping and elastic response of the fractures are assumed to contribute to an enhancementof the fracture permeability [32]. A permeable fracture was later confirmed by a temper-ature log indicating thermal perturbations in the vicinity of the casing shoe and at 4,677m depth [125].

C.5.2 St. Gallen

A small scale stimulation began in July 2013 beginning with an air lift test. Methanegas was released into the borehole from an unknown source and pressure at the wellheadrose rapidly. Operators decided to pump water and heavy mud down the well due to thisobservation [124]. Even though wellhead pressure decreased steadily, seismicity startedto increase suddenly. The seismicity intensified and culminated in a ML 3.5 event that waswidely felt in the area [124]. In the following hours, the operators were able to stabilizethe well and control the methane gas flow into the well. Seismicity decreased rapidlywithin a few days but two weeks later was still far from reaching the background level[124]. No information is reported in literature on the success of the stimulation at thistime.

C.6 Other sites

C.6.1 Rosemanowes, United Kingdom

The project was established based on the completion of Phase I of the Fenton Hill projectfunded by the U.K. Department of Energy and by the Commission of the European Com-munities. Rosemanowes was intended to be a large-scale rock mechanics experiment ad-dressing some of the issues surrounding stimulation of adequate fracture networks [126].Temperature gradients were high between 30-40°C per kilometer. Stimulation of RH12occurred using explosives, then hydraulically at rates up to 100 kg/s and wellhead pres-sures of 14 MPa. Predominant growth of the reservoir continued for nine months ofcirculation, and testing of the completed system showed it was not suitable for the pur-pose of modeling a full-scale commercial HDR reservoir [96]. Hydraulic stimulation of

Cari Covell 133

well RH15 was similar to RH12, where a series of flow tests in 1986 showed rates grad-ually stepping up. The reservoir was then circulated continuously at various flow rates(typically around 20-25 kg/s) for the next four years [96]. Additionally, flow path analy-sis showed that a preferential pathway - or short circuit - developed, which allowed coolinjected water to return too rapidly to the production well [127]. Well RH15 underwent anexperiment to place sand proppant in the joints as part of a secondary stimulation usinghigh viscosity gel as frac fluid. The stimulation significantly reduced water losses andimpedance, but also worsened the short circuiting and lowered the flow temperature evenfurther, concluding that the proppant technique would need to be used with caution in anyattempt to manipulate HDR systems [96]. Another experiment was carried out in the wellusing a temporary packer to seal off all upper parts of the wellbore ad a production flowtest was carried out to measure the flow rate from the low-flow zone at the bottom of thewell. No significant increase in flow was observed, suggesting that the most recent stim-ulated zone was parallel to, but largely unconnected with, the previously stimulated zone[128]. This showed that individual fractures at the well can have independent connectionsto the far-field fracture system, i.e., the fracture network is not well connected enough toform a commercial size reservoir over short sections of a well [96].

C.6.2 Fjallbacka, Sweden

The Fjallbacka site was established in 1984 as a field research facility for studying hy-dromechanical aspects of HDR reservoir development, where three wells were initiallydrilled. The ultimate goal of the project was to create a heat exchanger suitable for circu-lation and heat extraction experiments through hydraulic stimulation of pre-existing frac-tures in order to improve their hydraulic properties [96] [129]. Detailed packer tests to-gether with temperature logs have shown that a limited number of zones are fluid-bearingwith typical transmissivities on the order of 10−8 - 10−7 m2/s [130]. The major hydraulicstimulation of well Fjb1 in 1986 was carried out in an isolated section between 450-480m depth [130]. Operational parameters were chosen based on earlier predictions by hy-draulic fracturing models, which included injection via viscous gel and water at a flowrate of 20-30 l/s [131]. Packer tests showed a total transmissivity increase from 6×10−8

to 8×10−6 m2/s for the 30 m section [129]. Drilling of well Fjb3 intersected the stimu-lated fracture zone and an observation showed remnants of the viscous gel at a depth of460 m. This verified that the stimulation from Fbj1 reached the position of well Fbj3 aspredicted from previous microseismic measurements, and transmissivity of the zone wasabout four orders of magnitude larger than those measured elsewhere in the well [129]. Inaddition, an open-loop circulation test was performed between the two wells. Throughout


the 40 day test, production flow rate increased to a maximum of 51% [129]. Due to thissuccess, it was evident that natural fractures dominated the stimulation result [96].

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Appendix D

Fluid and proppant type properties

The fluid type properties of the low viscous gel WG-11 20 lb/Mgal was used for modelingstimulation, while 20/40 mesh Jordan sand was used as the proppant. Figures 37 and 38show the properties of each, respectfully.

Figure 37: Fluid type parameters for WG-11 20 lb/Mgal low viscous gel [72]


Figure 38: Proppant type parameters for 20/40 mesh Jordan sand [72]

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Appendix E

MFrac report

This appendix shows the output report for MFrac. The first report is from below thepacker, while the second is from above the packer. Please see the subsequent pages foreach report.

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139

Appendix F

MProd report

This appendix shows the output report for MProd above the packer. Please see the subse-quent pages for the full report.

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School of Science and EngineeringReykjavík UniversityMenntavegi 1101 Reykjavík, IcelandTel. +354 599 6200Fax +354 599 6201www.reykjavikuniversity.isISSN 1670-8539

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Hydraulic Well Stimulation in Low-Temperature Geothermal ... · Hydraulic Well Stimulation in Low-Temperature Geothermal Areas for Direct Use Cari Covell January 2016 Abstract Direct