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Modern Fracturing Enhancing Natural Gas Production

Michael J. Economides University of Houston

Tony Martin BJ Services

ET Publishing Houston,TX

© BJ Services Company 2007 BJ Services Company P.O. Box 4442 [77210-4442] 4601 Westway Park Blvd. Houston, TX 77041 Graphic design and production: Jay Clark Production manager: Alexander M. Economides Copy Editor: Stephanie Weiss Cover Art: Armando Izquierdo Published by: Energy Tribune Publishing Inc. 820 Gessner Rd.-Ste. 920 Houston, TX 77040 (713) 647-0903 (713) 647-0940 (fax) for orders and customer service enquires contact: [email protected]

All rights reserved. No part of the publication may be reproduced, stored in a retrieval system, or transmitted, in any form or by any means, except under the expressed permission of BJ Services Company, Designs and Patents Act 1988.

ISBN 978 1 60461 688 0 Printed and bound by Gulf Publishing Co.

Contents Preface



XV

Foreword

XVII

Contributing Authors

XVIII

Acknowledgements

XIX

Chapter 1 Introduction to this Book

1-1 Introduction 1-2 Natural Gas in the World Economy 1-3 Russia: A Critical Evaluation of its Natural Gas Resources

3 3 5



1-3.1 The Resource Base

7



1-3.2 Russian Natural Gas Production

8



1-4 Alaska, its Natural Gas Resources and their Impact on US Imports

8



1-4.1 Alaskan Reserves and Production

9



1-4.2 The Uncertain Destiny of the North Slope of Alaska Natural Gas

10



1-4.3 Alaska in the Context of the United States and Canadian Natural Gas

11

1-5 Qatar Natural Gas 12 1-5.1 North Field Characteristics and Development 13 1-6 Fracturing for the Efficient use of Existing Resources and for Increasing Recovery Factor 13

Chapter 2 Natural Gas Production

2-1 Introduction 2-2 Idiosyncrasies of Dry Gas, Wet Gas and Gas Condensates 2-3 Inflow from Natural Gas Reservoirs

19 19 20



2-3.1 Fundamentals of Non-Darcy Flow in Porous Media

20



2-3.2 Transient Flow

20



2-3.3 Steady State and Pseudosteady State Flow

21



2-3.4 Horizontal Well Flow

22



2-4 Effects of Turbulence

23 



2-4.1 The Effects of Turbulence on Radial Flow

23



2-4.2 Perforated and Cased Well in a High-Rate Gas Reservoir

24

2-5 Production from Hydraulically Fractured Gas Wells

25





2-5.1 Unique Needs of Fracture Geometry and Conductivity

26



2-5.2 Turbulence Remediation in High- and Low-Permeability Wells

26



2-5.3 Multi-fractured Horizontal Gas Wells

28



2-6 Well Deliverability, IPR and Well Flow Performance 2-7 Forecast of Well Performance





2-7.1 Gas Material Balance and Forecast of Gas Well Performance

2-8 Correlations for Natural Gas Properties

33 34 34

35



2-8.1 Pseudocritical Pressure, ppc and Pseudocritical Temperature, Tpc

35



2-8.2 Gas Viscosity

35



2-8.3 Gas Deviation Factor, Z

35

Chapter 3 Gas Well Testing and Evaluation

3-1 Introduction 3-2 Background Theory 3-3 Radial Flow Solutions 3-4 Superposition 3-5 Model Development 3-6 Hydraulically Fractured Wells 3-7 Specialized Plots 3-8 Type Curves and the Log-Log Derivative Plot 3-9 Flow Regime Identification 3-10 Derivatives – A Few Cautionary Remarks 3-11 PTA Interpretation Methods 3-12 Difference Between High and Low Permeability Analysis Techniques

41 42 44 45 46 47 48 49 51 54 56 57



3-12.1 High-Permeability Wells

57



3-12.2 Low-Permeability Wells — Pre-Treatment Evaluation

59



3-12.3 Example 3-1, PID Test

60



3-12.4 Low-Permeability Wells — Post-Treatment Evaluation

61



3-12.5 Example 3-2, Low-Permeability Well, Infinite-Conductivity Fracture

62



3-12.6 Example 3-3, Low-Permeability Well, Finite-Conductivity Fracture

65



3-13 Non-Darcy Flow

66



3-13.1 Example 3-4, Non-Darcy, High-Permeability Well, Finite-Conductivity Fracture

68



3-13.2 Example 3-5, Non-Darcy, Low-Permeability Well, Finite-Conductivity Fracture

69

II

3-14 Production Analysis

70



3-15 Heterogeneity

76



3-15.1 Dual Porosity

76



3-15.2 Anisotropy

76



3-16 Multiphase Flow

77



3-16.1 Gas Condensates

78



3-16.2 Fracture Fluid Cleanup

79



3-16.3 Example 3-6, Fracture Fluid Cleanup Case

79



3-17 Closure Analysis 3-18 Deconvolution

81 86

Chapter 4 Hydraulic Fracture Design for Production Enhancement

4-1 Introduction to Hydraulic Fracturing

93



4-1.1 Brief History of Fracturing and Qualitative Description of Process

93



4-1.2 High Permeability vs. Low Permeability

94



4-1.3 Near-Well Flow Enhancement vs. Reservoir Stimulation

94



4-1.4 Acceleration vs. Increase of Reserves

95



4-2 Description of the Process

95



4-2.1 One of the Most Energy- and Material-Intensive Industrial Activities

95







4-2.1.1 Understanding the Significance of Pressure

96







4-2.1.2 Different Types of Pressure

96







4-2.1.3 Net Pressure

97







4-2.1.4 Effects of Tortuosity and Perforation Friction

98







4-2.1.5 Fluid Leakoff and Slurry Efficiency

101







4-2.1.6 Dimensionless Fracture Conductivity

102







4-2.1.7 Nolte-Smith Analysis – Predicting Fracture Geometry from Pressure Trends

103







4-2.1.8 Step Rate Tests

104







4-2.1.9 Minifracs

106



4-2.2 The Role of Advanced Technology in Design, Execution and Evaluation

109







4-2.2.1 Recent Advances and Breakthroughs

109







4-2.2.2 Pressure Matching

112







4-2.2.3 Getting Closer to Understanding Fracture Geometry

115







4-2.2.4 Real-Time Analysis

115





4-2.3 From Fracturing a Single Vertical Well to Complex Well-Fracture Architecture

4-3 Rock Mechanical Characteristics

116

116



4-3.1 Basic Definitions

116







4-3.1.1 Stress and Strain

116







4-3.1.2 The Poisson’s Ratio

116

III







4-3.1.3 Young’s Modulus

117







4-3.1.4 Other Rock Mechanical Characteristics

118







4-3.1.5 Hooke’s Law

119







4-3.1.6 Failure Criteria and Yielding

119



4-3.2 In-Situ Stress and Fracture Orientation

121







4-3.2.1 Overburden Stress

121







4-3.2.2 Horizontal Stresses

121







4-3.2.3 The Effect of Pore Pressure

122







4-3.2.4 Fracture Orientation

122







4-3.2.5 Stress Around a Wellbore and Breakdown Pressure

123



4-3.3 Fracture Shape

125







4-3.3.1 Two-Dimensional (2-D) Fracture Geometry

125







4-3.3.2 Elliptical Fracture Geometry

125







4-3.3.3 Limitations to Fracture Height Growth

126







4-3.3.4 Complex Fracture Geometry

127



4-3.4 Fracture Propagation, Toughness and Tip Effects

127







4-3.4.1 Linear Elastic Fracture Mechanics

127







4-3.4.2 Significance of Fracture Toughness

129







4-3.4.3 Complexity at the Fracture Tip

130



4-3.5 Measuring Rock Mechanical Characteristics

132







4-3.5.1 Introduction

132







4-3.5.2 Methods of Measurement

132







4-3.5.3 Core Selection/Sample Preparation Considerations

134







4-3.5.4 Deducing Elastic Properties without Core

135



4-4 Fluid Rheological Characteristics

137



4-4.1 Viscosity

137







4-4.1.1 Shear Rate, Shear Stress and Viscosity

137







4-4.1.2 Measurement of Viscosity

137



4-4.2 Fluid Behavior

138







4-4.2.1 Newtonian Fluids

138







4-4.2.2 Non-Newtonian Fluids

138







4-4.2.3 Apparent Viscosity

139



4-4.3 Flow Regimes

140







4-4.3.1 Plug, Laminar and Turbulent Flow

140







4-4.3.2 Reynold’s Number

140



4-4.4 Fluid Friction

141







4-4.4.1 The Influence of Flow Regime

141







4-4.4.2 Predicting Pressure Loss due to Friction

141



4-5 Optimum Treatment Design



IV

4-5.1 Dimensionless Productivity Index and Dimensionless Fracture Conductivity

141 143



4-5.2 Optimum Dimensionless Conductivity

144



4-5.3 Optimum Length and Width

144



4-5.4 Treatment Sizing and Proppant Placement Efficiency

145



4-5.5 Taking Into Account Operational Constraints

145



4-5.6 Using Fracture Propagation Models

146







4-5.6.1 Height containment

146







4-5.6.2 2-D models

147







4-5.6.3 3-D models

149



4-6 Predicting Production Increase

150



4-6.1 Pseudo-radial Concepts: Equivalent Wellbore Radius, Fracture Skin

150



4-6.2 Finite Reservoir Concepts, Folds of Increase

150



4-6.3 Combining Productivity Index and Material Balance

151







4-6.3.1 Pseudo-steady state

151







4-6.3.2 Combined transient and stabilized flow

151

4-6.4 Reservoir Simulation and Nodal Analysis

152





4-7 Fracturing Under Specific Circumstances

153



4-7.1 Tight Gas

153







4-7.1.1 The Importance of Inflow Area

154







4-7.1.2 Effective vs Actual Propped Length

154



4-7.2 High-Rate Gas Wells

155







4-7.2.1 Non-Darcy Flow

155







4-7.2.2 Wellbore Connectivity

155



4-7.3 High-Permeability Wells

155







4-7.3.1 The Importance of Fracture Conductivity

156







4-7.3.2 The Tip Screenout

156



4-7.4 Unconsolidated Formations

156







4-7.4.1 Re-Stressing the Formation

156







4-7.4.2 The Frac-Pack Treatment

157



4-7.5 Skin-Bypass Treatments

157



4-7.6 Condensate Dropout

158







4-7.6.1 Description of Phenomena

158







4-7.6.2 Mitigating the Effect of Dropout

158



4-7.7 Shale Gas and Coal Bed Methane

158







4-7.7.1 Gas Shales

158







4-7.7.2 Coal Bed Methane

158



4-7.8 Acid Fracturing

159







4-7.8.1 Description of Process

159







4-7.8.2 Estimating Fracture Conductivity

159







4-7.8.3 Use of Diversion Techniques

160



Chapter 5 Well Completions

5-1 Wellbore Construction

169



5-1.1 Effects of Uncertainty in Reservoir Description

169



5-1.2 Fitting Well Design to the Reservoir Potential

169



5-1.3 Well Design

170



5-1.4 Other Well Equipment

171



5-1.5 Well Integrity

171



5-2 Gas Well Cementing

172



5-2.1 General Objectives for Gas Well Cementing Operations

172



5-2.2 Gas Well Zonal Isolation

173



5-2.3 Review of Fundamental Cement Placement Practices

174



5-2.4 Predictive Wellbore Stress Modeling

174



5-2.5 Cement Slurry Criteria for Hydraulically Fractured Gas Wells

176







5-2.5.1 Slurry Criteria for Optimized Placement

176







5-2.5.2 Slurry Criteria for Anti-Gas Migration

177







5-2.5.3 Slurry Criteria for Long-Term Zonal Isolation

178





5-2.6 Fracturing Constraints Required to Maintain Long-Term Zonal Isolation

5-3 Identifying Gas Pays, Permeability and Channels

179

179



5-3.1 Pay and Water Zone Logging Methods

179



5-3.2 Effect of Formation Clays and Micro-porosity

180



5-3.3 Wellbore Deviation and Resultant Logging and Flow Problems

181



5-3.4 Completion Considerations for Naturally Fractured Reservoirs

181



5-3.5 Formation Characterization for Well Completions

182



5-4 Sizing the Completion

183



5-4.1 Initial Design Considerations

183



5-4.2 Flow Factors for Tubing Design

184



5-4.3 Tubing Selection

185



5-4.4 Multi-Phase Flow and Natural Lift

185



5-4.5 Multiphase Flow and Flow Correlation Options

186



5-4.6 Critical Lift Factors

187



5-4.7 Liquid Hold-up and Back Pressure

188



5-4.8 Lift Options for Gas Wells

188



5-5 Completion Design for Flow Assurance

188



5-5.1 Completion Design for the Prevention of Gas Hydrates

188



5-5.2 Formation Damage in Gas Wells, Completion Damage and Scales

190



5-5.3 Organic Deposits and Condensate Banking

190



5-5.4 Effects of H2S and CO2 on Corrosion

191

VI



5-6 Sand Control for Gas Wells

192



5-6.1 Why is the Sand Flowing?

192



5-6.2 Is Sand Flow All Bad?

192



5-6.3 Establishing and Monitoringa Sand-Free Rate

193



5-6.4 Sand Control Methods for Gas Wells

194



5-6.5 Reliability of Sand Control Completions

194



5-6.6 Repairing and Restoring Productivity in Wells hat Flow Sand

194

Chapter 6 Fracture-to-Well Connectivity

6-1 Introduction 6-2 Completion Techniques and Their Impact on Well Connectivity

201 202



6-2.1 Cased-Well Isolation Techniques

202



6-2.2 Open-Hole Completions

205



6-2.3 Open-Hole and Uncemented Liner Fracture Treatment Diversion

205



6-3 Perforating in General 6-4 Perforating for Fracturing

206 206



6-4.1 Oriented Perforations

206



6-4.2 Deviated and Horizontal Well Perforating

208





209







6-4.2.1 Production Impairment from Inefficient Fracture-to-Wellbore Contact

6-4.3 Underbalanced vs. Extreme Overbalanced Perforating

6-5 Near-Wellbore Fracture Complexity

211

213



6-5.1 Near-Wellbore Complexity

214



6-5.2 Diagnosing and Quantifying Near-Wellbore Complexity (Tortuosity)

215



6-5.3 Minimizing the Effects of Tortuosity

217



6-6 Mid- and Far-Field Fracture Complexity

218



6-6.1 An Introduction to Complex Fracture Growth

219



6-6.2 Evidence of Complex Fracture Growth

220



6-6.3 Consequences of Complex Fracture Growth

220

Chapter 7 Fracturing Fluids and Formation Damage

7-1 Introduction 7-2 Fracturing Fluid Function



7-2.1 Fracture Initiation

227 228 228

VII





7-2.2 Proppant Transport

7-3 Fracturing Fluid Rheology

229

230



7-3.1 Pressure Loss Gradient in the Fracture

232



7-3.2 Rheology in the Presence of Proppant Material and its Relation to Settling

234



7-3.3 Impact of Fluid Rheology on Fluid Loss

235



7-3.4 Calculation of Pressure Loss in the Wellbore Using Rheological Parameters

and the Virk Maximum Drag Reduction Asymptote

235



7-3.5 Advanced Rheology

235



7-3.6 Foam Rheology

236



7-3.7 Effect of Proppant on Rheology

237



7-3.8 Laboratory Rheology Measurements

239



7-4 Types of Fracturing Fluids

242



7-4.1 Water-Based Fluids

243







7-4.1.1 Low-Viscosity Fluids

243







7-4.1.2 Crosslinked Fluids

243







7-4.1.3 Borate Crosslinked Fluids

244







7-4.1.4 Metallic Ion Crosslinked Fluids

244







7-4.1.5 Delayed-Crosslink Systems

245







7-4.1.6 Function of Breakers in Water-Based Fluids

246







7-4.1.7 Water-Based Fluids in Gas Wells

246



7-4.2 Oil-Based Fluids

247



7-4.3 Energized fluids

248



7-4.4 Foams and Emulsions

249



7-4.5 Unconventional Fluids

250







7-4.5.1 Viscoelastic Surfactant Fluids

250







7-4.5.2 Viscoelastic Surfactant Foams

251







7-4.5.3 Emulsion of Carbon Dioxide with Aqueous Methanol Base Fluid

251







7-4.5.4 Crosslinked Foams

251







7-4.5.5 Non-Aqueous Methanol Fluids

252







7-4.5.6 Liquid CO2-Based Fluids

253







7-4.5.7 Liquid CO2-Based Foam Fluid

254





7-4.6 Acid Fracturing Fluid

7-5 Fracturing Fluid Additives

254

254



7-5.1 Additives for Water-Based Fluids

254







7-5.1.1 Friction Reducers

254







7-5.1.2 Gelling Agents

255







7-5.1.3 Biocide

257







7-5.1.4 Buffers

259







7-5.1.5 Crosslinkers

259







7-5.1.6 Breakers

260

VIII







7-5.1.7 Clay Stabilizers

262







7-5.1.8 Surfactants

262



7-6 Fluid Damage to Fractures and Sources of Productivity Impairment

262



7-6.1 Example Calculation of Productivity Impairment from Fracture Damage

264



7-6.2 Formation Damage from Saturation Changes

265







7-6.2.1 Fluid Retention

265







7-6.2.2 Rock/Fluid Interactions

267







7-6.2.3 Fluid/Fluid Interactions

267







7-6.2.4 Wettability Alterations

267





7-6.3 Formation Damage from Production

268

7-7 Fracturing Fluid Selection

268



7-7.1 Mineralogical Evaluation

269







7-7.1.1 X-Ray Diffraction (XRD) Analysis

269







7-7.1.2 Scanning Electron Microscopy (SEM)

270







7-7.1.3 Immersion Testing

271







7-7.1.4 Capillary Suction Time Testing

271







7-7.1.5 Core Flow Analysis

271



7-8 Selection of Fracturing Fluids for Applications in Gas Wells

273

Chapter 8 Proppants and Fracture Conductivity

8-1 Introduction

283



8-1.1 Overview

283



8-1.2 The Evolution of Proppants

283



8-1.3 Fracture Conductivity

285



8.2 Conductivity Impact on Fractured Well Production Potential

286



8-2.1 How a Propped Fracture Benefits Well Flow Rate

287



8-2.2 Steady-State Solutions

288



8-2.3 Transient Solutions

288



8-3 Proppants

289



8-3.1 Sands

289







8-3.1.1 Ottawa Sands

290







8-3.1.2 Brady Sands

290



8-3.2 Ceramic Proppants

291







8-3.2.1 Sintered Bauxite

291







8-3.2.2 Intermediate Strength Ceramic Proppant

291







8-3.2.3 Lightweight Ceramic Proppant

292



8-3.3 Resin-Coated Proppants

292

IX





8-3.4 Ultra-Lightweight Proppants

294

8-4 Proppant Properties, Testing Protocols, and Performance Considerations 295



8-4.1 Proppant Testing Procedure Standards

295



8-4.2 Proppant Sampling

296



8-4.3 Grain Size and Grain Size Distribution

297





297



8-4.3.1 Proppant Size Testing



8-4.4 Proppant Shape

298





299



8-4.4.1 Proppant Shape Testing



8-4.5 Proppant Bulk Density and Apparent Specific Gravity

299





300



8-4.5.1 Proppant Bulk Density and Specific Gravity Testing



8-4.6 Proppant Quality

300







8-4.6.1 Acid Solubility Testing

300







8-4.6.2 Turbidity Testing

301



8-4.7 Proppant Strength

301







8-4.7.1 Proppant Crush and Fines Generation

302







8-4.7.2 Crush Testing

302





8-4.8 Proppant Concentration

8-5 Proppant Placement

303

305



8-5.1 Effects on Fluid Rheology

305



8-5.2 Convection

305



8-5.3 Proppant Transport

305

8-6 Fracture Conductivity

308





8-6.1 API “Short-Term” Testing Procedure

308



8-6.2 ISO “Long-Term” Testing Procedure

309



8-6.3 Non-Darcy Flow Testing

310



8-6.4 Multiphase Flow Tests

311



8-6.5 Gel Damage

312



8-6.6 Other Factors

313



8-7 Proppant Flowback

314



8-7.1 Proppant Flowback Control

314



8-7.2 Curable Resin-Coated Proppant

315



8-7.3 Proppant Flowback Control Additives

315







8-7.3.1 Tackifiers

315







8-7.3.2 Fibers

315







8-7.3.3 Deformable Particles

315



8-8 Proppant Selection

316



8-8.1 Productivity Potential

317



8-8.2 Flowback Control

317



8-8.3 Availability

317



8-8.4 The Cost-Value Proposition

318



Chapter 9 Execution of Hydraulic Fracturing Treatments

9-1 Introduction 9-2 Function of Equipment

323 324



9-2.1 High-Pressure Pumping Equipment

324



9-2.2 Blending Equipment

325



9-2.3 High-Pressure Treating Lines and Manifolds

326



9-2.4 Nitrogen and Carbon Dioxide Pumping

326



9-2.5 Treatment Control Vans and Cabins

327



9-3 Equipment Quality Control

328



9-3.1 How Much Horsepower and What is the Pressure Rating?

328



9-3.2 How Many High-Pressure Lines and Suction Discharge Hoses to Use?

329



9-3.3 Standby Pumping and Blending Equipment

329



9-3.4 Absolute Essentials for Every Job

329



9-4 Quality Control for Fracturing Fluids

330



9-4.1 Quality Control of Water-Based Fracturing Fluids Before Arriving on Location

330



9-4.2 Fracture Fluid Blending Methods

334



9-4.3 Quality Control of Water-Based Fracture Fluids on Location

334



9-4.4 Quality Control of Other Fluid Systems

335



9-5 Quality Control of Propping Agents





9-5.1 Quality Control Guideline for Propping Agents

9-6 Quality Control and Execution of Acid Fracturing

336 338

338



9-6.1 Quality Control for Acid Fracturing



9-7.1 Diverting Agents

342



9-7.2 Ball Sealers

342



9-7.3 Limited Entry

343



9-7.4 Multi-Stage Fracturing with Mechanical Isolation

344



9-7.5 New Multi-Stage Fracturing Technology

346



9-7.6 Horizontal Well Multi-Stage Fracturing

347





9-7 Multi-Stage Fracturing and Isolation Methods

9-8 Pre-Fracture Diagnostics and Fracture Evaluation Tests 9-9 Real-Time Pressure Interpretation

339

342

347 350



9-9.1 Nolte-Smith Plot (see also Section 4-2.1.7)

350



9-9.2 Surface Treating Pressure as a Tool

351



9-9.3 The Effects of Perforations on Surface Treating Pressure

353



9-9.4 The Effects of Pipe Friction on Surface Treating Pressure

354



9-10 Fracturing Fluid Recovery (Flowback)

355 XI

Chapter 10 Fracturing Horizontal Wells

10-1 Introduction 10-2 Production from Transversely Fractured Gas Horizontal Wells





10-2.1 A Calculation for Transversely Fractured Gas Horizontal Wells

10-3 Open-Hole Horizontal Well Completions

363 365 366

369



10-3.1 Perforating

370



10-3.2 Zonal Isolation

370



10-4 Open-Hole Fracturing

371



10-4.1 Acid Fracturing Execution

372



10-4.2 Proppant Fracturing Execution

372



10-4.3 Cleanup

373



10-5 Cased-Hole Completions

373



10-5.1 Cementing Horizontal Wells

373



10-5.2 Perforating Cemented Completions

374



10-5.3 Zonal Isolation in Cased Completions

375



10-6 Fracturing of Cased-Hole Completions

376



10-6.1 Acid Fracture Execution

376



10-6.2 Proppant Fracturing Execution

377

10-7 Rationale and Conditions of Fracturing Horizontal Wells in Gas Formation 377

Chapter 11 Unconventional Gas

11-1 Introduction 11-2 Description of Unconventional Reservoirs 11-3 Production Mechanisms

383 383 385



11-3.1 CBM (Coalbed Methane)

385



11-3.2 Shale Gas Reservoirs

385



11-3.3 Shale Gas Reserves

386



11-4 CBM Reservoirs

387



11-4.1 Coalbed Description

387



11-4.2 CBM Fractured Systems

388



11-4.3 Adsorption/Desorption

390



11-4.4 Stimulation Techniques

391



11-4.5 Alternate Completions and Enhanced Production Techniques

393

XII



11-4.6 Fracture Modeling of CBM Wells

396



11-4.7 Fracturing Treatment Evaluation of CBM Wells

397



11-4.8 Estimation of Reserves and Production Data Analysis

398



11-5 Shale Gas

400



11-5.1 Shale Description

400



11-5.2 Thermogenic and Biogenic Systems

401



11-5.3 Ft. Worth Basin Barnett Shale

402





404



11-5.3.1 Barnett Shale Slickwater Treatment Design Considerations



11-5.4 Barnett and Woodford Gas Shale, Delaware Basin

406



11-5.5 Fayetteville Shale in Arkansas

409





409



11-5.5.1 Treatment Design Considerations Fayettville Shale



11-5.6 Woodford/Caney Shale, Arkoma Basin

410



11-5.7 Floyd Shale/Conasauga Shale, Black Warrior Basin (Alabama)

412



11-5.8 Mancos and Lewis Shales

412



11-6 Shale Treatment Design and Evaluation

413



11-6.1 Stimulation and Treatment Design for Shale Reservoirs

413



11-6.2 Fracture Modeling

416



11-6.3 Summary

416

Chapter 12 Fracturing for Reservoir Development



12-1 Introduction 12-2 Impact of Fracturing on Reservoir- or Drainage-Wide Production

427 428



12-2.1 Example Application of Infield Drilling and Fracturing of Gas Wells

429



12-2.2 Transient Flow of Fractured Gas Wells

430



12-3 Forecasting Natural Gas Well Performance and Recovery

431



12-3.1 A Case Study for Reservoir Recovery Using Unfractured and Fractured Wells

431



12-3.2 Field Development Strategy

432



12-4 Impact of Fracture Azimuth on Well Planning

434



12-4.1 Determination of Fracture Azimuth

435



12-4.2 Considerations Regarding Directional Permeability in the Reservoir

435



12-4.3 Barnett Shale Case Study

437



12-5.1 Purpose of Data Mining

441



12-5.2 Data Sources

441



12-5.3 Data Preparation

442



12-5.4 Selected Data Mining Tools

442



12-5.5 Data Mining Case History

443



12-5 Data Mining Techniques

441

XIII

Chapter 13 Technologies for Mature Assets 13-1 Introduction 13-1.1 Definition of a Mature Asset

455 455



13-1.2 Minimum Cost & Maximum Value

456



13-1.3 Motivation for Fracturing

457



13-1.4 New Technologies/Approaches

458



13-1.5 Reducing Treatment Costs

462



13-2 Candidate Selection

464



13-2.1 Regional Considerations

464



13-2.2 Neighborhood Considerations

465



13-2.3 Localized Considerations

466



13-2.4 Risk Ranking and Data Manipulation

467



13-2.5 Case Histories and Results

468



13-3 Fracture Design in Mature Fields 13-4 Depletion Considerations

469 470



13-4.1 Pore-Pressure Considerations

470



13-4.2 Fracturing Fluid Selection

472



13-4.3 Proppant Selection

473



13-4.4 Cleanout and Flowback

474



13-4.5 Mechanical Deployment

476

13-5 Re-Fracturing Operations

479





13-5.1 Re-Fracturing Case Histories

480



13-5.2 Candidate Selection for Re-Fracturing

481



13-5.3 Re-Fracture Re-Orientation

481



13-5.4 Improved Treatment Design

483

Nomenclature

491

Index

503

XIV

Preface

I

It is with great pleasure that I welcome you to Modern Fracturing: Enhancing Natural Gas Production. BJ Services Company is proud to be involved in developing and publishing this work. We hope you find this book to be instructive, informative and interesting. This book is intended for use by all industry professionals, not just those who are already familiar with the engineering concepts and field practices of hydraulic fracturing. The pages within comprise a state-of-the-art engineering manual for planning, preparation, performance and evaluation of hydraulic fracture treatments in natural gas reservoirs. We envision industry professionals throughout the world benefiting from the information in this book. Hydraulic fracturing is already the completion method of choice for most natural gas wells in North America. As global dependence upon natural gas increases, it seems likely the application and popularity of this completion method will only increase further and spread farther. The techniques described within this book are applicable to all gas reservoirs, not just to the low permeability formations typically developed in North America. We firmly believe fracturing is the best possible completion technique for each and every gas reservoir throughout the world. A wide range of knowledgeable authors from throughout the industry have come together to produce this book. On behalf of BJ Services, I want to thank them for their sharing their experience and knowledge, as well as for their hard work and dedication in completing such an ambitious project. We feel certain that in the years to come, each author will continue to be proud of his or her involvement in this undertaking. We also trust that readers like you will continue to improve “best practices” in developing natural gas resources worldwide with the insights derived from this significant work. Dave Dunlap Executive Vice President and Chief Operating Officer, BJ Services

XV

Foreword 

I

I was very pleased when my friend Michael Economides asked me to write the Preface to his new book. BJ Services Company should be complimented for sponsoring this effort and for attracting some of the world’s top experts to contribute. I know many of the contributors, and I am sure the result will be lasting and useful for years to come.   I am even more pleased that this specific book is put together for three reasons. The first is that natural gas will shortly become the premier fuel of the world economy. Second, hydraulic fracturing, already the most important production enhancement technique for oil wells, is absolutely indispensable for natural gas wells. Third, the existing know-how and skill sets of the fracturing community are dreadfully inadequate, especially in management.   Fracturing in the petroleum industry is no longer an experimental or daring activity by some hot-shot, brash engineers, often working against the established old thinking and even worse, conservative managers who still believe that economics equal cost reduction, ignoring the benefit from improved well performance. When enhanced production and injection performance is the motivation, nothing can compete with properly integrated fracturing.   Often, people are confused about the real impact from this well completion and stimulation technique. Most often, any improvement in production compared to what a well did before fracturing is considered a “success.” In reality, we already know how much a well should be producing after fracturing by using the concept of maximizing the JD, the dimensionless productivity index. Anything less than that should be considered a performance gap and managed as such. We have to push the limits and manage the completion and execution community to deliver what we know can be done.   All activities in a company must be integrated with hydraulic fracturing. We are by definition “can-do” people. So the idea that ultra-high production targets are “unrealistic and theoretical” should be replaced by developing and implementing the know-how and skill sets to deliver maximum performance.   Consider this: When my associates and I (including Michael) were working in Russia, in a five-year period we managed to double a company’s production, increasing by 20% per year to almost 2 million barrels per day while shutting-in 50% of the original well stock. Most of this success occurred by pushing the limits of hydraulic fracturing and integrating the other parts of the production system. And despite this success, we were constantly enhancing materials and increasing job sizes to push the calculated performance limits. We established two management rules: 1. All new wells and workovers must be fractured unless top management approves otherwise. 2. All frac jobs must be designed and executed to perform at the peak of the NPV bell curve unless top management approves otherwise. The point is that many companies require approval to do it right but delegate enough financial authority, no approval required, to do it wrong. We reversed this by giving enough authority (no approval required) to do it right and required top management approval to do it wrong. It is not so difficult to reproduce the same performance everywhere else. Just look at current worldwide well performance, and one can easily see huge gaps, including the largest and best-known multinational oil companies. Fracturing can go a long way to correct this obvious problem. Not only will the benefit to companies be immediate and large, but silly talk about “peak oil” and “twilight in the desert” will go away.   Joe Mach - February 2007

XVII

Contributing Authors Editors Michael J. Economides, University of Houston Tony Martin, BJ Services

Authors Bob Bachman, Taurus Reservoir Solutions Steve Baumgartner, BJ Services Harold Brannon, BJ Services Andronikos Demarchos, Hess Corporation Michael J. Economides, University of Houston John Ely, Ely & Associates, Inc. Satya Gupta, BJ Services Robert Hawkes, BJ Services Barry Hlidek, BJ Services George King, BP Randy Lafollette, BJ Services

XVIII

David Mack, Marathon Oil Mark Malone, BJ Services Tony Martin, BJ Services C. Mark Pearson, Golden Energy, LLC David Ross, InTuition Energy Associates Ltd. Martin Rylance, BP Gary Schein, BJ Services Peter Valkó, Texas A&M University Leen Weijers, Pinnacle Technologies Xiuli Wang, BP Don Wolcott, Aurora Oil and Gas

Acknowledgements

F

First and foremost, the editors would like to express their sincere gratitude to JC Mondelli, who has been the champion of this book within BJ Services from its initial conception, all the way through to printing and publication. Without his perseverance and vision, this publication would never have come about. We would also like to thank the senior management of BJ Services for providing funding and, especially, for allowing a great number of highly dedicated people to put their time and energy into writing chapters, in spite of their busy schedules. Our thanks to Joe Mach for gracing the book with his Preface and endorsement, and who also, in his unique style, reminded all of us why doing this book mattered in the first place. Writing this book was an added task both for our BJ Services colleagues and those from other companies and institutions, and the result is a testament to their dedication and professionalism. Putting together a multi-authored, multi-edged book is never an easy task and to no small measure, the authors deserve particular praise for persevering and having to respond to suggestions and editorial interference by two admittedly highly demanding and opinionated Editors. Compliments and credit are deserved by all of them, without whom this project would not have been possible. Special thanks go to Greg Salerno who shepherded many of the logistical tasks and kept a level-headed approach on the day-to-day management of the project. Thanks also to Garth Gregory and Margaret Kirick for their invaluable help with the organisation and administration of this undertaking. The copy-editor Stephanie Weiss served a key role in the final version of the book. She is a highly experienced and exceptional technical copy editor, a formidable “vacuum cleaner” for cleaning up deficiencies, omissions and errors. Her work reminded all that adherence to detail and perfection are essential in elevating a professional book to a different level. She was a rare find. Alexander M. Economides and his staff in the Energy Tribune, headed by Jay Clark and the publication assistants Alex Lewis and George Song, did a spectacular job in producing the book. They deserve special praise. Michael J. Economides and Tony Martin - September 2007

XIX

Michael J. Economides is a professor at the Cullen College of Engineering, University of Houston, and the managing partner of a petroleum engineering and petroleum strategy consulting firm. His interests include petroleum production and petroleum management with a particular emphasis on natural gas, natural gas transportation, LNG, CNG and processing; advances in process design of very complex operations, and economics and geopolitics. He is also the editor-in-chief of the Energy Tribune. Previously he was the Samuel R. Noble Professor of Petroleum Engineering at Texas A&M University and served as chief scientist of the Global Petroleum Research Institute (GPRI). Prior to joining the faculty at Texas A&M University, Economides was director of the Institute of Drilling and Production at the Leoben Mining University in Austria. Before that, he worked in a variety of senior technical and managerial positions with a major petroleum services company. Publications include authoring or co-authoring 14 professional textbooks and books, including The Color Of Oil, and more than 200 journal papers and articles. Economides does a wide range of industrial consulting, including major retainers by national oil companies at the country level and by Fortune 500 companies. He has had professional activities in over 70 countries. Tony Martin is business development manager for international stimulation at BJ Services Company. Since graduating from Imperial College, London, with an honors degree in mechanical engineering and a master's degree in petroleum engineering, Martin has spent 17 years in the oil industry and has completed engineering assignments around the world. Martin's primary interest has been hydraulic fracturing and stimulation, and he has been involved in production enhancement projects in more than 25 countries. He teaches fracturing, acidizing and sand control both in-house and externally. A constant theme in this teaching is the need to de-mystify the world of hydraulic fracturing, in an attempt to make the process more accessible and less intimidating. He is the author or co-author of numerous SPE papers and has served on the technical committees for several SPE events. He is also the author of BJ Services’ Hydraulic Fracturing Manual.

Chapter 1 Introduction to this Book Michael J. Economides, University of Houston and Tony Martin, BJ Services

1-1 Introduction This is a book about enhancing natural gas production using one of the most important and widespread well completion technologies — hydraulic fracturing. The book addresses the way that natural gas is produced from natural reservoirs (Chapter 2) and then describes diagnostic techniques that can pinpoint whether the well is producing as it should or whether intervention should be undertaken (Chapter 3), which is the central theme of this book. Hydraulic fracturing is introduced as the solution of choice, showing the idiosyncratic nature of natural gas wells compared to oil wells (Chapter 4). The subsequent two chapters address important peripheral issues whose successful or failed resolution may affect the well performance with equal or even more serious consequences than the fracture treatment itself. These issues include well completions (Chapter 5) and the extremely important well-to-reservoir (and fracture) connectivity (Chapter 6). The next two chapters deal with materials for fracturing: fluids and proppants (Chapters 7 and 8). Their selection is essential to the successful execution of the treatment. The execution itself becomes the next chapter, and practical issues are addressed there (Chapter 9). Then some modern applications are described. One chapter deals with fracturing horizontal wells, increasingly an important option among reservoir exploitation strategies (Chapter 10). Not only new well architecture but also newer reservoir targets are opening up, and natural gas demand points towards unconventional sources, namely coalbed methane (CBM), shale gas and very low-permeability formations. Technology makes their exploitation possible, and this is the subject of the next chapter (Chapter 11). Finally, two issues round out the book: Fracturing is employed in the full development of reservoirs (Chapter 12); and how mature fields, a

mainstay of the developed world such as the United States and Europe, can be revitalized through this process (Chapter 13). Before the technical issues are addressed it is essential to look at natural gas in the world economy, why it is becoming increasingly important and what are the reasons for all the excitement surrounding its enhanced production.

1-2 Natural Gas in the World Economy Although natural gas, with some 23% of all world energy demand in 2005, is still slightly behind coal (25.6%) as the world’s third-largest source of primary energy (oil still dominates at 38%), it is poised to move up because of significantly emerging new trade. Member countries in the Organization for Economic Co-operation and Development (OECD) and the USA, specifically, consume about 51% and 22% respectively of global natural gas, now comprising about 103 Tcf (2.9 Bm3) per year (Energy Information Administration, EIA, 2007).

Figure 1-1 The top 12 holders of natural gas reserves: Russia, Iran and Qatar dominate (EIA, 2006, BP Statistical Review, 2006, ET, 2007)

There are several obvious benefits to the use of natural gas. First, it is the cleanest-burning fossil fuel and produces fewer emissions and pollutants than either oil or, especially, coal. Second, the resource is becoming increasingly diverse. Since the early 1970s, world reserves of natural gas have been increasing steadily, at an annual



Modern Fracturing Table 1-1 Top 25 Countries Ranked According to Proved Natural Gas Reserves and identifying the proved reserves-to-production ratio (R/P) for each country Proved Natural Gas Reserves at January 1, 2006

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

Country

Trillion Cubic Feet (Tcf)

Trillion Cubic Meters (Tm3)

Share of Total

Russian Federation Iran Qatar Saudi Arabia United Arab Emirates USA Nigeria Algeria Venezuela Iraq Kazakhstan Turkmenistan Indonesia Australia Malaysia Norway China Egypt Uzbekistan Canada Kuwait Libya Netherlands Azerbaijan Ukraine Total World Sum of Top 25 Countries

1688 944 910 244 213 193 185 162 152 112 106 102 97 89 88 85 83 67 65 56 55 53 50 48 39 6347.79 5885

47.8 26.7 25.8 6.9 6.0 5.5 5.2 4.6 4.3 3.2 3.0 2.9 2.8 2.5 2.5 2.4 2.4 1.9 1.9 1.6 1.6 1.5 1.4 1.4 1.1 179.82 166.7

26.6% 14.9% 14.3% 3.8% 3.4% 3.0% 2.9% 2.5% 2.4% 1.8% 1.7% 1.6% 1.5% 1.4% 1.4% 1.3% 1.3% 1.1% 1.0% 0.9% 0.9% 0.8% 0.8% 0.8% 0.6% 100% 92.7%

Rest of World

463

13.1

7.3%

rate of some 5%. Similarly, the number of countries with known reserves has also increased from around 40 in 1960 to about 85 in 2005. The distribution among those countries, dominating the global proved reserves of natural gas, is shown in Fig. 1-1 and Table 1-1. One reason for anticipated increase in demand for natural gas is the public concern over environmental issues. Furthermore, forecasts of rapid increase in natural gas demand over the next two decades, in the biggest market of all, the United States, have been exacerbated by forecasts of declining production. Declining production forecasts have been extended to Canada, a reliable provider to the US thus far (EIA, Annual Energy Outlook, 2007). Although natural gas demand is expected to increase, such an increase in the near future will be driven by additional demand from current uses,



Cumulative Share of Total 26.6% 41.5% 55.8% 59.6% 63.0% 66.0% 68.9% 71.5% 73.9% 75.6% 77.3% 78.9% 80.5% 81.9% 83.2% 84.6% 85.9% 86.9% 88.0% 88.8% 89.7% 90.5% 91.3% 92.1% 92.7%

Reserves / Production (R/P) Years 80.0 >100 >100 99.3 >100 10.4 >100 52.2 >100 >100 >100 49.3 36.3 67.9 41.4 28.3 47.0 54.4 33.2 8.6 >100 >100 22.3 >100 58.7 65.1

primarily power generation. There is yet little overlap between the use of natural gas and oil in all large markets. However, certain developments on the horizon, including the electrifying of transportation, will push natural gas use to ever higher levels. Although potential natural gas supplies abound throughout the world, facilities and infrastructure to receive and distribute the product to market are expensive to build, and their development can easily be hindered by geopolitics. These reasons have historically inhibited natural gas from reaching its full potential in the world’s energy markets. Natural gas is transported either by pipeline (73% of internationally traded gas in 2005, EIA 2007), mainly across land masses, and by liquefied natural gas (LNG) transportation across the oceans (the remaining 27%). The rapid expansion of LNG infrastructure worldwide in the past decade is

Chapter 1 Introduction to this Book

enabling natural gas to penetrate many more markets through the development of many remote reserves once considered to be stranded and uneconomic to develop. Ongoing construction and plans to expand and build new LNG receiving terminals in North America (Canada, Mexico and the United States) are opening up rapidly growing gas imports, destined to support many new LNG supply chains worldwide. European and Asian markets are also hungry for LNG. But beyond the usual energy-demanding markets, China and India have both emerged from the developing world to become globally significant economies in their own right, both requiring massive energy imports to sustain future economic growth. But their approaches are very different; China is focused on manufacturing, India more on services. However, both have large populations with aspirations to lead high-energy consuming lifestyles. Together, they are promoting globalization that is putting pressure on the world’s energy resources and existing supply chain, traditionally directed to serving the OECD world. The rapid growth in China and India over the last few years has precipitated huge increases in demand for all energy sources, because of their lack of sufficient indigenous energy resources. This has left the rest of the world scrambling for the same sources of energy, including natural gas. The US is hampered by the myriad permit approvals required and public opposition to siting of LNG receiving terminals. Nevertheless, major US companies and others are investing heavily in building new LNG liquefaction infrastructure in Qatar, several countries in West Africa and Russia’s Sakhalin Island. Transportation is an essential aspect of the gas business because gas reserves are often quite distant from the main markets. Gas is far more cumbersome than oil to transport, and the majority of gas is transported by pipeline. There are well-developed networks in Europe and North America and a relatively adequate one in the former Soviet Union. However, in its gaseous state, natural gas is quite bulky – for the same time, a high-pressure pipeline can transmit only about one-fifth of the amount of energy that can be transmitted in an oil pipeline of the same size, even though gas travels much faster. When gas is cooled to –160 °C it becomes liquid and much more compact, occupying 1/600 of its standard gas volume. Where long overseas distances are involved, transporting gas

in its liquid state becomes economic. But the supply chain consists of expensive and specialized facilities both upstream and downstream, and generally requires dedicated marine vessels. The LNG industry is set for a large and sustained expansion as improved technology has reduced costs and improved efficiency along the entire supply chain during the past decade. This shift in the dynamics of the natural gas market will further commoditize and diversify the natural gas globally. New LNG carriers are 1000 ft long and require a minimum water depth of 40 ft when fully loaded. The global fleet of LNG carriers reached 217 by the end of 2006 (Wood et al., 2006) with more than 11 million tons of LNG capacity. The order book for new LNG marine carriers to 2010 is some 120 firm and 32 proposed, meaning the future fleet may exceed 370 vessels by the end of 2010. The fleet was just 90 vessels in 1995 and 127 vessels in 2000. The current fleet transports more than 140 million metric tons of LNG every year (converted to 7 Tcf), about 23% of gas trade internationally and about 6.5% of total gas consumed worldwide. Below is a discussion of the state of natural gas in three of the most important countries/ regions of the world which, for different reasons, are defining the present and future of natural gas in the world economy.

1-3 Russia: A Critical Evaluation of its Natural Gas Resources The dissolution of the Soviet Union in 1991 and its replacement by the Commonwealth of Independent States (CIS), prominent among which was the Russian Federation, was a significant geopolitical event, affecting the subsequent development of Russian resources – particularly natural gas. Contrary to widely held beliefs, if current trends continue, Russia likely will have a severe natural gas shortfall by 2010 (Moscow Institute of Energy Research, 2007). This prediction is astonishing, given that Russia has more gas reserves than any other country, and one of the largest reserves-to-production ratios. One of the reasons for the looming gas shortfall is that over the past several years, Russia has not invested sufficiently and lacks the technology to develop new gas fields to replace its rapidly depleting ones.





Figure 1-2 Russian gas resources, infrastructure, pipelines and future plans

Chapter 1 Introduction to this Book

1-3.1 The Resource Base Russia has the world’s largest proven natural gas reserves, estimated at 1,680 Tcf (EIA, 2007), about double those of Iran, the next largest. Russia is also the largest gas producer and exporter. In 2004, Russia’s gas production exceeded 22.4 Tcf and exports totaled 7.1 Tcf. In addition, the gas industry plays a significant role in the Russian economy, contributing about 26% of total GDP in 2004 (ET, 2007). Fig. 1-2 is an annotated map of Russia with all important natural gas-related information (EIA, 2007, www.Gazprom. com, and BP Statistical review, 2006). Table 1-2 The World’s Largest Natural Gas Reservoirs (EIA, 1994-2004, Interfax, 2005,www.gazprom.com, ET, 2007)

Figure 1-1 compares Russian gas reserves with those of the other major gas producing countries. Table 1-2 lists the 13 largest gas fields in the world. As is shown, Russia owns two-thirds of them (ET, 2007, EIA, 2007, www.Gazprom.com, and BP Statisitcal review, 2006). Gazprom, tracing its origins to the Soviet Gas Ministry, is the dominant gas company in Russia. Fig. 1-3 shows Russia’s total gas production and consumption and Gazprom’s contribution from 2000 to 2005, which accounts for about 80%. Gazprom is not only Russia’s largest gas producer, it also owns the entire gas pipeline infrastructure in Russia – all 155,000 km of it, along with the compressor stations. In addition, Gazprom controls the sole means of getting gas to domestic and export markets. 24 22 20 Tcf/year

There are complicated reasons behind the state of Russia’s natural gas industry. A thorough understanding of the industry and its history is required before we can discuss its future (see Section 1-3.2). Next, we examine Russia’s natural gas reserves, production and transportation.

Total Production

18

Gazprom's Share

16 14

Panhandle-Hugoton

South Pars

Hassi R’Mel

Bovanenko

Medvezh’ye

100 50 0

Rank 1 2 3 4 5 6 7 8 9 10 11 12 13

12 2000

Total Consumption 2001

2002

2003

2004

2005

Figure 1-3 Russian gas production and consumption and Gazprom’s contribution (EIA, 2004-2006, Interfax, 2005, www.gazprom.com, ET, 2007) Kharasevey

150

Shtokman

200

Orenburg

250

Yamburg

300

Urengoy*

350

North Dome, 1,200 (Tcf)

400

Zapolyarnoye

450

Umm Shaif/Abu el-Bukush

*Urengoy had been the world’s largest gas field for years until the North Dome was discovered.

Field North Dome Urengoy Yamburg Orenburg Shtokman Umm Shaif/Abu el-Bukush Zapolyarnoye Kharasevey Bovanenko Medvezh’ye Hassi R’Mel South Pars Panhandle-Hugoton

Reserves 1,200 275 200 200 200 175 150 150 125 100 100 100 80

Location Qatar/Iran Russia Russia Russia Russia Abu Dhabi Russia Russia Russia Russia Algeria Iran U.S.A.

The reason that Russia has given Gazprom control over its natural gas is the so-called “social obligation.” Through Gazprom, the Russian government subsidizes its inefficient domestic industries with low-priced natural gas. Gazprom sells most of its gas to domestic customers at a considerable discount. The wholesale price of 1,000 m3 of gas for a Russian household is around $15.90 (about $0.45/Mscf ). For industrial users, gas costs around $24.20 ($0.69/Mscf ). By comparison, in the European Union, household tariffs range from Finland’s $159 ($4.50/Mscf ) to Denmark’s $735 ($20.82/Mscf, ET, 2007). Clearly, Gazprom is losing large amounts of money on domestic sales, compared to international market prices, and must rely on export revenues for the difference.



Modern Fracturing

1-3.2 Russian Natural Gas Production Gazprom holds about one-third of the world’s natural gas reserves and produces about 80% of Russia’s natural gas. The remaining percentage comes from independent producers. The company operates 155,000 km of natural gas pipeline and 43 compressor stations. As the world’s largest producer and exporter, Russia is also a huge consumer of natural gas. The country produces an annual 21 Tcf, consuming 14.5 Tcf and exporting the rest (2002 numbers from EIA and ET, 2007). Despite the country’s huge reserves, natural gas production has remained essentially flat over the past several years, with a mild production increase (1.3%) forecast for 2008. In contrast to the natural gas stagnation, oil production has flourished. The immediate future of natural gas production in Russia does not allow for much optimism. The overall production decline forecast for Gazprom is quite steep, as shown in Fig. 1-4 (Moscow Institute of Energy Research, 2006). Considering that Russia’s domestic consumption is increasing by 2.5% annually, the current demand in Europe, Turkey and the Commonwealth of Independent States (CIS) for up to 325 Bm3 (ET, 2007), and China’s demand for 38 Bm3 (Moscow Institute of Energy Research, 2006) it’s clear that additional sources of natural gas must be found if Russia wants to play a major role in the future natural gas market. It’s equally clear that the problem of Russia’s looming gas shortage can only be solved by optimizing existing fields and through the rapid development and production of major fields such as Yamal, Shtokman



and Sakhalin. Obviously, implementing these solutions will require a substantial investment that Gazprom has not yet been able to make. One scenario for the potential contribution of independent producers shows a net increase of 100 Bm3 per year by 2010 (Moscow Institute of Energy Research, 2006). 600 Gazp ro

m’s fo

500

Combined Bcm/year

Gazprom’s major challenge is the aging of its major producing gas fields. Production from these fields is declining and studies project steep declines in Russia’s overall natural gas output between 2008 and 2020. According to projections from the Moscow-based Institute of Energy Research (2006), Russia will face a gas shortfall of about 100 Bm3 by 2010. Considering that Russia owns the largest gas reserves in the world and one of the largest reserves-to-production ratios (81.5 years compared to Algeria’s 55.4 and Canada’s 8.8, for example, from EIA, 2007, calculated by ET, 2007), the future of Russian natural gas production efforts is important globally.

rec ast p

rod uct io

nd ec lin e

400

300

200

100

0 2004

2010

Others Orenburg Astrakhan Urengoyskoye(achimov) Ety-Purovskoye Yuzhno-Russkoye Vyngayahinskoye Pestsovoye Yubileynoye

2015

2020

Zapadno-Tarkosalinskoye Komsomol'skoye Zapolyarnoye Medvezhye Aner'yakhinskoye Kharvutinskoye Yabburgskoye En-Yakhinskoye Urengoyskoye

Figure 1-4 Gazprom’s production decline forecast (Moscow Institute of Energy Research, 2007)

1-4 Alaska, its Natural Gas Resources and their Impact on US Imports It has been known for many decades that Alaska has prolific hydrocarbon resources, first with the discovery of oil in the south central part (Cook Inlet) in the 1960s and then with the 1969 discovery of Prudhoe Bay, the US’s largest field. Oil has been successfully commercialized in Alaska since the 1970s construction of the Trans-Alaskan pipeline that stretches from the North Slope to Southern Alaska. From there, oil is shipped to the lower 48 states.

Chapter 1 Introduction to this Book

1-4.1 Alaskan Reserves and Production There are two major hydrocarbon producing areas in Alaska today: the Cook Inlet region in southcentral Alaska and the Prudhoe Bay complex on the North Slope. The proved gas reserves for the Cook Inlet and the North Slope are 2 Tcf (6% of total) and 27 Tcf (94% of the total), respectively (EIA, 2007). Currently all the gas produced on the North Slope is re-injected for pressure maintenance except for the gas needed to maintain field operations and fuel the local villages. Figure 1-5 shows the historical production and the prediction of natural gas production to 2025. As can be seen, the 2006 production from the two areas is approximately 490 Bcf per year of gas and is expected to decrease to 240 Bcf per year by 2025 (Alaska Department of Natural Resources, 2006).

Clearly, Cook Inlet gas production is on decline while North Slope gas production remains stable – with its market limited to the local market without a natural gas export pipeline to larger markets. 600 Cook Inlet

North Slope

500 400 Bcf/Year

300 200 100

2024

2018

2012

2006

2000

1994

1988

1982

1976

1970

1964

0 1958

Despite the success of Alaskan oil production, and although it is widely known that natural gas exists in large quantities in the state, two important questions have always arisen: 1) in what kind and size of reservoirs is the gas trapped and 2) how can it be commercialized? Furthermore, after 30 years of Alaskan oil production and almost 15 years after its production peak, substantial natural gas exploitation from the state is still not forthcoming. We are convinced that Alaska has a very large natural gas resource base, larger than commonly accepted. Beyond the conventional gas reserves on the North Slope (about 100 Tcf ) and Cook Inlet (at least 30 Tcf ), perhaps as much as 1000 Tcf are in the form of coalbed methane and, at least, 500 Tcf as natural gas hydrates (Anchorage Chamber of Commerce, 2005). Economic and technical obstacles abound. The cost for exploiting conventional reserves, with or without government subsidies, has been a hindering factor, but other factors such as the emerging large LNG trade are having an impact. The most important question is whether Alaskan gas will be commercialized any time in the foreseeable future, and we shall discuss this issue in detail. This has major implications on the future of the state, the USA and the natural gas trade into the country.

Figure 1-5 Historic and forecast gas production (Alaska Department of Natural Resources, 2006)

The forecast in Fig. 1-5 is only for the current proved reserves of natural gas. If we consider the unconventional resources in Alaska, the natural gas resource base grows much larger. However the technology and economics for developing the unconventional resource base are major blockers. The two main unconventional gas reservoirs that capture a lot of attention are coalbed methane and natural gas hydrates. It is estimated that coalbed methane is prevalent in the northern and southern parts of the state, shown on the map in Fig. 1-6 (Alaska Department of Natural Resources, 2006). Sonora

Guadalupe

15

Barrow

Hermosillo

Russia

Alaska Fort Yukon

Empalme

Guaymas Fairbanks

Nome

Ciudad Obregon Canada Navojoa Anchorage Bering Sea Bituminous & Higher Rank

Huatabampo Cordova Los Mochis

Subbituminous Lignite Rual Sites with Sufficient Data for Drill Testing of Coalbed Methane Potential

Ciudad Constitucion

Baja California Sur

1

La Paz

Pacific Ocean

Figure 1-6 Location of potential coalbed methane reservoirs (Alaska Department of Natural Resources, 2006)



Modern Fracturing

Alaska’s estimated coal resources exceed 5.5 trillion tons and may contain up to 1,000 Tcf of gas (Alaska Department of Natural Resources, 2006). In 1994 the Alaska Div. of Oil and Gas drilled the state’s first coalbed methane test well near the town of Wasilla, located in the northern portion of Cook Inlet Basin. The well was drilled to a total depth of 1245 ft; coal was continuously encountered, with the thickest seam measuring 6.5 ft and a net coal thickness of 41 ft. Thirteen seams were sampled for gas content. The results were encouraging, but as elsewhere they are likely to suffer from the standard CBM problems: low permeability, water disposal and difficult and expensive application of hydraulic fracturing and horizontal well technologies. Our current assessment of the total resource base for natural gas in Alaska, derived from a number of references, is shown in Fig. 1-7. Cook Inlet Conventional, 30, 2%

• A gas pipeline from the North Slope through Canada to the Lower 48 states. • An All-Alaska gas pipeline from the North Slope to Valdez, where the gas would be converted into LNG and taken to markets outside Alaska in LNG tankers. • A “spur line” to take natural gas from one or more off-take points on the main gas pipeline (whichever route it takes) and deliver that gas to customers and users in Alaska. “All Alaska” LNG shipped from “All Alaska” “Y-Branches from ”All Alaska” Guadalupe

North Slope Conventional, 100, 6%

Sonora

Northern Route Southern Route

15

Barrow

Hermosillo

Alaska Fort Yukon Nome

Empalme

Fairbanks Guaymas Ciudad Obregon Canada Navojoa Anchorage

Bering Sea

Huatabampo Cordova Los Mochis Juneau

Ciudad Constitucion North Slope Hydrates, 529, 32%

Unalaska

Baja California Sur

1

Guasave Sinaloa Prince Rupert La Paz

Pacific Ocean CBM, 1000, 60%

Figure 1-7 Natural gas resource base in Alaska (Williams et al., 2005, Meyers, 2005, Hite, 2006, and Kornfeld, 2002)

It is clear the 2006 resource assessment shows the majority of potential reserves are locked in unconventional reservoirs. For these plays to be developed, investment and technology hurdles will need to be overcome. 1-4.2 The Uncertain Destiny of the North Slope of Alaska Natural Gas Methods to deliver natural gas to market from the North Slope of Alaska have been studied and proposed for over 30 years. The various schemes can be grouped into three major categories, with variations in each (Anchorage Chamber of Commerce, 2005). See Fig. 1-8.

10

Figure 1-8 Potential Alaskan natural gas pipeline routes

There are two variations on the gas pipeline to the Lower 48 states proposal: the Northern Route and the Southern Route. The Northern Route, also referred to as the ARC over-the-top route (ARC is for the Artic Resources Company that first proposed such a gas pipeline in the early 1980s), would start from Prudhoe Bay, move offshore into the Beaufort Sea and run parallel to the coastline eastward into Canada to the Mackenzie River Delta, where up to 20 Tcf of natural gas reserves are just waiting to be produced. From there, if Canadians have already built a pipeline to transport the Mackenzie River reserves to Alberta, the Alaskan Northern Route would simply reach and merge with it. On the other hand, if Canadians haven’t started yet to exploit the Mackenzie Delta reserves and a pipeline to Alberta is not available, the Northern Route pipeline would be extended to Alberta, and

Chapter 1 Introduction to this Book

1-4.3 Alaska in the Context of the United States and Canadian Natural Gas The current situation of the oil and gas industry in Canada adds substantial reasons for considering the over-the-top Northern Route (the green line on Fig. 1-8) the most suitable option for the whole NorthAmerican continent. Canada has been a net exporter of natural gas for many years, and all of that exported gas has been imported into the United States. This gas comprises about 90% of the natural gas imported into the US and about 17% of the total US natural gas consumption. Although this relationship has been

25 20 15 10 5

Coalbed Methane Mackenzie Delta

Conventional Gas Nova Scotia

2020

2019

2018

2017

2016

2015

2014

2013

2012

2011

2010

2009

2008

2007

0 2006

The Southern Route, also known as the Alaska Natural Gas Transportation System or as the Foothills, would also start from Prudhoe Bay, but it would go south half-way the length of Alaska, just south of Fairbanks, and then cross into the Yukon and north eastern British Columbia. The All-Alaska route, also known as the Yukon Pacific LNG Proposal, would start from Prudhoe Bay, run for 805 miles parallel to the Trans-Alaska oil pipeline to Valdez and then turn to the east to Anderson Bay. A final (but tremendously important) part of the All-Alaska proposal would be the construction of a liquefaction and shipment plant in the Anderson Bay, to enable shipping as LNG the natural gas coming from the North Slope to Asian markets (Japan mainly) and potential terminals along the Canadian and US West Coast.

2005

• Rerouting Prudhoe Bay natural gas in the Canadian pipelines network that currently delivers Alberta gas to markets in Canada and the Lower 48 states. • Building a dedicated pipeline that would transport Prudhoe Bay natural gas straight to the Northern Midwest pipeline network.

successful for many years, Canada can no longer be relied upon to single-handedly secure the future of US natural gas supply. A declining conventional natural gas resource has pushed Canada into investing in arctic, CBM and tight gas plays. To date however, those unconventional resources have contributed a very small percentage to that country’s overall production of natural gas. As is apparent in Fig. 1-9, the conventional natural gas supply in Canada is predicted to decline by roughly 35% from 2005 to 2020, while the production of unconventional/stranded gas is expected to increase dramatically by 2012 (CAPP, 2006a). This assumes in part the construction of the Mackenzie pipeline to get arctic gas to the south as well as an expectation that CBM will be economic to produce within the next two decades.

Production, Bcf/D

in all probability it would still offer the prospect to carry also the Mackenzie gas along with the North Slope gas. After the Alaskan natural gas is delivered in Alberta, there still would be the open issue of how to carry it down to the rest of the United States. The two systems currently discussed and proposed to accomplish this goal are:

Figure 1-9, Canadian natural gas production forecast (CAPP, 2006a)

The amount of gas Canada will have left over to export to the US remains in question, and this is what may push the building of the North Slope pipeline. The first issue is that Canadian natural gas consumption is expected to increase by 1.6% per year. This equates to a demand of almost 12 Bcf per day by 2020 (Stringham, 2006.). However, this consumption does not include the gas that will be needed to produce the Canadian tar sands. That Canada expects to be producing about 4 million barrels a day by 2020 (CAPP, 2006b, Fig. 110) means more of Canada’s natural gas will be used for this purpose. In fact, the 0.5 Mcf of gas needed to process each barrel of this crude equates to at least 2 Bcf per day natural gas needed to meet the production forecast for Canada’s oil sands.

11

Modern Fracturing 5000

1-5 Qatar Natural Gas

4500

12

1000 900 800 700 600 500 400 300 200 100

Figure 1-11 Dominant natural gas producers in the Middle East (after EIA, 2006)

Ira n

tar Qa

ud iA

rab

ia

UA E

0

Sa

This, of course, causes some concern because the total natural gas production from Canada in 2020 is expected to be about 18 Bcf per day, and Canada will be using 14 Bcf per day for its needs. This leaves 4 Bcf per day suitable to be exported to the US. However, the demand in the US over the next several years is far greater than what Canada can provide. The over-the-top Northern Route is surely not the ultimate solution to the constantly growing hunger for natural gas in North America. The over-the-top pipeline may never be built because of competition from LNG imports, which are expected to boom in the next several years if additional terminals can be built. Our assessment of the Alaskan gas resources, and in particular the North Slope basin, indicates some opportunities to develop a sustained market for natural gas with the U.S. Lower 48 states and Eastern Asian destinations (mainly Japan, South Korea and Taiwan) via LNG shipments. This motivates all the projects proposed by several groups of advocates for transporting the natural gas produced in the North Slope into the Lower 48 states market, as well as Eastern Asia. Nevertheless, a wide set of reasons leads us to believe that these projects cannot even be considered marginally competitive to LNG, especially when compared to the economically superior LNG shipped from the recently developed fields and facilities in countries such as Qatar, Russia, Australia and Indonesia. In fact, as is usual for large construction projects, the technical feasibility of North Slope natural gas exploitation must be weighed against the inexorable balance of the economics. This is the bottleneck where all the advocated Alaskan gas pipeline schemes become difficult to justify.

t

Figure 1-10 Prediction of Canadian heavy oil sands growth (CAPP, 2006b)

Ira q

20 20

20 18

20 16

Oil Sands

Eg yp

Conventional

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20 0 20 9 10

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Qatar is a small, independent nation on the western coast of the Persian Gulf. The country has good relationships with its Middle Eastern neighbors like Iran, and it has been leading the region in democratic reforms. Before the discovery of its vast hydrocarbon reserves, dominated by natural gas, Qatar was a poor country. However, by 2006 Qatar had achieved one of the world’s highest per capita gross domestic products (Central Intelligence Agency, 2006). Figure 1-11 shows that compared to its neighbors in the Middle East, Qatar is a leader in natural gas reserves. Iran and Qatar have comparable amounts of gas reserves. This is because Qatar’s super giant North Field and Iran’s super giant South Pars Field overlie on the broad Qatar arch. The Qatar arch subdivides the Khuff formations into two basins located northwest (North Field) and south east (South Pars). The North Field reservoir boundary is the political boundary between Iranian and Qatari waters as shown in Fig. 1-12. (Note: The names of the fields in Fig. 1-12, at times cause confusion. Qatar’s North Field is north of Qatar but south of the Iranian demarcation boundary. The Iranian field known as South Pars is actually in southern Iranian waters but north of Qatar’s North Field. The two fields constitute essentially a single geological structure, one of the largest gas accumulations in the world.)

ria

3000

Sy

3500

Proven Reserves, Tcf

Production, Mbbl/D

4000

Chapter 1 Introduction to this Book

South Pars North Field Al Manamah

Doha

Persian Gulf

Figure 1-12 The North Field extends off the coast of Qatar and is divided from Iran’s South Pars Field by a political boundary

1-5.1 North Field Characteristics and Development The North Field is the largest non-associated gas field in the world with estimated reserves of 900 Tcf of gas. Al-Siddiqi and Dawe (1999) explain that the North Field produces from four intervals in the Khuff formation. These zones are Permian dolomite carbonates located at depths of 10,000 to 13,000 ft with thickness ranging from 1,300 to 2,000 ft. The gas produced is rich in condensates. Given the tremendous size of natural gas reserves, major investments for the production and transportation of natural gas have followed. QatarGas was founded 13 years after the North Field was discovered. Eight years later, in 1992, the first customer, Chubu Electric of Japan, signed a sales and purchase agreement (SPA) with QatarGas for 4 million metric tons per year (Mta) of LNG. Two years later, Chubu Electric and other buyers signed a second SPA for 2 Mta of LNG. Two years later, in January 1997, the first LNG ship delivered gas to Japan. Efficient production, processing, refrigeration, storing, loading and shipping processes for LNG established by QatarGas have allowed it to deliver 100 loads of LNG to Japan every year since 1997 (EIA, 2007). In October of 2002, BP signed an SPA with QatarGas for 0.75 Mta of LNG to deliver to Spain. To exploit the tremendous demand for natural gas in Europe, ExxonMobil signed an agreement with

QatarGas to deliver 15 Mta of LNG to the UK market. A year later, in June 2005, Shell signed a SPA for 7.8 Mta of LNG for Europe and North America. The contracts for LNG have been progressively getting bigger and bigger since the first SPA with Japan. RasGas was founded in 1993. In 1995, an SPA with KOGAS, a Korean company, was agreed upon. Two years later the SPA was increased to 4.9 Mta, and in April of 1999 the first LNG cargo left for Korea. The delivery time of LNG to KOGAS was four years, like the 4-year delivery time between QatarGas and Chubu Electric. Also, an SPA with Petronet of India was signed to deliver 5 Mta of LNG. The delivery time for this order was five years, and the first LNG cargo left for India in 2004. RasGas also signed a 25year SPA for 3.5 Mta of LNG with Edison Gas of the United States. The SPA agreement was altered to increase the LNG volume to 4.6 Mta in 2003. RasGas signed an agreement with ExxonMobil to deliver 15.6 Mta of LNG to the United States. In February of 2005, an SPA with Distrigas of Belgium was signed to deliver 2.07 Mta of LNG (EIA, 2007). It is interesting to note the disparity in development between Qatar and Iran. Qatar and Iran have comparable gas reserves. Despite its sizeable gas reserves, Iran remains a net importer of natural gas. According to Wood et al. (2006), Iran’s surging internal demand for natural gas and stiff gas market competition from Russia and Azerbaijan will present Iranian leadership with difficult hurdles to overcome in order to externally market those reserves. While Iran is relatively isolated politically, Qatar has been busy forging relationships with the major natural gas consumers such as Japan, the United Kingdom, and the United States. The Qatari civil reforms, natural gas resource development, and good political relationships have culminated in its enormous success.

1-6 Fracturing for the Efficient use of Existing Resources and for Increasing Recovery Factor Since its advent in the 1950s, hydraulic fracturing has proven to be a very robust technology, lending itself to many different types of reservoirs. Additionally, although fracturing is a very complex process, it remains – for the most part – extremely forgiving of the

13

Modern Fracturing

industry’s overall general lack of expertise. These two factors have led to fracturing becoming the most widely used completion process. Fracturing has its roots firmly planted in the gas production industry. Even with the widespread use of fracturing for oil and injection wells, gas well fracturing is still the largest sector of the industry, by a wide margin (see Fig. 1-13). The majority of gas reserves in North America are only produced as a result of hydraulic fracturing. However, apart from a few specific locations (such as China, Argentina, Australia and – to a lesser extent – Russia), the global gas industry has failed to embrace this technology to even a fraction of the extent it is used in North America (see Fig. 1-14).

Unconventional Gas 28%

Tight Gas 42%

Oil 25%

Other 5%

Figure 1-13 Targets of Fracture Treatments Performed in the USA in 2006 (BJ Services, 2006)

Canada 17%

USA 70%

Rest of the World (excl. China) 13%

Figure 1-14 Estimated Proportion of Fracturing Treatments Performed in the USA and Canada, compared to the Rest of the World, excluding China (BJ Services, 2007)

14

One reason for this is the relative size, immaturity and prolific productivity of the gas reservoirs outside North America (see earlier discussions in this Chapter). Another reason is that the USA is the only country in the world where the landowners often own the mineral rights under their land. In every other country, the government controls the mineral resources and decides how they are exploited. Consequently, in the US there is often a very fragmented approach to the depletion of a reservoir, habitually concentrating on wellbore tactics, whilst elsewhere gas companies are more inclined towards the “big picture,” allowing more focus on field development strategies. Canada sits somewhere in the middle, having inherited the British system of Crown ownership of all mineral rights, while at the same time being heavily influenced by the activities of the US gas industry. In any case, small operators, eager to maximize short-term cash flow, have always been the driving force behind the popularity of fracturing in the US. Outside the US, Canada, China, Argentina and – possibly – Russia, fracturing has failed to reach the “critical mass” that has allowed the easy exploitation of its potential in these countries. Operating companies often complain that service companies do not have the infrastructure and expertise necessary for the cost-effective execution of fracturing operations in a specific geographic area. At the same time, service companies complain that operators do not provide enough work to economically justify building up suitable equipment and personnel resources. This is a “Catch-22” situation that can only be overcome by a) field development projects that are large enough to justify the introduction of a complete fracturing operation, and b) having an operating company (or companies) with sufficient confidence in the fracturing process to proceed with fracturing-dependent field development. Outside the above-mentioned countries, there are very few companies with sufficient institutional confidence in the fracturing process to make this happen. Even companies based in North America with considerable experience in fracturing seem to be unable to translate this confidence internationally. However, confidence in the fracturing process is required if many countries and companies are to fully exploit their gas resources. It is hoped that the processes and experiences described in this book will help significantly with this process.

Chapter 1 Introduction to this Book

Ultimately, producing hydrocarbons from a reservoir comes down to efficient management of the pressure in the reservoir. Pressure, which is stored energy (or more accurately, energy per unit volume), lies at the heart of everything we do. The basic principle of hydrocarbon production is the fact that liquids and gases will move from a region of high energy (or pressure) to a region of low energy, if a flow path exists. When we drill a well, we are creating a region of low pressure at the wellbore, and the conductive path is provided by the formation’s permeability. If we are lucky, there is sufficient energy left in the liquids and gases to reach the surface, once they have arrived at the wellbore. In many cases, however, extra energy has to be supplied via pumps or gas lift systems, in order to achieve flow to the surface. Ultimately, the efficient production of a reservoir is all about getting the maximum amount of oil and gas out, while using the minimum energy to do so. In gas reservoirs, it is difficult to provide extra energy after the gas reaches the wellbore. Although the density of the gas means that far less energy is required to reach the surface, often there is insufficient energy to produce the gas at sufficient rates. In its most basic form, fracturing can be thought of as a process that minimizes the energy required for the gas to reach the wellbore. This has several benefits:

far further into the reservoir, providing much greater depletion at the drainage perimeter. This effect can be maximized if the fracture azimuth is known. Wells can be drilled further apart in the direction of fracture propagation and closer together in the perpendicular direction, allowing maximum depletion of resources. Such a strategy significantly reduces the localized or “pin-point” depletion caused by the wellbores and spreads the effects of the depletion much more evenly across the reservoir. Finally, it must be remembered that although fracturing can be very effectively used to redevelop a mature field (see Chapter 13), it reaches maximum effectiveness when applied to a new reservoir:

1. It leaves more energy available for bringing the gas to the surface. 2. It can reduce the minimum energy (i.e. pressure) required in the reservoir to achieve economic flow to the wellbore, thereby extending production beyond reserve levels that might otherwise be considered “depleted.” In gas reservoirs, pressure is reserves, and so minimizing energy losses during production can significantly increase the ultimate recovery from the reservoir. 3. It minimizes secondary pressure-dependent effects such as water production (and associated problems such as scale deposition, fines migration and hydrate formation), retrograde condensation within the reservoir, and non-Darcy flow.

1. After the fracture azimuth has been obtained, the placing of wells can be planned to allow for increased drainage efficiency in the direction of fracture propagation. This could easily result in the need for fewer wells. 2. Wellbores can be planned to facilitate fracturing. As discussed in Chapter 5, the wellbore can be completed in such a fashion as to make fracturing easy and reliable (whereas the completion often does just the opposite). In addition, perforations can also be planned to maximize the effectiveness of fracturing operations (see Chapter 6). Of all the things under our control, the perforations will have the single biggest effect on the outcome of any individual treatment. Finally, multiple intervals can be more effectively and efficiently stimulated on new wells than on existing wells (see Chapter 9). 3. Surface facilities also can be planned to facilitate fracturing, especially with regard to fluid recovery and handling of returned proppant. 4. Long-term relationships can be built between operating companies and service providers. This allows for building and retaining experience and expertise in both operational and technical personnel. This also improves project economics due to efficiencies of scale and a greater ability to plan for the long term.

Fracturing effectively allows the wellbore to achieve a significant size in comparison with the reservoir. This allows the wellbore’s localized depletion to spread

Hydraulic fracturing of gas wells is no longer a luxury – instead, it is now a necessity. For economic, environmental and political reasons, operating

15

Modern Fracturing

companies and national operating companies have an obligation to maximize the recovery from their resources, while doing this as efficiently as possible. There is no question that hydraulic fracturing will continue to be a major tool for achieving these goals. Fracturing will only increase in importance as reserves become more depleted and harder to exploit. Hydraulic fracturing remains an inherently complex process, and as a result is viewed with suspicion by many resources owners and asset managers. However, the reality is that fracturing is no more complex than any number of widely accepted practices, such as drilling deviated wellbores, performing pressure transient analysis, studying petrophysics and stimulating the reservoir. Yet these techniques are widely practised and trusted throughout the world, whereas hydraulic fracturing remains a largely unexploited technique outside of North America. Consequently, the authors of this book hope its publication will have two profound effects. First, we hope this book will help to improve the techniques and practices employed by those who are already familiar with hydraulic fracturing. Secondly, we hope this book will increase the utilization of fracturing technology in reservoirs and geographic areas that have hitherto failed to appreciate the potential of this reservoir development technique.

References “Alaska Oil & Gas Report,” Alaska Department of Natural Resources, Div. of Oil and Gas, Anchorage, Alaska (May 2006). Al-Siddiqi, A., and Dawe, R.A.: “Qatar’s Oil and Gasfields: A Review,” Journal of Petroleum Geology (October 1999) 22, 4, 417. Anchorage Chamber of Commerce: “Natural Gas and Alaska’s Future,” 2005. BJ Services Company: Internal Marketing Information (2006). BJ Services Company: Internal Marketing Information (2007). BP Statistical Review, 2006 Canadian Association of Petroleum Producers (CAPP): “Canadian Natural Gas, A stable Source of Energy

16

Supply,” 2006a. CAPP: “Canadian Crude Oil Supply and Forecast 2006-2020,” 2006b. Central Intelligence Agency: Fact Book, 2006. Energy Information Administration: Annual Energy Outlook, 2007. Energy Information Administration, 2007 http://www. eia.doe.gov/pub/international/iealf/table18.xls Energy Tribune, Various articles, February, 2007. Hite, D.M.: “Cook Inlet Resource Potential ‘Missing Fields’ Gas (and oil) Distributive/Endowment A Log-Normal Perspective,” presented at the South Central Alaska Energy Forum, September 2006. Kornfeld, S.: “Alaska North Slope Gas Task Force,” Presentation to the US Department of Energy, April 2002. Meyers, M.D.: “Alaska Oil and Gas Activities,” presentation to The House Special Committee on Oil and Gas, January 2005. Moscow Institute of Energy Research: “Russia’s Natural Gas Future,” 2006 (in Russian). Stringham, G.: “Canadian Natural Gas Outlook,” presentation by CAPP, October 2006. Williams, T.E., Millheim, K., and Liddell, B.: “Methane Hydrate Production from Alaskan Permafrost, Final Report,” (March 2005). Wood, D., Mokhatab, S., and Economides, M.J.: “Iran Stuck in Neutral,” Energy Tribune (December 2006). Wood, D., Mokhatab, S., and Economides, M.J.: “Global Trade in Natural Gas and LNG Expands and Diversifies,” Hydrocarbon Processing, 2007. www.interfax.com, 2006 www.Gazprom.com, 2007

Michael J. Economides is a professor at the Cullen College of Engineering, University of Houston, and the managing partner of a petroleum engineering and petroleum strategy consulting firm. His interests include petroleum production and petroleum management with a particular emphasis on natural gas, natural gas transportation, LNG, CNG and processing; advances in process design of very complex operations, and economics and geopolitics. He is also the editor-in-chief of the Energy Tribune. Previously he was the Samuel R. Noble Professor of Petroleum Engineering at Texas A&M University and served as chief scientist of the Global Petroleum Research Institute (GPRI). Prior to joining the faculty at Texas A&M University, Economides was director of the Institute of Drilling and Production at the Leoben Mining University in Austria. Before that, he worked in a variety of senior technical and managerial positions with a major petroleum services company. Publications include authoring or co-authoring 14 professional textbooks and books, including The Color Of Oil, and more than 200 journal papers and articles. Economides does a wide range of industrial consulting, including major retainers by national oil companies at the country level and by Fortune 500 companies. He has had professional activities in over 70 countries.

Dr. Xiuli Wang is a petroleum engineer with BP in Houston, currently functioning as a completion engineer with worldwide responsibilities. She serves as the project leader of a major companywide project in injection well completions and sand control. She has more than seven years of service with BP, from work as a reservoir engineer to full-field modeling work. She supported the completion team as a petroleum engineer, developing flux models and guidelines for minimizing erosion of producer well screens. Finally, she was the lead production engineer for a major field in the continental shelf. Before immigrating to the United States, Wang earned a MS degree from China’s premier technical university, Tsinghua University, followed by six years of work with one of China’s major petroleum companies, Sinopec. She joined BP after earning a PhD in chemical engineering, with a number of professional publications in the fundamentals of multi-phase and complex flow through porous media. She was recently featured in a major journal as an exemplary representative of Chinese-born engineers employed by the US based petroleum industry. In 2007, she was named the US 2007 Asian American Engineer of the Year.

Chapter 2 Natural Gas Production Michael J. Economides, University of Houston and Xiuli Wang, BP

2-1 Introduction The natural gas we use in everyday life - as a source of space heating after combustion, for power generation even as industrial feedstock - is primarily methane. Such fluid has been stripped of higher-order hydrocarbons. This is not how natural gas appears just one or two steps before its ultimate use. At the present time there are two main sources for natural gas as a petroleum production fluid. First, gas is found in association with oil. Almost all oil reservoirs, even those that in-situ are above their bubble point pressure, will shed some natural gas, which is produced at the surface with oil and then separated in appropriate surface facilities. The relative proportions of gas and oil produced depend on the physical and thermodynamic properties of the specific crude oil system, the operating pressure downhole, and the pressure and temperature of the surface separators. The second type of gas is produced from reservoirs that contain primarily gas. Usually such reservoirs are considerably deeper and hotter than oil reservoirs. We will deal with the production characteristics of these reservoirs in this chapter. There are other sources of natural gas, one of which (coalbed methane desorbed from coal formations) is already in commercial use. This process is described in relative detail in Chapter 11 of this book. In the far future, production from massive deposits of natural gas hydrates is likely, but such eventuality is outside the scope of this book.

2-2 Idiosyncrasies of Dry Gas, Wet Gas and Gas Condensates Petroleum fluids found in nature, are always multicomponent mixtures of hydrocarbons. Characterizing these fluids is difficult both from a scientific/laboratory point of view and in production operations. Thus,

petroleum engineers have traditionally examined oil field hydrocarbons in the context of phase behavior, separating the mixture into liquid and gas. Fig. 2-1 shows a two-phase envelope with a pseudocritical point (C) separating the bubble-point curve (AC) from the dew point curve (BC) at a constant composition. Emanating from the pseudocritical point are equal saturation quality curves (DC, EC) inside the two-phase envelope. To the right of the pseudocritical point is the maximum possible temperature, called the cricondentherm. Natural gas reservoirs whose pressure and temperature lie to the right of the cricondentherm are known as “dry gas” reservoirs. If fluids from these reservoirs stay outside of the two-phase envelope in traversing a pressure and temperature path from the reservoir to the wellhead, they will produce only dry gas. If the path from reservoir to surface carries the fluid into the two-phase envelope – below the cricondentherm – “wet gas” is produced.

Figure 2-1 Phase diagram showing regions of retrograde condensate

Between the critical point and the cricondentherm, liquid emerges as the pressure declines below the dew point value (at a constant temperature) from point 1 to point 2, shown in Fig. 2-1. As pressure decreases from point 2 to point 3, the amount of liquid in the reservoir increases. Further pressure reduction causes liquid to revaporize. This is the region of retrograde condensation (McCain, 1973). Many natural gas reservoirs behave in this manner. During production from such reservoirs, the pressure gradient formed between the reservoir pressure and the flowing bottomhole pressure may result in liquid condensation near the wellbore (Wang, 2000).

19

Modern Fracturing

One way to prevent condensate formation is to maintain the flowing well bottomhole pressure above the dew point pressure. This is often not satisfactory because the reservoir pressure drop may not be sufficient to achieve economic production rate. An alternative is to allow condensate to form but occasionally to inject methane gas into the producing well. The gas dissolves and sweeps the condensate into the reservoir. The well is then put back in production. This approach is repeated several times in the life of the well. It is known as gas cycling (Sanger and Hagoort, 1998).

2-3 Inflow from Natural Gas Reservoirs 2-3.1 Fundamentals of Non-Darcy Flow in Porous Media Fluid flow is affected by the competing inertial and viscous effects, combined by the well-known Reynolds number whose value delineates laminar from turbulent flow. In porous media the limiting Reynolds number is equal to 1 based on the average grain diameter (Wang and Economides, 2004). Because permeability and grain diameter are well connected (Yao and Holditch, 1993), for small permeability values (e.g., less than 0.1 md) the production rate is generally small, flow is laminar near the crucial sandface and it is controlled by Darcy’s Law: −

dp µg = vg , dx k g

(2-1)

where x represents the distance, p the pressure, vg the gas velocity, μg the gas viscosity, kg the effective permeability to gas. A small amount of connate water is almost always present besides the gas. The water saturation is often small and it does not affect the gas permeability significantly. Therefore, kg is often equal to k, the single-phase permeability. Non-Darcy flow occurs in the near-wellbore region of high-capacity gas and condensate reservoirs as the flow area is reduced substantially, the velocity increases, inertial effect becomes important, and the gas flow becomes non-Darcy. The relation between pressure gradient and velocity can be described by the Forchheimer (1914) equation:

20

−

dp µg = vg + ρ g β g vg 2 , dx k g

(2-2)

where ρg is the gas density and βg is the effective nonDarcy coefficient to gas. The condensate liquid may flow if its saturation is above the critical condensate saturation, Scc (Wang and Mohanty, 1999a). Additional condensate dropout because of the further reduced pressure will aggravate the situation. Therefore, two phenomena emerge Non-Darcy effects and a substantial reduction in the relative permeability to gas. Because of the radial nature of flow, the near well bore region is critical to the productivity of a well. This is true in all wells, but it becomes particularly serious in gas-condensate reservoirs. Forchheimer’s equation describes high-velocity, single-phase flow in isotropic media. Many naturallyoccurring porous media are, however, anisotropic (Wang et al., 1999). A direct understanding of multiphase non-Darcy flow behavior in porous media that are anisotropic at the pore-scale is studied elsewhere (Wang, 2000, Wang and Mohanty, 1999b). 2-3.2 Transient Flow To characterize gas flow in a reservoir under transient conditions, the combination of the generalized Darcy’s law (rate equation) and the continuity equation can be used. Thus: φ

 k  ∂ρ = ∇ ρ ∇p ,  µ  ∂t



(2-3)

where φ is porosity, and in radial coordinates: φ

∂ρ 1 ∂  k ∂p  = ρ r . ∂t r ∂r  µ ∂r 

(2-4)

Because gas density is a strong function of pressure (in contrast to oil, which is considered incompressible), the real gas law can be employed: ρ=

m pM = , V ZRT

(2-5)

and therefore ∂  p  1 ∂  k ∂p  φ   = rp .   ∂t  Z  r ∂r  µZ ∂r 

(2-6)

Chapter 2 Natural Gas Production

In an isotropic reservoir with constant permeability, Eq. 2-6 can be simplified to: φ ∂  p  1 ∂  p ∂p  (2-7) = r .   k ∂t  Z 

 r ∂r  µZ ∂r 

The solution of Eq. 2-13 would look exactly like the solution for the diffusivity equation cast in terms of pressure. Dimensionless time is (in oilfield units): 0.000264kt φ(µ ct )i rw

tD = , 2

Performing the differentiation on the right-hand side of Eq. 2-7 - assuming that the viscosity and gas deviation factor are a small functions of pressure and rearranging gives: φµ ∂p 2 ∂ 2 p 2 1 ∂p 2 (2-8) = + . 2 kp ∂t

∂r

r ∂r

For an ideal gas, cg = 1/p and, as a result, Eq. 2-8 leads to: ∂ 2 p 2 1 ∂p 2 φµc ∂p 2 (2-9) + = . ∂r 2

r ∂r

k

∂t

This approximation looks exactly like the classic diffusivity equation for oil. The solution would look exactly like the solution of the equation for oil, but instead of p, the pressure squared, p2, should be used, as a reasonable approximation. Al-Hussainy and Ramey (1966) used a far more appropriate and exact solution by employing the real gas pseudo-pressure function, defined as: p

p µZ

m( p ) = 2 ∫ dp, po

(2-10)

where po is some arbitrary reference pressure (usually zero). The differential pseudo-pressure, Δm(     p), defined as m( p) – m( pwf ), is then the driving force in the reservoir. Using Eq. 2-10 and the chain rule: ∂m( p ) ∂m( p ) ∂p = . ∂t ∂p ∂t

(2-11)

(2-14)

and dimensionless pressure is kh[m( pi ) − m( pwf )]

pD =

1424qT

.

(2-15)

Equations 2-13 to 2-15 suggest solutions to natural gas problems (e.g., well testing) that are exactly analogous to those for an oil well, except now it is the real gas pseudopressure functions that needs to be employed. This function is essentially a physical property of natural gas, dependent on viscosity and the gas deviation function. Thus, it can be readily calculated for any pressure and temperature by using standard physical property correlations. By analogy with oil, transient rate solution under radial infinite acting conditions can be written as: q=

kh[m( pi ) − m( pwf )] 1638 T −1

  k − 3.23 + 0.87 s  , ×  log t + log 2  (2-16) φ(µ ct )i rw  

where q is gas flow rate in Mscf/d, pi is reservoir pressure, pwf is the flowing bottomhole pressure, φ is porosity, ct is the total compressibility of the system, and s is the skin effect. Equation 2-16 can be used to generate transient IPR (Inflow Performance Relationship) curves for a gas well. 2-3.3 Steady State and Pseudosteady State Flow

Similarly, ∂m( p ) 2 p ∂p = . ∂r µZ ∂r

(2-12)

Therefore, Eq. 2-9 becomes ∂ 2 m( p ) 1 ∂m( p ) φµct ∂m( p ) + = . ∂r 2 r ∂r k ∂t

Starting with the well known Darcy’s law equation for oil inflow, kh( pe − pw )

q= , r

(2-13)

141.2 Bµ[ln( e ) + s ] rw

(2-17)

and recognizing that the formation volume factor,

21

Modern Fracturing

B, varies greatly with pressure, then an “average” expression can be used as shown by Economides et al. (1994): Bg =

0.0283ZT . ( p e + p wf )/ 2

(2-18)

With relatively simple algebra, and introducing the gas rate in Mscf/d, Eq. 2-17 and 2-18 yield: 141.2(1000 / 5.615)q (0.0283) Z T µ [( pe + pwf ) / 2]kh re × [ln( ) + s ], rw

pe − pwf =

(2-19)

and, finally: 2 pe2 − pwf =

r 1424q µZT [ln( e ) + s ], kh rw

(2-20)

which re-arranged provides the steady-state approximation for natural gas flow, again showing a pressure squared difference dependency. A similar expression can be written for pseudosteady state: 2

2 kh( p − pwf ) q= . 0.472re 1424µZT [ln( ) + s] rw

(2-21)

All expressions given thus far in this chapter have ignored one of the most important effects in natural gas flow: turbulence. One of the simplest and most common ways to account for turbulence effects is through the use of the turbulence coefficient, D, which is employed by adding a component to the pressure drop, as shown below for the steady-state equation: 2 wf

+

1424µZTD 2 q , kh

(2-22)

which rearranged, provides the well-known: 2 kh( pe2 − pwf ) q= . re 1424µZT [ln( ) + s + Dq ] rw

22

q=

kh[m( p ) − m( pwf )] 1424T [ln(0.472re / rw ) + s + Dq ]

.

(2-24)

2-3.4 Horizontal Well Flow Analogs to Eq. 2-23 (for steady state) and 2-24 (for pseudo-steady state) can be written for a horizontal well. Allowing for turbulence effects, the inflow performance relationships for a horizontal well in a gas reservoir are for the steady state: q=

2 k H h( pe2 − pwf ) ,      I ani h  I ani h     1424µZT  Aa + + Dq (2-25) ln    L  r ( I + 1 ) w ani    

where  a + a 2 − ( L / 2) 2      Aa = ln  ,   L/2      

and for pseudo-steady state: 2 k H h( p 2 − pwf ) q= ,      I ani h  I ani h 3     1424µZT  Aa + − + Dq ln    L     rw ( I ani + 1) 4 

(2-26) where I­ani is a measurement of vertical-to-horizontal permeability anisotropy given by: kH I ani = (2-27) . kV

In Eqs. 2-25 and 2-26, a is the large half-axis of the drainage ellipsoid formed by a horizontal well of length L. The expression for this ellipsoid is

r 1424µZT p −p = [ln( e ) + s ]q kh rw 2 e

Similarly, the same coefficient can be employed to the more rigorous expression using the real-gas pseudopressure. As an example, for pseudo-steady state with q in Mscf/d:

(2-23)

 4  r   L a=  0.5 +  0.25 +  eH    L / 2  2      L for < 0.9reH , 2

0.5 0.5

        

(2-28)

where reH is the equivalent radial flow drainage radius.

Chapter 2 Natural Gas Production

2-4 Effects of Turbulence The effects of turbulence have been studied by a number of investigators in the petroleum literature, pioneer and prominent among which have been Katz and co-workers (Katz et al., 1959; Firoozabadi and Katz, 1979; Tek et al., 1962). In their work they suggested that turbulence plays a considerable role in well performance showing that the production rate is affected by itself: The larger the potential rate, the larger the relative detrimental effect would be. One interesting means to account for turbulence was proposed by Swift and Kiel (1962), who presented Eq. 2-22, which when rearranged gives Eq. 2-23. Equation 2-23 is significant because it suggests that turbulence effects can be accounted for by a ratedependent skin effect, where the turbulence (at times referred to as the non-Darcy) coefficient, D, has the units of reciprocal rate. One of the implications is that in testing a high-rate gas well, a calculated skin effect must be construed as “apparent,” rather than the real damage skin. Among the procedures suggested for testing test gas wells are multi-rate testing with subsequent determination of apparent skins at each rate, and straight-line construction graphing of s+Dq vs q. The graph allows field determination of s, the skin not affected by turbulence, from the vertical axis intercept, and D from the slope (Economides et al., 1994). 2-4.1 The Effects of Turbulence on Radial Flow Katz et al. (1959) have presented an explicit relationship for the radial flow of gas into a well, using natural gas properties and by providing correlations for the coefficient, β: 2 pe2 − pwf =

r 1424µZT [ln( e ) + s ]q kh rw

3.16(10)−12 βγ g ZT ( +

where β=

2.33(10)10 . k 1.201

h2

1 1 − ) rw re

q2 ,

(2-29)

(2-30)

For an isotropic formation, k equals the horizontal permeability. For an anisotropic formation, k is defined as the equivalent permeability, keq = [1− log(

kV k 1 )]( V ) 3 k H , kH kH

(2-31)

where kV is the vertical and kH the horizontal permeability. To demonstrate the effects of turbulence on natural gas production, a number of calculations are shown here, using the Katz et al. (1959) approach for a range of permeabilities. Table 2-1 contains the well and reservoir data; Table 2-2 presents the results. Table 2-1. Well and Reservoir Characteristics pe

3000 psi

Case 1

Case 2

re

660 ft

pwf

1500 psi

2500 psi

rw

0.359 ft

μ

0.0162 cp

0.0186

h

50 ft

Z

0.91

0.9

T

710˚R

γg

0.7

Table 2-2 Turbulence Effect at Different Permeabilities and Different Drawdowns k, md 1 5 25 100 k, md 1 5 25 100

Case 1: ∆p = 1500 psi q (β=0, s=0) MMscf/d 3.0 15.1 75.3 301.2

q (β>0, s=0) MMscf/d 2.9 13.0 51.9 151.2

q (β>0, s0, s=0) MMscf/d

q (β>0, s 0.1

 1.6       −0.583 + 1.48 ln N prop     =  1.6 + exp    1 + 0 .1 1 42 ln N prop         N prop 

(2-36)

(2-37)

(2-33)

if N prop < 0.1 if 0.1 ≤ N prop ≤ 10 if Nprop >10

(2-34)

Chapter 2 Natural Gas Production

where kf,n is the nominal permeability (under Darcy flow conditions) in m2, β is in 1/m, v is the fluid velocity at reservoir conditions in m/s, µ is the viscosity of the fluid at reservoir conditions in Pa.s and ρ is the density of the flowing fluid in kg/m3. The value of β is obtained from: β = (1×108)

b (k f ,n )a

(2-38)

,

where a and b are obtained from Cooke (1973). Some values are given in Table 2-3. Table 2-3 Constants a and b Prop Size 8 to 12 10 to 20 20 to 40 40 to 60

a 1.24 1.34 1.54 1.60

b 17,423 27,539 110,470 69,405

The velocity, v, is determined as the volumetric flow rate in the fracture near the well divided by the fracture height times the fracture width (both determined from the design in each iteration.) For a detailed approach and example see Economides et al. (2002b). Table 2-4 presents the results for the fracture designs and expected production rates for the four permeabilities used earlier for the non-fractured wells presented in Table 2-2. These designs assumed sand as a proppant with kf = 60,000 md. There are some very important implications in comparing the results in Tables 2-2 and 2-4. At 5 md the non-fractured well would deliver 13 MMscf/d (with pwf = 1500 psi). If the fractureinduced skin of -5.1 is assumed the production rate would be 24.6 MMscf/d, approximately a twofold increase (see Table 2-2) This production ratio increase would be expected in an oil well flowing under laminar conditions. However, the implicit reduction in turbulence effects (because of the flow profile modification in going from converging radial flow to fracture flow) leads to a considerable further increase in the production to (in this example) 43.5 MMscf/d, a more than three-fold increase (see Table 2-4). For higher-permeability wells, the resulting folds of increase are similar, albeit in actual production rates the achievable results are spectacular (see Fig. 2-5).

Table 2-4 Results from Hydraulically Fractured Well ( kf = 60,000 md) k, md

s

Case 1: pwf = 1500 psi q, MMscf/d

kf,e , md

xf , ft

1

-5.7

13.1

9251

218

5

-5.1

43.5

7950

91

25

-4.3

160.3

6670

36

100

-3.7

524.0

5525

16

k, md

s

1

Case 2: pwf = 2500 psi q, MMscf/d

kf,e , md

xf , ft

-5.7

5.8

12493

250

5

-5.1

18.9

10770

108

25

-4.3

69.2

8980

44

100

-3.7

224.0

7494

20

Table 2-5 shows even more prolific fractured wells if premium proppants are used (kf = 600,000 md), “pushing the limits of hydraulic fracturing” (Demarchos et al., 2004). Table 2-5 Results from Hydraulically Fractured Well ( kf = 600,000 md) k, md

s

1

-6.1

Case 1: pwf = 1500 psi q, MMscf/d

kf,e , md

xf , ft

19.9

38300

375

5

-5.9

59.2

32050

182

25

-5.4

202.0

27110

75

100

-4.8

637.0

22410

35

k, md

s

Case 2: pwf = 2500 psi q, MMscf/d

kf,e , md

xf , ft

1

-6.1

8.8

51600

456

5

-5.9

26.3

44150

211

25

-5.4

88.4

37020

91

100

-4.8

270.0

31720

41

In summary, turbulence affects are the dominant features in the production of high-permeability (>5 md) gas wells. Turbulence may account for a 25 to 50% reduction in the expected open-hole production rate from such wells, if laminar flow is assumed. Cased and perforated wells may experience further turbulenceinduced rate declines, which can be alleviated somewhat with long-penetrating perforation tunnels and large

27

Modern Fracturing

perforation densities (e.g., 8 to 12 SPF). However, nothing can compete with hydraulic fracturing. In higher-permeability gas wells, the incremental benefits greatly exceed those of comparable permeability oil wells, exactly because of the dramatic impact on reducing the turbulence effects beyond the mere imposition of a negative skin. It is fair to say that any gas well above 5 md will be greatly handicapped if not hydraulically fractured. Indeed, pushing the limits of hydraulic fracturing by using large quantities of premium proppants will lead to extraordinary production rate increases (Wang and Economides, 2004). 1000.0

q, MMscf/d

Fractured Well (Premium) 100.0

Negative Skin

10.0

1.0

Depending on the well orientation with respect to the state of stress, either a longitudinal or a transverse fracture may be created in a horizontal well (Soliman and Boonen, 1997; Mukherjee and Economides, 1991; Soliman et al., 1999). The longitudinal configuration is generated when the well is drilled along the expected fracture trajectory. The performance of such well is almost identical to a fractured vertical well when both have equal fracture length and conductivity. Therefore, existing solutions for vertical well fractures can be applied to a longitudinally fractured horizontal well (Economides et al., 2002a; Soliman et al., 1999; Villegas et al., 1996; and Valkó and Economides, 1996).

Fractured Well

Radial Flow

Radial flow 1

10

100

Permeability, md

Figure 2-5 Comparison of gas production rates from nonfractured wells, wells with negative skin and fractured wells

2-5.3 Multi-fractured Horizontal Gas Wells Hydraulically fractured vertical well

As discussed in the previous section, in vertical gas wells turbulence can be greatly reduced through hydraulic fracturing because the flow pattern (shown in Fig. 26) through the hydraulic fracture towards the well is different than for radial flow (Wang and Economides, 2004). The same is not necessarily true for transversely fractured horizontal gas wells (see Section 10-2). Because turbulence effects are enhanced in the latter (due to the very small contact area between the well and the fracture), the conclusion is more nuanced. The limited communication between the transverse fracture and the wellbore generates an additional pressure drop and a choking effect for all transversely fractured horizontal gas wells. This also increases turbulence, which precludes application to essentially any well whose permeability is 1 md or more and, perhaps, to even much lower values of permeability, depending on project economics (Wei, 2004).

28

Figure 2-6 Configurations of radial flow and fractured vertical well

Almost all reported applications of fractured horizontal wells are for transverse fractures (Crisby et al., 1998; Emannuele et al., 1998; Eirafie and Wattenbarger, 1997; Minner et al., 2003; and Fisher et al., 2004). A transverse hydraulic fracture is created when the well is drilled normal to the expected fracture trajectory (Valkó and Economides, 1996; Soliman et al., 1999; and Economides et al., 1994). The configuration of a transversely fractured horizontal well is demonstrated in Fig. 2-7. The cross section of the contact between a transverse fracture and a horizontal well is 2π rww where w is the width of the fracture (which can be obtained by using a design procedure such as the Unified Fracture Design approach) and rw is the radius of the horizontal well. In this case, the flow from the reservoir into the

Chapter 2 Natural Gas Production

fracture is linear; the flow inside the fracture is converging radial (Economides et al, 1994). This combination of flows results in an additional pressure drop that can be accounted for by a choke skin effect, denoted as sc (Mukherjee and Economides, 1991). The horizontal well is assumed to be in the vertical center of a reservoir (see Fig. 2-7) and the flow is from the reservoir into the fracture and then from the fracture into the wellbore (Mukherjee and Economides, 1991). The produced fluid enters the wellbore only through the fracture, regardless of whether the remaining part of the well is perforated. In this study, this assumption is also valid.

Side view, fluid flow from reservoir to the fracture

Calculation Method and Theory for Transversely Fractured Gas Well To study the performance of a transversely fractured horizontal gas well, it is essential to account for turbulence effects, which are likely to be large because of high gas-flow velocity. Economides et al. (2002b) have developed an iterative procedure to account for turbulence effects in a hydraulic fracture. The main steps and the correlations used are described below. 1. Assume a Reynolds number, NRe , and calculate the effective fracture permeability kf,e using Eq. 2-36. 2. Using kf,e , calculate the Proppant Number, Nprop , from Eq. 2-32. 3. With Nprop , calculate the maximum productivity index, JDmax , and optimal dimensionless fracture conductivity, CfDopt , from Eq. 2-33 and 2-34, respectively. 4. With CfDopt , calculate the indicated optimum fracture dimension xfopt and wopt from Eq. 2-35. 5. With the known kf,e and wopt, calculate the choke skin factor by:

sc =

kh   h  π  ln   − . k f w   2rw  2 

(2-39)

6. With the calculated JD,max and sc, calculate the dimensionless productivity index of transversely fractured horizontal oil well JDTH (neglecting turbulence effects for now), JDTH :

J DTH =

1  1   + s  J  c DV

(2-40)



Top view, fluid flow from the fracture to the wellbore Figure 2-7 One transverse fracture intersecting a horizontal well

In the following section, the theory and calculation method for transversely fractured horizontal gas well are described. Then some results and discussions are presented.

where JDV is the dimensionless productivity index of the fractured vertical well calculated using the procedure described by Wang and Economides (2004). 7. With JDTH and drawdown, the actual production rate can be obtained using Eq. 2-41. With this production rate, a new Reynolds number NRe can be calculated with Eqs. 2-37 and 2-38, and the flow velocity v obtained from the crosssectional area of flow. 2 kh( p 2 − pwf ) q= J DTH . (2-41) 1424µZT

29

Modern Fracturing

8. Compare NRe calculated in Step 7 with the assumed NRe in Step 1. If they are close enough, the procedure can be ended. If they are not, repeat from Step 1 until they are close enough. The calculated results are optimum, which means that at a given Proppant Number the dimensionless productivity index is the maximum at the optimum dimensionless fracture conductivity (Demarchos et al., 2004). However, this optimization often must be tempered by physical and logistical constraints (Economides et al., 2002a) To compare the performance of fractured vertical and transversely fractured horizontal gas well, the Equivalent Number of Vertical Wells, X, is defined as: X=

J DTH . J DV



(2-42)

Assume the formation permeability is the same throughout and n transverse fractures are generated intersecting a horizontal well (Fig. 2-8). JDTHt is the total dimensionless productivity index (sum) for n transverse fractures. JDTH1 is the dimensionless productivity index of one isolated zone for a transversely fractured horizontal well. Therefore: J DTHt = nJ DTH 1.

(2-43)

Figure 2-8 Multiple transverse fractures intersecting a horizontal well

Results and Analysis for Formation Permeability from 1 to 100 md A case study is presented here for the multiple fracturing of a horizontal well in a gas reservoir with h = 50 ft, γg = 0.7, reservoir pressure of 3000 psi and flowing bottomhole pressure of 1500 psi. Assume a single transverse fracture is generated in the horizontal well and the mass of proppant is 150,000 lbm. Proppant-pack permeability, kf , is 600,000 md.

30

The details of the fracture design are omitted here. What are presented are fractured well performance results, summarized in Table 2-6. It should be noted that the skin choke effect, sc , (from Eq. 2-39) is inversely proportional to the proppant-pack permeability. Thus, choosing high-quality proppant would decrease sc and benefit the dimensionless productivity index, JDTH (Eq. 2-40), and the Equivalent Number of Vertical wells, X (Eq. 2-42). Table 2-6 Results for kf = 600,000 md kf = 600,000 md, 150,000 lbm mass, single transverse fracture k, md

JDV

JDTH

w, in.

sc

kf,e

1 5 10 25 50 100

0.739 0.457 0.389 0.324 0.288 0.255

0.121 0.056 0.036 0.018 0.013 0.009

0.35 0.69 0.86 1.04 1.48 2.07

4.64 13.3 22.3 48.7 69.1 100

1002 871 832 794 783 774

The results in Table 2-6 show the value of JDTH is very small (compared to that of the vertical well, JDV      ) and decreases dramatically with increasing formation permeability. It is obvious that turbulence effects influence the performance of a transversely fractured gas well so much that even with the most premium proppant (permeability 600,000 md), the results are unacceptable. The comparison of production between a fractured vertical well, a transversely fractured horizontal well and laminar flow open-hole well (the ideal case in Wang and Economides, 2004) is summarized in Fig. 2-9. The top solid curve (qv /qideal      ) represents the ratio of the fractured vertical well production to that from a laminar-flow, open-hole vertical well. The solid bottom curve shows the ratio of a transversely fractured horizontal well (one fracture) with the same laminar-flow, open-hole vertical well (qTH /qideal      ). Results clearly show that because the fracture in the vertical well changes the flow pattern in the near-wellbore area and alleviates the non-Darcy effect the qv /qideal is considerably larger than 1. Conversely, the qTH /qideal is much smaller than 1 even at reservoir permeability equal to 1 because of the choke skin and non-Darcy effects. The dashed line in Fig. 2-9 shows that even with four transverse fractures, the productivity ratio of a fractured horizontal well to an ideal open-hole is still less than 1 for permeability larger than 10 md.

Chapter 2 Natural Gas Production

Would increasing the mass of proppant improve the performance? The answer is no. The reason is that the main factor that makes JDTH so low is the converging skin effect, sc , which cannot be reduced by increasing the mass of proppant (see Eq. 2-39). For example, for the 1-md formation, doubling the mass of proppant to 300,000 lbm (with all other variables kept the same) increases the JDTH only to 0.122, almost the same as that for the 150,000-lbm mass case, where JDTH is 0.121. 6 5

qv / q ideal

3 4q TH / q ideal

2

These results further suggest that for high- and even moderate-permeability reservoirs, a transversely fractured horizontal gas well is not attractive because of the production impediment from turbulence effects and converging skin effect. For low-permeability (k ≤ 0.5 md) reservoirs, the results should be attractive if multiple fractures intersecting a horizontal well are generated (and if the project economics are attractive.)

Open Hole

1

qTH / q ideal

0 1

10 k, md

100

JDV and JDTH

q / q ideal

4

• The JDTH is smaller than JDV when other parameters are the same. • The JDTH decreases with increasing formation permeability regardless of proppant-pack permeability, as expected. • When reservoir permeability is less than 0.1 md, proppant-pack permeability has slight impact on sc. • When reservoir permeability increases, sc increases and X decreases.

Figure 2-9 Turbulence effect on fractured vertical and transversely fractured horizontal wells

JDV (kf =60,000 md)

JDTH (kf =600,000 md)

JDTH (kf =60,000 md) 0.1

JDV (kf =600,000 md)

k , md

1

Figure 2-10 (a) JDV, JDTH, vs. k for different proppants 0.8

40

0.7

35

0.6

X (k f =600,000 md)

X

0.5

30 sc (kf =60,000 md)

25

0.4 0.3

20 X (kf =60,000 md)

15 sc (k f =600,000 md)

0.2

Results and Analysis for Formation Permeability from 0.01 to 10 md A second study presents results for a much lower permeability range (0.01 to 10 md). Designs assume the use of 150,000 lbm mass of proppant with proppantpack permeabilities of 60,000 md and 600,000 md. Drainage radius is 660 ft. A single transversely fractured horizontal gas well is calculated. The results are plotted in Figs. 2-10 (a) and 2-10 (b). The obvious trends from these results are:

10

10

0.1 0

0.01

5 0.1

k, md

1

10

0

Figure 2-10 (b) sc, X vs. k for different proppants

Because JDV and sc are functions of the mass of proppant and proppant-pack permeability, it is worth performing a parametric study to show the effect of important reservoir and treatment variables on JDTH , JDV and X.

31

Sc

The conclusion from this part of the study is that hydraulic fracturing is essential for both stimulating and reducing the strong turbulence effects in higherpermeability vertical gas wells, but the same is not necessarily true for transversely fractured horizontal gas wells. Transversely fractured horizontal gas wells are not attractive in terms of productivities for moderate and higher formation permeability (e.g. k > 1 md).

2.0 1.8 1.6 1.4 1.2 1.0 0.8 0.6 0.4 0.2 0 0.01

Modern Fracturing

Impact of Fracture Treatment Size To find the impact of the mass of proppant on JDTH, a range of proppant mass from 75,000 to 300,000 lbm is used. The proppant-pack permeability used in this study is sand, with permeability 60,000 md, and the drainage radius is 660 ft. The results are summarized in Table 2-7. Table 2-7 Impact of Mass of Proppant on X and JDTH 75,000 lbm k, md

JDTH

X

sc

0.01 0.05 0.1 0.5 1 5 10

0.786 0.465 0.31

0.531 0.481 0.35 0.198 0.152 0.092 0.06

0.16 0.45 0.86 5.63 10.5 28.6 51.3

0.105 0.067 0.029 0.017

150,000 lbm k, md

JDTH

X

sc

0.01 0.05 0.1 0.5 1 5 10

1.075 0.345 0.323 0.106 0.067 0.029 0.018

0.589 0.487 0.294 0.162 0.127 0.08 0.058

0.08 0.43 0.91 5.66 10.6 28.7 51.3

a horizontal well are generated. Thus, it is useful to study how the number of isolated zones affects the Equivalent Number of Vertical Wells. Assume the total drainage radius is 1320 ft, the proppant-pack permeability kf is 60,000 md and mass of proppant is 150,000 lbm. The number of isolated zones and, thus, the number of transverse fractures intersecting a horizontal well vary from 1 to 4. The results, plotted in Fig. 2-11, show that when the number of transverse fractures is more than four for low permeability (k < 0.5 md), X becomes more than 1, which makes transversely fractured horizontal gas wells attractive. The lower the formation permeability is, the more attractive the transverse fracture configuration is (subject to overall economic considerations). If the formation permeability is larger than 1 md, the transverse configuration does not appear attractive. For example, X is only 0.280 for k = 10 md formation with four transverse fractures generated. 5.0 k =0.01 md

4.5

300,000 lbm

4.0

JDTH

X

sc

3.5

0.01 0.05 0.1 0.5 1 5 10

1.42 0.314 0.332 0.107 0.068 0.029 0.018

0.755 0.518 0.235 0.138 0.116 0.071 0.053

0.19 0.46 0.95 5.69 10.6 28.9 51.3

3.0 X

k, md

2.5

k =0.05 md

2.0

k =0.1 md

1.5 1.0

k =0.5 md k =1 md k =5 md k =10 md

0.5 0.0

It is apparent that increasing the mass of proppant has impact on the results for the low-permeability (k ≤ 0.1 md) formation but virtually no impact in higher permeabilities. The reason is that increasing the mass of proppant, while it may increase the dimensionless productivity index, also increases the skin factor sc (see Table 2-7). The one effect nullifies the other. Thus, there is no need to increase the mass of proppant. A modest treatment is sufficient. Impact of the Number of Isolated Zones on Equivalent Number of Vertical Wells, X As mentioned earlier, for low-permeability (k ≤ 0.5 md) reservoirs, fracture stimulation results will not be attractive unless multiple transverse fractures intersecting

32

1

2

3 n

4

5

Figure 2-11 Impact of number of fractures, n, on X

In summary, turbulence effects have a great impact on transversely fractured horizontal gas wells due to the small cross-section of the contact between the well and the fracture. Although a vertical fractured gas well in the permeability range of 1 to 100 md may perform very well, turbulence effect procduce in unacceptable results in transversely fractured horizontal gas wells in the same permeability range. For low permeability (k < 0.5 md), the results are attractive if a fracture stimulation treatment generates multiple fractures intersecting a horizontal well. However, if the permeability is larger than 0.5 md,