Crisman Annual Report 2009 - Harold Vance Department of ...

Harold Vance Department of Petroleum Engineering 

at Texas A&M University 

2009 Annual Report 

End of Coreflood for 3000 ppm gel: 

End of Coreflood for 10,000 ppm gel: 

Pure CO 2 

flood image (after 1.6 PV CO 2 

injected) 

Viscosified CO 2 


injected) 

0 

ΔP 

(psi/ft) 

0.50 

270 90 

0.06 

180 

Halliburton Center for Unconventional Resources 

Chevron Center for Well Construction and Production 

Schlumberger Center for Reservoir Description and Dynamics 

Center for Energy, Environment, and Transportation Innovation

Crisman Institute for Petroleum Research 

Harold Vance Department of Petroleum Engineering at Texas A&M University 

2009 Annual Report 

Halliburton Center for Unconventional Resources 

Chevron Center for Well Construction and Production 

Schlumberger Center for Reservoir Description and Dynamics 

Center for Energy, Environment, and Transportation Innovation

Issue 3, February 2010 

Stephen A. Holditch 

Director 

Nancy H. Luedke 

Editor 

Harold Vance Department of Petroleum Engineering 

3116 TAMU 

College Station TX 77843-3116 

979.845.2255 

© 2010 Harold Vance Department of Petroleum Engineering 

at Texas A&M University. All rights reserved. 

Kathy Beladi 

Editor 

Email: info@pe.tamu.edu 

Cover images (clockwise from top left): Gel strength study and comparison of flood fronts, Report 3.4.4, pg 78; Coreholer connected to slimtube, Report 

1.7.3, pg 44; Steam chamber temperature distribution image, Report 1.3.13, pg. 30; Structural permeability diagram for Barnett Shale, Report 2.5.10, 

pg. 61; Medium resolution 75 layer 3D geologic model, Report 3.1.22, pg. 71. 

2 

Crisman Annual Report 2009

Contents 

Vision ........................................................................................................................................ 7 

Mission ...................................................................................................................................... 7 

Objectives ................................................................................................................................. 7 

Summary ................................................................................................................................... 8 

Membership History................................................................................................................. 10 

Meetings .................................................................................................................................. 11 

Summary of Research Results 

Casing Failure ............................................................................................................................ 13 

An Advisory System for Selecting Drilling Technologies and Methods in Tight Gas Reservoirs ................. 14 

Assessment of API Thread Connections under Tight Gas Well Conditions ............................................ 15 

Gas Shales – Geomechanics/Completions ...................................................................................... 17 

PRISE – Petroleum Resource Investigation Summary and Evaluation ................................................. 18 

An Investigation of Regional Variations of Barnett Shale Reservoir Properties, and Resulting Variability 

of Hydrocarbon Composition and Well Performance ...................................................................... 19 

Gas Shales Simulation and Production Data Analysis ....................................................................... 20 

Characterization of Rock Transport Properties in Tight Gas and Shale ................................................. 22 

Rate Transient Analysis in Shale Gas Reservoirs with Transient Linear Behavior ................................... 23 

An Analytical Approach to Model Shale Gas Reservoir Flow Including Desorption Effects ....................... 24 

Water Production Issues in the Barnett Shale ................................................................................. 25 

Enhanced Oil Refining Technology through E-Beam Thermal Cracking ................................................ 27 

Experimental Investigation of Caustic Steam Injection for Heavy Oils ................................................ 29 

Experimental and Simulation Modeling Studies of Steam Assisted Gravity .......................................... 30 

In-Situ Oil Upgrading using Tetralin (C 10 

H 12 

) Hydrogen Donor and Fe(acac) 3 

Catalyst at Steam Injection 

Pressure and Temperature ........................................................................................................ 31 

Artificial Geothermal Energy Potential of Steam-Flooded Heavy Oil Reservoirs ..................................... 33 

Study of Solvent-Based Emulsion Injection to Improve Sweep and Displacement Efficiency in Heavy 

Oil Reservoir ........................................................................................................................... 34 

Investigation of Hybrid Steam-Solvent Processes to Increase Efficiency of Thermal Oil Recovery 

Methods ................................................................................................................................. 36 

Experimental Studies of Steam Injection with Surfactant for Enhancing Heavy Oil Recovery after 

Waterflooding ......................................................................................................................... 38 

Crisman Annual Report 2009 

3

Combustion Assisted Gravity Drainage (CAGD): An In-Situ Combustion Method to Recover Heavy 

Oil and Bitumen from Geologic Formations using a Horizontal Injector-Producer Pair ........................ 40 

Well Spacing and Infill Drilling in Coalbed Methane Reservoirs .......................................................... 42 

Drilling through Gas Hydrate Formations ........................................................................................ 43 

Experimental and Numerical Simulation Studies to Evaluate Improvement of Light Oil Recovery by 

WACO 2 

and SWACO 2 

in Fractured Carbonate Reservoirs ................................................................ 44 

Enhanced Oil Recovery of Viscous Oil by Injection of Water-in-Oil Emulsions ....................................... 46 

Managed Pressure Drilling Candidate Selection ............................................................................... 47 

Alternate Power and Energy Storage/Reuse for Drilling Rigs: Reduced Cost and Lower Emissions 

Provide Lower Footprint for Drilling Operations ............................................................................ 48 

Cement Fatigue Failure and HPHT Well Integrity .............................................................................. 49 

Propagation of Induced Hydraulic Fractures near Pre-Existing Fractures ............................................. 50 

Using Downhole Temperature Measurement to Assist Reservoir Characterization and Optimization ......... 51 

Optimization of Horizontal Well Performance in Low-Permeability Gas Reservoirs ................................. 53 

Decision Matrix for Liquid Loading in Gas Wells for Cost/Benefit Analyses of Lifting Options (Part 2) ....... 54 

Investigation of Swirl Flows Applied to the Oil and Gas Industry ........................................................ 55 

Potential for CO 2 

Sequestration and Enhanced Coalbed Methane Production, NW Black Warrior Basin ..... 57 

Transient Multiphase Sand Transport in Horizontal Wells ................................................................... 58 

Performance Driven Hydraulic Fracture Design for Deviated Wells ...................................................... 59 

Carbonate Heterogeneity and Acid Fracture Performance ................................................................. 60 

Modeling and Analysis of Reservoir Response to Stimulation by Water Injection .................................. 61 

Fracture Aperture Variation Caused by Reactive Transport of Silica and 

Poro-Thermoelastic Effect ......................................................................................................... 62 

Rheological Properties of a New Class of Viscoelastic Surfactant ........................................................ 63 

Acid Hydrolysis of Carboxybetaine Viscoelastic Surfactant ................................................................ 65 

Evaluation of Polymer-Based In-Situ Gelled Acids during Well Stimulation .......................................... 66 

Modeling of Discrete Fracture Network using Voronoi Grid System ..................................................... 68 

Thermo-Poroelastic Finite Element Analysis of Rock Deformation and Damage .................................... 70 

Application of Adaptive Gridding and Upscaling for Improved Tight Gas Reservoir Simulation ................ 71 

Measurement and Correlation of Gas Viscosities at High Pressures and High Temperatures ................... 72 

Measurement of Gas Viscosity at High Pressures and High Temperatures ............................................ 73 

4 


Numerical Modeling of Fracture Permeability Change in Naturally Fractured Reservoirs using a Fully 

Coupled Displacement Discontinuity Method ............................................................................... 75 

Improved Permeability Predictions using Multivariate Analysis Methods .............................................. 77 

CO 2 

Mobility Control using Cross-Linked Gel and CO 2 

Viscosifiers ....................................................... 78 

Stochastic History Matching, Forecasting, and Production with the Ensemble Kalman Filter ................... 79 

Sustainable Carbon Sequestration ................................................................................................. 81 

Aquifer Management for CO 2 

Sequestration .................................................................................... 82 

Pretreatment Options to Allow Re-Use of Frac Flowback and Produced Brine (Desalination Process) ....... 83 

Bibliography ............................................................................................................................ 84 


5

6 


Vision 

The vision of the Crisman Institute for Petroleum Research is to provide a vehicle to enhance development 

of petroleum engineering technology through cutting-edge, industry-directed research conducted in four 

dedicated research Centers in the Harold Vance Department of Petroleum Engineering at Texas A&M 

University. 

The Crisman Institute for Petroleum Research identifies and solves significant research 

problems of major interest to industry and government. The Institute conducts it efforts in four research 

Centers: the Halliburton Center for Unconventional Resources, the Chevron Center for Well Construction and 

Production, the Schlumberger Center for Reservoir Description and Dynamics, and the Center for Energy, 

Environment and Transportation Innovation. Industry and governmental representatives can help identify 

problems of major significance and support projects of particular interest to them through membership at 

the Institute, Center, or Project level. Additionally, membership provides seed money for identification and 

initiation of research into additional problems facing the industry. 

Mission 

» The mission of the Crisman Institute for Petroleum Research is to produce significant advances in upstream 

petroleum engineering technology through the combined efforts of faculty, post-doctoral researchers, 

highly qualified graduate students, in close cooperation with industry. 

» The mission of the Halliburton Center for Unconventional Resources is to increase our ability to 

characterize reserves of unconventional resources and to develop new, more efficient ways to reduce costs 

and improve recovery of these resources. 

» The mission of the Chevron Center for Well Construction and Production is to develop new 

tools, both theoretical and physical, to construct and complete wells in today’s increasingly challenging 

environments in a way that will reduce the finding and development costs. 

» The mission of the Schlumberger Center for Reservoir Description and Dynamics is to develop 

better approaches to describe and model petroleum reservoirs and to manage the resources identified 

there to reduce costs and improve recovery. 

» The mission of the Center for Energy, Environment, and Transportation Innovation is to form 

an interdisciplinary collaboration to study the needs of a 21 st century transportation system addressing 

energy, environment, and social issues. 

Objectives 

The Crisman Institute and its four Centers have seven primary objectives: 

» Work with industry and government representatives to identify the most important problems now facing 

the upstream petroleum industry and those that arise in the future. 

» Focus our efforts on solutions to as many of the identified problems as possible within the framework of 

available resources. 

» Develop solutions that will be immediately useful in the industry. 

» Maintain a clearinghouse of research efforts, tracking not only research in progress but also results of 

completed projects and perspectives on research possibilities for the future. 

» Continuously upgrade the problem-solving capabilities of the Institute through ongoing faculty development 

strategies and pursuit of outstanding post-doctoral and graduate students. 

» Ensure financial stability to continue to provide long-term solutions to technology-development problems. 

» Publicize the activities of the Institute and the contributions of the membership who make those activities 

possible. 


7

Summary 

The Crisman Institute has two main purposes. One purpose is based on the Vision, Mission and Objectives 

which is to do high-quality research. Another purpose is to help alleviate the manpower shortage that 

companies are experiencing. As we all know, the world needs more engineers and scientists, especially in 

the oil and gas industry. We are helping with this by producing more high-quality engineers over the last 

several years as shown in the tables below. 

Recent Trends in Graduate Enrollment 

Year Master Phd Total 

1997-1998 62 41 103 

1998-1999 64 37 101 

1999-2000 93 38 131 

2000-2001 134 30 164 

2001-2002 142 33 175 

2002-2003 132 33 165 

2003-2004 126 32 158 

2004-2005 123 43 166 

2005-2006 141 50 191 

2006-2007 157 55 212 

2007-2008 181 67 248 

2008-2009 189 81 270 

2009-2010 239 80 323 

Recent Trends in Graduate Degrees 

Year Master Phd Total 

1997-1998 27 11 38 

1998-1999 18 7 25 

1999-2000 20 13 33 

2000-2001 38 4 42 

2001-2002 65 5 70 

2002-2003 41 5 46 

2003-2004 67 12 79 

2004-2005 45 8 53 

2005-2006 40 4 44 

2006-2007 62 17 79 

2007-2008 51 12 63 

2008-2009 48 18 66 

Totals 522 116 638 

8 


The Crisman Institute has made great strides in 

growing and building the petroleum engineering 

department’s research program. Since 2005, the 

Crisman Institute has funded a total of 184 projects 

of which 139 are complete. For the Spring 2010 

semester, we had a total of 319 graduate students. 

We had 117 graduate research assistant positions 

during that time and Crisman funded 31 of them. 

Some of the research we have conducted 

through Crisman has allowed us to develop 

software and databases that can be used by 

industry. An additional benefit companies 

have experienced is the opportunity to 

become familiar with our students and their research 

which has often led companies to hire them post 

graduation. 

As noted in the tables and charts below, I have 

broken down the distribution of our progress for 

each of the four centers and for each year. 

» Halliburton Center for Unconventional Resources 

(UCR) 

» Chevron Center for Well Construction and 

Production (WCP) 

» Schlumberger Center for Reservoir Description 

and Dynamics (RDD) 

» Center for Energy, Environment, and Transportation 

Innovation (EETI) 

Projects by Centers 

Center Completed In Progress 

UCR 54 22 

WCP 39 13 

RDD 32 8 

EETI 14 2 

Total 139 45 

Total Projects: 184 

WCP 

Number of Projects 

UCR 

RDD 

EETI 

Total 

140 

120 

100 

80 

60 

40 

20 

Completed 

In Progress 

0 20 40 60 80 100 120 

0 

Completed Projects by Year 

Year 

Number 

2009 15 

2008 30 

2007 47 

2006 20 

2005 25 

2004 2 

Total 137 

2004 2005 2006 2007 2008 2009 Total 

Year 

140 

As you read through this annual report, I hope you 

see the many achievements we have experienced 

over the past 6 years. Through the support of 

industry, the Crisman Institute and the department 

are making an impact on our students, research, and 

industry. We intend to report even more successes 

in 2010. 


9

Membership History 

The Crisman Institute began operation in its current format on January 1, 2005. At the end of 2005, we 

had three endowed members, four institute members and six center members. The Institute maintained 

these membership categories until January 1, 2007. Since the beginning of 2007, we eliminated the 

center memberships and all companies now belong to the entire Crisman Institute. As such, all member 

companies have the rights to use all the results from all the projects sponsored by Crisman. Table 1 shows 

the membership history. 

2005 2006 2007 2008 2009 2010 

Halliburton Halliburton Halliburton Halliburton Halliburton Halliburton 

Chevron Chevron Chevron Chevron Chevron Chevron 

Schlumberger Schlumberger Schlumberger Schlumberger Schlumberger Schlumberger 

Anadarko Anadarko Anadarko Anadarko Anadarko 

Baker Hughes Baker Hughes Baker Hughes Baker Hughes Baker Hughes 

Nexen Nexen Nexen Nexen Nexen Nexen 

Economides Consulting 

IHS IHS IHS IHS IHS 

ExxonMobil ExxonMobil ExxonMobil ExxonMobil ExxonMobil 

Matador Resources 

Burlington 

Burlington 

Total Total Total Total Total Total 

Newfield Newfield Newfield Newfield Newfield Newfield 

Devon 

Devon 

BP BP BP BP BP 

ConocoPhillips ConocoPhillips ConocoPhillips ConocoPhillips ConocoPhillips ConocoPhillips 

Saudi Aramco Saudi Aramco Saudi Aramco 

El Paso El Paso El Paso 

BJ Services BJ Services BJ Services 

Marathon 

Shell 

Marathon 

Shell 

Repsol 

MI-Swaco 

ENI 

NETL-DOE 

Table 1. Membership History for the Crisman Institute. 

10 


Meetings 

Steering Committee Meeting 

» March 1, 2010 

One Day Technology Meetings/Center Meetings 

2010 

» June 1 - Enhanced Oil Recovery 

» May 27 - Environmentally Friendly Drilling Meeting 

» May 25 - Well Productivity Improvement 

» May 20 - Heavy Oil and IOR Research 

» May 18 - Shale Gas Meeting 

» February 23 - Environmentally Friendly Drilling 

Meeting in Houston, Texas 

2009 

» December 15 - Shale Gas 

» October 16 - Technology Transfer Meeting on 

Unconventional Gas and Hydraulic Fracturing 

» October 4 - Heavy Oil and IOR Methods 

» June 24 - Role of Chemistry in Well Production 

» May 19 - Shale Gas 

» May 14 - Reservoir Performance for Enhanced Oil 

Recovery by CO 2 Injection 

» April 23 - Environmentally Friendly Drilling Meeting 

in Houston, Texas 

» April 14 - Acid Fracture Conductivity 

» March 18 - Chemical EOR and Water Shut-Off 

Using Chemical Means 

» February 18 - Advanced Hydraulic Fracturing 

2008 

» December 16 - Shale Gas Meeting 

» December 12 - Heavy Oil and IOR Methods Meeting 

» December 11 - Business Meeting and Unconventional 

Gas Reservoirs Advisory Meeting 

» November 5 - Environmentally Friendly Drilling 

» June 5 - Shale Gas 

» May 30 - Low Impact Access in Environmentally 

Sensitive Areas 

» May 21 - Acid Fracture Conductivity 

» May 20 - Unconventional Gas 

» May 19 - Hydraulic Fracturing in Tight Gas 

Formations (afternoon) 

» May 19 - Intelligent Completion and Applications 

(morning) 

» May 8 - Heavy Oil and IOR Methods 


» May 5 - Gas Well Unloading 

2007 

» December 11 – Shale Gas Production Data 

Analyses 

» November 29 – Center for Energy Environmental, 

and Transportation Innovation 

» November 16 – Heavy Oil and Improved Recovery 

Methods 

» November 5 - Gas Well Unloading 

» October 25 - Acid Fracturing Conductivity 

» October 24 - Unconventional Gas Reservoirs & 

Resource Assessment 

» October 17 - Hydraulic Fracturing in Tight Gas 

Formation 

» October 9 - Advanced Drilling Technology 

» May 10 - Gas Well Unloading 

» May 9 - Tight Gas Sands Meeting 

» May 8 - Environmentally Friendly Drilling Meeting 

in Houston, Texas 

» April 26 - Fractured Shale Reservoirs Meeting 

» April 25 - Heavy Oil Recovery Meeting 

» April 11 - Intelligent Well Technology 

2006 

» November 9 - Halliburton Center 

» November 8 - Schlumberger Center 

» November 7 - Chevron Center 

» September 6 - Resource Assessment for 

Unconventional Reservoirs 

» September 6 - Fracture Fluid Damage and Cleanup 

» August 9 - Gas Well Deliquification 

» August 3 - Heavy Oil 

» May 25 - Halliburton Center 

» May 24 - Schlumberger Center 

» May 23 - Chevron Center 

2005 

» November 11 - Chevron Center 

» November 10 - Schlumberger Center 

» November 10 - Halliburton Center 

» May 26 - Halliburton Center 

» March 24 - Schlumberger Center 

» January 27 - Chevron Center 

11

12 


Casing Failure 

Objectives 

The objective is to develop a casing failure 

probabilistic model that describes casing behavior in 

the compacting reservoir. Depletion of pore pressure 

from oil production in an unconsolidated formation, 

or soft formations such as sandstone, chalk, and 

diatomite, causes casing deformation, which can 

later turn to failure. Creating a probabilistic model 

can explain the relationship between failure and 

involved parameters. By matching the model results 

with field history, the model is corrected for each 

specific field. Thus, the model can be projected 

for future casing failure of each field. Mitigation 

strategies can be implemented to minimize the rate 

of future casing failure according to the results of 

the model. 

Accomplishments 

Tests were done on the compression failure model. 

The results show that with a higher grade of casing 

the probability of failure decreases. Thus, increasing 

casing grade may help strengthen casing against 

compression failure. Well inclination is another 

factor that can decrease the probability of failure. 

For compression failure, vertical wells are more 

susceptible to failure than inclined wells, as shown 

in the results. Cementing plays an important role 

in compression failure. Slippage at the cementformation 

and cement-casing can reduce maximum 

casing strain subjected to reservoir compaction by 

30%-40%, which is also shown in the result. Also, 

the use of ductile cement can reduce the risk of 

compression failure through cement properties. 

Future Work 

Acquire all casing properties and parameters, such as 

diameter and thickness. The magnitude of buckling 

failure could depend on the unsupported length of 

casing. Run buckling failure model and analyze the 

results with different unsupported lengths. Compare 

the results of the unsupported with the supported 

to prove that buckling failure is likely to occur when 

casing is not laterally supported. 

CRISMAN INSTITUTE 

Project Information 

1.1.2 Reservoir Compaction and Casing Integrity in Texas 

Gulf of Mexico Coast, Part II 

Contacts 

Jerome Schubert 

979.862.1195 

jerome.schubert@pe.tamu.edu 

Catalin Teodoriu 

catalin.teodoriu@pe.tamu.edu 

Prasongsit Chantose 


13

An Advisory System for Selecting Drilling Technologies and Methods in Tight Gas 

Reservoirs 

Objectives 

The main objective of this research project is to 

develop a computer program dedicated to applying 

the drilling technologies and methods selection for 

drilling tight gas sandstone formations that have 

been documented as best practices in the petroleum 

literature. We have created an advisory module 

for tight gas that is part of a general Drilling & 

Completion Advisor for unconventional formations. 

This Drilling & Completion Advisory Module, along 

two other programs called BASIN (basin analogy) 

and PRISE (resource evaluation) is part of the 

UGR (unconventional gas resources) Advisor under 

development at Texas A&M by a team of graduate 

students and professors. 

Approach 

To complete the Drilling Advisory Module for tight 

gas reservoirs, we have identified and reviewed 

relevant data in worldwide literature on tight gas 

reservoirs with a strong emphasis on the latest 

drilling technologies, such as: casing drilling, 

underbalanced drilling, managed pressure drilling, 

horizontal drilling, directional S-shaped drilling (well 

clusters) and coiled tubing drilling. We have analyzed 

under which critical parameters one technology 

has been preferred or is currently being applied in 

comparison with other drilling techniques. Further, 

we have extracted key criteria and have developed 

decision charts, which mimic the thinking process of 

an expert. We have written Visual Basic programs 

using Microsoft Visual Studio implementing all the 

decisions charts created during this research. Finally, 

we will test and validate the Drilling Advisory Module 

with U.S. tight gas real cases. 


Our results have led to the following accomplishments: 

» A drilling advisory system has been designed and 

programmed for a Windows O.S. environment in 

order to capture the industry best drilling practices 

from tight gas reservoirs. 

» The advisory system has been divided into 

several sub-modules to guide the user through 

the multiple steps to make decision selecting 

drilling technologies and methods to drill tight gas 

reservoirs. Each of the sub-modules deals with 

a specific topic (well data, drilling parameters, 

drilling time, drilling cost, ranking). Each dataset 

can be loaded or saved in a text file for analysis 

or post-processing using other software (Microsoft 

Excel). 

» The advisory system is designed with a user-friendly 

interface, to help select efficient and successful 

drilling technologies and drilling methods. 

» The drilling advisory system outputs more than 

one feasible solution for a given well or field. 

» The logic behind the advisory system, mainly based 

on decision charts developed by collecting relevant 

data from the petroleum engineering literature 

and discussions with industry drilling experts, is a 

good approach to mimic expert decision-making. 

» This project has illustrated several examples that 

happen to match the current industry drilling best 

practices or anticipate upcoming drilling practices 

in the studied area. These simulations showed that 

the drilling advisory system could deliver similar 

recommendations in comparison with a team of 

experienced drilling experts. 

» Drilling time, drilling cost estimation and ranking 

technologies, and methods sub-modules provide 

the user with an extended decision making tool 

when several solutions are feasible. 

» The drilling advisory system has been designed 

and programmed for easy integration within the 

Unconventional Gas Resources Advisor. It can be 

further upgraded with other drilling sub-modules 

or new drilling technologies when they are mature 

on the market. 


1.1.12 Developing an Expert System for Well Completions 

in Tight Gas Reservoirs Worldwide 

Related Publications 

Pilisi, N.: 2009. An Advisory System for Selecting Drilling 

Technologies and Methods in Tight Gas Reservoirs. MS 

thesis, Texas A&M U., College Station, Texas. 

Contacts 


979.845.2255 

holditch@tamu.edu 



Nicolas Pilisi 


14 


Assessment of API Thread Connections under Tight Gas Well Conditions 

Introduction 

The modern oil and gas industry of America has seen 

most of the high quality, easily obtainable resources 

already produced, thus causing wells to be drilled 

deeper in search of unconventional resources. This 

means Oil Country Tubular Goods (OCTG) must 

improve in order to withstand harsher conditions, 

such as tight gas sand wells, especially the ability 

of connections to effectively create leak-tight seals. 

gas reservoirs around the world produced average 

reservoir properties, which can be used as guidelines 

when deciding which type of connections to be used. 

Objective 

This study investigated the use and sealing of API 

long thread connections in tight gas wells. 

Approach 

A review of previous works on the capabilities and 

limitations of thread connections was done. This 

review identified several experiments and studies 

done on API connections to determine the limits 

of their capabilities, and covered simulations done 

on API connections using Finite Element Method 

(FEM) analysis and the importance of their findings. 

Experiments conducted to test the performance of 

thread compounds were also reviewed. 

The average values obtained represent the minimum 

values API connections should be able to seal. These 

values can also be used in experiments designed to 

test the leakage of thread connections, namely the 

grooved plate method. The experiment can be done 

under these conditions of temperature and pressure 

and the results can signify the possible behavior of 

thread compounds and thread connections in tight 

gas fields. 

(continued on next page) 

In order to have an idea of the type of conditions 

present in tight gas reservoirs, published data from 

around the world was also reviewed, with a focus on 

reported reservoir properties and drilling plans. 

In addition, this study will measure the viscosity 

of thread compounds. Because thread compound 

is essential to the function of thread connections, 

the knowledge of its viscosity can help choose 

the most suitable compound. Some viscosity 

measurements were conducted on several samples 

of thread compounds to identify actual values for 

thread compound at certain conditions following 

the guidelines set down by ASTM D 2196 (American 

Society of Testing and Materials). This information 

will be useful in predicting the behavior of the 

thread compound inside the helical paths within the 

connection. Also, knowing the value of the viscosity 

of a thread compound can also be used to form an 

analytical assessment of the grooved plate method 

by providing a means to calculate a pressure gradient 

which impacts the leakage. 


A survey of many drilling projects done in tight 


1.1.17 Assessment of API LTC Wellbore Integrity for Tight 

Gas Sands 

Contacts 


979.862.1195 




Dwayne Bourne 



15

A procedure to measure the viscosity of thread 

compound was established and used to measure 

the viscosities of three different samples of thread 

compound at various temperatures. Viscosity values 

are shown below: 

The experiment known as the grooved plate method 

can be carried out using the results from the tight 

gas reservoirs as test parameters to identify leak 

parameters of API round thread connections. 

The slot flow approximation can be used as an 

analytical method to reinforce experimental data 

or be used instead of conducting lengthy and costly 

experiments. 

The data above was fitted to a function and 

extrapolated to find the viscosity at the average 

reservoir temperature found from the review of tight 

gas projects. The viscosities of each of the thread 

compounds at 256°F are shown below. These values 

represent the expected viscosity of thread compound 

in tight gas reservoirs. 

The thread viscosities found above can be used 

in conjunction with the slot flow approximation to 

provide a means of finding a pressure gradient along 

the grooves of the grooved plate used in the groove 

plate method. This pressure gradient can be used to 

simulated results by applying the pressure gradient 

to determine leak pressure before the experiment 

is actually conducted. This can be used as a check 

of experimental results to validate experimental 

procedure. 

Future Work 

The measurement of the viscosity of the thread 

compound samples can be repeated using the 

average temperatures, which can better represent 

downhole conditions of tight gas wells. 

16 


Gas Shales – Geomechanics/Completions 

Introduction 

The Woodford shale gas is an ultra-low permeability 

reservoir (0.000001 md to 0.001 md). Commercial 

gas production is made possible by hydraulic fracture 

stimulation. Optimum hydraulic fracture treatment 

design needs to consider geomechanical principles 

in fracture initiation and propagation of multiple 

transverse fractures in horizontal wells. Often, 

Woodford shale reservoir development is achieved 

by drilling multiple parallel horizontal wells (on N-S 

azimuth), with approximately 600 ft spacing. Each 

treatment stage in a well is designed to create a 

stimulated volume, defined as the rock volume 

contacted by treatment fluid and proppant, which 

experiences a desired enhancement to permeability. 

For reservoir optimization, the collective network of 

stimulations should affect the maximum volume, 

with minimal (optimal) overlap of adjacent treatment 

stages. 

Objectives 

The problem has several related components: the 

selection of an appropriate perforation scheme–for 

open and cased hole–for initiating multiple fractures 

within a fracture stage and the determination of an 

optimum fracture treatment spacing for a 1000 ft 

section of a well using fracture mechanics models. 

The latter should consider the interaction between 

neighboring wells in generating a stimulated volume. 

In this research, we present a survey of state-of-theart 

practices with reference to the above issues to 

assist in selecting the best strategy for the Woodford 

shale reservoir. 

Approach 

In wells with low to medium permeability like 

Woodford’s, transverse fractures that extend 

sideways provide drainage for a larger area of the 

formation, experiencing a long-term production 

increase. 

A major concern in designing the perforation clusters 

for transverse fracturing design is the stressshadow 

effect. When a hydraulic fracture is opened, 

the resulting compression will increase the amount 

of minimum horizontal stress because of the net 

fracturing pressure existence. If this compressional 

stress is big enough, it can turn minimum horizontal 

stress into maximum horizontal stress, thus changing 

a transverse fracture into a longitudinal one. 

By reducing the number of clusters per stage, 

stress interference can be minimized, which will 

reduce the likelihood of having improper fracture 

propagation. However, this reduction will increase 

the number of stages per well, which means more 

completion costs. Therefore, the number of stages 

and the spacing between the perforation clusters 

are the result of optimization between the cost of 

having more stages and reducing the stress shadow 

effect. For our cemented horizontal wells, the best 

completion strategy is to limit the number of stages 

and stimulate two or three perforation clusters per 

stage. 


Our study on stress shadow shows that it becomes 

quite small at an offset distance equal to about 

two times the fracture height (2H). This minimum 

spacing (2H) is required to effectively minimize the 

conflicts between two transverse fractures. Also 

the perforation-cluster lengths should not be longer 

than four times the wellbore diameter. This is to 

prevent the creation of competing multiple fractures. 

Considering the fracture height of 250 ft to 280 ft for 

Woodford shale formation (Vulgamore et al., 2007), 

and a horizontal lateral diameter of 7 in, the best 

option will be to have three perforation clusters with 

maximum lengths of 2 ft that are stimulated in a 

single stage for each 1000 ft of horizontal lateral. 

To align perforations with the preferred fracture 

plane, they should be oriented 0°/180° phasing. 

The other alternative is 60° phasing when used in 

conjunction with an acid-soluble cement system. 

Both perforation strategies have shown to be 

effective (Ketter et al., 2008). 



1.1.18 Gas Shales – Geomechanics/Completions 

Contacts 

Ahmad Ghassemi 

979.845.2206 

ahmad.ghassemi@pe.tamu.edu 

Babak Akbarnejad 


17

PRISE – Petroleum Resource Investigation Summary and Evaluation 

Introduction 

As conventional resources are depleted, 

unconventional gas resources (UGRs) are becoming 

increasingly important to the U.S and world energy 

supply. The volume of UGRs is generally unknown 

in most international basins. However, in 25 

mature U.S. basins, UGRs have been produced for 

decades and are well characterized in the petroleum 

literature. The objective of this work was to develop 

a method for estimating technically recoverable 

UGRs in target, or exploratory, basins. The method 

was based on quantitative relations between known 

conventional and unconventional hydrocarbon 

resource types in mature U.S. basins. 

hydrocarbon resources are conventional oil and gas, 

and 90% are from unconventional resources. 

Significance 

PRISE may be used to estimate the volume of 

technically recoverable hydrocarbon resources 

in any basin worldwide and, hopefully, assist 

early economic and development planning. PRISE 

methodology for estimating UGRs should be further 

tested in diverse sedimentary basin types. 

Conventional is 0–9% greater 

10/13/2009 

than in previous calculation From Old, 2009 

Objectives 

The primary objective of developing PRISE 

was to establish a methodology for estimating 

unconventional technically recoverable resources 

in basins with no, or very little, unconventional 

resource development or data. A second objective 

was to create a system the industry can use to 

better understand the potential of unconventional 

resources in the target basins around the world. 

Armed with such estimates and understanding, the 

industry can better justify its future development 

activities or, in some cases, change course. For 

this study, published resource information from the 

USGS, PGC, NPC, EIA, and GTI were used to quantify 

recoverable resources in seven North American 

basins. 

1 

Quantified Recoverable Resources – 7 N.A. Basins (Old, 2009). 


To develop the methodology to estimate resource 

volumes, we used data from the U.S. Geological 

Survey, Potential Gas Committee, Energy 

Information Administration, National Petroleum 

Council, and Gas Technology Institute to evaluate 

relations among hydrocarbon resource types in the 

Appalachian, Black Warrior, Greater Green River, 

Illinois, San Juan, Uinta-Piceance, and Wind River 

basins. PRISE can be used to predict technically 

recoverable UGRs for target basins, on the basis of 

their known conventional resources. Input data for 

PRISE are cumulative production, proved reserves, 

growth, and undiscovered resources. We use 

published data to compare cumulative technically 

recoverable resources for each basin. For the seven 

basins studied, we found that 10% of the recoverable 


1.1.20 Continued Development of PRISE 

Contacts 


979.845.2255 

holditch@tamu.edu 

Walter B. Ayers 

979.458.0721 

walt.ayers@pe.tamu.edu 

Kun Cheng 


18 


An Investigation of Regional Variations of Barnett Shale Reservoir Properties, and 

Resulting Variability of Hydrocarbon Composition and Well Performance 

Objectives 

Although the Barnett is one of the most prolific gas 

plays in the U.S., fundamental controls on variable 

gas productivity of individual wells and different 

regions are poorly understood. The Barnett shale 

is very heterogeneous; formation thickness and 

lithology, thermal maturity, structural setting, 

reservoir fluids, etc. vary greatly throughout the 

basin. The objectives of this research are to: 

» clarify the stratigraphic and regional variations of 

Barnett Shale reservoir and geologic properties; 

and 

» evaluate the controls that these properties exert 

on Barnett Shale gas well performance. 

maps (best monthly production, first 12 month 

cumulative production, etc.) to assess controls on 

reservoir performance. There were four phases to 

this project. 

First, we correlated reservoir facies to assess vertical 

and lateral variability of Barnett shale. The Barnett 

Shale was subdivided into 13 reservoir sequences 

that were then upscaled into four reservoir units 

(Fig. 1). Second, we mapped and analyzed regional 

variations of oil and gas production rates and gas/ 

oil ratios. Third, we evaluated shale geochemistry 

parameters, including organic richness, thermal 

maturity, and fluid types. We used petrophysical 

evaluations to estimate geochemical parameters 

from well logs and to estimate reservoir property of 

the four reservoir units. Finally, we integrated the 

above to assess reservoir controls on production 

rates of individual wells and different regions of the 

Fort Worth Basin. Structural settings and thermal 

maturity are dominantly controls on regional 

production variations. Local variations in Barnett 

production primarily vary with the perforation 

interval targeted in Barnett Shale. 

Significance 

The study lends insights to reservoir controls on 

well performance and should assist operators with 

optimization of development strategies and gas 

recovery. The approach used in this study may be 

applicable to other developing shale gas plays, such 

as the Marcellus and Haynesville Shales. 


Fig. 1. Type well log showing Barnett Shale stratigraphy and reservoir 

units mapped in this study. 

Approach 

This is an integrated study using well log and 

production data to evaluate geologic and engineering 

controls on reservoir performance. We used raster 

image logs to correlate and map Barnett Shale facies, 

and we used digital logs to assess petrophysical 

properties. Facies and petrophysical properties 

maps were compared to reservoir performance 


1.2.3 Assessment of API LTC Wellbore Integrity for Tight 

Gas Sands 


Tian, Y. and Ayers, W. Regional Stratigraphic and Sedimentary 

Facies Analyses, Barnett Shale, Fort Worth Basin, Texas. 

Paper 0919 presented at the 2009 International Coalbed 

and Shale Gas Symposium, Tuscaloosa, Alabama, 18-22 

May. 

Contacts 


979.458.0721 

walt.ayers@pe.tamu.edu 

Yao Tian 


19

Gas Shales Simulation and Production Data Analysis 

Objectives 

Rate decline forecasting of wells in tight gas/shale 

gas reservoirs using modern decline curve analysis 

can result in dramatic overestimation of reserves. 

The cause for this error is usually incorrect 

interpretation of transient flow data (i.e., data which 

are NOT affected by reservoir boundaries). 

The extremely low permeability of shale gas and 

tight gas reservoirs causes the transient flow period 

to last years or decades. Additionally, the physics 

of transport and storage controlling the gas flow in 

shale gas systems is complex and varies markedly 

between reservoirs. Finally, posing yet another 

complication, most wells in these reservoir types 

are drilled horizontally and hydraulically fractured 

multiple times. 

the flow concept of van Kruijsdijk and Dullaert, and 

showed how production data analysis can be used to 

identify these flow regimes. 

In 2009, TAMSIM was used to study the effects of 

variation of numerous reservoir and completion 

parameters on well performance. One paper 

(SPE 124961: A Numerical Study of Tight Gas 

and Shale Gas Reservoir Systems) published this 

year served to characterize the effects of sorption, 

fracture conductivity, fracture spacing, and matrix 

permeability for various assumptions of single- and 

dual-porosity reservoirs, with and without laterally 

conductive layers. This work was presented at the 

The objectives of this research project have been to 

build a numerical simulator for shale gas reservoir 

systems and to study the complex flow regimes 

found around horizontal wells with multiple hydraulic 

fractures and enable identification and interpretation 

of these regimes through production data analysis. 

Approach 

Our approach has been to determine the proper 

theoretical foundation for creating a tight gas/shale 

gas simulator, and to implement these concepts 

into the purpose-built numerical simulator TAMSIM, 

which is descended from the TOUGH+ family of 

numerical simulators. 

To determine a sound theoretical basis, we 

undertook a literature search, focusing on the 

physics and simulation of coalbed methane, tight 

gas, and shale gas reservoirs. This literature review 

also entailed research into specific storage and 

transport mechanisms such as flow in naturally and 

hydraulically fractured porous media, diffusion in 

porous media, and surface sorption. 

In 2008, work was focused on implementation and 

validation of the capability to accurately simulate 

horizontal wells with multiple transverse hydraulic 

fractures. This part of the functionality has been 

validated against various other methods, and used 

to provide synthetic cases for study and history 

matching. Through simulation, we created clear 

visualizations of the progression of flow according to 

The progression of flow regimes in multiple fractured horizontal wells 

(van Kruysdijk and Dullaert [1989]) 


1.2.5 Shale Gas Reserves Estimation 

Contacts 

Tom Blasingame 

979.845.2292 

t-blasingame@tamu.edu 

C. Matt Freeman 


20 


2009 SPE ATCE in New Orleans. A second paper (A 

Numerical Study of Microscale Flow Effects in Tight 

Gas and Shale Gas Reservoir Systems) concerning 

the micro- and nano-scale flow effects caused by 

extremely fine pore structure in shale was presented 

at the TOUGH Symposium at Lawrence Berkeley 

National Laboratory. 

Additionally, several other capabilities have been 

added to TAMSIM, though not yet rigorously 

validated. These include multiphase flow and 

multicomponent diffusion. Work on TAMSIM 

continues in collaboration with Dr. George Moridis. 

Significance 

The significance of the work to this point has been 

to provide clear visualization and diagnostic tools 

for identification of the complex flow regimes found 

near horizontal wells with multiple fractures in tight 

gas reservoirs, and to deliver insight into the effects 

of reservoir and completion parameters on the 

behavior of these profiles. Properly accounting for 

the flow regime effects of inter-fracture interference 

on production data will enable the engineer to 

constrain rate decline predictions. 


21

Characterization of Rock Transport Properties in Tight Gas and Shale 

Objectives 

The objective of this work is to determine transport 

properties such as permeability, porosity, and 

fracture characteristics in very low permeability 

rocks such as tight gas sandstone and shale. Further, 

we would be characterizing stress-induced changes 

in permeability in these low permeability rocks. 

This would be done using the pulse permeameter 

and steady-state measurements using under 

triaxial stress. Generally, “Pressure Pulse Test” 

is recommended in tight gas and shale reservoirs 

instead of conventional “Steady State Permeability 

Test”. The “Pressure Pulse Permeameter” machine 

in Rock Mechanics Lab can be a good tool for 

determining rock properties. 

permeability/porosity check plugs to make sure the 

values are precise. After calibrations and validations, 

we will be ready to measure permeability/porosity 

of the tight core samples. 

Approach 

During this month and the last month, we focused 

on the accuracy of the transducers and found out 

that a part of the measured leakage rate came from 

the fluctuations in the outputs of the transducers. 

The downstream differential transducer had a larger 

rate of fluctuations. We tested the leakage rate 

in different system pressures using impermeable 

core plugs and determined that the leakage rates 

in upstream and downstream transducers are 

consistent, which means the leakage comes from a 

point which connects both sections. 


To reduce the data fluctuation in the downstream 

part, we changed the downstream transducer, then 

calibrated and tested again. The leakage rate in the 

downstream part decreased from 1.6 psi/hr to ~ 1.1 

psi/hr. Then, since the shortest route that connects 

upstream and downstream sections to each other is 

the core holder, we inspected the core holder again 

and wrapped the outer diameter of the rubber sleeve 

inside the core holder with extra aluminum foil. It 

covered the torn parts of the previously wrapped 

foil, which had been generated due to shrinkage and 

extension of the rubber sleeve. With these changes 

made, we tested the leakage and the rates were 

now 0.3 psi/hr for upstream and 0.36 psi/hr for 

downstream, which are reasonable. 

Future Work 

Since the machine has had several changes and 

manipulations, for the next month we should calibrate 

the volumes and (if possible) test it with known 


1.2.6 Transport Properties Characterization of Tight Gas 

Shales 

Contacts 


979.845.2206 


Vahid Serajian 


22 


Rate Transient Analysis in Shale Gas Reservoirs with Transient Linear Behavior 

Introduction 

Many hydraulically fractured shale gas horizontal 

wells in the Barnett shale have been observed to 

exhibit transient linear behavior, characterized by 

a one-half slope on a log-log plot of rate against 

time. This transient linear flow regime is believed to 

be caused by transient drainage of low permeability 

matrix blocks into adjoining fractures, and is the only 

flow regime available for analysis in many wells. 

Objectives 

A hydraulically fractured horizontal shale gas 

well will be modeled as a horizontal well draining 

a rectangular geometry containing a network of 

fractures separated by matrix blocks (dual-porosity 

system). The solutions presented by El-Banbi for 

a linear dual porosity model will be extended and 

applied to this system. The effects of desorption 

and diffusion will be assumed negligible in this 

paper since they will not be important at reservoir 

pressures of interest in the Barnett shale. 

The objectives of this research are: 

» To develop mathematical models to analyze these 

multi-stage hydraulically fractured horizontal wells 

» To develop a rate transient analysis procedure for 

analyzing these wells to enable the determination 

of reservoir characteristics, drainage volume/ 

original gas-in-place (OGIP), fracture network 

characteristics and assessment of the effectiveness 

of different hydraulic fracture treatments. 


The hydraulically fractured shale gas reservoir system 

was described by a linear dual porosity model which 

consisted of a bounded rectangular reservoir with 

slab matrix blocks draining into adjoining fractures 

and subsequently to a horizontal well in the center. 

The well fully penetrates the rectangular reservoir. 

Convergence skin is incorporated into the linear 

model to account for the presence of the horizontal 

wellbore. 

Five flow regions were identified with this model. 

Region 1 is due to transient flow only in the 

fractures. Region 2 is bilinear flow and occurs when 

the matrix drainage begins simultaneously with 

the transient flow in the fractures. Region 3 is the 

response for a homogeneous reservoir. Region 4 

is dominated by transient matrix drainage and is 


the transient flow regime of interest. Region 5 is 

the boundary dominated transient response. New 

working equations were developed and presented 

for analysis of Regions 1 to 4. No equation was 

presented for Region 5 as it requires a combination 

of material balance and productivity index equations 

beyond the scope of this work. 

It is concluded that the transient linear region 

observed in field data occurs in Region 4, drainage of 

the matrix. A procedure was presented for analysis. 

The only parameter that can be determined with 

available data is the matrix drainage area, Acm. 

It was demonstrated that the effect of skin under 

constant rate and constant bottomhole pressure 

conditions is not similar for a linear reservoir, as 

the constant bottomhole pressure shows a gradual 

diminishing effect of skin. A new analytical equation 

was presented to describe this situation 

It was also demonstrated that different shape 

factor formulations (Warren and Root, Zimmerman 

and Kazemi) result in similar Region 4 transient 

linear response provided that the appropriate f(s) 

modifications consistent with lAc calculations are 

conducted. It was also demonstrated that different 

matrix geometry exhibit the same Region 4 transient 

linear response when the area-volume ratios are 

similar. 


1.2.8 Modeling and Analysis of Linear Transient Flow 

Regime in Shale Gas Reservoirs 


El-Banbi, A.H.: 1998, Analysis of Tight Gas Wells. PHD 

dissertation, Texas A&M 

U., College Station, Texas. 

Bello, R.O.: 2009, Rate Transient Analysis in Shale Gas 

Reservoirs with Transient Linear Behavior. PHD dissertation, 

Texas A&M U., College Station, Texas. 

Contacts 

Bob Wattenbarger 

979.845.0173 

bob.wattenbarger@pe.tamu.edu 

Rasheed Bello 


23

An Analytical Approach to Model Shale Gas Reservoir Flow Including Desorption 

Effects 

Objectives 

The objective of this work is to develop a semianalytical 

model to represent the pressure-time 

performance of shale gas reservoirs including 

desorption. To achieve this goal, we have developed 

a suite of simulation cases to study the effect of 

the desorption term, reservoir properties (primarily 

permeability), and gas flowrates. We have 

formulated a “dimensionless” form of the viscositycompressibility 

product as a mechanism to visualize 

and characterize the non-linear behavior of this 

case. 

Approach 

The “diffusivity equation” including desorption (as 

an effective compressibility, c e 

) is given as: 

1 p 

p gicei 

g ce 

p 

r 

 

r r 

r 

k 

gicei 

 

t 

Where 

c 

m gSC 

VL 

pL 

ce 

cg 

 

 

2 

[ p p] 

We use numerical simulation to generate a suite 

of constant rate pressure-time responses for an 

infinite-acting circular reservoir. The behavior of 

the nonlinearity (i.e., μ g 

c e 

) was studied for specific 

reservoir properties and flowrate. Using these 

results we developed an appropriate dimensionless 

time function (t D 

) to account for the effects due to 

desorption and formation permeability. 

In addition to a dimensionless time function, we 

also created a dimensionless rate function (q D 

), 

which accounts for permeability and flowrate. In 

Fig. 1 we present the overall “correlation” of the 

non-linear term as functions of dimensionless time 

and rate. 

Significance 

» The non-linear desorption term can be expressed 

as an effective compressibility term in the gas 

diffusivity equation. 

» The effects of desorption can be incorporated into 

an appropriately defined dimensionless time. 

» The effects of reservoir properties and flowrate 

can be incorporated in an appropriately defined 

dimensionless rate. 

g 

L 

p 

Fig. 1. Overall “correlation” of the non-linear term, presented as functions 

of dimensionless time and rate. 

» For higher values of the flowrate (or dimensionless 

flowrate), the non-linear term becomes more 

dominant (deviates from liquid flow theory). 

Future Work 

» Develop an exhaustive sequence of cases to 

investigate the non-linear behavior caused by 

pressure-dependent gas expansion and gas 

desorption. 

» Develop a semi-analytical solution for the pressuretime 

behavior of this case based on the correlation 

of the non-linearity. 


1.2.9 Modeling Shale Gas Reservoir Performance 


Bumb, A.C. and McKee, C.R. Gas-Well Testing in the 

Presence of Desorption for Coalbed Methane and Devonian 

Shale. SPEFE (March 1988): 179-185. 

Contacts 

Tom Blasingame 

979.845.2292 

t-blasingame@tamu.edu 

Sonia Jam 


24 


Water Production Issues in the Barnett Shale 

Objectives 

The objectives of this research project were as 

follows: 

» Determine in a quantitative sense the effect of 

water production on gas production in gas shales. 

» Identify the different water producing mechanisms 

in the Barnett Shale and characterize them based 

on production data. 

» Determine the relationship between well location, 

reservoir, fracturing treatment/completion data 

and water production. 

Our focus was an analysis of data available from 

the Barnett Shale using descriptive statistical and 

virtual intelligence techniques. 

Approach 

A Barnett Shale water production dataset from 

approximately 11,000 completions was analyzed 

using conventional statistical techniques. Additionally, 

a water-hydrocarbon ratio and first derivative 

diagnostic plot technique developed elsewhere for 

conventional reservoirs was extended to analyze 

Barnett Shale water production mechanisms. In 

order to determine hidden structure in well and 

production data, self-organizing maps and the 

k-means algorithm were used to identify clusters 

in data. A competitive learning based network 

was used to predict the potential for continuous 

water production from a new well. A feed-forward 

neural network was used to predict average water 

production for wells drilled in the Denton and Parker 

Counties of the Barnett Shale (Fig. 1). 

Self organized maps 

K-means algorithm 

Competitive learning 

Vector quantizer 

Neural networks 

Enable us see how 

data are clustered 

Enable us determine optimum 

number of clusters 

Enable us partition dataset 

into class of water producers 

and non-water producers 

Prediction of average 

water/gas production 

Fig. 1. Utility of various virtual intelligence routines. 


Using conventional techniques, we conclude that 

for wells of the same completion type, location is 

more important than time of completion or hydraulic 

fracturing strategy. Liquid loading has the potential 

to affect vertical more than horizontal wells (Fig. 

2). A MATLAB-based neural network tool was 

Flowing wellhead pressure (psia) 

2500 

2000 

1500 

1000 

500 

Minimum Required Flow Rate (Mcfd) vs WHP (psi) 

0 

0 200 400 600 800 1000 1200 1400 1600 1800 2000 

Average vertical 

well in Denton 

No Liquid Loading 

Minimum Required Flow Rate to prevent liquid loading (Mcfd) 

Fig. 2. Predictive Chart for onset of liquid loading in the Barnett Shale. 


Liquid Loading 

region 

Average vertical 

well in Parker 

Average horizontal 

well in Denton 



1.2.10 Shale Gas Water Production Issues 

Average horizontal 

well in Parker 


Awoleke, O.O. 2009. Analysis of Data from the Barnett 

Shale with Conventional Statistical and Virtual Intelligence 

Techniques. MS Thesis. Texas A&M U., College Station, 

Texas. 

Awoleke, O.O., Lane, R.H. Analysis of Data from the Barnett 

Shale Using Conventional Statistical and Virtual Intelligence 

Techniques. SPE Paper 127919 to be presented at the 2010 

SPE International Symposium and Exhibition on Formation 

Damage Control, Lafayette, Louisiana, 10–12 February. 

Contacts 

Robert Lane 

979.862.7654 

robert.lane@pe.tamu.edu 

Obadare Awoleke 


25

P90 

P50 

P10 

Fig. 3. P10, P50 and P90 predictions of water production for horizontal 

wells drilled in the Parker County of the Barnett Shale. 

developed to predict average water production for 

Barnett Shale wells in Denton and Parker Counties 

(Fig. 3). The average prediction error for the tool 

varied between 10-26%, depending on well type 

and location. 

Significance 

Results from this work can be utilized to mitigate 

risk of water problems in new Barnett Shale wells 

and predict water issues in other shale plays. 

Engineers are provided a tool to predict potential 

for water production in new wells. The methodology 

used to develop this tool can be used to solve similar 

challenges in new and existing shale plays. 

26 


Enhanced Oil Refining Technology through E-Beam Thermal Cracking 

Objectives 

One of the critical problems with heavy oil and bitumen 

is that they require large amounts of thermal energy 

and expensive catalysts to upgrade. This research 

demonstrates that electron beam (E-Beam) heavy 

oil upgrading, which uses unique features of E-Beam 

irradiation, may be used to improve conventional 

heavy oil upgrading. E-Beam processing lowers the 

thermal energy requirements and could sharply 

reduce the investment in catalysts. The design of 

the facilities can be simpler and will contribute to 

lowering the costs of transporting and processing 

heavy oil and bitumen. The main objective of this 

research is to investigate the effects of E-Beam 

irradiation on hydrocarbons and evaluate economics 

and potential applications of E-Beam technology 

throughout petroleum industry. 

a preliminary economic analysis based on energy 

consumption and comparing the economics of 

E-Beam upgrading with conventional upgrading. 


We studied pure n-C 16 

, a naphtha cut, a combination 

of a well-defined hydrocarbon group, and asphaltene 

to evaluate the effect of radiation on heavy and 

very viscous components. To estimate the energy 

transfer mechanism in the system, we conducted 

two simulations: heat transfer simulation using 

computational fluid dynamics (CFD), and radiation 

transport Monte-Carlo simulation. With the results 

we obtained from the laboratory investigations, we 

proposed potential applications of this technology. 

In addition, we conducted a preliminary economic 

evaluation to compare E-Beam upgrading and 

conventional upgrading based on the energy used 

in each process. 

Significance 

The results of our study are very encouraging. From 

the experiments, we found that E-Beam effect on 

hydrocarbon is significant. We used less thermal 



A conceptual design of pipeline heavy oil upgrading. Electrons with high 

kinetic energy are generated by two E-Beam machines. These electrons 

enter the heavy oil and break the heavy molecules of the heavy oil. 

Approach 

Based on an intensive brainstorming with experts 

in the industry and an extensive literature review 

of past and current research, we set up three 

major stages to evaluate the applicability of 

E-Beam for heavy oil upgrading. First, we planned 

laboratory experiments to investigate the effects of 

E-Beam on hydrocarbons. We used a Van de Graff 

accelerator, which generates the high kinetic energy 

of electrons, and a laboratory scale apparatus to 

investigate extensively what effect radiation has 

on hydrocarbons. Second, we planned to study the 

energy transfer mechanism of E-Beam upgrading 

to optimize the process. Third, we planned to make 


1.3.4 Enhanced Oil Refining Technology through E-Beam 

Thermal Cracking 


Yang, D., Kim, J., Silva, P., Barrufet, M. Moreira, R., and 

Sosa, J. Laboratory Investigation of E-Beam Heavy Oil 

Upgrading. Paper SPE 121911, presented at the 2009 

SPE Latin American and Caribbean Petroleum Engineering 

Conference, Cartagena, Columbia, 31 May-3 June. 

Yang, D.: 2009. Heavy Oil Upgrading from Electron Beam 

(E-Beam) Irradiation. MS thesis. Texas A&M U., College 

Station, Texas. 

Contacts 

Maria Barrufet 

979.845.0314 

maria.barrufet@pe.tamu.edu 

Daegil Yang 


27

Density distribution from heat transfer simulation and corresponding 

radiation amount distribution of multiphase n-C16 at 2.0 cm (a), 4.0 cm 

(b), and 6.0 cm (c) from the bottom of the reactor. 

energy for distillation of n-hexadecane (n-C 16 

) and 

naphtha with E-Beam. The results of experiments 

with asphaltene indicate that E-Beam enhances 

the decomposition of heavy hydrocarbon molecules 

and improves the quality of upgraded hydrocarbon. 

From the study of energy transfer mechanism, we 

estimated heat loss, fluid movement, and radiation 

energy distribution during the reaction. The results 

of our economic evaluation show that E-Beam 

upgrading appears to be economically feasible 

in petroleum industry applications. These results 

indicate significant potential for the application 

of E-Beam technology throughout the petroleum 

industry, particularly near production facilities, 

transportation pipelines, and refining industry. 

28 


Experimental Investigation of Caustic Steam Injection for Heavy Oils 

Introduction 

Heavy oil is a part of the unconventional petroleum 

reserve. Heavy oil does not flow very easily and 

is classified as heavy because of its high specific 

gravity. With increasing demand for oil and with 

depleting light oil resources, it is essential to explore 

the unconventional petroleum reserve of which 

heavy oil constitutes a major part, about 15% of the 

world’s remaining oil reserves. 

Objectives 

An experimental study was conducted to compare 

the effect of steam injection and caustic steam 

injection in improving the recovery of San Ardo and 

Duri heavy oils. 

Approach 

A 67 cm long x 7.4 cm O.D (outer diameter), 

steel injection cell was used in the study. Six 

thermocouples were placed at specific distances 

in the injection cell to record temperature profiles 

and thus the steam front velocity. The injection cell 

was filled with a mixture of oil, water and sand. 

Steam was injected at superheated conditions of 

238°C with the cell outlet pressure set at 200 psig, 

the cell pressure similar to that found in San Ardo 

field. The pressure in the separators was kept at 50 

psig. The separator liquid was sampled at regular 

intervals. The liquid was centrifuged to determine 

the oil and water volumes, and oil viscosity, density 

and recovery. Acid number measurements were 

made by the titration method using a pH meter and 

measuring the EMF values. The interfacial tensions 

of the oil for different concentrations of NaOH were 

also measured using a tensionometer. 


Experimental results show that for Duri oil, the 

addition of caustic results in an increase in recovery 

of oil from 52% (steam injection) to 59% (caustic 

steam injection). However, caustic has little effect 

on San Ardo oil where oil recovery is 75% (steam 

injection) and 76 % (caustic steam injection). 

Significance 

Oil production acceleration is seen with steam-caustic 

injection. With steam caustic injection there is also a 

decrease in the produced oil viscosity and density for 

both oils. Sodium hydroxide concentration of 1 wt% 

is observed to give the lowest oil-caustic interfacial 


tension. The acid numbers for San Ardo and Duri oil 

are measured as 6.2 and 3.57 respectively. 

Future Work 

The following are the main recommendations for 

future research: 

» To study further the effect of sodium hydroxide 

on different kinds of oils and to understand the 

effect of the acids present in the oil in reducing 

interfacial tension. 

» To conduct the experiments on previously 

waterflooded sandpacks for very heavy oils like 

San Ardo. 

» Core flooding would also be helpful in understanding 

the process of alkaline steam flooding with both 

heavy and lighter oils. 

» To test the combination of sodium hydroxide 

with additives which form the basis for alkaline 

surfactant process–as in Alkaline Surfactant 

Polymer (ASP) injection-in improving the recovery 

of oil. 

» To test non-thermal means of caustic flooding for 

heavy oils. 


1.3.12 Experimental and Simulation Studies of Heavy Oil 

Recovery using Steam and Steam Additives 


Madhaven, R.: 2009. Experimental Investigation of Caustic 

Steam Injection for Heavy Oils. MS thesis. Texas A&M U., 

College Station, Texas. 

Contacts 

Daulat Mamora 

979.845.2962 

daulat.mamora@pe.tamu.edu 

Rajiv Madhaven 


29

Experimental and Simulation Modeling Studies of Steam Assisted Gravity 

Objectives 

Our main research objectives are to conduct 

experimental and simulation modeling studies to 

investigate oil recovery mechanisms and steam 

injection efficiency during production of heavy oil 

under Steam Assisted Gravity Drainage (SAGD). 

Additionally, the research will also investigate the 

feasibility of petroleum distillates as steam additives 

to improve SAGD efficiency. 

Approach 

A 2-D scaled physical model made of Teflon has been 

fabricated and successfully pressure tested. The 

physical model will contain the sand mix, consisting 

of sand and heavy oil (Athabasca oil). Expansion 

of the steam chamber, its shape and area, and 

temperature distribution (Fig.1) will be visualized 

using a thermal (infra-red) video camera. Isotherms 

and steam chamber interface will be analyzed to 

study oil recovery and drainage mechanisms. Other 

data including model pressure, steam injection rate, 

oil and water production volumes will be recorded 

using a data logger and a personal computer. 

Simulation will be conducted to investigate the effect 

of different solvent types and ratios on production 

performance. 

efficiency and steam injections. Co-injecting low 

concentration ratios of multi-component solvents can 

deliver higher production rates and recovery factors 

along with taking advantage of both vaporized and 

liquid solvents. 

Experimental work will be continued to investigate 

SAGD performance and steam injection efficiency 

using Athabasca oil. Pure steam injection, coinjecting 

different solvent, including pure solvent 

and solvent mixture, and different solvent ratio 

conditions will be studied. 

Fig. 2. SAGD simulation shows the effect of different solvent types and 

ratios on oil displacement. 


Fig. 1. Typical photo captured by thermal (infra-red) video camera to 

show steam chamber temperature distribution. 


Simulation of SAGD using CMG has been performed. 

Results show solvent types and ratios affect 

production performance (Fig.2). Meanwhile, 

vaporized solvent can be delivered by steam to 

the entire steam chamber to reduce the bitumen 

viscosity. Liquid solvent accelerates near-well bore 

flow, and so improves the mobility oil drainage 


1.3.13 Experimental and Analytical Modeling Studies of 

Steam Assisted Gravity Drainage (SAGD) with NaOH and 

Petroleum Distillate as Steam Additives 


Butler, R.M. 1991 Thermal Recovery of Oil & Bitumen, 285- 

359. Prentice Hall Inc., New Jersey. 

Nasr, T.N., Beaulieu, G., Golbeck, H. and Heck, G. Novel 

expanding solvent-SAGD process “ES-SAGD”. January 

2003. J. Cdn. Pet. Tech. 42 (1): 13-16 

Contacts 

Daulat Mamora 

979.845.2962 


Weiqiang Li 

30 


In-Situ Oil Upgrading using Tetralin (C 10 

H 12 

) Hydrogen Donor and Fe(acac) 3 

Catalyst at Steam Injection Pressure and Temperature 

Objectives 

In-situ upgrading has advantages over conventional 

surface upgrading technology. First, in-situ upgrading 

enhances oil recovery, increases well production, 

and lowers lifting and transportation costs from 

reservoir to refinery. It eliminates the cost of building 

catalytic reactors or vessels. The in-situ process can 

be applied onshore or offshore as well as in remote 

locations where surface facilities may be prohibited. 

Second, in-situ upgrading can be applied on a wellto-well 

basis, and thus can be adjusted for declining 

production rates whereas surface processing are 

designed for a specified range of crude volume. 

Third, implementation of in-situ upgrading reduces 

energy consumption since the same energy from 

steam injection is used to produce and upgrade the 

oil. Finally, in-situ upgrading is more environmentally 

friendly, yielding lower quantities of byproducts that 

reduce disposal expenditures. 

The main objectives of the research are as follows: 

» Follow up on research by Ahmad Mohammad, for 

example, in-situ oil upgrading using tetralin (C 10 

H 12 

) 

and Fe(CH 3 

COCHCOCH 3 

) 3 

[i.e., Fe(acac) 3 

] catalyst 

at steam injection pressure and temperature as 

found in the field. 

» Make runs in which we inject a slug or slugs of 

tetralin/catalyst followed by steam injection. 

» Simulate longer injection periods in the experiments 

by making runs for several days, stopping at the 

end of each day. 

» Make runs using a reactor cell and synthetic oil 

made of several pure components (similar to 

Ramirez’s PhD research). Analyze any change 

in synthetic oil composition by GC analysis. This 

type of experiment will help us determine which 

components are upgraded by tetralin/catalyst, and 

then extrapolate the results to actual oil. 

» For both displacement and reactor cell experiments, 

investigate the effect of steam-surfactant injection 

to lower IFT and thus increase recovery factor. 

Approach 

For reactor cell experiments, one single hydrocarbon 

component will be used for each run. The hydrocarbon 

component, water, tetralin, and catalyst are 

mixed in the cell and then pressurized and heated 

to reservoir steam flooding conditions for a period 

of time. At the end of the run, a sample of the 

liquid from the cell is removed and its composition 

analyzed using a GC. 

For injection tests, the experimental apparatus (Fig 

1) is made up of four main parts: injection cell, fluid 

injection system, fluid production system, and data 

recording system. 

The experimental procedure is as follows: 

(1) Prepare sand/water/oil mixture, (2) Tamp 

mixture into injection cell and pressure test, (3) 

Install injection cell into vacuum jacket and pressure 

test whole system, (4) Set heating jacket to reservoir 

temperature and leave overnight, (5) Condition 

steam generator and pressurize injection cell, (6) 

Start tetralin or tetralin-catalyst injections (only for 

injection runs), and (7) Start steam injection and 

collect samples. 


Set up reactor cell, GC and other equipment, and 

investigated chemical requirements for research. 

Reviewed papers and books on oil upgrading using 

tetralin/catalyst. 



1.3.17 Experimental Studies of Non-Thermal EOR Methods 

for Heavy and Light Oil Recovery 


Mohammad, A. A. and Mamora, D. D. In-Situ Upgrading of 

Heavy Oil under Steam Injection with Tetralin and Catalyst, 

Paper presented at the 2008 International Thermal 

Operations and Heavy Oil Symposiums, Calgary, Alberta, 

Canada, 20-23 October. 

Contacts 

Daulat Mamora 

979.845.2962 


Zhiyong Zhang 



31

Fig. 1. Set up of displacement apparatus. 

32 


Artificial Geothermal Energy Potential of Steam-Flooded Heavy Oil Reservoirs 

Objectives 

The concept of harnessing geothermal potential 

of heavy oil reservoirs with the coproduction of 

incremental oil recovery using hot water injection 

will be investigated. Rather than abandon the 

heavy oil field once it becomes uneconomic, 

remaining geothermal energy from a steamflood 

or hot waterflood process that has been trapped 

in reservoir rock could be recovered. Preliminary 

results of a study of geothermal energy harvesting 

in a synthetic model using numerical reservoir 

simulation showed possible achievement of this 

concept. We will analyze economics of the overall 

project composed of reservoirs, wells, and surface 

facilities to show the feasibility of this project to 

extend the life of a heavy-oil field by means of the 

heat-recovery phase after the oil-recovery phase. 

Approach 

We have developed the synthetic reservoir model 

representing the analogue field from classical heavy 

oil fields. The model represents a pattern of inverted 

five-spot steamflood process in the heavy oil reservoir 

with homogenous properties. We have investigated 

the production and heat profiles in the period of hot 

water injection after 90% water cut is observed. We 

have conducted the sensitivity analysis to identify 

the effect of reservoir/design parameters on heat 

recovery. Also, we have estimated the possible 

range of heat recovery, pressure, and temperature 

at bottomhole conditions resulting from hot water 

injection. Those outputs will be used to model 

heat loss in the injection and production well by 

using typical well completions for thermal process. 

Then, we will integrate the wellbore model with the 

reservoir simulation model to quantify the overall 

heat efficiency based on heat input from hot water 

injection. Finally, the economic evaluation will be 

conducted to verify whether this proposed concept 

is feasible. 


Sensitivity analysis of reservoir/design parameters 

focused on five group parameters: reservoir 

geometry, reservoir rock properties, reservoir 

initial condition, oil viscosity, and steam injection 

conditions. Based on our analog field, the range of 

heat recovery at bottomhole conditions could vary 

from 70% to 95% by using of hot waterflood to 

extract residual heat from the steamflood process. 

Besides, we have observed heavier oil components 

resided at the very bottom of the reservoir, resulting 

from gravitational segregation effects by thermal 

processes. This allows performing the horizontal 

infill drilling to improve the economics of the project. 

The result from a reservoir simulation study will be 

integrated with the wellbore model to investigate 

the heat transfer inside the well at the later stage. 

Energy efficiency (%) 

95 

90 

base 

87% 

85 

80 

75 

70 

Sensitivity of parameters to energy efficiencies during hot water flooding period 

Res. 

Geometries 

300 

2 

5 

Area (acre) 

50 

Thickness (ft) 

25 

35 

Porosity (%) 

Rock 

Properties 

5000 

1000 

Permeability (md) 

Sensitivity analysis indicates that we could recover the heat at least 70% 

of heat inputs by using hot water injection. 



1.3.19 Harnessing the Geothermal Energy Potential of 

Heavy Oil Reserves 

Contacts 

Gioia Falcone 

979.847.8912 

gioia.falcone@pe.tamu.edu 



Akkharachai Limpasurat 

SS 

LS 

Lithology 

Res. Initial 

Condition 

600 

100 

Initial reservoir 

pressure (psi) 

90 

130 

Initial reservoir 

temperature (°F) 

Viscosity 

1000 

4484 

viscosity (cp) 

500 

250 

Steam injection rate 

(BCWE/day) 

Steam Injection 

Condition 

500 

250 

Steam injection 

temperature (°F) 

2500 

1500 

Steam injection 

pressure (psi) 

dry 

wet 

Steam quality 


33

Study of Solvent-Based Emulsion Injection to Improve Sweep and Displacement 

Efficiency in Heavy Oil Reservoir 

Introduction 

About two-thirds of the original oil in reservoirs is left 

behind, even after gas injection or water-flooding. 

However most of the oil contacted by a solvent 

may be recovered, as a solvent is miscible with 

reservoir oil. Unfortunately, the low solvent viscosity 

results in unfavorable mobility ratio and poor sweep 

efficiency particularly in heavy oil reservoirs. Thus 

this research investigates residual oil reduction 

by solvent and sweep efficiency improvement by 

emulsion. 

Objectives 

This research has two parts: 

Experimental research 

Main objectives are as follows: 

» Investigate the feasibility of solvent-based 

emulsion flooding to improve displacement and 

sweep efficiency in heavy oil reservoirs 

» Conduct core-flood experiments to compare 

recovery efficiency using various emulsions after 

water-flooding. 

Fig. 1. Emulsion ternary phase diagram. 

the ternary phase diagram shown in Fig. 1. Emulsion 

containing 5wt% silica nanoparticles shows a higher 

viscosity than emulsion without nanoparticles (Fig. 

2). Cores have been scanned to measure porosity 

and initial oil and water saturations (Fig. 3). 

Simulation study 

Main research objectives are as follows: 

» Perform history matching of the experimental 

results using CMG 

» Conduct simulation study of sweep efficiency in a 

5-spot well pattern. 

Approach 

This research has two parts, namely, experiments 

and simulation study. First, a bench test is performed 

to get the emulsion system properties, such as 

viscosity, IFT, and ternary phase diagram. Based on 

the bench test results, the optimized emulsions are 

chosen to perform the core flooding experiments. 

Second, different core flooding experiments are 

conducted to investigate the effect of these emulsions 

on oil recovery. The aluminum coreholder will be 

x-ray CT scanned to measure residual oil saturation 

in the core. Lastly, a simulation will be conducted 

to history match the experiment results to enable a 

study of sweep efficiency for a 5-spot well pattern. 


The bench tests have been completed. The results 

showing micro- and macro-emulsions are plotted in 

34 


1.3.20 Microemulsion-Solvent Injection to Improve Sweep 

and Displacement Efficiency of Heavy and Light Oil 


Willhite, G.P., Green, D.W., Okoye, D.M., and Looney, M.D. 

A Study of Oil Displacement by Microemulsion Systems: 

Mechanisms and Phase Behavior. SPE-7580. 

Contacts 

Daulat Mamora 

979.845.2962 


Fangda Qiu 



1000 

Viscosity vs Shear Rate 

Emulsion with 5wt% nanoparticles 

Emulsion without nanoparticles 

Viscosity (cp) 

100 

10 

1 

0.1 

1 

10 

Shear Rate (sec -1 ) 

100 

1000 

Fig. 2. Emulsion rheology diagram. 

Fig. 3. CT-scan of dry core. 


35

Investigation of Hybrid Steam-Solvent Processes to Increase Efficiency of Thermal 

Oil Recovery Methods 

Objectives 

Steam assisted gravity drainage (SAGD) has received 

considerable attention as a proven technique to 

recover heavy oil and bitumen which are immobile 

at reservoir conditions. The main drawbacks of this 

process are high energy intensity (steam generation 

requirements) and environmental issues. 

The addition of light hydrocarbon solvents to steam is 

the simplest and most important approach to improve 

SAGD process and reduce potential problems. Main 

benefits possibly obtained by a hybrid steam solvent 

process include: reduced Steam Oil Ratio, reduced 

environmental impact, increased recovery via 

reduced S or 

, reduced capital to startup and enhanced 

well productivity. Principal challenges are the choice 

of solvent and concentration and operating strategy. 

Our main research objective is to reduce energy 

intensity of SAGD process by using solvents 

and investigate the effect of different operating 

strategies. Key tasks are to evaluate the effect on 

oil recovery of the following: 

» Solvents, (e.g., butane, hexane and condensates) 

» Solvent concentration 

» Injection types (e.g., cyclic steam solvent injection) 

Fig. 1. Simulation results of oil recovery. 

with increasing concentration. The aluminum 2D 

cylindrical model is under construction. The sandmix 

space has an inner radius of 4 in, 1-in thickness, and 

10-in height, and will be lined with insulating Teflon 

layers (Fig. 2). The experimental set up is shown 

in Fig. 3. 

Approach 

Experiments will be carried out in a scaled 2D 

cylindrical cell to evaluate the effect of steam-solvent 

processes. Pujol and Boberg’s scaling method has 

been used to design the model. Advantages of the 

cylindrical model are the relatively high pressure 

capability without a pressure jacket, the use of inner 

thermal insulation, and the ability to conduct gravity 

drainage experiments (e.g., VAPEX, SAGD). Oil and 

water production, gas composition, and temperature 

would be measured and analyzed. Numerical 

simulation will be used for parametric studies. 


Compositional reservoir simulation studies of Cold 

Lake bitumen were performed to investigate the 

effect of solvent type and concentration on recovery 

under SAGD at 220°C and 3100 kpa (450 psia) 

(Fig. 1). With C5-C7 as solvents, bitumen recovery 

increases to about 80% at 20 wt%. C2 and C3 

however exist as vapor and act as thermal insulators 

at the steam-bitumen interface, reducing recovery 


1.3.22 Investigation of Hybrid Steam-Solvent Injection to 

Increase Efficiency of Thermal Oil Recovery Processes 


Nasr T.N., and Ayodele O.R. New Hybrid Steam-Solvent 

Processes for the Recovery of Heavy Oil and Bitumen. 

Paper SPE 101717, presented at the 2006 International 

Petroleum Exhibition and Conference, Abu Dubai, UAE, 5-8 

November. 

Ayodele, O.R., et al. Laboratory Experimental Testing 

and Development of an Efficient Low Pressure ES-SAGD 

Process. 2009. J. Cdn Pet. Tech. 48 (9). 

Contacts 

Daulat Mamora 

979.845.2962 


Mojtaba Ardali 


36 


Fig. 2. Scaled 2D cylindrical cell. 

Fig. 3. Schematic diagram of experimental set up. 


37

Experimental Studies of Steam Injection with Surfactant for Enhancing Heavy Oil 

Recovery after Waterflooding 

Objectives 

Steam injection with added surface active chemicals 

is an EOR process aimed at recovering residual oil 

after primary production. Researchers have shown 

that after waterflooding, the oil swept area can be 

increased by steam surfactant due to reduced steam 

override effect and reduced interfacial tension 

between oil and water in the formation. 

was tamped into the cell. 

A 3.0 wt% nonionic surfactant Triton X-100 was coinjected 

with the steam superheated to 200°C and 

pressured to 100 psig. For the vertical cell runs, 

steam injection rates were 5.5 ml/min and 2.5 ml/ 

min TX-100; for the horizontal cell runs, steam 

injection rates were 4.0 ml/min and 1.0 ml/min TX- 

100 solution. 

The main objective of this research is to evaluate the 

effect on oil recovery of steam surfactant injection 

compared to that of pure steam injection. The 

experimental study will use a 1D displacement cell 

containing a sand mix of 20.5°API California oil. 

Approach 

Two experimental models were used: a vertical 

cylindrical cell 67 cm long x 7.4 cm ID (Fig. 1) and 

Fig. 2. Horizontal cell. 


Fig. 1. Vertical cell. 

a horizontal cell 110.5 cm long x 3.5 cm ID (Fig. 2). 

The horizontal smaller diameter cell is less subject to 

channeling and is therefore more representative of 

one-dimensional steam injection process. A uniform 

mixture of sand, water and 20.5°API California oil 


1.3.23 Experimental Study of Steam Injection with 

Surfactants for Enhancing Heavy Oil Recovery 

Contacts 

Daulat Mamora 

979.845.2962 


Dinmukhamed Sunnatov 

38 



The main conclusions of the study are made based 

on the horizontal cell runs. 

» For the two runs with steam surfactant, average 

oil recovery was 55% OIP compared to an average 

48% OIP with pure steam injection (Fig. 3). 

That is, the average incremental oil recovery with 

steam surfactant flood was 7.0% OIP above that 

with pure steam injection. 

» As the run progressed, viscosity at 23°C of 

produced oil decreased from 497 cp to 13.4 cp 

(steam injection) and to 1.7 cp (steam surfactant 

injection). The oil gravity increased from 19.1°API 

to 35.0°AIP (steam injection) and to 36.6°API 

(steam-surfactant injection). 

60 

60 

50 

50 

SI oil recovery, % OIP 

40 

30 

20 

10 

cum. oil production SI 

cum. oil production 5 

cum. oil production 6 

40 

30 

20 

10 

SSI oil recovery, % OIP 

0 

0 

0 0.4 0.8 1.2 1.6 2.0 

Steam injected, PV 

Fig. 3. Oil recovery with steam-surfactant injection (55%) is 7% OIP 

more than that with steam injection (48%). 

Note that IFT’s for the average produced oil and 

water are smaller when compared to that of the 

original oil and water. 


39

Combustion Assisted Gravity Drainage (CAGD): An In-Situ Combustion Method 

to Recover Heavy Oil and Bitumen from Geologic Formations using a Horizontal 

Injector-Producer Pair 

Objectives 

In-situ combustion (ISC) is a recovery process 

particularly suitable for heavy oil reservoirs at 

depths greater than 3500 ft when steam injection 

is not feasible due to severe wellbore heat losses. 

We have developed a method in which a horizontal 

air injector is placed above a horizontal producer 

(Fig. 1). In this Combustion Assisted Gravity 

Drainage (CAGD) method, a heated chamber is 

created that would more uniformly transfer heat 

from the combustion front. Mobilized oil is produced 

by gravity drainage to the lower horizontal well. 

Gravity segregation enhances air flow to propagate 

the combustion front. Main research objectives are 

as follows: 

» Assess CAGD using Computer Modelling Group 

(CMG) simulator 

» Conduct experiments using a scaled 3D physical 

model to test viability of CAGD for heavy oil and 

Cold Lake bitumen 

» Compare CAGD and toe-to-heel air injection 

(THAI) processes 

» Using CMG simulator, history-match laboratory 

CAGD results and scale up to field conditions 

experimental results and scale up to field conditions 

and evaluate CAGD. 


A 50 cm x 15 cm x 35 cm Cartesian simulation 

model was constructed representing the half 

symmetry element of a 750 m long x 56 m width x 

35 m thick drainage volume; we placed the injector 

at 7 m above the reservoir base with a producer 

5 m below the injector. The model was based on 

typical Athabasca oil and rock properties. Runs 

were made to compare CAGD with steam assisted 

gravity drainage (SAGD) and THAI. Results indicate 

CAGD to have the highest oil production with the 

lowest energy consumption (Figs. 2 and 3). 

The physical model, measuring 60 cm x 40 cm x 15 

cm, is nearly completed (Fig. 4). The steel sides 

will be lined with ceramic fiber insulation. Seventy 

two thermocouples will measure temperature in the 

sandmix with an operating pressure at about 30 

psig. 


Fig. 1. Schematic illustration of CAGD. 

Approach 

We will conduct a simulation using CMG for a 

preliminary evaluation of CAGD. If simulation 

results show CAGD to be promising, we will conduct 

experimental runs using a physical model to evaluate 

performance of CAGD. We will also history match 

40 


1.3.24 Combustion Assisted Gravity Drainage (CAGD): 

An In-Situ Combustion Method to Recover Heavy Oil and 

Bitumen from Geologic Formations using a Horizontal 

Injector-Producer Pair 


Greaves, M., Xia, T.X. and Turta, A.T. Stability of THAI 

Process-Theoretical and Experimental Observations. Paper 

presented at the 2007 Canadian International Petroleum 

Conference, Calgary, Alberta, 12-14 June. 

Contacts 

Daulat Mamora 

979.845.2962 


Hamid Rahnema 


Fig. 2. Oil production rate for CAGD,THAI and SAGD. 

Fig. 3. Cumulative energy/oil ratio for CAGD,THAI and SAGD. 

Fig. 4. Scaled CAGD physical model. 


41

Well Spacing and Infill Drilling in Coalbed Methane Reservoirs 

Objectives 

Reservoir simulation has been used to describe 

the mechanism of gas desorption and diffusion in 

coal to reflect the response of the reservoir system 

and the relationship among coalbed methane 

reservoir properties, operation procedures, and 

gas production. The objective of this work is to 

investigate well spacing and completion design 

practices under various development scenarios by 

using reservoir simulation. 

In a coal bed methane reservoir there is a natural 

fracture system which conducts the fluid flow to the 

wellbore and matrix system where essentially all 

gas is stored. Instead of gas being compressed in 

the pore space, most is adsorbed on the surface of 

it. Considering the small pore size in this reservoir 

system, the Klinkenberg effect or slippage factor 

could effect the permeability change during 

reservoir depletion. The amount of gas adsorbed is 

quantified by an adsorption curve (isotherm curve) 

of the Langmuir equation. As the reservoir pressure 

declines during production from the fracture system, 

gas desorbs from the coal surfaces. Flow gas from 

the coal matrix to the fracture system is a molecular 

diffusion, expressed by Fick’s law rather that Darcy’s 

law. Because of the adsorption curve’s convex shape, 

it becomes very important to attain low reservoir 

pressure; this is a much more important factor than 

in conventional reservoirs. After long dewatering, 

water production will decrease and gas production 

increase and peak after water production has 

significantly declined from its original rate. Predicting 

the time and magnitude of this peak is a large part 

of the early evaluation of the wells. Eventually the 

wells decline and have a more conventional rate 

pattern. In the later stage of depletion (effective 

fracture permeability increasing during matrix 

desorption at lower pressure), this rock mechanic 

can be described by the Palmer-Mansoori effect. 

Approach 

A reservoir simulator will be developed to determine 

the effect of various spacing and completion 

decisions on recovery for particular scenarios of 

reservoir properties/description. The outcome of 

the simulation and history matching will typify the 

reservoir of interest and will be used to develop 

further analysis, such as: 

» Determine where the Palmer-Mansoori permeability 

and the Klinkenberg effect are important in 

42 

reservoir mechanics 

» Demonstrate the importance of various parameters 

on spacing 

» Determine desirability and expected performance 

of either vertical or horizontal wells 

» Develop well spacing correlations to determine 

optimum well spacing for new reservoir 

development and guideline for several practical 

circumstances 


A single well, 2D, single phase reservoir simulator 

has been developed using Macros Visual Basic. 

Reservoir simulation results for different sorption 

pressure cases are presented in Fig. 1. The work is 

still being continued to accommodate multiphase, 

Klinkenberg effect, and Palmer-Mansoori effect. 

Gas Rate (SCFD) 

1.E+07 

1.E+06 


1.4.4 Effects of Infill Drilling Coalbed-Methane Reservoirs 

Contacts 

Bob Wattenbarger 

979.845.0173 

bob.wattenbarger@pe.tamu.edu 

Pahala D. Sinurat 

Simulation Result for Constant Pressure Case 

1.E+05 

0.1 1 10 100 1000 

Time (days) 

Sorption Pressure = 1103.20 psi 



Fig. 1. Reservoir simulation results for various sorption pressure. 

Significance 

Residual method can be applied in developing a 

reservoir simulator for coalbed methane reservoirs 

to provide a rapid screening approach looking at the 

prospect of development or purchase or production 

improvement. 



Drilling through Gas Hydrate Formations 

Objectives 

The modern petroleum industry meets highly complex 

technical challenges with an increasing demand of 

operations in deepwater offshore and onshore arctic 

environments, where greater emphasis should 

be placed on quantifying the hazards to drilling 

operations caused by gas hydrates. As progress 

is aimed towards ultradeep waters, it becomes 

important for future drilling operations to be able to 

identify ahead of time when problems are likely to 

occur. 

The objective of this research is to develop a 

comprehensive numerical algorithm for the 

estimation of risks while drilling through hydratebearing 

sediments. 

Approach 

We divided the problem into three “sub-problems.” 

The hydrate dissociation possibility will be separately 

analyzed at first in a drilled formation, then at the bit, 

and finally in the wellbore. The available field data 

will be gathered to assess heat transfer phenomena 

in the reservoir and the wellbore. 

bottomhole temperature using a numerical model 

for temperature distribution in the wellbore while 

drilling. On average, the radius of the formation 

affected by drilling was 500 m. The estimated size of 

the problem was used to build a model for numerical 

calculations. 

Temperature (K) 

294 

293 

292 

291 

290 

289 

288 

287 

0.10 

0.15 

Temperature Profile 

0.20 

0.25 

Radial heat transport from hot drilling fluid in wellbore into the formation 

(J.Yang). 

0.30 

0.35 

Distance from Wellbore Center (m) 

0.40 

at 0.139 hr 

at 0.278 hr 

at 2.78 hr 

at 5.56 hr 

at 6.94 hr 

at 8.33 hr 



1.5.5 Design of Fluids for Drilling Though Hydrates 


Peterson, J. Computing the Danger of Hydrate Formation 

using a Modified Dynamic Kick Simulator. Paper presented 

at the 2005 Asia Pacific Oil and Gas Conference, Jakarta, 

Indonesia, 5-7 April. 

Gas-hydrate related problems. 


Using an analytical model of hydrate dissociation 

under changing pressure and temperature, 

we estimated how far into the formation initial 

conditions will be changed due to drilling. For 

boundary conditions, we obtained bottomhole 

pressure from the measurements and we calculated 

Tan, C.P., et al. Managing Wellbore Instability Risk in Gas- 

Hydrate-Bearing Sediments. Paper presented at the 2005 

Asia Pacific Oil and Gas Conference, Jakarta, Indonesia, 

5-7 April. 

Contacts 

Gioia Falcone 

979.847.8912 




Tagir Khabibullin 


43

Experimental and Numerical Simulation Studies to Evaluate Improvement of Light 

Oil Recovery by WACO 2 

and SWACO 2 

in Fractured Carbonate Reservoirs 

Objectives 

Oil recovery from mature fields deteriorates with 

time and significant oil in place is then left behind. 

Also, large economical hydrocarbon discoveries 

have become rarer in recent years. Therefore, the 

need to increase the reserves by improving recovery 

techniques has become essential. Water alternating 

gas (WAG) and simultaneous water and gas injection 

(SWAG) have been proposed and applied with varying 

results. However, extensive studies to examine 

the latter have not been carried out, especially in 

carbonate reservoirs and fractured rocks. Therefore, 

this study will investigate the effect on oil recovery 

and reservoir fluids by injecting water and CO 2 

in 

different modes. 

This research project will study four injection 

modes: waterflooding, continuous gas (CGI), water 

alternating gas (WAG), and simultaneous water 

and gas (SWAG). These modes will be injected in 

two different sets of carbonate cores, fractured 

and unfractured. The study aims to examine the 

influence of these different modes of injection on 

incremental light oil recovery and changes in rock 

and fluid properties. Comparison parameters would 

be as follows: 

» Oil recovery versus time 

» Residual oil saturation in the core matrix and the 

fracture using X-Ray CT scanning 

» Displacement efficiency improvement by the 

addition of NaI to the injected water 

Approach 

This research uses a core flood apparatus which 

contains high-grade aluminum to allow for X-Ray 

CT scanning. The core is connected to a 40-ft 

slimtube coil that will provide the necessary length 

to achieve miscibility, Figs. 1 and 2. The carbonate 

core measures 6 in long by 2 in OD on which the 

two scenarios will be investigated. The fracture will 

be created by sawing the core and placing a 1 mm 

spacer in the fracture to keep it open, and putting 

the fractured core in the coreflood cell. Injection 

pressures will be at 1900 psi to simulate downhole 

conditions and ensure miscibility between injectant 

gases and oil in place. Numerical simulation (CMG) 

will be conducted to model the experimental results. 


A fit-to-purpose experimental apparatus was 

designed. The minimum miscibility pressure (MMP) 

between west Texas light oil and CO 2 

has been 

measured using the industry standard method, 

slimtube, and numerical simulation. It was found 

that the core will not permit multiple contact 

miscibility to occur as tested by the slimtube. This is 

because of the core’s short length and heterogeneity 



1.7.3 Analytical Modeling and Experimental Studies 

to Evaluate Improvement and Recovery of Light Oil in 

Carbonate Reservoirs by Simultaneous Water Alternating 

Gas (SWAG) 


Mamora, D.D.. and Seo, J. G. Enhanced Gas Recovery by 

Carbon Dioxide Sequestration in Depleted Gas Reservoirs. 

Paper 77347, presented at the 2002 SPE-ATCE, San 

Antonio, Texas, 29 September – 2 October. 

Silva, Carlos F. R.: 2003. Water Alternating Enriched Gas 

Injection to Enhance Oil Production and Recovery from 

San Francisco Field, Colombia. MS thesis, Texas A&M U., 

College Station, Texas. 

Contacts 

Daulat Mamora 

979.845.2962 


Fig. 1. Coreholer connected to slimtube. 

Ahmed Aleidan 

44 


Fig. 2. CT scanning of 6” long by 2” diameter carbonate core yields 

porosity and saturation. 

compared to the slimtube. To overcome the lack 

of length, a 40-ft slimtube coil is placed ahead of 

the core to pre-equilibrate the oil with CO 2 

. With 

this arrangement, three types of injections have 

conducted on unfractured core: waterflood alone, 

CGI, and CGI followed by water injection after 

CO 2 

depletion. Injecting water after CO 2 

depletes 

the core showed promising results of 18% OOIP 

incremental recovery. 


45

Enhanced Oil Recovery of Viscous Oil by Injection of Water-in-Oil Emulsions 

Objectives 

Water-in-Oil (W/O) emulsions have been used for 

enhancing oil recovery by improving the mobility 

ratio, thus sweep efficiency, and by miscibility with 

the reservoir oil, thus reducing residual oil. Heavy 

crude oil has been used to make W/O emulsions 

(with addition of nanoparticles) to recover the 

same oil with very good recovery in a core flooding 

experiment. However, crude oil emulsions become 

much more viscous as more water is added, resulting 

in poor injectivity. 

Our research objectives are therefore as follows: 

» Find an oil that can be used to make a moderately 

viscous emulsion system. 

» Make stable W/O emulsions out of this oil without 

the addition of expensive components (e.g., 

surfactant). 

» Verify the performance of the emulsion by core 

flooding experiments. 

Approach 

We will make emulsions by adding water into 

different types of oil, and blending them with a 

blender. Nanoparticles might be mixed into the oil 

prior to the addition of water. If a stable emulsion is 

obtained, its viscosity will be measured at different 

water content, shear rate, and temperature. 


Used engine oil is found to be a very good candidate 

to make stable emulsions (Fig. 1) for several 

reasons: 

» Existing soot provides perfect oleophilic 

nanoparticles to stabilize the W/O emulsion. 

» Moderate oil viscosity allows moderately high 

viscosity achievement for the emulsion (Fig. 2). 

» Stable and well behaved emulsions are obtained 

simply by blending in water, without extra 

surfactant or nanoparticles needed. 

» Used engine oil is produced in large quantities (~1 

billion gallons/year) and needs to be recycled–it is 

therefore relatively cheap. 

Significance 

A simple formulated stable emulsion system is 

obtained, with high potential use as a displacement 

fluid for heavy oil EOR. 

46 

Fig. 1. W/O emulsion with used Pennzoil 5W-30 is stable with water 

content up to 70%. 


100000 

10000 

1000 

100 


1.7.4 Experimental Study of Polymer-Solvent Injection for 

Enhanced Oil 


Bragg, J.R. 1999. Oil Recovery Method Using an Emulsion. 

US Patent 5,885,243. 

D’Elia, S. R. and Ferrer, G. J. Emulsion Flooding of Viscous 

Oil Reservoirs. Paper SPE 4674, presented at the 1973 

annual meeting of SPE of AIME, Las Vegas, Nevada, 30 

September. 

Johnson, C. E. Jr. Status of Caustic and Emulsion Methods. 

JPT (January 1976) 85-92. 

Contacts 

Daulat Mamora 

979.845.2962 


Xuebing Fu 

10 

0 

50 100 150 

Shear rate (s -1 ) 

200 


0% water 

20% water 

40% water 

50% water 

60% water 

70% water 

Fig. 2. Viscosity at 25ºC of W/O emulsion with used Pennzoil 5W-30 

engine oil. 


Managed Pressure Drilling Candidate Selection 

Introduction 

Managed Pressure Drilling (MPD), now at the 

pinnacle of the ‘Oil Well Drilling’ evolution tree, has 

itself been coined in 2003. It is an umbrella term for 

a few new drilling techniques and some preexisting 

drilling techniques, all of them aiming to solve several 

drilling problems, including non-productive time 

and/or drilling flat time issues. These techniques, 

now sub-classifications of MPD, are referred to as 

‘Variations’ and ‘Methods’ of MPD. 

Objectives 

Although using MPD for drilling wells has several 

benefits, not all wells that seem a potential candidate 

for MPD, need MPD. The drilling industry has 

numerous simulators and software models to perform 

drilling hydraulics calculations and simulations. 

Most of them are designed for conventional well 

hydraulics, while some can perform Underbalanced 

Drilling (UBD) calculations, and a select few can 

perform MPD calculations. Most of the few available 

MPD models are modified UBD versions that fit MPD 

needs. However, none of them focus on MPD and its 

candidate selection alone. 

Perform Hydraulic 

Analysis 

Are 

BHP & Ann Pr No 

Inside the PP & 

FP Window 

? 

Are 

All Project 

Objectives 

Met 

? 

Yes 

Yes 

MPD is not Required 

START 

Procure Information & Define Project Objectives 

Change Design 

Parameters 

No 

Is 

Rheology / 

MW / Other 

Design Variations 

Possible 

? 

MPD is not Useful 

STOP 

Perform Hydraulic 

Analysis 

Is 

an MPD 

Variation Available, 

Meeting the 

Criterion 

? 

MPD is Applicable 

Example of MPD candidate selection flow diagram. 

Yes 

No 

No 

Yes 

Are 

All the 

Constraints & 

Project Objectives 

Met 

? 

Yes 

Change Design 

Parameters 

No 

Yes 

Is 

Another 

Method Available or 

Perameter Change 

Possible 

? 

No 

MPD is not Useful 

A ‘Managed Pressure Drilling Candidate Selection 

Model and software’ that can act as a preliminary 

screen to determine the utility of MPD for potential 

candidate wells will be developed as a part of this 

research dissertation. 

Approach 

A model and a flow diagram are needed to identify 

the key steps in candidate selection. The software 

will perform the basic hydraulic calculations and 

provide useful results in the form of tables, plots 

and graphs that would help in making better 

engineering decisions. An additional MPD worldwide 

wells database with basic information on a few 

MPD projects will also been compiled that can act 

as a basic guide on the MPD variation and project 

frequencies and aid in MPD candidate selection. 


Finished the MPD Candidate Selection Flow Diagram, 

Worldwide MPD wells database and the MPD 

Candidate Selection Thesis. 



2.1.1 Managed Pressure Drilling Candidates Selection Model 


Nauduri, S., Medley, G.H., and Schubert, J.J. MPD: Beyond 

Narrow Pressure Windows. IADC/SPE Paper Number 

122276-PP, presented at the 2009 IADC/SPE, Managed 

Pressure Drilling and Underbalanced Operations Conference 

and Exhibition, San Antonio, Texas, 12-13 February. 

Contacts 


979.862.1195 


Hans Juvkam-Wold 

979.845.4093 

juvkam-wold@tamu.edu 

Anantha Nauduri 


47

Alternate Power and Energy Storage/Reuse for Drilling Rigs: Reduced Cost and 

Lower Emissions Provide Lower Footprint for Drilling Operations 

Introduction 

Diesel engines operating the rig pose the problems 

of low efficiency and large amount of emissions. In 

addition the rig power requirements vary a lot with 

time and ongoing operation. Therefore it is in the 

best interest of operators to research on alternate 

drilling energy sources which can make entire drilling 

process economic and environmentally friendly. One 

of the major ways to reduce the footprint of drilling 

operations is to provide more efficient power sources 

for drilling operations. There are various sources 

of alternate energy storage/reuse. A quantitative 

comparison of physical size and economics shows 

that rigs powered by the electrical grid can provide 

lower cost operations, emit fewer emissions, are 

quieter, and have a smaller surface footprint than 

conventional diesel powered drilling. 

with significantly lower emissions, quieter operation, 

and smaller size well pad. 

Objectives 

This project describes a study to evaluate the 

feasibility of adopting technology to reduce the size 

of the power generating equipment on drilling rigs 

and to provide “peak shaving” energy through the 

new energy generating and energy storage devices 

such as flywheels. 

Approach 

An energy audit was conducted on a new generation 

light weight Huisman LOC 250 rig drilling in South 

Texas to gather comprehensive time stamped 

drilling data. A study of emissions during drilling 

operation was also conducted during the audit. The 

data was analyzed using MATLAB and compared to a 

theoretical energy audit. 


The study showed that it is possible to remove 

peaks of rig power requirement by a flywheel 

kinetic energy recovery and storage (KERS) system 

and that linking to the electrical grid would supply 

sufficient power to operate the rig normally. Both 

the link to the grid and the KERS system would fit 

within a standard ISO container. 

Significance 

A cost benefit analysis of the containerized system 

to transfer grid power to a rig, coupled with the KERS 

indicated that such a design had the potential to save 

more than $10,000 per week of drilling operations 


2.1.5 Rig Energy Efficiency Study 


Verma, A.: 2009. Alternate Power and Energy Storage/ 

Reuse for Drilling Rigs: Reduced Cost and Lower Emissions 

Provide Lower Footprint for Drilling Operations. MS thesis. 


Contacts 

David Burnett 

979.845.2274 

david.burnett@pe.tamu.edu 

Ankit Verma 


48 


Cement Fatigue Failure and HPHT Well Integrity 

Objectives 

There have been a lot of experimental investigations 

on the mechanism of fatigue failure of structures 

like buildings and bridges but the fatigue behavior of 

well cement is still relatively unknown to engineers. 

This research tries to give a better understanding 

of cement fatigue and failure, especially for high 

pressure, high temperature (HPHT) wells. Through 

the development of equations specific to well 

cement from experimental data, we will test new 

failure mechanism, crack initiation, and propagation 

and failure theories, and then predict the fatigue life 

of cement as related to HPHT wells. 

Approach 

Based on the experimental method carried out by 

other fields, such as civil engineering, we will design 

a specific experiment related to HPHT cementing. 

The experiment involves the following steps: 

specimen fabrication, test specimen preparation, 

static compression tests, fatigue tests, and data 

analysis. Water-cement ratio, temperature, and 

pressure are the three variables to be considered. 

According to obtained data, we will then develop the 

failure theory and predict the fatigue life of cement. 


Based on the background research, the research 

methods can be divided into two categories: lab 

test and finite element methods. For the field of lab 

testing, our representatives are K.J. Goodwin and 

D. Stiles. In 1992, Goodwin built a test model for 

determining conditions for cement sheath failure. 

The study clearly shows that sealants that are 

stiffer or possess a high Young’s modulus are more 

susceptible to damage when subjected to changes 

in pressure and temperature. In 2006, Stiles built 

another model for testing the long term HPHT 

condition on the properties of cements. For finite 

element method analysis, FEM models are easy to 

carry out. The right input data and choosing the 

right FEM model are the most important parts of 

FEM analysis. Martin Bosma and Kris Ravi did the 

research on this. Their work showed that, in order 

to help reduce the risk of cement failure, the cement 

under downhole conditions should be compensated 

for hydration volume reduction and rendered less 

stiff and more resilient than conventional oilwell 

cements. 

The best way to study the HPHT well cement failure 

was to combine the lab test and FEM methods, using 

the lab data to improve and verify the FEM model 

results. 

Significance 

Using the theory of probability, the high pressure 

cement failure study showed that: 

» Both cement systems show the same failure 

characteristic. Without cycle load, both systems 

fail in tensile strength. At this time the shear 

failure and compressive failure probability is zero. 

» If the tensile failure probability is high, the system 

failure probability is much higher than the fatigue 

failure probability. 

» Compressive strength should not be the most 

important parameter when designing the 

cement system. Latex modified cement shows 

better behavior than conventional cement, 

though conventional cement has a much higher 

compressive strength. 


2.3.5 Reducing the Risk of Cement Failure in High Pressure, 

High Temperature (HPHT) Conditions, Rock Mechanics 

Aspects through Analytical and Finite Element Method 

Approaches 

Contacts 


979.862.1195 




Zhaoguang Yuan 



49

Propagation of Induced Hydraulic Fractures near Pre-Existing Fractures 

Objectives 

Hydraulic fracturing is a widely used technology 

for stimulating oil and gas wells. The intersection 

of hydraulic fractures with natural fractures or 

other discontinuities in a rock mass can give rise to 

significant changes to fracture growth. The objective 

of this project is to study the potential propagation 

behaviors of hydraulic fractures near pre-existing 

fractures considering linear and non-linear fault 

behavior and poroelastic effects. 

Approach 

We use 2D boundary element method to model 

the stress field ahead of a hydraulic fracture in the 

vicinity of a pre-existing fracture. A unified structural 

criterion is used to predict the crack propagation 

behavior. The work initially considers fractures in an 

elastic media. Poroelastic effects, which arise from 

coupling of rock deformation and fluid flow inside the 

fracture, are considered next. Propagation behaviors 

of single pressurized crack and interaction between 

multiple cracks are studied. And finally, interaction 

between hydraulic fractures and natural fractures in a 

homogeneous poroelastic media will be investigated. 


A 2D real DD boundary element method has been 

developed and used to simulate fracture propagation 

trajectories for single and multiple cracks. Parametric 

studies are carried out for different crack propagation 

Y, m 

0.3 

0.2 

0.1 

0 

-0.2 

-0.1 

0 

X, m 

Crack A 

Crack B 

v = 1.e-1m/s, c/ t 

= 1.1 

v = 1.e-3m/s, c/ t 

= 1.1 

v = 1.e-1m/s, c/ t 

= 1.5 

v = 1.e-3m/s, c/ t 

= 1.5 

Crack propagation path near an inclined crack at different crack propagation 

speeds (S H 

= 1 MPa, S h 

= 0.5 MPa, p = 3.5 MPa, c/σ t 

= 1.1). 

0.1 

0.2 

speeds, far field stresses, rock cohesion and internal 

fluid pressures to investigate the influential factors 

on fracture propagation in a poroelastic rock and the 

results are compared with those given by an elastic 

model. We find that matrix pore-pressure increase 

could change crack propagation mode and direction. 

Significance 

This study will enable us to predict the potential 

fracture patterns that can arise from the intersection 

of a fluid-driven hydraulic crack with a pre-existing 

fracture. The results will assist us in design of 

fracture treatments in complex geo-mechanical 

environment. Future work will consider various joint 

properties, fluid injection rates as well as the impact 

of reservoir depletion. 


2.4.2 Studies of Propagation of Induced Hydraulic Fractures 

through Pre-Existing Fractures 


Ghassemi, A., Zhang, Q. 2006. Poro-thermoelastic 

Response of a Stationary Crack using the Displacement 

Discontinuity Method. ASCE J. Engineering Mechanics 132 

(1): 26-33. 

Koshelev, V., Ghassemi, A. Complex Variable BEM for 

Stationary Thermoelasticity and Poroelasticity. J. Eng. 

Anal. with Boundary Elements 28 (2004) 825-832. 

Xue, W., Ghassemi, A. Poroelastic Analysis of Hydraulic 

Fracture Propagation. Paper 129, presented at the Asheville 

Rocks 2009, 43rd US Rock Mechanics Symposium, Asheville, 

North Carolina, 28 June–1 July. 

Contacts 


979.845.2206 


Wenxu Xue 


50 


Using Downhole Temperature Measurement to Assist Reservoir Characterization 

and Optimization 

Introduction 

Downhole temperature distribution in horizontal 

wells can be an important source of information that 

helps us characterize the reservoir and understand 

the bottom-hole flow conditions. The temperature 

measurements are obtained from permanent 

monitoring systems such as downhole temperature 

gauges and fiber optic sensors. Also, production 

history and bottomhole pressures are usually 

readily available and are routinely used for history 

matching to improve the initial geological models. 

Combining the downhole temperature distribution 

and the production history, we can extract more 

reliable information about the reservoir permeability 

distribution and bottomhole flow conditions that help 

us optimize the wellbore performance, particularly 

in horizontal wells. 

Objectives 

We will use a thermal model and a transient, 3D, 

multiphase flow reservoir model to characterize the 

reservoir and horizontal well flow profile. 

Approach 

Earlier work has shown that downhole temperature 

interpretation can provide a coarse-scale reservoir 

permeability distribution (Li and Zhu, 2009). The 

question we address here is how to incorporate this 

information for geologic modeling and production 

history matching. There are two potential approaches, 

possibly among others. The first is to incorporate the 

coarse-scale permeability information as ‘secondary’ 

information while constructing the prior geologic 

model. This model can then be history matched 

to further update the geologic model. The second 

approach would be to include the temperaturederived 

coarse-scale permeability as a penalty 

function during the history matching process. We 

will adopt the former approach. 

Fig. 1 shows an outline of an integrated approach 

that combines the temperature interpretation and 

production history matching for dynamic reservoir 

characterization and modeling. It includes four 

major steps as follows: 

» Use temperature interpretation method to match 

the observed temperature data, and obtain a 

coarse-scale permeability distribution. 

» Generate a high-resolution geologic model 

constrained to the coarse-scale permeability 

estimate. This is accomplished using Sequential 

Gaussian Simulation with Block Kriging, much 

along the line of seismic data integration into 

geologic models. 

» Use the geologic model as the prior model for 

production history matching. The history matching 

is carried out using a fast streamline-based 

approach that is well-suited for the high resolution 

model. 

No 


2.4.5 Production Monitoring and Control with Intelligent 

Technology 


Li, Z. and Zhu, D. Predicting Flow Profile of Horizontal 

Well by Downhole Pressure and DTS Data for Water-Drive 

Reservoir. Paper SPE 124873, presented at the 2009 SPE 

Annual Technical Conference and Exhibition, New Orleans, 

Louisiana, 4-7 October. 

Contacts 

Ding Zhu 

979.458.4522 

ding.zhu@pe.tamu.edu 

Zhuoyi Li 

Temperature interpretation 

Obtain a coarse-scale 

perm distribution 

Downscale the coarsescale 

permeability via 

sequential Gaussian 

simulation with block kriging 

Temperature 

data match? 

Finish 

Yes 

Yes 

Prior geologic model 

for history matching 

Forward simulation for 

reservoir pressure and 

saturation 

Calculation of production 

data misfit 

Production 

data match? 

No 

Calculation of sensitivity 

coefficients from streamline 

Updating permeability 

via minimizing production 

data misfit 

Fig. 1. Integrated workflow for incorporating temperature data into history 

matching. 




51

» Use forward modeling of wellbore temperature 

to cross-check that the history matched model 

reproduces the temperature data. If the updated 

model reproduces the wellbore temperature 

measurements within a pre-specified tolerance, 

we accept the refined permeability distribution. 

Otherwise, we go back to step two and repeat the 

process. 


We presented several synthetic cases to illustrate 

the procedure. The results show that with only 

production history matching without distributed 

data along the wellbore, the water entry location in 

horizontal wells cannot be detected satisfactorily. 

Combining production history matching with the 

temperature distribution in the wellbore, we can get 

an improved geological model that can match the 

production history and also locate the water entry 

correctly. Based on the downhole flow conditions and 

the updated geological model, we can now optimize 

the well performance by controlling the inflow rate 

distribution, such as shutting the high water inflow 

sections. Fig.2 shows an example of the procedure 

developed from this project. 

Fig. 2. Example of using temperature interpretation and history match to 

characterize reservoir and downhole flow. 

52 


Optimization of Horizontal Well Performance in Low-Permeability Gas Reservoirs 

Objectives 

The objective of this research is to develop an 

approach to evaluate horizontal well performance for 

fractured or unfractured gas wells, and to conduct a 

sensitivity study of gas well performance in a low 

permeability formation. Different mathematical 

model approaches will be used, including analytical 

solutions, Point/Line source method, and Distributed 

Volumetric Source (DVS) method for numerical 

simulation. The methods will predict a production 

index for horizontal wells. In addition, permeability, 

well trajectory, fracture geometry, and in-situ 

stresses of formations, which are critical parameters 

for horizontal well and hydraulic fracturing design, 

will also be studied. 

Approach 

Analytical Solution 

Many horizontal well models have been developed 

for both steady-state flow and pseudo-steady 

flow. However, for tight gas formation, the flow is 

more likely to have a longer transient period. The 

performance of transient flow for horizontal gas 

wells should be studied in this research. 

to decide the horizontal well length and the numbers 

of fractures. 


» Slab source method has been developed to 

calculate the horizontal well, which has a good 

match with Babu and Odel’s method. 

» Horizontal well with one or two fractures has been 

solved for both transient and pseudo-steady state 

conditions. 

» For finite conductivity boundary conditions, we 

divided the fracture into several segments, and 

the pressure drop can be calculated. 

Future Work 

The ultimate goal of this project is to develop an 

Expert system. This system will help in calculating the 

performances of oil/gas horizontal wells, with other 

aspects conducted in the performances of fractures. 

By integrating these two topics, a system can be 

created to aid the industry to develop hydraulic 

fracture horizontal wells more economically and 

efficiently. 

Point/Line Source Solution 

A line source solution for horizontal well has been 

developed by Kamkom (2007). Investigate the 

possibility of using point source to represent fracture 

performance. 

Slab Source Solution 

The research will use the slab source method to 

predict well performance of a single fracture and 

multiple fractures. By comparing results with line 

source solution, the difference will be discussed 

Numerical Simulation 

The model built from the research will be combined 

with a commercial simulator (ECLIPSE) and a 

fine grid fracture to build a model for a tight gas 

horizontal well with and without fractures. 

Significance 

This project is a major initiative to review current 

fractured horizontal well performance in analytical 

theory. The results of this project allow comparing 

different fluid types and different boundary 

conditions reservoir to select an optimization method 


2.4.10 Optimization of Horizontal Well Performance in Low- 

Permeability Gas Reservoirs 

Contacts 

Ding Zhu 

979.458.4522 


Jiajing Lin 



53

Decision Matrix for Liquid Loading in Gas Wells for Cost/Benefit Analyses of Lifting 

Options (Part 2) 

Objectives 

Liquid loading is one of the main drawbacks of 

gas well production. Although there are literature 

reviews available regarding solutions to liquid loading 

problems in gas wells, a tool capable of helping an 

operator select the best option for a specific field 

case still does not exist. 

The ultimate goal of this project is to fulfill the 

decision matrix tool initiated by a previous graduate 

student. Developing the tool itself and adding 

more available water unloading options and more 

limitations in each technique, using both technical 

and economic factors, will complete the full cycle for 

this project. 

Approach 

This project develops and expands the existing 

decision matrix tool used to evaluate and screen 

the possible available alternatives for dealing with 

liquid loading in gas wells. Limitations of liquid 

unloading techniques from literature reviews and 

practical actual data from the industries will be 

collected to become a database. A full cycle analysis 

of a production simulation will then be performed, 

emphasizing technical and economic impacts. First, 

simulation of gas production will be done using a 

material balance method. From this, production 

profiles and gas decline rates can be obtained. A 

decline curve analysis will also be done if the data 

available to confirm the results from the simulation 

exist. Then a cash flow analysis consisting of the cost 

and the benefits of each technique will be performed 

to obtain economic yardsticks such as NPV or IRR. 

Using these yardsticks should provide the most 

optimum (practical and economical) unloading 

technique to be selected. 

Significance 

By using this decision matrix tool as a preliminary 

screening tool, companies can determine which 

technique is the best fit for their conditions. The 

operators can also save time and money usually 

wasted when considering and trying many different 

liquid unloading techniques by themselves. 

Future Work 

The completed decision matrix is the ultimate goal of 

this project, therefore the types of liquid unloading 

techniques, the limitations of each technique, 

the actual set of production data from the oil and 

gas companies, and the results from production 

simulations have to be applied to the decision matrix 

codes as much as possible to make this program 

provide a good representation of each alternative. 

Flow diagram for Decision Matrix. 


2.4.13 Decision Matrix for Liquid Loading in Gas Wells for 

Cost/Benefit Analyses of Lifting Options (Part 2) 


Park, Han-Young: 2008, Decision Matrix for Liquid Loading 

in Gas Wells for Cost/Benefit Analyses of Lifting Options. 

MS thesis, Texas A&M U., College Station, Texas. 

Contacts 

Gioia Falcone 

979.847.8912 


Nitsupon Soponsakulkaew 

Evaluation Start 

Preliminary Screening 

- Well information - Production status 

- Fluid properties - Reservoir properties 

- Power supply 

Technical Evaluation using Decision Matrix 

- Technical Efficiency - Reserves information 

- Production profiles - Production Decline Rate 

Economic Evaluation 

- Economic yardsticks (NPV, IRR) 

Final Selection and Ranking 


54 


Investigation of Swirl Flows Applied to the Oil and Gas Industry 

Introduction 

Swirl flow (or vortex flow) is a fluid stream which has 

a rotational velocity as well as a linear velocity (Fig. 

1). It typically occurs in cyclones, hydrocyclones, 

spray dryers, heat exchangers with twisted-tape 

inserts, and vortex burners. It is also the basic 

principle behind foam-breaking or de-foaming 

separators, which have received significant industrial 

attention in recent years. Current research at Texas 

A&M University is studying the various applications 

of swirl flow to help mitigate particular problems 

in the oil and gas industry. Among the swirl flow 

applications under investigation are liquid unloading 

in gas wells and wet gas metering. 

Swirling Flow 

For the purpose of the analysis presented here, the 

expansion/contraction section and the venturi were 

excluded from the simulations in order to allow focus 

on the effects of the swirling device. 

In prior described experiments (Falcone et al., 

2003), the actual length of straight pipe upstream 

of the swirler was about 10 m. This resulted in fully 

developed annular flow prior to the fluid reaching 

the swirler. To simulate this correctly with the CFD 

model while minimizing the mesh requirements 

(and hence the running times), a sensitivity analysis 

was performed on the length of pipe to be modeled 

before the swirler. It was found that a length of 2 

m in the model yielded annular flow upstream the 

swirler. The final model used for the CFD simulations 

is shown in Fig. 2. 


Axial Flow 

Direction 

Fig. 1. Schematic of a swirl flow, showing a particle’s helical path. 

Objectives 

A commercial CFD software package will be used 

in this study, with the objective of investigating 

the efficiency of the liquid separation at high gas 

fraction and evaluating the persistence of the swirl 

downstream of the flow conditioning device. These 

features are essential to understand not only the 

efficiency of in-line separation devices used for wet 

gas metering purposes, but also that of downhole 

tools for liquid unloading in gas wells. 

Approach 

A commercial CFD software package was used. 

A model of the ANUMET meter was built and 

simulations were run using the input data from the 

reported experiments (Falcone, 2006). The pipe 

diameter was increased from 31.8 mm to 32.1 mm, 

which provided a 0.15 mm thick inflation boundary 

on the pipe walls that helped to capture the film 

thickness more efficiently than tetrahedral elements. 


2.4.17 Investigation of Swirl Flows Applied to the Oil and 

Gas Industry 


Falcone, G., Hewitt, G.F., Lao, L., Richardson, S.M. ANUMET: 

A Novel Wet Gas Flowmeter. Paper SPE 84504 presented at 

the 2003 SPE Annual Technical Conference and Exhibition, 

Denver, Colorado, 5-8 October. 

Surendra, M., Falcone, G., Teodoriu, C. Investigation of 

Swirl Flows Applied to the Oil and Gas Industry. Paper 

SPE 115938 presented at the 2008 SPE Annual Technical 

Conference and Exhibition, Denver, Colorado, 21-24 

September. 

Contacts 

Gioia Falcone 

979.847.8912 




Meher Surendra 



55

fractions involved, a detailed sensitivity analysis 

of the model used for this work would be required 

to assess the effects of varying the liquid content 

and also the operating pressure and the phase flow 

rates. 

Fig. 2. CFD model of the section of interest of the ANUMET meter. The 

flow is along the Z axis. 

Significance 

The preliminary results confirm that the twisted tape 

induces a swirling motion that results in a separated 

flow downstream of the device. The liquid flows 

along the pipe walls, although there remains some 

entrainment within the gas core. The distribution of 

the phases across the pipe section is not the same 

at different locations downstream of the swirler. 

In particular, it appears that the efficiency of the 

separation is highest at the furthermost location 

from the device. However, due to the particular 

geometry investigated, this study has not been able 

to verify how far from the twisted tape the swirling 

motion persists, and whether this is accompanied 

by an efficient separation of the phases. It is in fact 

believed that, due mainly to gravity effects, there is 

a point where the vortex motion becomes negligible. 

Future Work 

For the ANUMET wet gas meter application, it is 

important to understand where the maximum 

liquid deposition occurs, so that the measured 

film thickness would be most representative of the 

total liquid hold up in the pipe. For downhole liquid 

unloading applications, it is important to understand 

whether the swirling motion induced by vortex 

devices can actually persist up to the wellhead. More 

work is needed to prove the actual flow dynamics 

through these devices and the relationship between 

tool configuration, flow rates, operating pressure, 

well geometry (length, diameter and orientation) 

and swirl persistence. Also, because of the high gas 

56 


Potential for CO 2 

Sequestration and Enhanced Coalbed Methane Production, NW 

Black Warrior Basin 

Objectives 

This project is going to assess the potential for 

CO 2 

sequestration and enhanced coalbed methane 

(ECBM) production of the Pottsville formation coals. 

The ultimate goal is to rank Black Warrior basin CBM 

fields by their potential for profitability and to select 

a pilot site that is suitable for injection of CO 2 

at a 

commercial scale of up to 50 MMcf/d. The assessment 

will address technical issues, such as CO 2 

injection 

rates, injection volumes and pressures, number of 

wells, and well spacing. 

as evaluation of the CO 2 

sequestration and ECBM in 

this area becomes more commercial. 

Approach 

We will design study cases to optimize the production 

and the sequestration, which includes well spacing, 

completion layers, dewatering time, injecting rate, 

etc. We will collect the data for the Blue Creek field. 

We will also specify the reservoir properties and set 

up the model of the formation. 


Our simulation study was based on a 5-spot well 

pattern 40-ac well spacing. For the entire Blue 

Creek field of the Black Warrior basin, if 100% CO 2 

is injected into the Pratt, Mary Lee and Black Creek 

coal zones, enhanced methane resources recovered 

are estimated to be 0.3 Tcf, with a potential CO 2 

sequestration capacity of 0.88 Tcf. The methane 

recovery factor is estimated to be 68.8%, if the three 

coal zones are completed but produced one by one. 

Approximately 700 wells may be needed in the field. 

For multi-layered completed wells, the permeability 

and pressure are important in determining the 

breakthrough time, methane produced, and CO 2 

injected. Dewatering and soaking do not benefit 

the CO 2 

sequestration process, but do allow higher 

injection rates. Permeability anisotropy affects CO 2 

injection and enhanced methane recovery volumes 

of the field. 

We recommend a 5-spot pilot project with a maximum 

well BHP of 1,000 psi at the injector, a minimum 

well BHP of 500 psi at the producer, a maximum 

injection rate of 70 Mscf/D, and a production rate of 

35 Mscf/D. 

Significance 

For environmental and economical factors, it is 

feasible to have several ECBM programs in Black 

Warrior Basin. These programs are win-win projects 

Coalbed methane fields in the Black Warrior Basin, Alabama (from Pashin 

et al. 2004). 


2.4.22 Evaluation of Potential for CO 2 

Sequestration and 

CO 2 

ECBM, Pottsville Formation, Black Warrior Basin 

Contacts 


979.845.2447 

walt.ayers@tamu.edu 

Maria Barrufet 

979.845.0314 

maria.barrufet@pe.tamu.edu 

Ting He 



57

Transient Multiphase Sand Transport in Horizontal Wells 

Introduction 

Multiphase technology solutions have enabled the 

process industries, such as the petroleum industry, 

mining industry and nuclear industry, to improve their 

production performance, extend their operation, 

and address previously insoluble problems. 

Objectives 

The objective of the dissertation is to develop a 

dynamic simulation tool for sand transport and 

control in oil-gas and oil-water multiphase flow 

systems through horizontal and vertical wellbores, 

pipelines, and production rises. 

Approach 

Unsteady state multiphase flow and optimal sand 

transport control models will be developed based on 

a multi-fluid modeling approach in the CFX Ansys, 

STAR CCM+ and MATLAB platforms to predict sand 

particle transport and hydrodynamic behavior under 

various system, operation, and geometric conditions. 

New data from sand transport and entrainment 

experimental flow loops will be used to validate 

the developed model(s) and to achieve a better 

understanding, and to improve project performance 

and value creation. The new design and engineering 

analysis tool will provide best practices guidelines 

and performance assessment of gas-oil-sand and 

oil-water-sand multiphase flow system design 

options and optimal operational methodologies. 


» Reviewed literature of current multiphase models 

and their limitations 

» Developed a mechanistic model for predicting 

effect on the pressure drop of sand transport in 

horizontal wells 

» Placed a purchasing order for flange gaskets to be 

used in the flow loop facility in Room 601. 

Future Work 

» Continue with the literature review of sand 

transport and multiphase models. 

» Jump-start the flow loop in Room 601. 

» Modify the flow loop to accommodate sand 

transport mechanism. 



2.4.23 Transient Multiphase Sand Transport in Horizontal 

Wells 

Contacts 

Gioia Falcone 

979.847.8912 


Ime Udong 

58 


Performance Driven Hydraulic Fracture Design for Deviated Wells 

Introduction 

Unrestricted fracturing, long-established for lowpermeability 

reservoirs, is not applicable to highpermeability 

formations where the resulting width 

would be far less than indicated by rigorous design 

approaches such as the Unified Fracture Design 

(UFD). Thus, tip screenout (TSO) treatments are 

necessary, in which the lateral migration of the 

fracture is arrested followed by inflation of the 

fracture to the desired/optimum width. The term 

high-performance fracturing (HPF) better reflects 

the high performance standard targeted by this 

completion technique. 

Connectivity between the well and the fracture is 

a very important issue and has been addressed 

repeatedly in the literature. Because HPF’s dominate 

Gulf of Mexico well completions where well deviation 

angles established for extended reach drilling are 

maintained through the productive zone, the issue 

of well to fracture connectivity becomes even more 

serious. Ehlig-Economides et al. introduced a new 

model for hydraulically fractured wells, hypothesizing 

that only those perforations in the intersection 

between the far field hydraulic fracture plane and the 

wellbore actually connect flow through the fracture 

to the well. In turn, Zhang et al. introduced a new 

model allowing for flow both through the fracture 

and bypassing the fracture through perforation that 

are not connected to the fracture. 

Objectives 

This research is intended to provide new 

computational tools to quantify how the presence 

of the deviated wellbore open to flow impacts the 

expected performance of the hydraulic fracture, 

allowing a design of the system “deviated wellbore 

open to flow + transverse hydraulic fracture” to 

maximize overall productivity. 

Approach 

The problem is approached by combining the UFD 

technique with the “Method of Distributed Volumetric 

Sources” (DVS). We are developing a convenient 

implementation/methodology that will iteratively 

find the optimal fracture geometry that would result 

in a maximum productivity index of the deviated 

and fractured wells. 

Future Work 

We intend to carry on the following three main tasks: 

» Provide analytical/empirical expression(s) for 

the mechanical skin that includes all contributing 

factors such as well deviation, perforation density, 

phasing, penetration depth, diameter, minimum 

in-situ stress direction, proppant permeability, 

halo effect, production rate, and turbulence beta 

factors. 

» Provide analytical/empirical expression(s) for the 

composite productivity index (J D 

) that includes all 

previously mentioned major contributing factors. 

» Generate simplified correlations and benchmarking 

plots for the composite productivity index (J D 

) 

versus well deviation and reservoir permeability. 



2.4.24 Hydraulically Fractured Well Performance in High 

Rate Wells 


Economides, M. J., Oligney, R.E., and Valkó, P.P. 2002. 

Unified Fracture Design (hardbound). Houston: Orsa Press. 

Ehlig-Economides, C.A., Tosic, S., and Economides, M.J. 

Foolproof Completions for High-Rate Production Wells. 

Paper SPE 111455, presented at the 2008 SPE International 

Symposium and Exhibition on Formation Damage Control, 

Lafayette, Louisiana, 13-15 February. 

Zhang, Y., Marongiu-Porcu, M., Ehlig-Economides, C.A., 

Tosic, S., and Economides, M.J. Comprehensive Model for 

Flow Behavior of High-Performance Fracture Completions. 

Paper SPE 124431, presented at the ATCE 2009 SPE 

Annual Technical Conference and Exhibition, New Orleans, 


Valko, P.P., and Amini, S. Method of Distributed Volumetric 

Sources for Calculating the Transient and Pseudosteady 

State Productivity Index of Complex Well-fracture 

Configurations. Paper SPE 106279, presented at the 2007 

SPE Hydraulic Fracturing Technology Conference, College 

Station, Texas, 29-31 January. 

Contacts 

Christine Ehlig-Economides 

979.458.0797 

c.economides@pe.tamu.edu 

Matteo Porcu 


59

Carbonate Heterogeneity and Acid Fracture Performance 

Objectives 

The objective of this work is to evaluate the expected 

performance of acid fracturing for two wells in the 

Hugoton field. Permeability data from cores and 

outcrops as well as mineralogical descriptions of 

the sampled rock will be used to characterize the 

carbonate heterogeneity. Specifically, the standard 

deviation of permeability, vertical correlation length, 

and horizontal correlation length will be defined. 

These geostatistical parameters are inputs for an acid 

fracture simulator developed by Mou et al. (2009) 

that incorporates an intermediate-scale acid etching 

model. This work will be combined with a model of 

fracture surface deformation behavior under closure 

stress developed by Deng et al. (2009), and the 

overall acid fracture conductivity will be determined 

for the case in the Hugoton field. 

Approach 

Determination of the vertical correlation length will 

depend on permeability measurements taken on 

cores from the productive zones of the Hugoton 

field. The horizontal correlation length will primarily 

depend on permeability data from outcrops, but 

may also be supported with well and field data, 

analogues, and literature on carbonates in the 

Chase Group. Mou’s acid fracture simulator, along 

with Deng’s model of fracture conductivity under 

closure stress, will be applied to this case. 


Core permeability data was collected every inch 

over ten feet in three productive zones for two wells 

in the Hugoton field. From this data, the vertical 

correlation length can be derived through analysis 

of each vertical semivariogram (Fig. 1). Numerous 

Chase Group outcrop locations have been identified 

in Kansas for collection of horizontal permeability 

and mineralogy data. 

Future Work 

The models developed by Mou and Deng will be 

combined to produce one overall acid fracture 

simulator. The Hugoton case will serve as a test 

case by which the practicality of the simulator will 

be evaluated and improved as needed. 

(h) 

250 

200 

150 

100 

50 



2.5.1 Acid Fracture Performance – Scale-Up of Fracture 

Conductivity 


Deng, J., Hill, A.D. and Zhu, D. A Theoretical Study of 

Acid Fracture Conductivity Under Closure Stress. Paper 

SPE-124755, presented at the 2009 SPE Annual Technical 

Conference and Exhibition, New Orleans, Louisiana, 4-7 

October. 

Mou, J., Zhu, D. and Hill, A.D. A New Acid-Fracture 

Conductivity Model Based on the Spatial Distributions of 

Formation Properties. Paper SPE-127935 presented at the 

2010 SPE International Symposium on Formation Damage 

Control, Lafayette, Louisiana, 10-12 February. 

Mou, J., Zhu, D. and Hill, A.D. Acid-Etched Channels 

in Heterogeneous Carbonates—A Newly Discovered 

Mechanism for Creating Acid Fracture Conductivity. 

Paper SPE-119619 presented at the 2009 SPE Hydraulic 

Fracturing Technology Conference, The Woodlands, Texas, 

19-21 January. 

Contacts 

Dan Hill 

979.845.2278 

dan.hill@pe.tamu.edu 

Ding Zhu 

979.458.4522 


Flower Well Towanda Member Semivariogram 

0 

0 20 40 60 80 100 120 

h 

Fig. 1. Semivariogram for the Flower Well in the Towanda Member, illustrating 

a vertical correlation length of approximately 5 inches. 

Cassandra Beatty 

60 


Modeling and Analysis of Reservoir Response to Stimulation by Water Injection 

Objectives 

The distributions of pore pressure and stresses 

around a fracture are of interest in conventional 

hydraulic fracturing operations, fracturing during 

water-flooding of petroleum reservoirs, shale gas, 

and injection/extraction operations in a geothermal 

reservoir. During the operations, the pore pressure 

will increase with fluid injection into the fracture 

and leak off to surround the formation. The pore 

pressure increase will induce the stress variations 

around the fracture surface. This can cause the 

slip of weakness planes in the formation and cause 

the variation of the permeability in the reservoir. 

Therefore, the investigation on the pore pressure 

and stress variations around a hydraulic fracture in 

petroleum and geothermal reservoirs has practical 

applications. With the pore pressure distribution, 

the failed reservoir volume can be estimated by 

considering the failure of rock mass. 

Y, ft 

3000 

2400 

1800 

1200 

(psi) 

6558.00 

600 

6148.33 

5738.67 

0 

5329.00 

4919.33 

-600 

4509.67 

4100.00 

-1200 

-1800 

-2400 

-3000 -2400 -1800 -1200 -600 0 600 1200 1800 2400 

X, ft 

Fig. 1. Pore Pressure Distribution around a Hydraulic Fracture. 

Approach 

In our study, we built up a model (FracJStim model) 

to calculate the pore pressure distribution around a 

fracture of a given length under the action of applied 

internal pressure and in-situ stresses as well as their 

variation due to cooling and pore pressure changes 

(Fig. 1). In the FracJStim model, the Structural 

Permeability Diagram (Fig. 2) is used to estimate 

the required additional pore pressure to reactivate 

the joints in the rock formations of the reservoir. By 

estimating the failed reservoir volume and comparing 

it with the actual stimulated reservoir volume, the 

enhanced reservoir permeability in the stimulated 

zone can be approximated. 

0 

270 90 

180 

Fig. 2. Structural Permeability Diagram for Barnett Shale. 

P 

(psi/ft) 

0.50 

0.06 

Significance 

This work is of interest in interpretation of microseismicity 

in hydraulic fracturing and in assessing 

permeability variation around a stimulation zone. 

The work can also be used to assess the accuracy of 

more complex numerical models. 

Future Work 

We will continue developing the model to three 

Dimensions, including the stresses variations and 

heterogeneous conditions. We will also improve 

the application of this work by simulating multiple 

fractures. 



2.5.10 Pore Pressure and Stress Distributions around an 

Injection-Induced Fracture 

Contacts 


979.845.2206 


Jun Ge 


61

Fracture Aperture Variation Caused by Reactive Transport of Silica and 

Poro-Thermoelastic Effect 

Introduction 

Poro-thermo-mechanical processes and 

mineral precipitation/dissolution change the 

fracture aperture and thus affect the fluid 

flow pattern in the fracture. 

a. 

t =3 months 

b. 

t =3 months 

Different aspects of thermal and mechanical 

processes have been studied (e.g. Ghassemi 

and Zhang, 2004; Ghassemi et al., 2005, 

2007, 2008, and 2009). The thermoelastic 

effects are dominant near the injection when 

compared to those of poroelasticity. Under 

some conditions, silica reactivity tends to 

dominate permeability (Kumar and Ghassemi, 

2007). Experimental studies (Carroll et al., 

1998; Johnson et al., 1998; Dobson et al., 

2003) also show that chemical precipitation 

and dissolution of minerals significantly affect 

fracture aperture. 

c. t =3 months 

d. 

t =3 months 

Objectives 

We will study this phenomenon by the 

development and application of a threedimensional 

poro-thermoelastic model 

incorporating mineral dissolution/precipitation 

effects. 

Approach 

Simulating the poro-thermoelastic chemical 

mechanisms usually requires solving a coupled set 

of equations (e.g., fluid flow, heat transport, solute 

transport/reactions and elastic response of the 

reservoir). These processes are coupled and nonlinear. 

In this work, the solid mechanics aspect of 

the problem is treated using poro-thermoelastic 

displacement discontinuity method (Ghassemi et 

al., 2009), while reactive flow and heat transport in 

the fracture is solved using finite element method. 

Similarly, the solution system in the reservoir rock 

is obtained using the boundary element method. We 

focus on single-component mineral reactivity and 

its transport in the fracture. The solute reactivity 

and solubility in fracture plane is considered using a 

temperature dependent formulation (e.g., Robinson, 

1982, and Rimstidt and Barnes, 1980). 

Significance 

We apply the model to simulate the process of 

low-temperature fluid injection and production of 

high-temperature fluid in a hot-rock-reservoir, and 

a. Flow vector in planar fracture; b. Contour plot of the temperature (K) distribution; 

c. Contour plot of silica concentration (ppm) in the fracture; d. Ratio of 

current fracture aperture to the initial fracture aperture. 

thus its impact on mineral mass distribution, pore 

pressure and thermal stress. Recent computations 

include temporal evolution of mineral concentration 

and its dissolution/precipitation, temperature, and 

fluid pressure in the fracture. 


2.5.14 Fracture Aperture Variation due to Reactive Transport 

of Silica and Poro-Thermoelastic Effect 


Rawal C. and Ghassemi A. A 3-D Analysis of Solute 

Transport in a Fracture in Hot- and Poro-elastic Rock. Paper 

to be presented at the 2010 44th U.S. Rock Mechanics 

Symposium, ARMA, Salt Lake City, Utah, 27-30 June. 

Rawal C. and Ghassemi A. Reactive Flow in a Natural 

Fracture in Poro-thermoelastic Rock. Paper presented at 

the 2010 35th Stanford Geothermal Workshop. Stanford, 

California, 1-3 February. 

Contacts 


979.845.2206 


Chakra Rawal 


62 


Rheological Properties of a New Class of Viscoelastic Surfactant 

Objectives 

Surfactant-based acid systems were developed over 

the last few years for diversion, to overcome the 

severe problems caused by polymer residue and 

crosslinker precipitate after polymer-based system 

treatments during matrix and fracture acidizing. 

Surfactant molecules can form rod-like micelles and 

significantly increase the viscosity in the presence of 

salts. After acid treatments, the surfactant gel can 

be broken by mixing with hydrocarbons, external 

breakers, or internal breakers or by reducing the 

concentration of salts via dilution with water. Acid 

additives and Fe (III) contamination can influence 

the formation of the rod-shaped micelles and result 

in different rheological properties from what we 

want. A new class of viscoelastic surfactant (VES)- 

amidoamine oxide has been tested in this study. 

The effects of acid additives, Fe (III) contamination, 

temperatures and shear rates need to be examined 

on the rheological properties of this new surfactant. 

Approach 

Acid additives studied included corrosion inhibitors, 

mutual solvents, non-emulsifying surfactants, iron 

control agents and a hydrogen sulfide scavenger. 

The Grace Instrument M5600 HPHT Rheometer was 

used to measure the apparent viscosity of live and 

spent acids under different conditions. The wetted 

material is Hastelloy C-276, which is acid-resistant. 

Measurements were made at temperatures from 75- 

220°F, and 300 psi at various shear rates from 0.01- 

935 s -1 . An Orion 950 analytical titrator was used to 

measure HCl concentration. The centrifuge used in 

this study was Z 206 A from Labnet International. 

Apparent Viscosity (cp) 

1200 

1000 

800 

600 

400 

200 

0 

5 

10 

15 


C HCl 

(wt%) 

20 

8 

10 

12 

15 

18 

20 

25 

28 

Acid Concentration (wt%) 


108.8632 

706.438 

984.783 

175.0444 

12.1892 

5.8126 

2.8148 

2.896 

25 30 

Fig. 1. Apparent viscosity (10 s -1 ) of surfactant-based live acids that contained 

4 wt% surfactant, 1 wt% CI-A and various HCl concentrations. 

Apparent Viscosity (cp) 

1800 

1600 

1400 

1200 

1000 

800 

600 

400 

200 


Calcium chloride increased the apparent viscosity 

of live acids. Concentration of HCl in the live acid 

system affected its apparent viscosity. Live acid 


2.5.15 Reaction of Organic Acids with Calcite 


Li, L., Nasr-El-Din, H.A., Crews, J.B., and Cawiezel, K.E. 

2010. Impact of Organic Acids/Chelating Agents on 

Rheological Properties of Amidoamine Oxide Surfactant. 

Paper SPE 128091 will be presented at the 2010 SPE 

International Symposium on Formation Damage Control, 

Lafayette, Louisiana, 10-12 February. 

Li, L., Nasr-El-Din, H.A., and Cawiezel, K.E. 2009. 

Rheological Properties of a New Class of Viscoelastic 

Surfactant. Paper SPE 121716 presented at the 2009 

SPE International Symposium on Oilfield Chemistry, The 

Woodlands, Texas, 20-22 April. 

Contacts 

Hisham A. Nasr-El-Din 

979.862.1473 

hisham.nasreldin@pe.tamu.edu 

Lingling Li 

-1 

Shear Rate = 10 s 

P = 300 psi 

0 

50 70 90 110 130 150 170 190 210 230 

Temperature (°F) 

only CI-A 

0.1 wt% FeCl3 

0.5 wt% H2S scavenger 

0.5 wt% demulsifier 

Fig. 2. Effect of some acid additives on the apparent viscosity of spent 

acids (pH = 4 ~ 5). All solutions contained CI-A. 



63

that contained 12 wt% HCl showed the highest 

apparent viscosity. Low concentrations of Fe (III) 

caused an increase in the apparent viscosity. Two 

immiscible liquids and then a precipitate were noted 

as the concentration of ferric ion was increased in 

live acids. Iron control agents reduced the apparent 

viscosity of surfactant-based acids. The impact of 

lactic acid on the apparent viscosity was significant, 

especially at high lactic acid concentrations. Citric 

acid also reduced the viscosity of surfactant based 

acids, but cannot be used at concentrations greater 

than 0.5 wt% because of this precipitation of 

calcium citrate. Ethylenediaminetetraacetic acid 

(EDTA) slightly reduced the viscosity of surfactant 

based acids, but the solubility of EDTA in 20 wt% 

HCl is very low. Up to 1 wt% methanol can be used 

with this spent acid system at temperatures below 

175°F. Higher concentrations of methanol caused 

significant reduction in the apparent viscosity. 

Future Work 

Simple organic acids and iron control agents 

(α-hydroxyl carboxylic acids) can interfere with 

micelle shape and reduce the apparent viscosity 

of VES-based acids, therefore their influences will 

be tested in the future. A transmission electron 

microscope (TEM) will also be used to examine the 

effects of acids on micelle shapes. 

64 


Acid Hydrolysis of Carboxybetaine Viscoelastic Surfactant 

Objectives 

Viscoelastic surfactants (VES) are recognized by 

their unique ability to form gel in-situ, and thus 

have been widely applied in acid diverting and 

fracturing treatments. Several types of VES have 

been used, including carboxybetaine surfactants. 

However, when mixed with hydrochloric acid under 

high temperatures, this particular type of VES is 

subjected to acid hydrolysis and may lose its viscoelastic 

property. 

The objective of this study is to examine the impact 

of acid hydrolysis of carboxybetaine surfactants on 

their performance in various field applications. 

Approach 

Hydrolysis experiments were conducted on HCl 

solutions that contained 7 wt% VES at various 

temperatures, acid concentrations and time. These 

fluids were heated to the temperature of interest, 

held for different periods of time, cooled to room 

temperature, neutralized by CaCO 3 

and their 

viscosity was measured as a function of shear rate 

using a Grace Instrument M3600 viscometer. 


It was found that these VES fluids lost viscosity 

significantly after hydrolysis, and the viscosity of the 

hydrolyzed sample was influenced by temperature, 

acid concentration, and time. Moreover, an oily 

phase was separated from the aqueous phase in the 

hydrolyzed samples. 

Significance 

The observations from the experiments indicated 

that when carboxybetaine VES is mixed with HCl at 

high temperature, it may lose its ability to increase 

fluid viscosity; and further more, the two phase 

mixture after hydrolysis may cause formation 

damage. Current research work will be conducted 

to investigate what factors affect acid hydrolysis of 

carboxybetaine surfactants, and how they affect it. 

At the end of this research, recommendations will be 

given on how to use these surfactants in the field. 



2.5.16 Quantitative Analysis of Amphoteric Surfactant 


Yu, M. and Nasr-El-Din, H. Quantitative Analysis of an 

Amphoteric Surfactant in Acidizing Fluids and Coreflood 

Effluent. Paper SPE 121715 presented at the 2009 SPE 

Symposium on Oilfield Chemistry, Woodlands, Texas, 20- 

22 April. 

Contacts 

Hisham Nasr-El-Din 

979.862.1473 


Meng Yu 


65

Evaluation of Polymer-Based In-Situ Gelled Acids during Well Stimulation 

Introduction 

An in-situ gelled system based on a polymer that is 

stable in an aqueous acid environment can be crosslinked 

in the presence of ferric ions or zirconium ions 

at a pH of about 2 or greater. The polymer should 

contain carboxyl groups; such polymers include 

acrylamide and acrylamide copolymers. Initial 

spending of the live acid, during leak-off and wormholing, 

produces a rise in pH to a value of above, 

or about, 2, which initiates cross-linking of the 

polymer (resulting in a rapid increase in viscosity). 

This increase in viscosity creates the diversion 

from wormholes, from fissures, and from within 

the matrix. As the acid spends further and the pH 

continues to rise, the reducing agent converts the 

ferric ions to ferrous ions. The gel structure will 

collapse and the acid system reverts back to a low 

viscosity fluid. 

Approach 

Three commercial acid systems from three different 

companies were evaluated under normal and 

severe contamination of iron and salt. Experimental 

studies were conducted to measure the rheological 

properties for in-situ gelled acid using an oscillation 

rheometer and a rotational viscometer. To the best of 

our knowledge, this is the first time that the elastic 

properties were measured for these acids. Finally, 

a coreflood study was conducted using Indiana 

limestone cores (1.5 in diameter, 20 in long) at 

250°F. Propagation of the acid, polymer, and crosslinker 

inside the long cores was examined for the 

first time in detail. 

Objectives 

In-situ gelled acids that are based on polymers have 

been used in the field for several years, and were the 

subject of many lab studies. There are conflicting 

opinions about using these acids. These acids were 

used in the field, with mixed results, yet recent lab 

work indicated that these acids can cause damage 

under certain conditions. There is no agreement 

on when this system can be successfully applied in 

the field, therefore the objective of this research is 

to recommend the best conditions where polymerbased 

acids can be used. 

Normalized Pressure Drop 

12 

10 

8 

6 

4 

2 

0 

Shear Rate, s -1 

743 

1288 

1780 

2161 

0 1 2 3 4 5 6 

Cumulative Injected Volume, PV 

Normalized Pressure Drop for the four experiments conducted at different 

shear rate, T = 250°F. 



2.5.17 Viscosity of Polymer-Based In-Situ Gelled Acids 

during Well Stimulation 


Gomaa, A.M., and Nasr-El-Din, H.A. Rheological Properties 

of Polymer-Based In-Situ Gelled Acids: Experimental and 

Theoretical Studies. Paper SPE 128057, presented at the 

2010 Oil and Gas India Conference and Exhibition, Mumbai, 

India, 20–22 January. 

Gomaa, A.M., Mahmoud, M., and Nasr-El-Din, H.A. When 

Polymer-based Acids can be used? A Core Flood Study. 

Paper TPTC 13739, presented at the 2009 SPE International 

Petroleum Technology Conference, Doha, Qatar, 7–9 

December. 

Gomaa, A.M., Nasr-El-Din, H.A. Viscosity of Polymer- 

Based In-Situ Gelled Acids during Well Stimulation. Paper 

SPE 121728, presented at the 2009 SPE International 

Symposium on Oilfield Chemistry held in The Woodlands, 

Texas, 20–22 April. 

Contacts 

Hisham A. Nasr-El-Din 

979.862.1473 


Ahmed Gomaa 

66 


Determination of CT number for gel residue. 

Future Work 

A parallel coreflood study will be conducted using 

multistage acid injection. Propagation of each acid 

stage, polymer, and cross-linker inside the long 

cores will be examined in detail. Also, reaction 

rate measurement for the in-situ gelled acid using 

a rotating disk apparatus will be conducted under 

different conditions. 


67

Modeling of Discrete Fracture Network using Voronoi Grid System 

Objectives 

Dual-porosity (DP) is the most common model to 

simulate fluid flow through fractured media. This 

model comprises several limitations (i.e., it is not 

well suited to accurately model fracture networks 

with multiple orientations). On the other hand, a 

single-porosity model with conventional gridding 

techniques requires an excessive number of grids to 

model fractures explicitly. 

The objectives of this work are to develop a 

reservoir simulator (DFNSIM) along with a novel 

gridding technique based on Voronoi algorithm to 

allow fracture networks represented explicitly into 

reservoir model. 

Approach 

It requires two different domains to represent 

fractures explicitly in a simulation model: geometrical 

and computational (Fig. 1). In the geometrical 

domain, the fracture is represented as a line. The 

volume and permeability of each fracture segment 

are calculated based on a given fracture aperture 

distribution (i.e. log-normal distribution from X-Ray 

CT Scan) in the computational domain. 

(a) Geometrical domain 

(b) Computational domain 

(a) Unfractured 

(b) Fractured 

Fig. 2. Grid generation for unfractured and fractured systems. 

by Chong et al. However, the governing equation of 

the simulator was similar to DFNSIM (CVFD). 

Prior to using DFNSIM in modeling reservoirs with 

fractures including their apertures distribution, 

the simulator was validated against commercial 

simulators. The simulator provides results in close 

agreement with those of reference finite-difference 

simulators (SPE-1 comparative solutions; after Aziz 

& Odeh, SPEJ, 1981). 



3.1.19 Modeling of Discrete Fracture Network using Voronoi 

Grid System 


Chong, E., Syihab, Z., Putra, E., Hidayati, D.T., Schechter, 

D. A New Grid Block System for Reducing Grid Orientation 

Effect, Journal of Petroleum Science and Technology. 

(November 2007) London, UK. 

Fig. 1. Fracture representation (geometrical and computational domains). 


Two major accomplishments were achieved from 

this work: (1) fracture network gridding and (2) 

development of a control volume finite-difference 

numerical simulatior (CVFD), which can be used for 

both fractured and unfractured systems (Fig. 2). 

The unstructured grid (without fracture) was initially 

tested to reduce the grid orientation effect. The 

grid model was constructed by a combination of 

rectangular, hexagonal, and triangle shapes. The 

test was run using a separate simulator developed 

Tae, H. K. and Schechter, D.S. Estimation of Fracture 

Porosity of Naturally Fractured Reservoirs with No Matrix 

Porosity Using Fractal Discrete Fracture Networks. Paper 

SPE presented at the 2007 SPE Annual Technical Conference 

and Exhibition, Anaheim, California, 11–14 November. 

Syihab, Zuher.: 2009. Simulation of Discrete Fracture 

Network Using Flexible Voronoi Gridding. PhD dissertation. 


Contacts 

David Schechter 

979.845.2275 

david.schechter@pe.tamu.edu 

Zuher Syihab 

68 


After successful validation, a fractal discrete fracture 

network (FDFN) model was generated based on a 

real outcrop data from Bridger Gap, Wyoming (Fig. 

3). The model was compared with a system with no 

fractures to observe the impact of the fractures on 

sweep efficiency (Fig. 4). 

The grid model of the fracture network is depicted in 

Fig. 2b and Fig. 3c. 

(a) Rose Diagram of FDFN 

120 

90 

6 

60 

4 

150 

2 

30 

180 0 

(b) Fracture network map 

(c) Grid system 

210 

330 

240 

270 

300 

Oil producer 

Fig. 3. (a) Rose diagram, (b) fracture network map, and (c) grid system 

of an outcrop at Bridger Gap, Wyoming. 

(a) Connected fractures 

(b) No fracture 

Fig. 4. Gas saturation at 730 days (fractured and unfractured systems). 

Significance 

A numerical simulator was developed in this work 

that allows direct input and simulation of discrete 

fracture networks. This work solved the problem 

of how to grid fracture intersections. We now have 

the capability of modeling connected fracture 

networks thus bypassing conventional dual porosity 

simulation. 


69

Thermo-Poroelastic Finite Element Analysis of Rock Deformation and Damage 

Introduction 

Stress change and permeability variations caused 

by rock failure play an important role in geothermal 

reservoir development, particularly in understanding 

stimulation outcomes and induced seismicity. 

Cold water injection causes significant change in 

temperature, pore pressure, and thus the stresses 

near the wellbore and in the reservoir which, in turn 

influence rock permeability. 

Permeability (md) 

22 

20 

18 

16 

14 

12 

10 

8 

6 

1 sec 

10 sec 

30 sec 

Objectives 

In this work, we present the development of a fullycoupled 

thermo-poro-mechanical finite element 

model with damage mechanics and stress dependent 

permeability for simulating rock response to cold 

water injection. 

4 

2 

0 

1 

2 

3 

r/a 

Permeability distributions around the wellbore. 

14 

4 

5 

Stress (MPa) 

140 

120 

100 

80 

60 

1.0 

0.8 

0.6 

0.4 

Damage 

Pore Pressure (MPa) 

12 

10 

8 

6 

4 

1 sec 

30 sec 

ref-1 sec 

ref-30 sec 

40 

0.2 

Stress 

20 

Damage 

0 

0.005 0.010 0.015 0.020 0.025 0.030 

r/a 

Finite element simulations of a triaxial test. Green line: brittle behavior 

of strain-stress relationships; red line: damage evolution when stresses 

satisfy the failure criterion. 

Approach 

Both conductive and convective heat transport are 

considered in the thermo-poroelastic formulation. 

The model is used to perform a series of numerical 

experiments to study the influence of cold water 

injection on rock damage and permeability 

enhancement. The rock damage is reflected in the 

alteration of its elastic modulus and permeability. 


The results show that damage propagation is 

accompanied by a relaxation of the effective stress 

in the damage zone and its concentration in the 

intact rock near the interface with the damage zone. 

2 

0 

1 

2 

Pore pressure distributions around the wellbore. Solid lines represent 

pore pressure distributions for damage; Dashed lines give the results for 

the reference case with no damage. 

Significance 

The model provides a tool for the analysis of stress 

induced micro-seismicity and fracture propagation 

in geothermal and petroleum reservoirs. 



3.1.21 Reservoir Geomechanics: Thermo-Poroelastic 

Analysis of Rock Deformation and Damage 

Contacts 


979.845.2206 


3 

r/a 

4 

5 

Sang Hoon Lee 

70 


Application of Adaptive Gridding and Upscaling for Improved Tight Gas Reservoir 

Simulation 

Objectives 

The objective of this research is to improve the 

flow simulation of tight gas reservoirs through the 

application of unstructured upscaling of detailed 3D 

geo-cellular models. The techniques are designed 

to preserve the high resolution well productivity 

and connectivity of the reservoir description while 

at the same time reducing the cost of the reservoir 

simulation computation. 


We have completed the conversion of the tight gas 

Eclipse field model (made available to us through 

an MCERI project) to the VIP and Nexus simulators. 

We have provided our own high resolution 

transmissibility upscaling algorithms for simple grid 

coarsening geometries as a pre-requisite to more 

difficult upscaling problems. We have also compared 

our transmissibility upscaling algorithms with the 

VIP and Nexus simulators’ cell property-based 

upscaling, to determine under what circumstances 

the high resolution algorithms provide better flow 

characterization. 

Detailed View of the High Resolution 375 Layer 3D Geologic Model, giving 

a better perspective of the variation of sand thickness associated with the 

individual simulation layers. 

Future Work 

We will work on the understanding of VIP/Nexus’s 

underlying theory for the upscaling, and replace 

its upscaled properties (transmissibility and well 

index) with our own upscaled properties to get more 

accurate results. 

Medium Resolution 75 Layer 3D Geologic Model of the 10 x 10 x 375 test 

volume of a Tight Gas Reservoir. This model was developed using the VIP 

simulator’s built-in grid and property coarsening algorithms, here for 1 x 

1 x 5 coarsening. Our research project will provide improved coarsened 

representations of the fine scale reservoir model that better preserve the 

reservoir connectivity and properties. 


High Resolution 375 Layer 3D Geologic Model of a 10 x 10 test area of a 

Tight Gas Reservoir. This model shows the intermittent connectivity associated 

with the fluvial nature of these reservoirs. 


3.1.22 Application of Adaptive Gridding and Upscaling for 

Improved Tight Gas Reservoir Simulation 

Contacts 

Michael King 

979.845.1488 

mike.king@pe.tamu.edu 

Yijie Zhou 


71

Measurement and Correlation of Gas Viscosities at High Pressures and High 

Temperatures 

Introduction 

High-pressure and high-temperature (HPHT) gas 

reservoirs are defined as having pressures greater 

than 10,000 psia and temperatures over 300°F. 

Modeling the performance of these reservoirs 

requires the understanding of gas behavior at 

elevated pressure and temperature. An important 

fluid property is gas viscosity, as it is used to model 

the gas mobility in the reservoir and can have a 

significant impact on reserves estimation during field 

development planning. Accurate measurements of 

gas viscosity at HPHT conditions are both extremely 

difficult and expensive, thus this fluid property is 

typically estimated from published correlations 

based on laboratory data. Unfortunately, the 

correlations available today do not have a sufficiently 

broad range of applicability in terms of pressure and 

temperature, so their accuracy may be doubtful for 

the prediction of gas viscosity at HPHT conditions. 

Objectives 

This project will review the databases of hydrocarbon 

gas viscosity that are available in the public domain, 

and discuss the validity of published gas viscosity 

correlations based on their applicability range. 

Approach 

A falling body viscometer was used to measure the 

HPHT gas viscosity in the laboratory. This system is 

very common for the measurement of liquid viscosity 

and, in some specific circumstances (lubrication or 

small percentage of liquid phase), can also measure 

low viscosities. The decision to use such a viscometer 

was based on the consideration that it is the only 

device built to withstand extreme high pressure at 

an acceptable cost. The instrument was calibrated 

with nitrogen and then, to represent reservoir gas 

behavior more faithfully, pure methane was used. 

The subsequently measured data, recorded over a 

wide range of pressure and temperature, was then 

used to evaluate the reliability of the most commonly 

used correlations in the petroleum industry. The 

results of the comparison suggest that at pressures 

higher than 8000 psia, the laboratory measurements 

drift from the National Institute of Standards and 

Technology (NIST) values by up to 7.48%. 

Finally, a sensitivity analysis was performed to 

assess the effect of gas viscosity estimation errors 

on the overall gas recovery from a synthetic HPHT 

reservoir, using numerical reservoir simulations. The 

result shows that a -10% error in gas viscosity can 

produce an 8.22% error in estimated cumulative 

gas production, and a +10% error in gas viscosity 

can lead to a 5.5% error in cumulative production. 

Significance 

The preliminary results indicate that the accuracy 

of gas viscosity estimation can have a significant 

impact on reserves evaluation. 

Future Work 

This project has led to the following conclusions: 

» Accurate measurements of natural gas viscosity 

under HPHT conditions are yet to be obtained, 

» Gas viscosity correlations derived from data 

obtained at low to moderate pressures and 

temperatures cannot be confidently extrapolated 

to HPHT conditions, 

» Gas viscosity correlations currently available to 

the petroleum industry were derived from data 

obtained with limited impurities, and so their 

accuracy for use with gases containing large 

quantities of impurities is unknown, 

» Laboratory investigations performed using 

nitrogen showed a consistently negative error 

when compared to the NIST reported values. 

Preliminary results stress the importance of 

obtaining an exhaustive range of measurements of 

the viscosity of natural gases under HPHT conditions 

in order to ensure better reserves estimations. To 

this aim, further tests are ongoing. 


3.2.4 Measurement and Correlation of Gas Viscosities at 

High Pressures and High Temperatures 

Contacts 

Gioia Falcone 

979.847.8912 




Ehsan Davani 


72 


Measurement of Gas Viscosity at High Pressures and High Temperatures 

Introduction 

Gas viscosity is an important fluid property in 

petroleum engineering due to its impact in oil 

and gas production and transportation where it 

contributes to the resistance to the flow of a fluid 

both in porous media and pipes. Although this 

property has been studied thoroughly at low to 

intermediate pressures and temperatures, there is a 

lack of detailed knowledge of gas viscosity behavior 

at high pressures and high temperatures (HPHT) in 

the oil and gas industry. 

The need to understand and be able to predict 

gas viscosity at HPHT has become increasingly 

important as exploration and production has moved 

to ever deeper formations where HPHT conditions 

are more likely to be encountered. Knowledge of 

gas viscosity is required for fundamental petroleum 

engineering calculations that allow one to optimize 

the overall management of an HPHT gas field and 

to better estimate reserves. Existing gas viscosity 

correlations are derived using measured data at low 

to moderate pressures and temperatures, i.e. less 

than 10,000 psia and 300°F, and then extrapolated 

to HPHT conditions. No measured gas viscosities at 

HPHT are currently available, and so the validity of 

this extrapolation approach is doubtful due to the 

lack of experimental calibration. 

Objectives 

The National Institute of Standards and Technology 

(NIST) has developed a computer program that 

predicts thermodynamic and transport properties 

of hydrocarbon fluids, which allows comparison 

of its values with those from correlations and 

gives an insight into the current understanding of 

gas viscosity correlations. Note that Viswanathan 

modified the Lee, Gonzalez, and Eakin correlation 

by using NIST values. The above review of existing 

gas viscosity correlations reveals that there are 

no measurements available at HPHT conditions. 

Correlations derived from data at low to moderate 

pressures and temperatures should not be simply 

extrapolated to HPHT conditions without validation 

against experimental measurements. 

Our objectives are to measure the viscosity of four 

naturally occurring hydrocarbon gases at various 

pressures and temperatures, with emphasis on high 

pressures and temperatures; use the measured 

viscosities to check and extend an existing correlation 

proposed by Lee et al.; use gas compressibility 

factors to check and extend the gas compressibility 

correlation equation proposed by Piper et al.; and 

develop a new correlation to predict viscosity as a 

function of composition, pressure, and temperature. 

Approach 

Our facility consists of a gas source, a gas booster 

system, a measuring system, and a data acquisition 

system. The measuring system is the Cambridge 

SPL440 High Pressure Research Viscosity Sensor 

that is tailored to measure gas viscosities at 

HPHT conditions. This technology is based on an 

electromagnetic concept, with two coils moving a 

piston back and forth magnetically at a constant 

force. The piston’s two-way travel time is then 

related to the fluid’s viscosity by a proprietary 

equation. The viscosity range for the system is 0.02 

to 0.2 cp, with a reported accuracy of 1% of full 

scale. The maximum operating pressure is 25,000 

psig. The Cambridge ViscoLab PVT software was 

used to record the measurements. 



3.2.4 Measurement and Correlation of Gas Viscosities at 

High Pressures and High Temperatures 

Contacts 

Gioia Falcone 

979.847.8912 




Kegang Ling 



73

The falling body viscometer is selected to measure gas 

viscosity for a pressure range of 3,000 to 24,500 psia 

and temperature range of 100 to 415°F. Nitrogen was 

used to calibrate the instrument and to account for 

the fact that the concentrations of non-hydrocarbons 

are observed to increase dramatically in HPHT 

reservoirs. Then methane viscosity is measured to 

reflect the fact that, at HPHT conditions, the reservoir 

fluids will be very lean gases, typically methane with 

some degree of impurity. The experiments showed 

that while the correlation of Lee et al. accurately 

estimates gas viscosity at low to moderate pressure 

and temperature, it does not provide a good match 

to gas viscosity at HPHT conditions. 

higher than the values provided by the NIST and 

by previous investigators. The difference increases 

as temperature decreases, and it increases as 

pressure increases. These preliminary results stress 

the importance of obtaining an exhaustive range 

of measurements of the viscosity of natural gases 

under HPHT conditions in order to ensure better 

reserves estimation. To this aim, further tests are 

ongoing at Texas A&M University. 


Comparing our result with NIST values and data at 

low to moderate pressure and temperature from 

previous investigators showed that: 

» Nitrogen viscosity—The lab data matched the 

NIST values as well as those reported by other 

investigators at low to moderate pressures, while 

they are lower at high pressure. The difference 

between measured data and NIST values increases 

as temperature decreases; this difference also 

increases as pressure increases. 

» Methane viscosity—New lab data matched the 

NIST values at low to moderate pressure, but the 

new experimental viscosities are higher at high 

pressure. The mismatch decreases as temperature 

increases, and increases as pressure increases. 

Significance 

Gas viscosity correlations derived from data obtained 

at low to moderate pressures and temperatures cannot 

be confidently extrapolated to HPHT conditions. The 

gas viscosity correlations that are currently available 

to the petroleum industry were derived from data 

obtained with gases with limited impurities, and so 

their accuracy for use with gases containing large 

quantities of impurities is unknown. 

The laboratory investigations performed at TAMU 

show that, at high pressure, the experimental 

nitrogen viscosities are lower than the values 

provided by the NIST and by previous investigators. 

The observed mismatch increases as temperature 

decreases, and it increases as pressure increases. 

For methane, the TAMU investigations show that, 

at high pressure, the experimental viscosities are 

74 


Numerical Modeling of Fracture Permeability Change in Naturally Fractured 

Reservoirs using a Fully Coupled Displacement Discontinuity Method 

Introduction 

Pressure depletion in a naturally fractured reservoir 

can result in effective stress change that, in turn, 

can affect fracture aperture and the reservoir 

permeability. The dependence of fracture aperture and 

reservoir permeability on stress must be considered 

in modeling a naturally fractured reservoir. The 

dependence involves coupled interactions among 

fluid, porous matrix, and fracture. The previous 

methods on the dependence of fracture permeability 

on the pressure depletion did not consider the fully 

coupled interactions of fluid, porous matrix, and 

fracture or the real deformation mechanism of 

fracture. 

Approach 

We developed a new approach to solve the fluid 

pressure, stress change, and fracture aperture 

change in fractures simultaneously. We did this 

by combining a finite difference method (FDM) to 

solve the fluid diffusion in fractures a fully coupled 

displacement discontinuity method (DDM) to 

build the global relation of fracture deformation, 

and a nonlinear Barton-Bandis model of fracture 

deformation to build the local relation of fracture 

deformation. The fully coupled DDM is based on 

Biot’s theory of poroelasticity which is a linear 

elastic theory to account for the coupled interactions 

between porous matrix and fluid in a porous medium 

saturated with a compressible fluid. The analytical 

solution of induced stress and pore pressure by the 

deformation of a finite thin fracture in an infinite 

elastic porous medium is provided. The influences 

of deformation of complicated fracture network are 

obtained by the superposition of the fundamental 

analytical solution. The stress acting on the fracture 

surface and the deformation of the fracture also must 

comply with the fracture deformation model (e.g. 

Barton-Bandis model). The fluid flow in the fracture 

network is solved by an FDM. The interface flow 

rate between the fracture and matrix is implicitly 

included in the fully coupled DDM. As a result, the 

approach is able to model the fracture deformation 

due to reservior pressure change in naturally 

fractured reservoirs by considering the fully coupled 

interactions of fluid, porous matrix, and fractures. 

Application 

This method has been applied to model the fracture 

permeability change for a two-dimensional regular 

Fig. 1. Pore pressure (psi) distribution after 360 days production. 

fractured network (Fig. 1) in a compressible 

single-phase fluid-saturated porous medium. Under 

isotropic in-situ stress conditions, the fracture 

permeability decreases with the pressure reduction 

during production (Fig. 2). But at high anisotropic 

stress conditions, the fracture permeability could 

be enhanced by production due to shear dilation 

(Fig. 3). 



3.2.10 Well Test Models for Caves in a Karstic Carbonate 

Reservoir 

Contacts 


979.458.0797 


Qingfeng Tao 



75

Fracture permeability (md) 

12 

10 

8 

6 

4 

2 

0 

Fracture intersected 

by the Well 

Fracture at the Boundary 

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 

Time (hr) 

Fig. 2. Fracture permeability declines with time. 

Fig. 3. Distribution of fracture permeability and shear displacement 

(shown with arrows) after 360 days production for the case fractures are 

already yielded before production. 

76 


Improved Permeability Predictions using Multivariate Analysis Methods 

Introduction 

Predicting rock permeability from well logs 

in uncored wells is an important task in 

reservoir characterization. Due to the high 

costs of coring and laboratory analysis, 

typically cores are acquired in only a few 

wells. Since most wells are logged, the 

common practice is to estimate permeability 

from logs using correlation equations 

developed from limited core data. Most 

commonly, permeability is estimated from 

various well logs using statistical regression. 

For sandstone reservoirs, the logarithm of 

permeability can be correlated with porosity, 

but in carbonate reservoirs the porositypermeability 

relationship tends to be much 

more complex and erratic. 

Objectives 

In order to improve the permeability estimation in 

complex carbonate reservoirs, several statistical 

regression techniques have been tested in previous 

work to correlate permeability with different well 

logs (Lee, Arun and Datta-Gupta, 2002; Mathisen, 

Lee, and Datta-Gupta, 2003). It has been shown 

that statistical regression for data correlation is quite 

promising, but using all the possible well logs to 

predict permeability may not be appropriate because 

the possibility of spurious correlation increases as 

more well logs are used. Therefore, the objective 

of this study is to further improve permeability 

prediction by selecting appropriate well logs for data 

correlation via variable selection procedures. 

Approach 

In statistics, variable selection is used to remove 

unnecessary independent variables and give a more 

robust prediction. We will apply variable selection 

methods to the permeability prediction procedure 

to improve permeability estimation. Specifically, 

we have proposed a new method combining the 

stepwise regression with Alternating Conditional 

Expectation (ACE) techniques and will compare the 

proposed method with two other methods: the tree 

regression and the Multivariate Adaptive Regression 

Splines (MARS) method. 


Three methods are tested and compared using data 

from a complex carbonate reservoir in west Texas: 

Predicted vs. Measured 

MSE=1.9728 MAE=1.0682 =0.68227 

10 -2 10 -1 10 0 10 1 10 2 10 3 

Measured permeability 

the Salt Creek Field Unit (SCFU). The results of 

SCFU show that the stepwise regression with the 

ACE method outperforms the other two methods in 

permeability prediction. The figure shows the result 

of the stepwise regression with the ACE method vs. 

true permeability for a blind test data set. 


3.2.13 Improved Permeability Predictions using Multivariate 

Analysis Methods 


Lee, S. H. and Datta-Gupta, A. 2002. Electrofacies 

Characterization and Permeability Predictions in Carbonate 

Reservoirs: Role of Multivariate Analysis and Non-parametric 

Regression. SPE Reservoir Evaluation and Engineering 5 

(3): 237-248. DOI 10.2118/78662-PA. 

Mathisen, T., Lee S. H., and Datta-Gupta, A. 2003. 

Improved Permeability Estimates in Carbonate Reservoirs 

Using Electrofacies Characterization: A Case Study of the 

North Robertson Unit, West Texas SPE Reservoir Evaluation 

and Engineering 6 (3): 176-184. 

Contacts 

Akhil Datta-Gupta 

979.847.9030 

a.datta-gupta@pe.tamu.edu 

Jiang Xie 

Depth 

6220 

6240 

6260 

6280 

6300 

6320 

6340 

6360 

6380 

6400 

6420 

Measured 

permeability 

Permeability vs. Depth 


Predicted 

permeability 

Permeability Predictions from Well logs Using Stepwise Regression with ACE (Alternating 

Conditional Expectations) for the Salt Creek Field Unit, West Texas. 


77

CO 2 

Mobility Control using Cross-Linked Gel and CO 2 

Viscosifiers 

Objectives 

1. Investigate and test different approaches in the 

laboratory to control CO 2 

mobility during CO 2 

flooding to increase the overall efficiency. 

2. Develop a simulation model which would 

incorporate the CO 2 

viscosity relationship 

with pressure, then use this model to predict 

viscosified CO 2 

flooding efficiency in comparison 

with pure CO 2 

flooding. 


The visualization of CO 2 

flow within core using CT- 

Scanning provides us with a more direct observation 

for the CO 2 

flood fronts in the core. We have studied 

two approaches to control CO 2 

mobility: HPAM/ 

Cr(III) gel conformance control treatment, and the 

direct increase of CO 2 

viscosity using viscosifier 

chemicals (PVAc or Polysiloxanes). 

For the study of gel conformance control, crosslinked 

HPAM/Cr(III) gel was applied to fractured cores 

in order to get incremental oil recovery. We have 

tested 10,000 ppm of high concentration gel and 

found out it had a better stability when compared 

with the 3,000 ppm gel we used previously. The 

10,000 ppm gel appeared to be more stable and 

also gave a higher pressure drop in CO 2 

flooding, 

which means better mobility control. 

For the study of CO 2 

viscosifiers, a controlled CO 2 

flooding experiment using pure CO 2 

was conducted 

and the expected low recovery was obtained due to 

rapid breakthrough of CO 2 

through the fracture. The 

first low molecular weight viscosifier was studied 

and we observed significant differences in CO 2 

flood 

front images. A more uniform, piston-like CO 2 

flood 

front was formed in the viscosifier case, suggesting 

a reduction in CO 2 

viscosity. Higher oil recovery was 

also observed using viscosified CO 2 

. 

A black-oil pseudo-miscible model for an oil field in 

Peru was developed using data from one of the wells. 

To account for the increase in CO 2 

viscosity, new 

viscosity/pressure relationships were integrated into 

the simulation model. We are currently simulating 

viscosified cases to develop cost benefit relations. 

Future Work 

More viscosifier chemical structures will be studied 

to compare the efficiency differences between low 

78 

and high molecular weight viscosifiers. The injection 

scheme will be altered to reflect field sequence of 

events: we will begin with pure CO 2 

until no more 

oil is recovered, and then we will begin injecting 

viscosified CO 2 

to determine the incremental 

recovery caused by viscosified CO 2 

after pure CO 2 

injection. We will also develop simulation tools 

capable of accounting for viscosified CO 2 

cases. 

End of Coreflood for 3000 ppm gel: 

End of Coreflood for 10,000 ppm gel: 

Gel Strength Study - (red/yellow color shows gel distribution after CO 2 

flooding, blue color is the sandstone matrix. The sandstone core is fractured 

both horizontally and vertically. CO 2 

injection from right to left.) 

Pure CO 2 


injected) 

Viscosified CO 2 


injected) 

Comparison of pure CO 2 

flood front and viscosified CO 2 

flood front. The 

pure CO 2 

flood case has most of the CO2 concentrated in the fracture 

region. A more stable piston-like displacement is observed in the viscosified 

CO 2 

case. 


3.4.4 Application of X-Ray CT for Investigating Fluid Flow 

and Conformance Control during CO 2 

Injection in Highly 

Heterogenous Systems 

Contacts 

David Schechter 

979.845.2275 

david.schechter@pe.tamu.edu 

Shuzong Cai 



Stochastic History Matching, Forecasting, and Production with the Ensemble 

Kalman Filter 

Introduction 

The data assimilation process of adjusting variables 

in a reservoir simulation model to honor observations 

of field data is known as ‘history matching’ and 

has been extensively studied for few decades. 

However, despite the progress that has been made, 

development of more accurate and efficient history 

matching techniques that produce geologically 

realistic outcomes (reservoir models) is still one 

of the main challenges for reservoir engineers, 

mainly due to the high complexity of the problem, 

data scarcity, and computational demand for field 

applications. Because of the insufficient information 

about reservoir spatial property distribution, 

history matching of heterogeneous reservoirs is 

an inherently ill-posed inverse problem; that is, 

it is possible to obtain several reservoir models 

that honor observed measurements but have 

geologically distinct features and provide incorrect 

predictions. Two common approaches to deal with 

ill-posed history matching problems are either to 

constrain the structural form of acceptable solutions 

(regularization) or to reduce the number of unknown 

parameters (reparameterization). While these 

methods have been successfully used as effective 

strategies to improve the solution of ill-posed inverse 

problems, they may not provide accurate solutions 

where a simple structural assumption can be defined 

for features with more complex geometry. 

for incorporating dynamic flow measurements into 

multipoint pattern simulation with the Single Normal 

Equation SIMulation (SNESIM) algorithm. 


The generated probability map represents the main 

information in the nonlinear dynamic measurements 

and can be easily integrated into the SNESIM 

algorithm to simulate an updated ensemble of 

conditional facies (Fig. 1b). We have illustrated 

the effectiveness of this approach through several 

experiments. The results of development have been 

summarized into a manuscript that is currently 

being reviewed in the Computational Geosciences 

Journal. Figure 1 shows a simple example from the 

manuscript that is undergoing review. 

Future Work 

We are currently working to advance the 

implementation of our approach to deal with 

uncertainty in the training image that is used for 

pattern simulation and to address some of the 

limitations of the EnKF-based implementation of our 

algorithm. 


Objectives 

The ensemble Kalman filter (EnKF) has recently 

been introduced to reservoir engineering literature 

as a promising history matching technique. It is easy 

to implement, provides considerable flexibility for 

describing reservoir model uncertainty, and supplies 

valuable information about reservoir performance 

prediction uncertainty. Among the limitations of the 

EnKF is its covariance-based (second order) model 

updating scheme that restricts its application to 

estimate discrete geological objects that are not 

amenable to covariance-based descriptions. When 

the standard EnKF implementation is used to update 

facies permeability values in each grid block (Fig. 

1a), the connectivity between the existing features 

is not preserved even when facies description is 

parameterized to encourage continuity. 

In this project, by using the EnKF to generate a 

probability map to describe the spatial distribution of 

facies, we are developing a more consistent approach 




3.6.6 Stochastic History Matching, Forecasting, and 

Production with the Ensemble Kalman Filter 

Contacts 

Behnam Jafarpour 

979.845.0666 

behnam.jafarpour@pe.tamu.edu 

Morteza Khodabakhshi 

79

(a) Standard EnKF for permeability estimation 

True Perm. 

(b) Prob. Map estimation with EnKF 

initial 

3 months 

6 months 

18 months 

36 months 

initial 

3 months 

6 months 

18 months 

36 months 

ens. mean 

ens. mean 

sample 5 

prob. map 

sample 5 

sample 4 

sample 4 

sample 3 

sample 3 

sample 2 

sample 2 

sample 1 

sample 1 

Fig. 1. Facies estimation from production data using the standard EnKF implementation (a), and application of EnKF 

to update the probability map of facies distribution (b). In (a), the First to Fifth rows show the evolution of sample 

permeability fields in time (after update steps) with the mean of 300 samples shown in the Sixth row. In (b), the 

update to the probability map is shown in the First row while the resulting permeability facies from the SNESIM algorithm 

are shown in the Second to Sixth rows. The last row contains the mean of the 300 sample permeabilities. 

80 


Sustainable Carbon Sequestration 

Introduction 

Concerns that CO 2 

emissions from the combustion 

of fossil fuel are causing global climate change have 

led to research that focuses on various ways in 

which CO 2 

can be captured, sequestered and stored 

permanently in deep saline aquifers. The majority 

of CO 2 

produced in the US comes from coal-fired 

power plants which account for about 50% of the 

electricity generation. At the rate in which CO 2 

is 

produced from a typical power plant, it will require 

multiple injection wells, and each well will have a 

finite injection well area. 

Objectives 

Bulk CO 2 

injection in a finite volume increases the 

pressure of the aquifer. To avoid breeching the 

aquifer seal, the injection well pressure must not 

exceed the formation fracture pressure. The result 

is a need for many wells and a prohibitively large 

aquifer area. Alternatively, it may be possible to 

avoid pressurizing the aquifer area and increase CO 2 

storage efficiency by producing the same volume 

of brine as is injected as CO 2 

. This transforms the 

problem from CO 2 

storage to water handling. 

brine displacement with and without saturated brine 

injection. Finally, insights gained from the conceptual 

modeling phase will be used to develop optimization 

methods for improving CO 2 

sweep efficiency. 

Significance 

The significance of this approach lies in its potential 

advantages over processes currently envisioned. 

Aquifer pressurization that may lead to breaching 

the integrity of the reservoir seal is avoided, and the 

CO 2 

storage efficiency is increased compared to bulk 

CO 2 

injection. 

V z 

This study will investigate options for CO 2 

storage 

management, including evaluating the feasibility of 

desalinating produced brine. 

Approach 

Previous studies have addressed issues related 

to sequestration of CO 2 

in closed aquifers and the 

risk associated with aquifer pressurization. In this 

study, we will produce brine to relieve the pressure 

in the aquifer. First, we begin by extending known 

(waterflooding) conceptual models to apply to the 

CO 2 

/brine displacement process. This will help in 

the determination of well completion geometries, 

spacing, and flow rates that optimize CO 2 

storage 

efficiency. Next, we will extend the work of Anchliya, 

2009, such that the brine injector will inject saturated 

brine from the desalination process. Anchliya 

intended that injected brine would help curtail CO 2 

breakthrough while increasing CO 2 

trapping, as seen 

in Fig. 1. The conceptual models will be calibrated 

using rigorous numerical models. For this work, 

it will also be the mechanism to handle saturated 

brine from the desalination process. 

We will evaluate the economic feasibility of CO 2 

/ 

Fig. 1. Conceptual case of a horizontal CO2 and a brine injector and two 

horizontal brine producers (Anchliya, 2009). 



4.1.7 Sustainable Carbon Sequestration 


Anchliya, A., and Ehlig-Economides, C.A. Aquifer 

Management to Accelerate CO 2 

Dissolution and Trapping. 

Paper SPE 126688, presented at the 2009 International 

Conference on CO 2 

Capture, Storage, and Utilization, San 

Diego, California, 2-4 November. 

Contacts 


979.458.0797 


Oyewande Akinnikawe 


81

Aquifer Management for CO 2 

Sequestration 

Objectives 

Among various possible solutions to mitigate the 

increasing concentration of “greenhouse gases” in 

the atmosphere, geological sequestration seems the 

most attractive and promising one. This research 

explores carbon dioxide sequestration in deep saline 

aquifers, and will study issues related to aquifer 

pressurization, monitoring, and risk mitigation using 

a numerical reservoir simulator that models the 

multiphase flow physics of CO 2 

process using the 

Peng-Robinson equation of state (EOS). 

Approach 

Simulations clearly indicated that bulk CO 2 

injection 

into a single well could rarely inject the volume of 

CO 2 

produced by the power plant in a typical aquifer, 

and that multiple wells would be required. In an 

array of injection wells, the aquifer volume allotted 

to each injection well is limited by interference with 

other injection wells. Therefore, modeling of CO 2 

injection must consider a closed outer boundary, 

and bulk injection in a closed system will pressurize 

the aquifer. Simulations confirm this conclusion. 

An analytical model developed for this study extends 

a previously published one for an open aquifer to 

a closed aquifer. A spreadsheet model provides 

similar results to detailed simulation in a fraction of 

the time, enabling systematic determination of the 

aquifer volume and the number of wells required to 

sequester the target amount of CO 2 

. Results indicate 

that, depending on the aquifer properties, the 

sequestration operation would require thousands of 

square miles of aquifer area or hundreds of wells or 

both. In either case, the aquifer must be pressurized, 

and CO 2 

would accumulate at the top of the aquifer, 

leading to an unacceptable risk of leakage. 

Over 30 years of simulations on injection have 

demonstrated the value of regular pressure falloff 

monitoring of CO 2 

injection wells. Falloff responses 

provide ongoing indications of the dry zone and 

two-phase zone radii over time and quantification 

of the zone mobility values. For the case studied, 

these responses also provided reasonable estimates 

for the ongoing average aquifer pressure used 

for material balance analysis. In turn, analysis 

of average pressure over time can indicate if the 

behavior is that of an open or closed aquifer and an 

estimation of the aquifer size. Alternatively, average 

pressure over time can signal the presence of an leak 

and provide an estimation of how much fluid may 

be leaking from the aquifer and whether the leak is 

predominantly CO 2 

or brine. These results suggest 

that bulk CO 2 

injection is neither economically nor 

environmentally acceptable. 

To avoid pressurization and to reduce the number 

of wells required to sequester the CO 2 

, brine should 

be produced from the aquifer as a volume equal to 

that of the injected CO 2 

. This approach addresses 

the pressurization risk, but not the problem of CO 2 

accumulating at the top of the aquifer. 

Significance 

An engineered system is proposed to both 

avoid aquifer pressurization and accelerate CO 2 

dissolution and trapping. This system would position 

a horizontal brine injection well above and parallel 

to a horizontal CO 2 

injection well with the brine 

production wells drilled parallel to the CO 2 

injection 

well at a specified lateral spacing. Simulations show 

that this configuration prevents CO 2 

accumulation at 

the top of the aquifer during injection, where 90% of 

the CO 2 

is permanently dissolved or trapped during 

injection after 50 years, including the 30 years of 

injection. This approach would greatly reduce the 

risk of CO 2 

leakage both during and forever after 

injection. 



4.1.8 Aquifer Management for CO 2 

Sequestration 


Anchliya, A.: 2009. Aquifer Management for CO 2 

Sequestration. MS thesis. Texas A&M U., College Station, 

Texas. 

Anchliya, A., Ehlig-Economides, C.A. Aquifer Management 

to Accelerate CO 2 

Dissolution and Trapping. Paper 

SPE 126688, presented at the 2009 SPE International 

Conference on CO 2 

Capture, Storage, and Utilization, San 

Diego, California, 2-4 November. 

Contacts 


979.458.0797 


Abhishek Anchliya 

82 


Pretreatment Options to Allow Re-Use of Frac Flowback and Produced Brine 

(Desalination Process) 

Objectives 

Our objective is to identify a reliable and cost-effective 

pre-treatment method which allows the treatment 

and re-use of field-produced brine and fracture flowback 

waters. The project aims to develop a mobile 

and multifunctional water treatment specifically for 

“pre-treatment” of field waste brine. The project is 

part of the multi-sponsor Environmentally Friendly 

Drilling (EFD) program. 

Approach 

This project seeks to identify, develop, and 

demonstrate cost-effective technologies that will 

achieve volume reduction of liquid wastes while 

simultaneously producing effluents that could be 

re-used in oil-field applications, thereby reducing 

environmental impacts of waste water disposal and 

cost. Some of the key contaminants in produced 

water are suspended and entrained solids (TSS) 

and membrane rejection of such solids is one of our 

goals. 


We tested different samples of produced water and 

frac flowback water from various sources using a 

GE Sepa osmotic cell with nano-membranes and 

ultra-filtration membranes. Data obtained allowed 

for comparison between the membrane and further 

testing to be carried out on the field using a 

combination of membranes to determine the best 

result/analysis of permeate obtained while at the 

same time matching this with cost. Table 1 shows 

the TSS removal effectiveness of this membrane filter 

at a low pressure. This solids removal is a significant 

step in the overall process train of removing oil, 

solids, hardness, and salinity. 

Significance 

A quantitative comparison of the analysis of the 

permeate is obtained at the end of filtration, from 

which an evaluation of membrane filtration as a way 

to remove suspended and entrained particles in frac 

flowback or produced water to create re-useable 

effluents can be determined. 

Sample 

Filter Used 

Designation 

Turbidity 

(NTU) 

TDS 

Calcium 

concentration 

(ppm) 

Chloride 

concentration 

(ppm) 

Advanced 

Hydrocarbons 

Produced 

Water 

Untreated 454 49.35 1501.54 42.3 

Advanced 

Hydrocarbon: 

Pretreated 

Advanced 

Hydrocarbon: 

Average 

Permeate 

Result 

Percent 

Reduction 

5micron 

cartridge 

JW 

ultrafilter 

201 43.4 1461.1 42.115 


Pressure 

In (Psig) 

Pressure 

Out 

(Psig) 

26.85 44.55 1471.9 42.05 97.5 88.75 

86% 8% 2% 0% 

Table 1. Analysis of suspended solids removal from produced water 

sample. The pressure in and out shown above are average pressures for 

all rounds of permeate collection. 


4.2.9 Low Impact Oil & Gas Activity; Environmentally 

Friendly Drilling Systems 


Oluwaseun, O., Burnett, D., Hann, R., and Haut, R. 

Application of Membrane Filtration Technologies to Drilling 

Wastes. Paper SPE 115587, presented at the 2008 SPE 

Annual Technical Conference and Exhibition, Denver, 

Colorado, 21-24 September. 

Contacts 

David Burnett 

979.845.2274 

david.burnett@pe.tamu.edu 

Gene Beck 

979.862.1138 

gene.beck@pe.tamu.edu 

Uche Eboagwu 


83

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84 


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2007 

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85

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» Ibeh, Chijioke; Investigation on the Effects of Ultra-High Pressure and Temperature on the Rheological 

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» Jaiswal, Namit; Experimental and Analytical Studies of Hydrocarbon Yields Under Dry-, Steam-, and 

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» Kamkom, Rungtip; Modeling Performance of Horizontal, Undulating, and Multilateral Wells, PhD 2007, Zhu. 

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» Li, Yamin; Evaluation of Travis Peak Gas Reservoirs, West Margin of the East Texas Basin, MS 2007, Ayers. 

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Zhu. 

» Malagon Nieto, Camilo; 3D Characterization of Acidized Fracture Surfaces, MS 2007, Hill. 

» Marpaung, Fivman; Investigation of the Effective of Gel Residue on Hydraulic Fracture Conductivity Using 

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» Adegoke, Adesola Ayodeji; Utilizing the Heat Content of Gas-to-Liquids By-Product Streams for Commercial 

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86 


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2005 

» Al Harbi, Mishal Habis; Streamline-based Production Data Integration in Naturally Fractured Reservoirs, 

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Neural Networks, MS 2005, Startzman. 

» Chakravarthy, Deepak; Application of X-Ray CT for Investigating Fluid Flow and Conformance Control 

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87

» Diyashev, Ildar; Problems of Fluid Flow in a Deformable Reservoir, PhD 2005, Holditch. 

» Furrow, Brendan; Analysis of Hydrocarbon Removal Methods for the Management of Oilfield Brines and 

Produced Waters, MS 2005, Barrufet. 

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» Garcia Quijada, Marylena; Optimization of a CO2 Flood Design: Wasson Field, West Texas, MS 2005, 

Schechter. 

» Gasimov, Rustam; Modification of the Dykstra-Parsons Method to Incorporate Buckley-Leverett Displacement 

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» Gaviria Garcia, Ricardo; Reservoir Simulation of CO2 Sequestration and Enhanced Oil Recovery in the 

Tensleep Formation, Teapot Dome Field, MS 2005, Schechter. 

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» Liu, Jin; Investigation of Trace Amounts of Gas on Microwave Water-Cut Measurement. MS 2005, Scott. 

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Using a Bayesian Framework, MS 2005, McVay. 

» Okeke, Amarachukwu; Sensitivity Analysis of Modeling Parameters that Affect the Dual Peaking Behaviour 

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» Paknejad, Amir; Foam Drilling Simulator, MS 2005, Schubert. 

» Perez Garcia, Laura; Integration of Well Test Analysis into a Naturally Fractured Reservoir Simulation, MS 

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» Romero Lugo, Analis A.; Temperature Behavior in the Build Section of Multilateral Wells, MS 2005, Hill. 

» Shahri, Mehdi Abbaszadeh; Detecting and Modeling Cement Failure in High Pressure/High Temperature 

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» Simangunsong, Roly; Experimental and Analytical Modeling Studies of Steam Injection with Hydrocarbon 

Additives to Enhance Recovery of San Ardo Heavy Oil, MS 2005, Mamora. 

» Tschirhart, Nicholas R.; The Evaluation of Waterfrac Technology in Low-Permeability Gas Sands in the East 

Texas Basin, MS 2005, Holditch. 

» Wang, Wenxin; Methodologies and New User Interfaces to Optimize Hydraulic Fracturing Design and 

Evaluate Fracturing Performance for Gas Wells, MS 2005, Valko. 

» Yuan, Chengwu; An Efficient Bayesian Approach to History Matching, MS 2005, Datta-Gupta. 

» Zhakupov, Mansur; Application of Convolution and Average Pressure Approximation for Solving Non-Linear 

Flow Problems. Constant Pressure Inner Boundary Condition for Gas Flow, MS 2005, Blasingame. 

2004 

» Al-Meshari, Ali; New Strategic Method to Tune Equation-of-State to Match Experimental Data for 

Compositional Simulation, PhD 2004, McCain. 

» Sandoval, Jorge; A Simulation Study of Steam and Steam-Propane Injection using a Novel Smart Horizontal 

Producer to Enhance Oil Production, MS 2004, Mamora. 

88 


List of Articles/Papers/Reports 

2010 

» Awoleke, O.O., Lane, R.H. Analysis of Data from the Barnett Shale Using Conventional Statistical and 

Virtual Intelligence Techniques. SPE Paper 127919 presented at the 2010 SPE International Symposium 

and Exhibition on Formation Damage Control, Lafayette, Louisiana, 10–12 February. 

» Bello, R. and Wattenbarger, R.A. Multi-stage Hydraulically Fractured Shale Gas Rate Transient Analysis. 

Paper SPE 126754, presented at the 2010 SPE North Africa Technical Conference and Exhibition, Cairo, 

Egypt, 14–17 February. 

» Currie, S.M., Ilk, D., Blasingame, T.A. Continuous Estimation of Ultimate Recovery. Paper SPE 132352 

presented at the 2010 SPE Unconventional Gas Conference, Pittsburgh, Pennsylvania, 23-25 February. 

» Freeman, C.M., Ilk, D., Blasingame, T.A., and Moridis, G.J. A Numerical Study of Tight Gas/Shale Gas 

Reservoirs - Effects of Transport and Storage Mechanisms on Well Performance. Paper SPE 131583 to be 

presented at the 2010 IOGCEC International Oil & Gas Conference and Exhibition, Beijing, China, 8-10 

June. 

» Gomaa, A.M., and Nasr-El-Din, H.A. Rheological Properties of Polymer-Based In-Situ Gelled Acids: 

Experimental and Theoretical Studies. Paper SPE 128057 presented at the 2010 Oil and Gas India 

Conference and Exhibition, Mumbai, India, 20–22 January. 

» Li, L., Nasr-El-Din, H.A., Crews, J.B., and Cawiezel, K.E. 2010. Impact of Organic Acids/Chelating Agents 

on Rheological Properties of Amidoamine Oxide Surfactant. Paper SPE 128091 presented at the 2010 SPE 

International Symposium on Formation Damage Control, Lafayette, Louisiana, 10-12 February. 

» Mou, J., Zhu, D. and Hill, A.D. A New Acid-Fracture Conductivity Model Based on the Spatial Distributions 

of Formation Properties. Paper SPE-127935 presented at the 2010 SPE International Symposium on 

Formation Damage Control, Lafayette, Louisiana, 10-12 February. 

» Rawal C. and Ghassemi A. A 3-D Analysis of Solute Transport in a Fracture in Hot- and Poro-elastic Rock. 

Paper to be presented at the 2010 44th U.S. Rock Mechanics Symposium, ARMA, Salt Lake City, Utah, 

27-30 June. 

» Rawal C. and Ghassemi A. Reactive Flow in a Natural Fracture in Poro-thermoelastic Rock. Paper presented 

at the 2010 35th Stanford Geothermal Workshop. Stanford, California, 1-3 February. 


» Anchliya, A., and Ehlig-Economides, C.A. Aquifer Management to Accelerate CO2 Dissolution and Trapping. 

Paper SPE 126688, presented at the 2009 SPE International Conference on CO2 Capture, Storage, and 

Utilization, San Diego, California, 2-4 November. 

» Bello, R., and Wattenbarger, R.A. Modeling and Analysis of Shale Gas Production with a Skin Effect. Paper 

CIPC 2009-082, presented at the 2009 Canadian International Petroleum Conference, Calgary, Alberta, 

16–18 June. 

» Boulis, A., Ilk, D., and Blasingame, T.A. A New Series of Rate Decline Relations Based on the Diagnosis 

of Rate-Time Data. Paper CIM 2009-202 presented at the 2009 60th Annual Technical Meeting of the 

Petroleum Society, Calgary, Alberta, 16-18 June. 

» Davani, E., Ling, K., Teodoriu, C., McCain, W.D., Falcone, G. More Accurate Gas Viscosity Correlation for 

Use at HP/HT Conditions Ensures Better Reserves Estimation. Paper SPE 124734, presented at the 2009 

SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 4-7 October. 

» Deng, J., Hill, A.D. and Zhu, D. A Theoretical Study of Acid Fracture Conductivity Under Closure Stress. 

Paper SPE-124755, presented at the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 



89

» Freeman, C.M., Ilk, D., Moridis, G.J., and Blasingame, T.A. A Numerical Study of Performance for Tight 

Gas and Shale Gas Reservoir Systems. Paper SPE 124961 presented at the 2009 SPE Annual Technical 

Conference and Exhibition, New Orleans, Louisiana, 4–7 October 2009. 

» Freeman, C.M., Moridis, G.J., and Blasingame, T.A. A Numerical Study of Microscale Flow Behavior in 

Tight Gas and Shale Gas Reservoir Systems. Paper presented at the 2009 TOUGH Symposium, Berkeley, 

California, 14–16 September. 

» Gomaa, A.M., Mahmoud, M., and Nasr-El-Din, H.A. When Polymer-based Acids can be used? A Core Flood 

Study. Paper TPTC 13739 presented at the 2009 SPE International Petroleum Technology Conference, 

Doha, Qatar, 7–9 December. 

» Gomaa, A.M., Nasr-El-Din, H.A. New Insights into the Viscosity of Polymer-Based In-Situ Gelled Acids. Paper 

SPE 121728, presented at the 2009 SPE International Symposium on Oilfield Chemistry, The Woodlands, 

Texas, 20–22 April. 

» Gomaa, A.M., Nasr-El-Din, H.A. Acid Fracturing: The Effect of Formation Strength on Fracture Conductivity. 

Paper SPE 119623 presented at the 2009 SPE Hydraulic Fracturing Technology Conference, The Woodlands, 

Texas, 19–21 January. 

» Ilk, D., Rushing, J.A., and Blasingame, T.A. Decline-Curve Analysis for HP/HT Gas Wells: Theory and 

Applications. Paper SPE 125031 presented at the 2009 SPE Annual Technical Conference and Exhibition, 

New Orleans, Louisiana, 4–7 October. 

» Johnson, N.L., Currie, S.M., Ilk, D., Blasingame, T.A. A Simple Methodology for Direct Estimation of Gas-inplace 

and Reserves Using Rate-Time Data. Paper SPE 123298 presented at the 2009 SPE Rocky Mountain 

Technology Conference, Denver, Colorado, 14-16 April. 

» Li, L., Nasr-El-Din, H.A., and Cawiezel, K.E. 2009. Rheological Properties of a New Class of Viscoelastic 

Surfactant. Paper SPE 121716 presented at the 2009 SPE International Symposium on Oilfield Chemistry, 

The Woodlands, Texas, 20-22 April. 

» Li, W., Jensen, J.L., Ayers, W.B., Hubbard, S.M., and Heidari, M.R. 2009, Comparison of Interwell Connectivity 

Predictions using Percolation, Geometrical, and Monte Carlo Models. Journal of Petroleum Science and 

Engineering. (2009) 180-186. 

» Li, Z. and Zhu, D. Predicting Flow Profile of Horizontal Well by Downhole Pressure and DTS Data for 

Water-Drive Reservoir. Paper SPE 124873, presented at the 2009 SPE Annual Technical Conference and 

Exhibition, New Orleans, Louisiana, 4-7 October. DOI: 10.2118/124873-MS. 

» Ling, K., Teodoriu, C., Davani, E., Falcone, G. Measurement of Gas Viscosity at High Pressures and High 

Temperatures. Poster 13528, presented at the 2009 International Petroleum Technology Conference, 

Doha, Qatar, 7-9 December. 

» Liu, C., and McVay, D.A. Continuous Reservoir Simulation Model Updating and Forecasting Using a Markov 

Chain Monte Carlo Method. Paper SPE 119197, presented at the 2009 SPE Reservoir Simulation Symposium, 

The Woodlands, Texas, 2-4 February. 

» Mou, J., Zhu, D. and Hill, A.D. Acid-Etched Channels in Heterogeneous Carbonates—A Newly Discovered 

Mechanism for Creating Acid Fracture Conductivity. Paper SPE-119619 presented at the 2009 SPE Hydraulic 

Fracturing Technology Conference, The Woodlands, Texas, 19-21 January. 

» Nauduri, S., Medley, G.H., and Schubert, J.J. MPD: Beyond Narrow Pressure Windows. IADC/SPE Paper 

Number 122276-PP, presented at the 2009 IADC/SPE, Managed Pressure Drilling and Underbalanced 

Operations Conference and Exhibition, San Antonio, Texas, 12-13 February. 

» Park, H.Y., Falcone, G., Teodoriu, C. 2009. Decision Matrix for Liquid Loading in Gas Wells for Cost/Benefit 

Analyses of Lifting Options. Journal of Natural Gas Science and Engineering 1 (3): 72-83. 

» Rawal C. and Ghassemi A. A 3-D Thermoelastic Analysis of Reactive Flow in a Natural Fracture. Paper 

90 


presented at the 43rd U.S. Rock Mechanics Symposium, 2009, Asheville, North Carolina, 28 June-1 July. 

» Surendra, M., Falcone, G., Teodoriu, C. 2009. Investigation of Swirl Flows Applied to the Oil and Gas 

Industry. SPE Projects, Facilities & Construction Journal 4 (1): 1-6. 

» Tian, Y. and Ayers, W. Regional Stratigraphic and Sedimentary Facies Analyses, Barnett Shale, Fort 

Worth Basin, Texas. Paper 0919 presented at the 2009 International Coalbed and Shale Gas Symposium, 

Tuscaloosa, Alabama, 18-22 May. 

» Wang, Y., Holditch, S.A., and McVay, D.A. Modeling Fracture Fluid Cleanup in Tight Gas Wells. Paper SPE 

119624, presented at the 2009 SPE Hydraulic Fracturing Technology Conference held in Woodlands, Texas, 

19-21 January. 

» Wei, Y., Holditch, S.A. Computing Estimated Values of Optimal Fracture Half Length in the Tight Gas Sand 

Advisor Program. Paper SPE 119374 (2009). 

» Xue, W., Ghassemi, A. Poroelastic Analysis of Hydraulic Fracture Propagation. Paper 129, presented at the 

Asheville Rocks 2009, 43rd US Rock Mechanics Symposium, Asheville, North Carolina, 28 June–1 July. 

» Yang, D., Kim J., Silva, P., Barrufet, M., Moreira, R., and Sosa, J. Laboratory Investigation of E-Beam Heavy 

Oil Upgrading. Paper SPE 121911, presented at the 2009 SPE Latin American and Caribbean Petroleum 

Engineering Conference, Cartagena, Columbia, 31 May-3 June. 

» Yu, M. and Nasr-El-Din, H. Quantitative Analysis of an Amphoteric Surfactant in Acidizing Fluids and 

Coreflood Effluent. Paper SPE 121715 presented at the 2009 SPE Symposium on Oilfield Chemistry, 

Woodlands, Texas, 20-22 April. 

» Zhang, Y., Marongiu-Porcu, M., Ehlig-Economides, C.A., Tosic, S., and Economides, M.J. Comprehensive 

Model for Flow Behavior of High-Performance Fracture Completions. Paper SPE 124431, presented at the 

ATCE 2009 SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 4-7 October. 

2008 

» Bello, R.O. and Wattenbarger, R.A. Rate Transient Analysis in Naturally Fractured Reservoirs. Paper SPE 

114591 presented at the 2008 CIPC/SPE Gas Technology Symposium, Calgary, Canada, 16-19 June. 

» Catalin Teodoriu, Schubert, J., Vivek G., Ibeh C. Investigations to Determine the Drilling Fluid Rheology 

Using Constant Shear Rate Conditions. Presented at the 2008 IADC World Drilling Conference & Exhibition, 

Berlin, Germany, 11-12-June. 

» Chava, G., Falcone, G., and Teodoriu, C. Development of a New Plunger-Lift Model Using Smart Plunger (*) 

Data. Paper SPE 115934 presented at the 2008 SPE Annual Technical Conference and Exhibition, Denver, 

Colorado, 24-26 September. 

» Grover, T., Moridis, G., and Holditch, S.A. Analysis of Reservoir Performance of the Messoyahka Gas Hydrate 

Reservoir. Proceedings of the 2008 SPE ATCE, Denver, Colorado, 21-24 September. 

» Haut, R.C., Burnett, D. B., Rogers, J. L., Williams, T. E. Determining Environmental Tradeoffs Associated 

with Low Impact Drilling Systems. Paper SPE 114592, presented at the 2008 Annual Technical Conference 

and Exhibit, Denver, Colorado, 21-24 September. 

» Ibeh, C, Schubert, J.J., Teodoriu, C. Methodology for Testing Drilling Fluids under Extreme HP/HT Conditions. 

Paper No. AADE-08-DF-HO-14, presented at the 2008 AADE Fluids Technical Conference and Exhibit, 

Houston, Texas, 8-9 April. 

» Ibeh, C., Schubert, J., Teodoriu, C., Gusler, W., and Harvey, F. Investigation on the Effects of Ultra-High 

Pressure and Temperature on the Rheological Properties of Oil-based Drilling Fluids. Paper No. AADE-08- 

DF-HO-13, Presented at the 2008 AADE Fluids Technical Conference and Exhibit, held in Houston, Texas, 

8-9 April. 

» Mohammad, A. A. and Mamora, D. D. In Situ Upgrading of Heavy Oil Under Steam Injection with Tetralin 


91

and Catalyst. Paper presented at the 2008 International Thermal Operations and Heavy Oil Symposiums, 

Calgary, Alberta, 20-23 October. 

» Oluwaseun, O., Burnett, D., Hann, R. and Haut, R. HARC.Application of Membrane Filtration Technologies 

to Drilling Wastes. SPE 115587. 

» Rutqvist, J., Moridis, G., Grover, T., and Holditch, S. Coupled Hydrological, Thermal and Geomechanical 

Analysis of Wellbore Stability in Hydrate-Bearing Sediments. Paper OTC-19572 presented at the 2008 

Offshore Technology Conference held in Houston, Texas, 4-8 May. 

» Surendra, M., Falcone, G., Teodoriu, C. Investigation of Swirl Flows Applied to the Oil and Gas Industry. 

Paper SPE 115938 presented at the 2008 SPE Annual Technical Conference and Exhibition held in Denver, 

Colorado, USA, 21–24 September. 

» Verma, A., Burnett, D. Alternate Power and Energy Storage/Reuse for Drilling Rigs: Reduced Cost and 

Lower Emissions Provide Lower Footprint for Drilling Operations. SPE 122885 

» Wang,T., Holditch, S. A., McVay, D. Simulation of Gel Damage on Fracture Fluid Cleanup and Long-term 

Recovery in Tight Gas Reservoirs. Paper SPE 117444, presented at the 2008 SPE Eastern Regional/AAPG 

Eastern Section Joint Meeting held in Pittsburgh, Pennsylvania, 11-15 October. 

» Yu, O.-Y., Guikema, S. D., Bickel, J. E., Briaud, J.-L. and Burnett, D. Systems Approach and Quantitative 

Decision Tools for Technology Selection in Environmentally Friendly Drilling. SPE 120848. 

2007 

» Badicioiu, M., Teodoriu, C. Sealing Capacity of API Connections - Theoretical and Experimental Results. 

Paper SPE 106849 presented at the 2007 SPE Productions and Operations Symposium, Oklahoma City, 

Oklahoma, 31 March-3 April. 

» Chandra, S. and Mamora, D. D. Improved Steamflood Analytical Model. SPE 97870 accepted for publication 

in SPE Reservoir Evaluation & Engineering (December 2007). 

» Cheng, Y. Lee, J., and McVay, D. Improving Reserve Estimates from Decline Curve Analysis of Tight and 

Multilayer Gas Wells. Paper SPE 108176, presented at the 2007 SPE Hydrocarbon Economics and Evaluation 

Symposium, Dallas, Texas, 1-3 April. 

» Haghshenas, A., Schubert, J., Paknejad, A., and Rehm, B. Pressure Transient Lag Time Analysis During 

Aerated Mud Drilling. Paper presented at the 2007 AADE National Technical Conference & Exhibition held 

in Houston, Texas, 10-12 April. 

» Holditch, S., Hill, A. D., and Zhu, D. Advanced Hydraulic Fracturing Technology for Unconventional Tight 

Gas Reservoirs. Final research report to DOE DE-FC26-06NT42817, August, 2007. 

» Holmes, J.C., McVay, D.A. and Senel, O. A System for Continuous Reservoir Simulation Model Updating 

and Forecasting. Paper SPE 107566, presented at the 2007 SPE Digital Energy Conference and Exhibition, 

Houston, Texas, 11-12 April. 

» Jaiswal, N. and Mamora, D.D. Distillation Effects in Heavy Oil Recovery under Steam Injection with 

Hydrocarbon Additives. Paper SPE 110712, presented at 2007 SPE Annual Technical Conference and 

Exhibition, Anaheim, California, 11-14 November. 

» Kamkom, R., Zhu, D., Bond, A. Predicting Undulating Well Performance. Paper SPE 109761, presented 

at the 2007 SPE Annual Technical Conference and Exhibition held in Anaheim, California, U.S.A., 11–14 

November 2007. 

» Magalhaes, F., Zhu, D., Amini, S., and Valko, P. Optimization of Fractured Well Performance of Horizontal 

Gas Wells. Paper SPE 108779, presented at the 2007 International Oil Conference and Exhibition in Mexico 

held in Veracruz, Mexico, 27–30 June 2007. 

» Melendez, M.G., Pournik, M., Zhu, D., and Hill, A. D. The Effects of Acid Contact Time and the Resulting 

92 


Weakening of the Rock Surfaces on Acid Fracture Conductivity. Paper SPE 107772, presented at 7th SPE 

European Formation Damage Conference in Scheveningen, The Netherlands, 2007, 30 May - 1 June. 

» Morlot, C. and Mamora, D. D. TINBOP Cyclic Steam Injection Enhances Oil Recovery in Mature Steamfloods. 

Paper CIPC 2007-158, presented at proceedings CIPC 58th Ann. Tech. Mtg., Calgary, 2007, 12-14 June. 

» Mou, J., Hill, A.D., and Zhu, D. The Velocity Field and Pressure Drop Behavior in a Rough-Walled Fracture. 

Paper SPE 105182 presented at the 2007 SPE Hydraulic Fracturing Technology Conference, College Station, 

Texas, 29–31 January. 

» Paknejad, A., Amani, M., and Schubert, J. Foam Drilling Simulator. Paper SPE 105338, presented at the 

2007 Latin American & Caribbean Petroleum Engineering Conference held in The Buenos Aires, Argentina, 

15-18 April. 

» Paknejad, A., Schubert, J., Amani, M., and Teodoriu, C. Sensitivity Analysis of Key Parameters in Foam 

Drilling Operations. SPE 150 Years of the Romanian Petroleum Industry, held in Bucharest, Romania, 14- 

17 October, 2007. 

» Paknejad, A., Schubert, J., and Haghshenas, A. A New and Simplified Method for Determination of 

Conductor/Surface Casing Setting Depths in Shallow Marine Sediments (SMS). Paper presented at the 

2007 AADE National Technical Conference & Exhibition held in Houston, TX., 10-12 April. 

» Paknejad, A., Schubert, J., and Amani, M. A New Method to Evaluate Leak-Off Tests in Shallow Marine 

Sediments. Paper SPE 110953 presented at the 2007 SPE Technical Symposium held in Dhahran, Saudi 

Arabia, 7-8 May. 

» Pournik, M., Zuo, C., Malagon Nieto, C., Melendez, M., Zhu, D., Hill, A. D. and Weng, X. Small-Scale 

Fracture Conductivity Created by Modern Acid Fracture Fluids. Paper presented at 2007 Hydraulic Fracturing 

Technology Conference, in College Station, TX, SPE 106272, 29-31 January. 

» Rivero, J.A., and Mamora, D.D. Oil Production Gains for Mature Steamflooded Oil Fields Using Propane as 

a Steam Additive and a Novel Smart Horizontal Producer. Paper SPE 110538, presented 2007 SPE-ATCE, 

Anaheim, California, 11-14 November. 

» Teodoriu, C., Falcone, G., Espinel, A. Letting Off Steam and Getting Into Hot Water – Harnessing the 

Geothermal Energy Potential of Heavy Oil Reservoirs. Paper presented at the 20th World Energy Congress 

- Rome 2007, Rome, Italy, 11-15 November. 

» Valko, P.P., and Amini, S. Method of Distributed Volumetric Sources for Calculating the Transient and 

Pseudosteady-State Productivity of Complex Well-Fracture Configurations. Paper SPE 106279 presented at 

the 2007 SPE Hydraulic Fracturing Technology Conference, College Station, 29-31 January. 

» Yoshioka, K., Dawkrajai, P., Romero, A., Zhu, D., Hill, A. D., and Lake, L. W. A Comprehensive Statistically- 

Based Method To Interpret Real-Time Flowing Well Measurements. Final research report to DOE DE-FC26- 

03NT15402, January, 2007. 

» Yoshioka, K., Zhu, D., and Hill, A. D. A New Inversion Method to Interpret Flow Profiles from Distributed 

Temperature and Pressure Measurements in Horizontal Wells. Paper SPE 109749, presented at the 2007 

SPE Annual Technical Conference and Exhibition held in Anaheim, California, U.S.A., 11–14 November. 

» Zhu, D., Magalhaes, F., and Valko, P. Predicting the Productivity of Multiple-Fractured Horizontal Gas Wells. 

Paper SPE 106280, presented at 2007 Hydraulic Fracturing Technology Conference, in College Station, 

Texas, 29-31 January. 

2006 

» Bond, A., Zhu, D., and Kamkom, R. The Effect of Well Trajectory on Horizontal Well Performance. Paper 

SPE 104183, presented at the 2006 International Oil Conference and Exhibition in Beijing, China, 5-7 

December. 

» Izgec, B., Kabir, C.S., Zhu, D. and Hasan, A.R. Transient Fluid and Heat Flow Modeling in Coupled Wellbore/ 

Reservoir Systems. Paper SPE 102070, presented at the 2006 SPE Annual Technical Conference and 


93

Exhibition, San Antonio, Texas, 24-27 September. 

» Kamkom, R. and Zhu, D. Generalized Horizontal Well Inflow Relationships for Liquid, Gas or Two-Phase 

Flow. Paper SPE 99712 presented at the 2006 SPE/DOE Symposium on Improved Oil Recovery held in 

Tulsa, Oklahoma, 22–26 April. 

» Malagon Nieto, M., Pournik, M., and Hill, A. D. The Texture of Acidized Fracture Surfaces – Implications for 

Acid Fracture Conductivity. Paper SPE 102167, presented at 2006 SPE Annual Technical Conference and 

Exhibition, San Antonio, Texas, 24-27 September. 

» Simangunsong, R., Jaiswal, N. and Mamora, D.D. Improved Analytical Model and Experimentally Calibrated 

Studies of Steam Injection with Hydrocarbon Additives to Enhance Heavy Oil Recovery. Paper SPE 100703, 

presented at 2006 SPE Annual Technical Conference and Exhibition, San Antonio, 24-27 September. 

» Yoshioka, K., Zhu, D., Hill, A. D., Dawkrajai, P., and Lake, L. W. Detection of Water or Gas Entries in 

Horizontal Wells from Temperature Profiles. Paper SPE 100209, presented at the 2006 SPE Europec/EAGE 

Annual Conference and Exhibition held in Vienna, Austria, 12-15 June. 

» Zhu, D. and Furui, K. Optimizing Oil and Gas Production by Intelligent Technology. Paper SPE 102104, 

presented at 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24-27 September. 

2005 

» Mamora, D. and Sandoval, J. Investigation of a Smart Steamflood Pattern to Enhance Production from 

San Ardo Field, California. Paper SPE 95491, presented at the 2005 SPE Annual Technical Conference and 

Exhibition, Dallas, Texas, 9-12 October. 

» Yoshioka, K., Zhu, D., Hill, A. D., and Lake, L. W. Interpretation of Temperature and Pressure Profiles 

Measured in Multilateral Wells Equipped with Intelligent Completions. Paper SPE 94097, presented at the 

2005 14th Europec Piennial Conference, Madrid, Spain, 13-16 June. 

» Yoshioka, K., Zhu, D., Hill, A. D., Dawkrajai, P., and Lake, L. W. A Comprehensive Model of Temperature 

Behavior in a Horizontal Well. Paper SPE 95656, presented at the 2005 SPE Annual Technical Conference 

and Exhibition, Dallas, Texas, 9-12 October. 

94

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