Natural Gas Processing from Midstream to Downstream

Dedication

To our families and children

To the memory of our colleague Professor M. Sam Mannan.

List of Contributors

Noof Abdalla

Chemical Engineering Program

Texas A&M University at Qatar

Qatar

Shaik Afzal

Chemical Engineering Program

Texas A&M University at Qatar

Qatar

Monir Ahammad

Mary Kay O'Connor Process Safety Center

Artie McFerrin Department of Chemical Engineering

Texas A&M University

USA

Ahmad Al‐Douri

Department of Chemical Engineering

Texas A&M University

USA

Ali Almansoori

Khalifa University

The Petroleum Institute

Abu Dhabi

United Arab Emirates

Saad A. Al‐Sobhi

Department of Chemical Engineering

University of Waterloo

Waterloo

ON

Canada

and

Department of Chemical Engineering

Qatar University

Doha

Qatar

Andrew Avalos

Dwight Look College of Engineering

Texas A&M University

USA

Christos Boukouvalas

Laboratory of Thermodynamics and Transport Phenomena

School of Chemical Engineering

National Technical University of Athens

Athens

Greece

Joel G. Cantrell

Bryan Research & Engineering

LLC

Texas

USA

Nikolaos A. Diangelakis

Artie McFerrin Department of Chemical Engineering and

Texas A&M Energy Institute

Texas A&M University

USA

Ioannis G. Economou

Texas A&M University at Qatar

Qatar

TEES Gas and Fuels Research CenterTexas A&M Engineering Experiment Station

USA

Nimir O. Elbashir

Petroleum Engineering Program

Texas A&M University at Qatar

Qatar

TEES Gas and Fuels Research Center

Texas A&M Engineering Experiment Station

USA

Mahmoud M. El‐Halwagi

TEES Gas and Fuels Research Center

Texas A&M Engineering Experiment

and Artie McFerrin Department of Chemical Engineering

Texas A&M University

USA

Ali Elkamel

Department of Chemical Engineering

University of Waterloo

Ontario

Canada

and

Khalifa University

The Petroleum Institute

Abu Dhabi

United Arab Emirates

Marwan El Wash

Chemical Engineering Program

Texas A&M University at Qatar

Qatar

Fatih S. Erenay

Department of Management Studies

University of Waterloo

ON

Canada

Michael Fowler

Department of Chemical Engineering

University of Waterloo

Ontario

Canada

Vinay Gadekar

EPCON Software™

Houston

USA

Kenneth R. Hall

Bryan Research & Engineering

LLC

Texas

USA

Rasha Hasaneen

Dwight Look College of Engineering

Texas A&M University

USA

Ahmed Farid Ibrahim

Petroleum Engineering Department

Texas A&M University

USA

Swarom R. Kanitkar

Cain Department of Chemical Engineering

Louisiana State University

Baton Rouge

USA

Eirini Karakatsani

Haldor Topsoe A/S

Nymøllevej 55, Kgs. Lyngby

Denmark

Tala Katbeh

Chemical Engineering Program

Texas A&M University at Qatar

Qatar

Georgios M. Kontogeorgis

Center for Energy Resources Engineering (CERE)

Department of Chemical and Biochemical Engineering

Technical University of Denmark

Denmark

Vasiliki Louli

Laboratory of Thermodynamics and Transport Phenomena

School of Chemical Engineering

National Technical University of Athens

Greece

M. Sam Mannan

Mary Kay O'Connor Process Safety Center

Artie McFerrin Department of Chemical Engineering

Texas A&M University

USA

Mozammel Mazumder

Dan F. Smith Department of Chemical Engineering

Lamar University

USA

Vasileios K. Michalis

Molecular Thermodynamics and Modeling of Materials Laboratory

Institute of Nanoscience and Nanotechnology

National Center for Scientific Research Demokritos

Greece

Nasr Mohamed

Petroleum Engineering Program

Texas A&M University at Qatar

Qatar

Rajib Mukherjee

TEES Gas and Fuels Research Center

Texas A&M Engineering Experiment Station

USA

Hisham A. Nasr‐El‐Din

Petroleum Engineering Department

Texas A&M University

USA

Paul A. Nelson

EPCON Software™

Houston

USA

Nefeli Novak

Laboratory of Thermodynamics and Transport Phenomena

School of Chemical Engineering

National Technical University of Athens

Greece

Emmanuel Ogbe

Department of Chemical Engineering

University of Waterloo

Ontario

Canada

and

Khalifa University

The Petroleum Institute

Abu Dhabi

United Arab Emirates

Gerald S. Ogumerem

Artie McFerrin Department of Chemical Engineering and

Texas A&M Energy Institute

Texas A&M University

USA

Ecem Özinan

Artie McFerrin Department of Chemical Engineering

Texas A&M University

USA

Eleni Panteli

Equinor ASA

Research & Technology Center

Trondheim

Norway

Konstantinos D. Papavasileiou

Molecular Thermodynamics and Modeling of Materials Laboratory

Institute of Nanoscience and Nanotechnology

National Center for Scientific Research Demokritos

Greece

Georgia Pappa

Laboratory of Thermodynamics and Transport Phenomena

School of Chemical Engineering

National Technical University of Athens

Greece

Loukas D. Peristeras

Molecular Thermodynamics and Modeling of Materials Laboratory

Institute of Nanoscience and Nanotechnology

National Center for Scientific Research Demokritos

Greece

Eirini Petropoulou

Laboratory of Thermodynamics and Transport Phenomena

School of Chemical Engineering

National Technical University of Athens

Greece

Efstratios N. Pistikopoulos

Artie McFerrin Department of Chemical Engineering and

Texas A&M Energy Institute

Texas A&M University

USA

Debalina Sengupta

TEES Gas and Fuels Research Center

Texas A&M Engineering Experiment Station

USA

Mostafa Shahin

ORYX GTL Company

Ras Laffan

Qatar

Munawar A. Shaik

Department of Chemical Engineering

Khalifa University

Abu Dhabi

UAE

Department of Chemical Engineering

Indian Institute of Technology (IIT)

New Delhi

India

Mohammed Shammaa

Dwight Look College of Engineering

Texas A&M University

USA

Nathan Sibley

Dwight Look College of Engineering

Texas A&M University

USA

Stathis Skouras

Equinor ASA

Research & Technology Center

Trondheim

Norway

Justin C. Slagle

Bryan Research & Engineering, Inc.

Texas

USA

James J. Spivey

Cain Department of Chemical Engineering

Louisiana State University

Baton Rouge

USA

Manolis Vasileiadis

Molecular Thermodynamics and Modeling of Materials Laboratory

Institute of Nanoscience and Nanotechnology

National Center for Scientific Research Demokritos

Greece

Epaminondas Voutsas

Laboratory of Thermodynamics and Transport Phenomena

School of Chemical Engineering

National Technical University of Athens

Greece

Ben R. Weber, Jr

Synfuels International

INC

Parkland Hall

USA

Moye Wicks III

EPCON Software™

USA

Todd J. Willman

EPCON Software™

Houston

USA

Qiang Xu

Dan F. Smith Department of Chemical Engineering

Lamar University

USA

About the Editors

Dr. Nimir O. Elbashir (editor)

Professor Elbashir holds a joint appointment as a professor in the Chemical Engineering Program and the Petroleum Engineering Program at Texas A&M University at Qatar and the chair of the Petroleum Engineering Program., He is the director of Texas A&M's Engineering Experiment Station Gas and Fuels Research Center, a major research center that involves 30 faculty members from both the Qatar and College Station campuses of Texas A&M University and the chair of the ORYX GTL Excellence Program in Gas‐to‐Liquid technology. He has extensive research and teaching experience from four different countries around the world, including his previous position as a researcher at BASF R&D Catalysts Center in Iselin, New Jersey. The focus of his research activities is the design of advanced reactors, catalysts, and conversion processes for natural gas, coal, and CO2 to ultraclean fuels and value‐added chemicals. He has established several unique global research collaboration models between academia and industry with research funds exceeding twelve million dollars during the past six years. He holds several U.S. and European patents and a large number of scientific publications in the form of peer‐reviewed journals, conference papers, and technical industry reports as well as invited talks and conference presentations. The scholarship of his research activities has been recognized by awards from Qatar Foundation, BASF Corp., Texas A&M University Engineering Experiment Station, Texas A&M University Qatar, the American Institute of Chemical Engineers, and others

Dr. Mahmoud M. El‐Halwagi (co‐editor)

Professor El‐Halwagi is the McFerrin Professor at Artie McFerrin Department of Chemical Engineering, Texas A&M University. He is also the managing director of the Texas A&M Gas and Fuels Research center. Dr. El‐Halwagi's main areas of expertise are process integration, synthesis, design, operation, and optimization. Specifically, Dr. El‐Halwagi's research focuses on sustainable design through the development of systematic and generally applicable approaches and tools. Dr. El‐Halwagi is a fellow of the AIChE and is the recipient of several awards, including the AIChE Sustainable Engineering Forum Research Excellence Award and the National Science Foundation's National Young Investigator Award. Dr. El‐Halwagi received his Ph.D. in chemical engineering from the University of California, Los Angeles, and his M.S. and B.S. from Cairo University.

Dr. Kenneth R. Hall (co‐editor)

Professor Hall is a Senior Consulting Engineer at Bryan Research & Engineering. He formerly held positions as Professor of Chemical Engineering Program at Texas A&M University in College Station and Qatar and Regents Professor in the Texas A&M University System. He served in a large number of administrative positions at Texas A&M University, where he served as professor for over 42 years. Dr. Hall received numerous research and teaching awards. He graduated 34 doctorate students and 27 masters students. He received more than 25 million U.S. dollars of research funding during his tenure as professor. He has 16 U.S. patents and 271 peer‐reviewed journal papers and 9 books. His primary emphasis in research is the thermodynamics of fluids and fluid mixtures with concentration upon the measurement and correlation of precise property data. Experimental efforts in this area include: PVT, VLE, enthalpy, vapor pressure, dew and bubble point apparatus. In each case, the emphasis is to gather state‐of‐the‐art data. His theoretical efforts include equation‐of‐state studies and modern evaluation of properties in the vapor‐liquid critical region focusing upon natural gas‐type fluids and mixtures. A secondary interest is flow and energy measurements of compressible fluids.

Dr. Ioannis G. Economou (co‐editor)

Dr. Economou is the Associate Dean for Academic Affairs and Professor of Chemical Engineering at Texas A&M University at Qatar. Prior to this, he was the Associate Provost for Graduate Studies and Professor of Chemical Engineering at the Petroleum Institute, Abu Dhabi (2009–12). From 1995 to 2009, he worked at the National Center for Scientific Research Demokritos in Athens, Greece. He holds a Diploma in Chemical Engineering from the National Technical University of Athens, Greece (1987) and a PhD also in Chemical Engineering from The Johns Hopkins University in Baltimore, Maryland, USA (1992). He worked as a post-doctoral researcher in Delft University of Technology in the Netherlands (1993–94) and in Exxon Research and Engineering Company, in New Jersey, USA (1994–95), as research fellow in University College London (1994–96) and Princeton University (2004 and 2015), and as visiting Professor in the Technical University of Denmark (2001 and 2006–07) and the American College of Greece (2007–09). He has consulted extensively for major oil and chemical companies in North America, Europe and Middle East. He has supervised 18 MSc students, 14 PhD students and 16 post‐docs, he has published more than 190 peer‐reviewed research papers in leading journals in Chemical Engineering, Physical Chemistry and Polymer Science, 10 book chapters and has given approximately 300 presentations in conferences, Universities and industrial research centers worldwide. His research interests are related to molecular thermodynamics, complex fluids, aqueous systems, CO2 management, green solvents, and soft materials including polymers, ionic liquids, metal organic frameworks, etc. From 2007 to 2014, he was the Founding Chairman of the Working Party on Thermodynamics and Transport Properties of the European Federation of Chemical Engineering. He is Editor of Fluid Phase Equilibria, and member of the Editorial Boards in Journal of Chemical and Engineering Data and in Journal of Supercritical Fluids.

Preface

This book focuses on highlighting global experience in the production and monetization of shale gas and natural gas while providing techno‐economic assessments of the midstream and downstream natural gas processing technologies. Natural gas has become a significant player in the global energy mix as a result of rising prosperity, which drives an increase in global energy demand that is expected to increase by more than 30% in a few decades. Natural gas, a fossil fuel, enjoys several environmental benefits over the other fossil fuels, such as coal and petroleum products. This book identifies the current status and the challenges facing the advancement of natural gas monetization looking at the entire process with emphasis upon midstream‐ and downstream‐related topics from the fundamental to the applied. Particular focus is on the downstream processes including physical treatment (Liquefied Natural Gas or LNG) and the chemical conversion (both direct (e.g., natural gas to methanol) and indirect (e.g., gas‐to‐liquid or GTL).

The authors of this book are leading researchers from academia and industry, who provide a broad, but well‐integrated coverage of several technologies and processes for treating and producing natural gas while highlighting the economics and risks facing the monetization technologies. Also, to offer a wide range of perspectives the book includes participants from different parts of the world, specifically from nations in which natural gas plays a critical role in the energy mix and the economy of the country. The book emphasizes success stories in natural gas monetization while identifying the challenges involved.

This book gives to the reader a broad picture of the current status of natural gas production, treatment, and monetization technologies and identifies challenges that these efforts face.

The book covers a broad range of topics interesting to various audiences, but it also can serve as a general reference for natural gas production/processing/use. It is useful for researchers and graduate students working with shale gas and natural gas production and monetization, while simultaneously being of interest to experts in the oil and gas industry who emphasize technical or economic aspects of the technology. Some chapters emphasize the importance of collaboration between academia and industry to advance existing commercial technologies and to develop innovative processes and techniques.

The initiative for this work emanates from the Texas A&M University Engineering Experiment Station Gas & Fuels Research Center (GFRC), which involves 30 professors from both Texas A&M University in College Station, Texas and the Qatar campus (http://gfrc.tamu.edu/).The GFRC is focusing upon advancing research and development activities that support growth in shale gas, specifically in the Gulf of Mexico region, which should bring to the United States chemical industry estimated incremental capital investments of $71.7 billion by 2020. In addition, the GFRC supports the State of Qatar in monetizing its natural gas wealth and sustaining its position as The Gas Processing World Capital. GFRC works closely with industry and academia around the globe to provide solutions for several problems in the fields of natural gas exploration, production, and monetization and to work with industry to create skilled engineers and scientists capable of supporting and advancing this field.

This book has twenty‐one chapters that are arranged in four sections:

Section 1: Introduction

This section highlights the importance of the global energy market and the different stages of natural gas exploration, production, handling, and monetization. Natural gas exploration and production appears in an oil and gas section while natural gas treatment to remove impurities and produce methane, and condensates, is in the midstream process section. Natural gas processing to final products in the form of fuels and chemicals is in the downstream process section. The section also briefly highlights the advantages and the constraints facing the different natural gas monetization techniques with emphasis on the United States, Russia, and Qatar.

Section 2: Upstream

Three book chapters address both fundamental and applied topics on upstream‐related issues such as geologic sequestration of CO2, and its role in enhanced oil and gas recovery. A major challenge facing the environmental assessment of natural gas products is potential greenhouse gas emissions during the processing of natural gas to fuels. Also, this section includes a chapter that addresses thermodynamic modeling of natural gas and condensate properties that is essential in natural gas production and another chapter that covers the technical, microeconomic analyses and policy implications of environmental remediation techniques for shale gas wells in the Barnett Shales. Two other chapters, lying between upstream and midstream natural gas production, address fluid flow fundamentals and advanced techniques.

Section 3: Midstream

Seven chapters of this book address topics in midstream or in midstream‐downstream parts of the natural gas monetization chart. The topics vary from the use of process simulators to design and optimize the operations of midstream and downstream plants to the optimization of natural gas network operations under uncertainty. This section also includes chapters that address the optimization of shale gas monetization supply chains and the identification of optimal operation for natural gas liquid recovery and products. Also, this section includes a chapter that covers fundamental topics such as thermodynamic modeling of natural gas processing units and another that focuses upon applied topics such as safety in midstream and downstream processing of natural gas.

Section 4: Downstream

The downstream and the monetization section has ten chapters that address several direct and indirect natural gas conversion routes to chemicals and fuels (including gas‐to‐liquid (GTL) technology) as well as the physical treatment of natural gas (liquefied natural gas processes (LNG)). Also, this section includes techno‐economic assessment of the natural gas monetization processes as well as the characterization and the design of the GTL fuels and chemicals.

1

Introduction to Natural Gas Monetization

Nimir O. Elbashir

Petroleum Engineering Program, Texas A&M University at Qatar, Qatar

TEES Gas and Fuels Research Center, Texas A&M Engineering Experiment Station, USA

Chapter Menu

1.1 Introduction

1.2 Natural Gas Chain

1.3 Monetization Routes for Natural Gas

1.4 Natural Gas Conversion to Chemicals and Fuels

1.5 Summary

1.1 Introduction

Natural gas, mainly methane, has been known and utilized since the ancient Greek and Chinese civilizations. Natural gas began playing a prominent role in the energy market as early as the 1780s, during the start of the Industrial Revolution, where it was used in the United Kingdom as a source of lighting for homes and streets. Baltimore became the first city in the United States to light its streets using natural gas by the mid‐1880s.

Currently, natural gas enjoys a significant share in the primary energy mix market compared to other fossil fuel sources (oil and coal) as well as renewables and other sources (hydro and nuclear). As shown in Figure 1.1 the contribution of natural gas as a primary energy source increased by almost 40% from 1995 to 2017, and as the fastest‐growing fuel per annum, its share is expected to reach 30% by 2035 [1, 2]. Countries with the largest natural gas reserves are Russia (∼1,688 trillion cubic feet (tcf)), Iran (∼1,187 tcf), Qatar (∼890 tcf), the United States of America (∼388.8 tcf), Turkmenistan (∼353 tcf), Saudi Arabia (∼290 tcf), United Arab Emirates (∼215 tcf), Venezuela (∼195 tcf), Nigeria (∼182 tcf), and Algeria (∼159 tcf). These countries control almost 80% of the proven global natural gas reserves [3].

The global demand for natural gas is shown in Figure 1.2. The figure shows the apparent rise of natural gas demand in the United States and the rest of the world as a result of the significant enhancement in shale gas production, while the forecast shows a slight decrease in demand for the European nations. The world's largest consumers of natural gas are the United States, Russia, China, and Iran, while the most significant producers are Russia, the United States, Canada, Qatar, and Iran.

Figure 1.1 The global energy sources and their forecasted shares (*Renewables includes wind, solar, geothermal, biomass, and biofuels) [1].

Figure 1.2 The past and the prospected demand of natural gas (data obtained from [2]).

Qatar, a small country in the Middle East, is a good example of a success story in natural gas production and monetization since it is the fourth‐largest producer of natural gas, globally [4]. At current reserves‐to‐production (R/P) rates, Qatar has more than 135 years' worth of natural gas [4]. Thus, natural gas will continue to be a major contributor to Qatar's economy for the foreseeable future. Qatar also aims to be at the forefront of developing innovative ways to monetize natural gas, not only in economic terms but also in environmental terms. This chapter sheds light on the differences in natural gas monetization pathways of major world players in this field, either as producers or as consumers, with a focus on Russia, the United States, and Qatar. The first section of this chapter will briefly highlight the differences between the significant monetization routes for natural gas while the second part will reflect the differences in natural gas monetization between Russia, the United States, and Qatar.

1.2 Natural Gas Chain

As shown in Figure 1.3, the Upstream part of natural gas chain starts with the exploration and the production of natural gas from either a conventional source (associated and non‐associated reservoirs) or a non‐conventional source (shale, coalbed methane (CBM), oil sand, or tight gas reservoir). The different technologies that have been used to extract, process, transport, store, and distribute natural gas depend on the location and composition of the gas as well as the production location. The second part of the natural gas chain is the Midstream, whereby the major treatment takes place, depends on the application of the gas and the specification required by downstream processes and the end users. A typical composition of natural gas from the wellhead to the pipeline is shown in Table 1.1. The purpose of the Midstream part is to remove components other than methane from natural gas in a series of separation processes that would combine different technologies and processes. Figure 1.4 shows a typical sequence of midstream natural gas processing plant. The Downstream part of the natural gas chain depends mainly on the end use of natural gas, and it could be composed of a physical treatment (e.g., liquefied natural gas (LNG)) or chemical treatment (e.g., gas‐to‐liquid (GTL)).

Table 1.1 Typical composition of natural gas from the wellhead to the pipeline.

1.3 Monetization Routes for Natural Gas

1.3.1 Large Industries and Power Plants

The industry and the power plants sector account for the highest monetization of natural gas compared to others [5]. Specifically in the United States, coal began modestly in 2008 and dropped from 48.21% to 33.18% in 2015. Coal lost 15 % of the market, while natural gas increased 11% in the same period, as shown in Table 1.2. Renewable sources (not including solar and hydropower) increased 3.6% to 6.7% overall. The electricity sector is a major emitter of CO2 in the United States, and it is assumed to be responsible of 29% of global warming emissions. Coal is the major source for these emissions, and therefore natural gas and renewables emerged to substitute for coal in this sector [6, 7]. That results in natural gas and renewables picking up 14.8% of the market (i.e., or ∼99% of the market lost by coal). In 2016, natural gas become the major sources of electricity in the United States (∼34%) followed by coal (30%), nuclear (∼20%), and the renewables (∼16%) [8].

Table 1.2 Role of natural gas in the United States electricity generation.

Figure 1.3 Natural gas chain from the upstream to the downstream.

Figure 1.4 The processes of midstream natural gas plant.

Table 1.3 lists the main advantages and disadvantages of monetizing natural gas in the large industry and power plant sectors. The major advantage is that natural gas doesn't require an expensive midstream treatment, while the major challenge is the low load factor due to the use of dual‐fired generators, which is common practice in many places.

Table 1.3 Advantages and disadvantages for monetizing natural gas in industry and power plants.

1.3.2 Small/Medium Industries and Commercial Users

The size and importance of the small/medium industries and the commercial user sector vary from country to country, and represent the use of natural gas in small machines like heated big/medium‐sized washing machines that have dephosphatizing, rinsing, and drying treatments for fasteners and general small metal components. This sector has a strong presence in the developed nations but much lower contribution in developing nations. Table 1.4 shows the summary of the advantages and the disadvantages in monetizing natural gas in this sector. The major advantage in monetizing natural gas in this sector is that has high load factor offtakes and higher values in terms of heat compared to conventional steam. On the other hand, the gas has to be treated in a more expensive midstream process compared to monetization in power plants.

Table 1.4 Advantages and disadvantages for monetizing natural gas in small/medium industries and commercial users.

1.3.3 Residential

One of the first priorities of local natural gas monetization is residential heating requirements. Gas is delivered to homes through pipelines or in tanks as CNG (compressed natural gas). This is the conventional use of natural gas to warm homes or for water heating. Also, it is also used in stoves, ovens, clothes dryers, lighting fixtures, and other appliances. Table 1.5 lists the major advantages in using natural gas in residential versus the disadvantages and the challenges facing the same.

Table 1.5 Advantages and disadvantages for monetizing natural gas in small/medium industries and commercial users.

1.3.4 Natural Gas Export

1.3.4.1 Pipeline Export

A major route of natural gas transportation both within state and out of the state is via pipelines. Russia is one of the world's largest producers of crude oil (including lease condensate) and the second‐largest producer of dry natural gas, ∼20 tcf in 2016. The majority of Russia's reserves are located in West Siberia, with the Yamburg, Urengoy, and Medvezhye fields accounting for a significant share of Russia's total natural gas reserves. Russia has built strong pipeline network utilities (259,913 kilometers (km)) for local distribution of natural gas and for export of its natural gas to Europe. In 2014, almost 90% of Russia's 7.1 tcf of natural gas were exported to customers in Europe via pipelines, with Germany, Turkey, Italy, Belarus, and Ukraine receiving the bulk of these volumes. As a result, Russia's economy is highly dependent on its oil and gas, and hydrocarbon revenues, which account for more than 40% of the federal budget revenues. These pipelines that travel long distances should sustain high pressure in the pipeline anywhere from 200 to 1500 pounds per square inch (psi). The United States has the world largest pipeline infrastructure both for onshore and offshore lines, of 2,225,032 km of interstate and intrastate transmission pipelines, and distribution pipelines (1,984,321 km of this network is for natural gas transportation). Canada ranks number three after the United States and Russia with a total length of 100,000 km [9]. According to the U.S. Department of Transportation, pipelines are the safest, most environmentally friendly and most efficient and reliable mode of transporting natural gas [10].

Table 1.6 lists the advantages and the disadvantages for exporting natural gas via pipeline whether overland or subsea.

Table 1.6 Advantages and disadvantages for transporting natural gas via pipeline.

1.3.4.2 Liquefied Natural Gas (LNG)

Natural gas liquefaction is a physical treatment of natural gas to change methane from the gaseous phase to liquid phase to reduce its volume to 1/600 to ease its transportation and storage. The LNG process is a sophisticated technology. Only a very limited number of energy companies are capable of designing and operating such a process, which requires cooling methane to extremely low temperatures for the liquefaction process to take place. LNG is odorless, colorless, non‐toxic and non‐corrosive. It is classified as a flammable hazardous substance, specifically when vaporized into a gaseous state. The LNG process involves a gas treatment plant that is similar to the midstream plant shown in Figure 1.4. The gas is then cooled to separate the heavier hydrocarbons such as C3, C4, and C5+ components. These heavier components are fractionated to produce condensates (C5+ and liquefied petroleum gas (LPG) products). The lean gas is then liquefied in cryogenic exchangers at (–165 °C), and the liquefied LNG is then flashed to atmospheric pressures and stored in specialized atmospheric tanks prior to shipping. This technology allows the transportation of natural gas in the liquid phase form for thousands of miles under maximum pressure of 4 psi using special ships designed for this purpose.

Qatar is a peninsula that extends into the Arab Gulf followed by several islands and is connected with the eastern coast of the Arabian Peninsula only from the southern part of the country. The economy of Qatar before the oil and natural gas boom relied on pearl diving, fishing, agriculture, and handicrafts. Qatar's success in becoming a world‐leading nation in natural gas monetization is based on the discovery of the North Field, the world's largest non‐associated gas reservoir with a reserve of ∼900 tcf natural gas (14% of the total world's known reserves of natural gas). The North Field was discovered in 1971. It is a joint ownership with Iran's South Pars (6,000 square km is the area of the North Field that is in Qatari territorial waters while 3,700 square km (South Pars) is in Iranian territorial waters). Since 2012 Qatar has reached a natural gas production of around 70 million tons per year, and very recently in July 2017 Qatar Petroleum announced its plans to introduce new projects to increase this production to 100 million tons per year. The history of Qatar in building up the world's largest LNG facilities started with the creation of Qatargas in 1984 (a joint venture with Qatar Petroleum, the national energy company), which led several joint venture projects with world‐leading energy corporations (e.g., ExxonMobil, Shell, and Total). In 1996 Qatargas sent its first LNG shipment to Japan, and in 2012 Qatar's national gas companies (Qatargas and Rasgas) became the world's largest producer of LNG, reaching a capacity of 42 million tons per annum. Qatar established Nakilat (Qatar Transport Company) in 2004 as the owner, operator, and manager of Qatar's LNG vessels and to provide shipping and marine‐related services to a range of participants within the Qatari hydrocarbon sector. This company owns the world's largest LNG ships currently including 67 vessels. In January 2018, Qatar's two major LNG companies merged to become Qatargas [11].

Russia, a major producer of natural gas, has the Sakhalin II LNG project of 9.6 million tons of LNG per year. It sells its product to Japan, South Korea, the USA, and Mexico. The United States has only one operational LNG plant, the Cheniere plant at the Sabine Pass Facility, which has a current capacity of 2 billion cubic feet per day. It is expected that United States will become a major player in the LNG market by 2019, with five additional LNG projects under construction with a total capacity of about 7.5 billion cubic feet per day (see Figure 1.6).

Table 1.7 lists the major advantages and the constraints facing LNG technology, which has shown significant growth lately to reach 258 million tons in 2016 with more than 879 million tons per annum (MTPA) of proposed project development, concentrated in North America, East Africa and Asia Pacific [12].

Table 1.7 Advantages and disadvantages for transporting natural gas via LNG technology.

1.4 Natural Gas Conversion to Chemicals and Fuels

Natural gas can be directly or indirectly converted to chemicals and fuels via different chemical catalytic routes (see Figure 1.5). The critical step in these chemistries is the breaking of the carbon–hydrogen bond of methane, a step that requires a large amount of energy and normally takes place at relatively high temperatures. The indirect conversion routes of methane to synthesis gas or syngas (a mixture of carbon monoxide and hydrogen) takes place at temperatures above 800 °C. The gas‐to‐liquid (GTL) technology is one such indirect conversion route of natural gas and comprises three main stages. In the first one, methane is re‐formed to form syngas (a high temperature process and the most expensive part of the GTL technology, which accounts for 65–70% of the total cost). The second stage involves the Fischer‐Tropsch (FT) chemistry to convert syngas into condensates and liquid hydrocarbon over an iron‐based or cobalt‐based catalyst at lower temperatures than the reforming technologies. The FT reactor accounts for 20–24% of the cost of the GTL plant. The third stage is the refining stage to produce fuels and the other hydrocarbon products, which accounts for 9–11% of the GTL plant costs. The high cost of the first stage (the re‐forming stage) is because of the high temperature requirements of the process and the need of pure oxygen in the plant, specifically for the partial oxidation re‐former and the autothermal re‐former. Despite the great potential of the GTL technology for the production of ultra‐clean fuels (free of aromatics and sulfur), the energy‐intensive technology faces three major hurdles:

High CO2 emission especially in the re‐forming stage that challenges its environmental benefit as an ultra‐clean fuel

Economy‐of‐scale limitations of the FT stage to make the GTL process economically sound, requiring either a large‐sized slurry reactor (Sasol technology), or multi‐tubular reactors filled with catalyst particles (Shell technology)

GTL fuels and other products require special marketing campaigns as well as design blending with additives for them to compete as premium fuels with crude‐oil refinery products. Typical GTL products compared are shown in Table 1.8.

Figure 1.5 Natural gas chain with the different routes of natural gas monetization.

Figure 1.6 Historical, current and predicted trends in natural gas expansion in the United States. Y‐axis represents US natural gas trade in trillion cubic feet.

Table 1.8 Typical composition of GTL products.

Qatar is a global leader in the GTL field with two large‐scale plants, the ORYX GTL plant – a joint venture between Qatar Petroleum (QP) (51%), and Sasol‐Chevron (49%) that came online in 2007 – and the world's largest GTL plant, the Pearl GTL Plant (a joint venture between Shell and QP). The ORYX GTL project uses about 330 million cubic feet per day (MMcf/d) of natural gas feedstock from the Al Khaleej field to produce 34,000 barrel/day (b/d) composed of 24,000 b/d diesel, 9,000 b/d naphtha, and 1,000 b/d of LP gas. The Pearl GTL project uses 1.6 billion cubic feet per day (Bcf/d) of natural gas feedstock to produce 140,000 b/d of GTL products as well as 120,000 b/d of natural gas liquids and LPG. Qatar is one of few countries having GTL plants along with South Africa, Nigeria (Escravos GTL plant of similar capacity and technology for the ORYX GTL Plant of Qatar) and Malaysia (the Bintulu GTL plant). Other major natural gas–producing countries, such as Russia and the United States, have yet to build large‐scale GTL plants partially because of the challenges listed above as well as because of the strong market of natural gas on the local monetization in terms of electricity and other sectors as discussed above.

The major advantages and constraints of converting natural gas (mainly methane) to fuels and chemicals is listed in Table 1.9.

Table 1.9 Advantages and constraints in natural gas conversion to chemicals and fuels.

1.5 Summary

This chapter summarizes the monetization routes of natural gas with focus on the experience of three countries that are considered among the major producers and/or exporters of natural gas and its products (the United States, Qatar, and Russia). Each of the aforementioned countries developed different natural gas monetization strategies depending on the local needs and the established marketing plans for its natural gas wealth. As shown in Figure 1.7, the United States natural gas monetization plant has not been changed in recent years despite the significant increase in the role of natural gas in its energy mix as a result of shale gas and tight gas production that reached almost 60% of total U.S. dry natural gas production in 2016 [13]. This book covers different topics related to the fundamentals and applied side of these aforementioned monetization technologies from the upstream to midstream to downstream.

Figure 1.7 The United States natural gas historical, current and forecast natural monetization distribution [3].

Acknowledgment

Part of the material covered in this chapter is a result of research funded by Qatar National Research Fund (QNRF) in several National Priority Research Project (NPRP) that are focused on advancing natural gas processing in Qatar, specifically the Gas‐to‐Liquid Technology. Also, part of the assessment of natural gas monetization techniques is obtained from Shell workshops notes on natural gas processing. The author also would like to acknowledge ORYX GTL company for their support of their support of several projects in natural gas monetization summarized in this chapter.

References

1. BP Energy Outlook 2017 Report. Available from: https://www.bp.com/content/dam/bp/pdf/energy‐economics/energy‐outlook‐2017/bp‐energy‐outlook‐2017.pdf.

2. Key world energy statistics, 2016. International Energy Agency.

3. ExxonMobil Energy Outlook, 2016 report. ExxonMobil. Available from: http://corporate.exxonmobil.com/en/energy/energy‐outlook/a‐view‐to‐2040

4. Dudu P., The world's biggest natural gas reserves. In: Hydrocarbons technology. Available from: http://www.hydrocarbons‐technology.com/features/feature‐the‐worlds‐biggest‐natural‐gas‐reserves/; November 2013.

5. International Energy Agency. Gas. market analysis and forecasts to 2022. Market report series; 2017. Available from: http://www.iea.org/bookshop/741‐Market_Report_Series:_Gas_2017.

6. Environmental Protection Agency. Inventory of U.S. greenhouse gas emissions and sinks: 1990–2015; 2017.

7. Energy Information Agency (EIA). How much of the U.S. carbon dioxide emissions are associated with electricity generation? 2017.

8. U.S. Energy Information Agency. EIA—electricity data. Available at: https://www.eia.gov/electricity/; 2017.

9. The United States Central Intelligence Agency (CIA)The world fact book. Available from: https://www.cia.gov/library/publications/the‐world‐factbook/fields/2117.html.

10. U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration. Pipeline safety fact sheet. Available from: https://www.aga.org/research/fact‐sheets/pipeline‐safety/.

11. CNBC Energy News. Qatar announces huge rise in gas production amid diplomatic crisis. Available from: https://www.cnbc.com/2017/07/04/qatar‐ratchets‐up‐gas‐production‐30‐percent‐despite‐sanctions.html.

12. International Gas Union. 2017 world LNG report; 2017. Available from: https://www.igu.org/sites/default/files/103419‐World_IGU_Report_no%20crops.pdf.

13. U.S. Energy Information Administration (EIA). How much shale gas is produced in the United States? 2016. Available from: https://www.eia.gov/tools/faqs/faq.php?id=907&t=8.

2

Techno‐Economic Analyses and Policy Implications of Environmental Remediation of Shale Gas Wells in the Barnett Shales

Rasha Hasaneen, Andrew Avalos, Nathan Sibley and Mohammed Shammaa

Dwight Look College of Engineering, Texas A&M University, USA

Chapter Menu

2.1 Introduction

2.2 Shale Gas Operations

2.3 The Barnett Shale

2.4 Environmental Remediation of Greenhouse Gas Emissions Using Natural Gas as a Fuel

2.5 Environmental Remediation of Water and Seismic Impacts

2.6 Theoretical Calculations

2.7 Results and Discussion

2.8 Opportunities for Future Research

2.1 Introduction

2.1.1 Framing the Issues: The Energy and Environmental Equation

Global demand for energy as well the global carbon footprint is expected to rise consistently through 2050 (EIA 2017a). United States energy demand/consumption continues to be among the largest in the world, as does its carbon footprint, especially when compared to other global economies (EIA 2017a). The U.S. is expected to remain the largest consumer of energy and emitter of CO2, after China, through 2050 as shown in Figure 2.1.

Figure 2.1 Projected global energy demand and CO2 emissions.

While it is true that both the energy and CO2 intensities (per dollar of GDP) of the United States paint a much better picture (EIA 2017a), the issue still remains that the U.S. will continue to need more energy and emit more carbon dioxide than most other countries on the planet. Although it is difficult to accurately characterize energy reserves globally, it is clear that United States demand is expected to outstrip what can be produced domestically from traditional sources, across all sectors of the economy (EIA 2017a).

In addition, the current United States energy mix sways heavily toward coal and oil, totaling about 52% of total fuel consumption (EIA 2017b), which have a high environmental tax as compared to cleaner sources. Electricity generation sways more towards coal while transportation relies heavily on petroleum. Without clean, domestic alternatives to support this demand, the United States will continue to rely heavily on foreign energy sources and negatively impact the environment.

In recent years, shale gas has emerged as a potential alternative to this issue. Advances in horizontal drilling and hydraulic fracturing technologies have driven a rapid and widespread growth in natural gas production from shale formations in the United States. This development has narrowed the production‐consumption gap in U.S. energy and is expected to turn the United States into a net exporter of natural gas by 2020 (EIA 2013a). As natural gas is considered among the cleanest of conventional fuels, in terms of usage, this also promises a reduction of the carbon footprint of the United States (EIA 2012b), as many of the industries which are heavily reliant on coal and oil turn to natural gas as an alternative.(EIA 2012a; EPA 2013; EIA 2013a).

While natural gas itself is considered a clean fuel, the extraction process, attributed to natural gas derived from shale formations, has raised many debates as to the total lifecycle environmental footprint of the fuel (Armendariz 2009; Arthur et al. 2008; COGA 2012; Fontenot et al. 2013; McHugh et al. 2014; Fontenot et al. 2014; Skone et al. 2011; Jaramillo et al. 2007; EIA 2011). Many argue that the environmental impact of drilling and production processes employed in shale gas operations severely limit the environmental benefit of the use of shale gas as a clean fuel alternative (Howarth et al. 2010; Howarth et al. 2011; Cathes et al. 2012).

While research in this area is still developing, there are unique elements of shale gas drilling and production operations that inherently contribute to their environmental footprint. Shale reservoirs are massive, typically spanning multiple communities, many coming close to metropolitan areas and agricultural zones (EIA 2011). As a result, localized environmental impacts have less opportunity to dissipate and must be contained much more tightly. Also, as compared to vertical wells, in conventional oil and gas formations, unconventional wells tend to be more closely spaced and can take months to drill. They require horizontal drilling to access the formation and more fully drain the rock matrix and must employ hydraulic fracturing at extensive rates to stimulate production. The hydraulic fracturing process involves the injection of large amounts of chemical‐laden water and mud into the well at high pressures, in order to fracture the rock and allow the gas to be produced (Kell 2009). Although hydraulic fracturing has been used for decades to stimulate traditional oil and gas wells, the main issue with shale is scale. The size and number of fractures required to release the gas from shale is much more significant than those previously employed by the industry (Clark et al. 2013).

As the current boom in shale production is relatively new, there is still fragmentation among operators in terms of drilling and production processes. Many of the producers typically operate using traditional techniques, which allow for minimal up‐front capital investment. Also, since the breakeven gas/oil price for unconventional resources is much higher than those in conventional reservoirs, these operators are typically very cost sensitive. This has led to operations that have proven to be suboptimal from an environmental perspective (Fontenot et al. 2013; Howarth et al. 2010; Jenner and Lamadrid 2013).

These issues are becoming more pronounced as we discover and characterize more and more shale gas deposits. The situation has led to a negative perception of shale gas (Thomas et al. 2017) and growing opposition to the hydraulic fracturing process with several bans and moratoria on shale gas extraction, led by local and municipal governments, both in the United States and across the world (Hagstrom and Jackanich 2011; Metze 2017) Without alternatives that reduce this environmental impact, shale gas production may have significant adverse effects on both immediate environmental health and safety as well as on the broader environment.

The process it takes to develop a gas well requires an extensive use of diesel fuel, fresh water, contingencies to local water supply, roads, and reinjection of waste water into deep wells for disposal. The environmental impacts of these activities (Zoback et al. 2010; Annevelink et al. 2016) include:

Land impacts – Number of wells that need to be drilled; acreage and clearing for well pads and impoundments; clearing land for building new roads

Greenhouse gas emissions – Fugitive methane emissions and flaring; release of pollutants from diesel and gasoline engines used in the operation

Impacts on water – Overconsumption of fresh water for fracturing (millions of gallons per well) (Kell, 2009) and waste water management required due to the contamination of water with fracturing chemicals and methane (local streams/rivers and well water); pond fires due to wastewater pond negligence (Tagliaferri et al. 2017)

Seismic impacts – Increased seismic activity related to hydraulic fracturing (COGA 2012), natural gas extraction and waste water re‐injection (Nicholson and Wesson 1987)

Additional impacts – Release of VOCs from well installation and radioactive particles in waste water

While these issues are common among unconventional gas plays, the unique composition of the gas in each play could require additional processes, which would also need environmental remediation such as dewatering or CO2 removal. As a result, looking at these issues can form a foundation for analysis of other plays, but cannot be applied directly without adaptation.

2.1.2 Well Lifecycle Analysis and Environmental Impacts

In order to focus the analysis, a specific shale gas play was evaluated. Depending on the underlying depositional system, different shale plays will require different remediation approaches, so limiting the analysis to a specific play enables a focused approach to the analysis. The Barnett Shale was chosen as it is among the most established and most mature shale gas plays in the United States today, and it plays a critical role in the U.S. natural gas landscape. As a result, a robust data set collected from operations in the Barnett could be used to conduct the analyses.

In looking at the environmental impacts of shale gas, it was assumed that once the gas is produced and processed for transportation, its environmental footprint will be similar to that of natural gas from conventional sources. Therefore, the focus of this analysis is on the environmental footprint of the drilling and production processes associated with shale gas extraction, the well lifecycle, and not on the entire lifecycle of the shale gas itself.

As discussed previously, there are a number of environmental issues tied to shale gas development. Issues around greenhouse gas emissions, water consumption and disposal during hydraulic fracturing, and seismicity are the most consistent among shale gas plays and have the most direct impact on the immediate environment. In addition, these elements are among the most difficult to manage and mitigate.

As a result, the well lifecycle analysis across this chapter focuses on these three elements, and the proposed improvements to reduce the impact on the immediate environment were analyzed and discussed at length. In the first section, the analysis will focus on greenhouse gas emissions. Specifically, it focuses on emissions resulting from the burning of fuel to run drilling and production equipment rather than fugitive methane emissions, which can also be a source of greenhouse gas emissions in the operations. The second part of the analysis will turn its focus towards the impacts on water consumption and disposal and seismicity, which are inter‐related.

2.2 Shale Gas Operations

To analyze the environmental impact of the drilling and production processes associated with shale gas, it is useful to understand the overall operation: how the gas is extracted and how it differs from conventional operations. This is the basis for the well lifecycle analysis.

2.2.1 Summary of Shale Gas Operations

After the initial exploration, permitting, and exploratory drilling stages are completed, an operator will begin drilling and production activities. Land is cleared for the operation and vertical wells are drilled into the shale formation through to the total formation depth. Conventional wells are typically drilled into sandstone, and the natural permeability allows the fluids to flow to the low‐pressure wellbore; thus artificial stimulation, such as fracturing, is not necessary. In contrast, a wellbore in an unconventional reservoir may make contact with some natural fractures, but the hydrocarbons that could be produced from these are insufficient for economic production of gas. In order to bring enough fluid to the surface, the fracture network needs to be greatly expanded. Thus, a well needs to be designed in a way that will connect to the maximum number of fractures and allow induced fractures to expand as far as possible. This is achieved in the first two phases of the well's lifecycle: drilling and completion. The final phase of the lifecycle, the production phase, requires marginal effort, as it typically consists of a pumper making daily checks on the well or performing a workover, as required. Most new gas wells go through these three major phases in their life: drilling, completion/stimulation, and production. The drilling and completion phases are relatively brief, typically one to two months in duration, but require a tremendous amount of energy and capital. It is during these phases that much of the environmental impacts occur. The production phase starts when the well begins flowing and continues until it reaches the end of its economic life. Since many unconventional wells can live for decades, the marginal environmental impact of the production phase can sum up to a material amount.

Drilling: In the drilling phase, a well is drilled that descends into the targeted formation and bores through it, horizontally, increasing the contact area with the reservoir. Horizontal wells are drilled to a kick‐off point (KOP), and the bit is driven in a soft angle until it reaches approximately 90° and will continue to bore to the desired measured depth. As a well is drilled, the hole will be encased with steel pipes, and cement will be pumped around it to improve isolation of the well from the subsurface zones. One of the advantages of horizontal wells is that multiple wells can be drilled into the targeted formation from a single well pad. This reduces the impact to the surface environment and reduces costs.

Completions: Once a well has been drilled, cased, and cemented, the stimulation or completion process begins. In the completion phase, the well bore is perforated to establish communication with the reservoir, and fractures are induced using hydraulic fracturing (Kell 2009). Hydraulic fracturing is a process that induces fractures into the rock, by pumping fluid down at very high rates. The fluid is often fresh‐water‐based and filled with proppant, a sandy or gel‐like substance that fills in the newly created fractures and keeps them propped open to allow reservoir fluids to flow. This perforation and fluid pumping process is repeated several times in stages and connects the natural fractures within the reservoir. The combination of these fractures creates a large network of interconnected pores to the wellbore and allows for economical flow of oil and gas (Gale et al. 2007; Gottschling 2005).

Production: The gas is then produced by allowing fluid to flow to the surface. The gas is collected for processing and transportation.

The drilling and completion phases are relatively brief, typically one to two months in duration, but require a tremendous amount of energy and capital. It is during these phases that much of the environmental impacts occur. Specifically, it is during the completion phase that the well is hydraulically stimulated by fracturing the underlying matrix to release the gas. This hydraulic fracturing is the focus for much debate as it relates to water usage, disposal, and seismicity. The production phase starts when the well begins flowing and continues until it reaches the end of its economic life. During the production phase, much of the water that is used to fracture the well flows back and is produced with the natural gas. It must then be transported and disposed of. Since many unconventional wells can live for decades, the marginal environmental impact of the production phase can add up to a significant amount.

2.2.2 Hydraulic Fracturing and Water Impacts

Fracturing fluid is typically a slurry of water, proppant, and chemical additives, typically, 90% of the fluid is water and 9.5% is sand, with chemical additives accounting to about 0.5%.(Ciferno et al. 2012; API 2010) The quality of the water used is critical as impurities can reduce the efficiency of the additives used in the process. An average well requires 3 to 8 million U.S. gallons (11,000 to 30,000 m³) of water over its lifetime (Ciferno et al. 2012), while the average well in the Barnett Shale formation uses from approximately 2.8 million (Nicot and Scanlon 2012) to 5 million (Nicot et al. 2014) gallons of water depending on horizontal fracture length and number of stages per well. Today, most water used in hydraulic fracturing comes from surface water sources such as lakes, rivers, and municipal supplies. However, groundwater can be used to augment surface water supplies where it is available in sufficient quantities.

While the cost of water also varies, water can behave as a public good, and water rights are typically granted with the land lease, along with mineral rights. In these cases, the cost of water represents the opportunity cost of selling that water on the market. In other cases, water is purchased from neighboring water authorities. This cost will vary dramatically based on the abundance of water in the region for alternatives such as farming, industrial operations, and urban usage.

The use of vast amounts of potable, fresh water has raised concerns in communities neighboring shale gas operations. This is heightened by the fact that shale reservoirs span such large territories, many across rural areas where potable water is in high demand (Grattan 2014). In addition, the transport of such large amounts of water requires the use of trucks, which has both cost and greenhouse gas implications. This transportation element becomes critical in arid areas or areas of high water stress that have large shale formations (Reig et al. 2014a).

Slickwater fracturing has additional issues in terms of the expected ultimate recovery of oil and gas from shale resources. As, typically, less than 50% of the water injected is produced over the life of the well, it can actually act as a barrier to optimal production by impeding the flow of oil and gas back through the network of fractures created (Burke et al. 2011; Reynolds et al. 2013).

Perhaps as critical as the use of fresh water, is the disposal of produced water once the fracturing operation is completed. The fluid that returns to the surface through the wellbore is not only the chemically treated fracture water, but also water from the rock formation that can contain salts, metals, and radionuclides. This water can contain hydrocarbons, high levels of total dissolved solids (TDS), suspended solids, and residual production chemicals. That wastewater must be captured and stored on site, and then is often shipped long distances for deep well injection. Produced water stored on the surface for long periods of time is subject to evaporation, which can further increase the salt concentration of the water. Additionally, flowback of produced water, generated during completion and production operations, could have catastrophic results on the underground drinking water supply, if done improperly. About 30% of injected water returns to the surface as produced water in the first month with another 20–30% returning over the life of the well. This implies that about 40–50% of the injected water remains in the rock matrix and in many cases impedes the flowback of natural gas through the well bore. A hydraulic fracture typically exhibits about 20% efficiency (Khuwaja et al. 2014).

2.2.2.1 Fresh Water Consumption

Although it is difficult to generalize on water usage by well, by focusing on the Barnett Shale play, averages can be used to estimate the potential benefits of environmental remediation. Nicot and Scanlon estimate that an average well in the Barnett Shale uses 2.8 million gallons of water for hydraulic fracturing (Nicot and Scanlon 2012). While the cost of water also varies, groundwater typically behaves as a public good, and water rights are typically granted with the land lease, along with mineral rights. Thus, the cost of water used in the simulator represents the publicly available price of water in the Barnett Shale area for "gas