Crisman Annual Report 2009 - Harold Vance Department of ...
Crisman Annual Report 2009 - Harold Vance Department of ...
Crisman Annual Report 2009 - Harold Vance Department of ...
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<strong>Harold</strong> <strong>Vance</strong> <strong>Department</strong> <strong>of</strong> Petroleum Engineering<br />
at Texas A&M University<br />
<strong>2009</strong> <strong>Annual</strong> <strong>Report</strong><br />
End <strong>of</strong> Coreflood for 3000 ppm gel:<br />
End <strong>of</strong> Coreflood for 10,000 ppm gel:<br />
Pure CO 2<br />
flood image (after 1.6 PV CO 2<br />
injected)<br />
Viscosified CO 2<br />
flood image (after 1.3 PV CO 2<br />
injected)<br />
0<br />
ΔP<br />
(psi/ft)<br />
0.50<br />
270 90<br />
0.06<br />
180<br />
Halliburton Center for Unconventional Resources<br />
Chevron Center for Well Construction and Production<br />
Schlumberger Center for Reservoir Description and Dynamics<br />
Center for Energy, Environment, and Transportation Innovation
<strong>Crisman</strong> Institute for Petroleum Research<br />
<strong>Harold</strong> <strong>Vance</strong> <strong>Department</strong> <strong>of</strong> Petroleum Engineering at Texas A&M University<br />
<strong>2009</strong> <strong>Annual</strong> <strong>Report</strong><br />
Halliburton Center for Unconventional Resources<br />
Chevron Center for Well Construction and Production<br />
Schlumberger Center for Reservoir Description and Dynamics<br />
Center for Energy, Environment, and Transportation Innovation
Issue 3, February 2010<br />
Stephen A. Holditch<br />
Director<br />
Nancy H. Luedke<br />
Editor<br />
<strong>Harold</strong> <strong>Vance</strong> <strong>Department</strong> <strong>of</strong> Petroleum Engineering<br />
3116 TAMU<br />
College Station TX 77843-3116<br />
979.845.2255<br />
© 2010 <strong>Harold</strong> <strong>Vance</strong> <strong>Department</strong> <strong>of</strong> Petroleum Engineering<br />
at Texas A&M University. All rights reserved.<br />
Kathy Beladi<br />
Editor<br />
Email: info@pe.tamu.edu<br />
Cover images (clockwise from top left): Gel strength study and comparison <strong>of</strong> flood fronts, <strong>Report</strong> 3.4.4, pg 78; Coreholer connected to slimtube, <strong>Report</strong><br />
1.7.3, pg 44; Steam chamber temperature distribution image, <strong>Report</strong> 1.3.13, pg. 30; Structural permeability diagram for Barnett Shale, <strong>Report</strong> 2.5.10,<br />
pg. 61; Medium resolution 75 layer 3D geologic model, <strong>Report</strong> 3.1.22, pg. 71.<br />
2<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Contents<br />
Vision ........................................................................................................................................ 7<br />
Mission ...................................................................................................................................... 7<br />
Objectives ................................................................................................................................. 7<br />
Summary ................................................................................................................................... 8<br />
Membership History................................................................................................................. 10<br />
Meetings .................................................................................................................................. 11<br />
Summary <strong>of</strong> Research Results<br />
Casing Failure ............................................................................................................................ 13<br />
An Advisory System for Selecting Drilling Technologies and Methods in Tight Gas Reservoirs ................. 14<br />
Assessment <strong>of</strong> API Thread Connections under Tight Gas Well Conditions ............................................ 15<br />
Gas Shales – Geomechanics/Completions ...................................................................................... 17<br />
PRISE – Petroleum Resource Investigation Summary and Evaluation ................................................. 18<br />
An Investigation <strong>of</strong> Regional Variations <strong>of</strong> Barnett Shale Reservoir Properties, and Resulting Variability<br />
<strong>of</strong> Hydrocarbon Composition and Well Performance ...................................................................... 19<br />
Gas Shales Simulation and Production Data Analysis ....................................................................... 20<br />
Characterization <strong>of</strong> Rock Transport Properties in Tight Gas and Shale ................................................. 22<br />
Rate Transient Analysis in Shale Gas Reservoirs with Transient Linear Behavior ................................... 23<br />
An Analytical Approach to Model Shale Gas Reservoir Flow Including Desorption Effects ....................... 24<br />
Water Production Issues in the Barnett Shale ................................................................................. 25<br />
Enhanced Oil Refining Technology through E-Beam Thermal Cracking ................................................ 27<br />
Experimental Investigation <strong>of</strong> Caustic Steam Injection for Heavy Oils ................................................ 29<br />
Experimental and Simulation Modeling Studies <strong>of</strong> Steam Assisted Gravity .......................................... 30<br />
In-Situ Oil Upgrading using Tetralin (C 10<br />
H 12<br />
) Hydrogen Donor and Fe(acac) 3<br />
Catalyst at Steam Injection<br />
Pressure and Temperature ........................................................................................................ 31<br />
Artificial Geothermal Energy Potential <strong>of</strong> Steam-Flooded Heavy Oil Reservoirs ..................................... 33<br />
Study <strong>of</strong> Solvent-Based Emulsion Injection to Improve Sweep and Displacement Efficiency in Heavy<br />
Oil Reservoir ........................................................................................................................... 34<br />
Investigation <strong>of</strong> Hybrid Steam-Solvent Processes to Increase Efficiency <strong>of</strong> Thermal Oil Recovery<br />
Methods ................................................................................................................................. 36<br />
Experimental Studies <strong>of</strong> Steam Injection with Surfactant for Enhancing Heavy Oil Recovery after<br />
Waterflooding ......................................................................................................................... 38<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
3
Combustion Assisted Gravity Drainage (CAGD): An In-Situ Combustion Method to Recover Heavy<br />
Oil and Bitumen from Geologic Formations using a Horizontal Injector-Producer Pair ........................ 40<br />
Well Spacing and Infill Drilling in Coalbed Methane Reservoirs .......................................................... 42<br />
Drilling through Gas Hydrate Formations ........................................................................................ 43<br />
Experimental and Numerical Simulation Studies to Evaluate Improvement <strong>of</strong> Light Oil Recovery by<br />
WACO 2<br />
and SWACO 2<br />
in Fractured Carbonate Reservoirs ................................................................ 44<br />
Enhanced Oil Recovery <strong>of</strong> Viscous Oil by Injection <strong>of</strong> Water-in-Oil Emulsions ....................................... 46<br />
Managed Pressure Drilling Candidate Selection ............................................................................... 47<br />
Alternate Power and Energy Storage/Reuse for Drilling Rigs: Reduced Cost and Lower Emissions<br />
Provide Lower Footprint for Drilling Operations ............................................................................ 48<br />
Cement Fatigue Failure and HPHT Well Integrity .............................................................................. 49<br />
Propagation <strong>of</strong> Induced Hydraulic Fractures near Pre-Existing Fractures ............................................. 50<br />
Using Downhole Temperature Measurement to Assist Reservoir Characterization and Optimization ......... 51<br />
Optimization <strong>of</strong> Horizontal Well Performance in Low-Permeability Gas Reservoirs ................................. 53<br />
Decision Matrix for Liquid Loading in Gas Wells for Cost/Benefit Analyses <strong>of</strong> Lifting Options (Part 2) ....... 54<br />
Investigation <strong>of</strong> Swirl Flows Applied to the Oil and Gas Industry ........................................................ 55<br />
Potential for CO 2<br />
Sequestration and Enhanced Coalbed Methane Production, NW Black Warrior Basin ..... 57<br />
Transient Multiphase Sand Transport in Horizontal Wells ................................................................... 58<br />
Performance Driven Hydraulic Fracture Design for Deviated Wells ...................................................... 59<br />
Carbonate Heterogeneity and Acid Fracture Performance ................................................................. 60<br />
Modeling and Analysis <strong>of</strong> Reservoir Response to Stimulation by Water Injection .................................. 61<br />
Fracture Aperture Variation Caused by Reactive Transport <strong>of</strong> Silica and<br />
Poro-Thermoelastic Effect ......................................................................................................... 62<br />
Rheological Properties <strong>of</strong> a New Class <strong>of</strong> Viscoelastic Surfactant ........................................................ 63<br />
Acid Hydrolysis <strong>of</strong> Carboxybetaine Viscoelastic Surfactant ................................................................ 65<br />
Evaluation <strong>of</strong> Polymer-Based In-Situ Gelled Acids during Well Stimulation .......................................... 66<br />
Modeling <strong>of</strong> Discrete Fracture Network using Voronoi Grid System ..................................................... 68<br />
Thermo-Poroelastic Finite Element Analysis <strong>of</strong> Rock Deformation and Damage .................................... 70<br />
Application <strong>of</strong> Adaptive Gridding and Upscaling for Improved Tight Gas Reservoir Simulation ................ 71<br />
Measurement and Correlation <strong>of</strong> Gas Viscosities at High Pressures and High Temperatures ................... 72<br />
Measurement <strong>of</strong> Gas Viscosity at High Pressures and High Temperatures ............................................ 73<br />
4<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Numerical Modeling <strong>of</strong> Fracture Permeability Change in Naturally Fractured Reservoirs using a Fully<br />
Coupled Displacement Discontinuity Method ............................................................................... 75<br />
Improved Permeability Predictions using Multivariate Analysis Methods .............................................. 77<br />
CO 2<br />
Mobility Control using Cross-Linked Gel and CO 2<br />
Viscosifiers ....................................................... 78<br />
Stochastic History Matching, Forecasting, and Production with the Ensemble Kalman Filter ................... 79<br />
Sustainable Carbon Sequestration ................................................................................................. 81<br />
Aquifer Management for CO 2<br />
Sequestration .................................................................................... 82<br />
Pretreatment Options to Allow Re-Use <strong>of</strong> Frac Flowback and Produced Brine (Desalination Process) ....... 83<br />
Bibliography ............................................................................................................................ 84<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
5
6<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Vision<br />
The vision <strong>of</strong> the <strong>Crisman</strong> Institute for Petroleum Research is to provide a vehicle to enhance development<br />
<strong>of</strong> petroleum engineering technology through cutting-edge, industry-directed research conducted in four<br />
dedicated research Centers in the <strong>Harold</strong> <strong>Vance</strong> <strong>Department</strong> <strong>of</strong> Petroleum Engineering at Texas A&M<br />
University.<br />
The <strong>Crisman</strong> Institute for Petroleum Research identifies and solves significant research<br />
problems <strong>of</strong> major interest to industry and government. The Institute conducts it efforts in four research<br />
Centers: the Halliburton Center for Unconventional Resources, the Chevron Center for Well Construction and<br />
Production, the Schlumberger Center for Reservoir Description and Dynamics, and the Center for Energy,<br />
Environment and Transportation Innovation. Industry and governmental representatives can help identify<br />
problems <strong>of</strong> major significance and support projects <strong>of</strong> particular interest to them through membership at<br />
the Institute, Center, or Project level. Additionally, membership provides seed money for identification and<br />
initiation <strong>of</strong> research into additional problems facing the industry.<br />
Mission<br />
» The mission <strong>of</strong> the <strong>Crisman</strong> Institute for Petroleum Research is to produce significant advances in upstream<br />
petroleum engineering technology through the combined efforts <strong>of</strong> faculty, post-doctoral researchers,<br />
highly qualified graduate students, in close cooperation with industry.<br />
» The mission <strong>of</strong> the Halliburton Center for Unconventional Resources is to increase our ability to<br />
characterize reserves <strong>of</strong> unconventional resources and to develop new, more efficient ways to reduce costs<br />
and improve recovery <strong>of</strong> these resources.<br />
» The mission <strong>of</strong> the Chevron Center for Well Construction and Production is to develop new<br />
tools, both theoretical and physical, to construct and complete wells in today’s increasingly challenging<br />
environments in a way that will reduce the finding and development costs.<br />
» The mission <strong>of</strong> the Schlumberger Center for Reservoir Description and Dynamics is to develop<br />
better approaches to describe and model petroleum reservoirs and to manage the resources identified<br />
there to reduce costs and improve recovery.<br />
» The mission <strong>of</strong> the Center for Energy, Environment, and Transportation Innovation is to form<br />
an interdisciplinary collaboration to study the needs <strong>of</strong> a 21 st century transportation system addressing<br />
energy, environment, and social issues.<br />
Objectives<br />
The <strong>Crisman</strong> Institute and its four Centers have seven primary objectives:<br />
» Work with industry and government representatives to identify the most important problems now facing<br />
the upstream petroleum industry and those that arise in the future.<br />
» Focus our efforts on solutions to as many <strong>of</strong> the identified problems as possible within the framework <strong>of</strong><br />
available resources.<br />
» Develop solutions that will be immediately useful in the industry.<br />
» Maintain a clearinghouse <strong>of</strong> research efforts, tracking not only research in progress but also results <strong>of</strong><br />
completed projects and perspectives on research possibilities for the future.<br />
» Continuously upgrade the problem-solving capabilities <strong>of</strong> the Institute through ongoing faculty development<br />
strategies and pursuit <strong>of</strong> outstanding post-doctoral and graduate students.<br />
» Ensure financial stability to continue to provide long-term solutions to technology-development problems.<br />
» Publicize the activities <strong>of</strong> the Institute and the contributions <strong>of</strong> the membership who make those activities<br />
possible.<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
7
Summary<br />
The <strong>Crisman</strong> Institute has two main purposes. One purpose is based on the Vision, Mission and Objectives<br />
which is to do high-quality research. Another purpose is to help alleviate the manpower shortage that<br />
companies are experiencing. As we all know, the world needs more engineers and scientists, especially in<br />
the oil and gas industry. We are helping with this by producing more high-quality engineers over the last<br />
several years as shown in the tables below.<br />
Recent Trends in Graduate Enrollment<br />
Year Master Phd Total<br />
1997-1998 62 41 103<br />
1998-1999 64 37 101<br />
1999-2000 93 38 131<br />
2000-2001 134 30 164<br />
2001-2002 142 33 175<br />
2002-2003 132 33 165<br />
2003-2004 126 32 158<br />
2004-2005 123 43 166<br />
2005-2006 141 50 191<br />
2006-2007 157 55 212<br />
2007-2008 181 67 248<br />
2008-<strong>2009</strong> 189 81 270<br />
<strong>2009</strong>-2010 239 80 323<br />
Recent Trends in Graduate Degrees<br />
Year Master Phd Total<br />
1997-1998 27 11 38<br />
1998-1999 18 7 25<br />
1999-2000 20 13 33<br />
2000-2001 38 4 42<br />
2001-2002 65 5 70<br />
2002-2003 41 5 46<br />
2003-2004 67 12 79<br />
2004-2005 45 8 53<br />
2005-2006 40 4 44<br />
2006-2007 62 17 79<br />
2007-2008 51 12 63<br />
2008-<strong>2009</strong> 48 18 66<br />
Totals 522 116 638<br />
8<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
The <strong>Crisman</strong> Institute has made great strides in<br />
growing and building the petroleum engineering<br />
department’s research program. Since 2005, the<br />
<strong>Crisman</strong> Institute has funded a total <strong>of</strong> 184 projects<br />
<strong>of</strong> which 139 are complete. For the Spring 2010<br />
semester, we had a total <strong>of</strong> 319 graduate students.<br />
We had 117 graduate research assistant positions<br />
during that time and <strong>Crisman</strong> funded 31 <strong>of</strong> them.<br />
Some <strong>of</strong> the research we have conducted<br />
through <strong>Crisman</strong> has allowed us to develop<br />
s<strong>of</strong>tware and databases that can be used by<br />
industry. An additional benefit companies<br />
have experienced is the opportunity to<br />
become familiar with our students and their research<br />
which has <strong>of</strong>ten led companies to hire them post<br />
graduation.<br />
As noted in the tables and charts below, I have<br />
broken down the distribution <strong>of</strong> our progress for<br />
each <strong>of</strong> the four centers and for each year.<br />
» Halliburton Center for Unconventional Resources<br />
(UCR)<br />
» Chevron Center for Well Construction and<br />
Production (WCP)<br />
» Schlumberger Center for Reservoir Description<br />
and Dynamics (RDD)<br />
» Center for Energy, Environment, and Transportation<br />
Innovation (EETI)<br />
Projects by Centers<br />
Center Completed In Progress<br />
UCR 54 22<br />
WCP 39 13<br />
RDD 32 8<br />
EETI 14 2<br />
Total 139 45<br />
Total Projects: 184<br />
WCP<br />
Number <strong>of</strong> Projects<br />
UCR<br />
RDD<br />
EETI<br />
Total<br />
140<br />
120<br />
100<br />
80<br />
60<br />
40<br />
20<br />
Completed<br />
In Progress<br />
0 20 40 60 80 100 120<br />
0<br />
Completed Projects by Year<br />
Year<br />
Number<br />
<strong>2009</strong> 15<br />
2008 30<br />
2007 47<br />
2006 20<br />
2005 25<br />
2004 2<br />
Total 137<br />
2004 2005 2006 2007 2008 <strong>2009</strong> Total<br />
Year<br />
140<br />
As you read through this annual report, I hope you<br />
see the many achievements we have experienced<br />
over the past 6 years. Through the support <strong>of</strong><br />
industry, the <strong>Crisman</strong> Institute and the department<br />
are making an impact on our students, research, and<br />
industry. We intend to report even more successes<br />
in 2010.<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
9
Membership History<br />
The <strong>Crisman</strong> Institute began operation in its current format on January 1, 2005. At the end <strong>of</strong> 2005, we<br />
had three endowed members, four institute members and six center members. The Institute maintained<br />
these membership categories until January 1, 2007. Since the beginning <strong>of</strong> 2007, we eliminated the<br />
center memberships and all companies now belong to the entire <strong>Crisman</strong> Institute. As such, all member<br />
companies have the rights to use all the results from all the projects sponsored by <strong>Crisman</strong>. Table 1 shows<br />
the membership history.<br />
2005 2006 2007 2008 <strong>2009</strong> 2010<br />
Halliburton Halliburton Halliburton Halliburton Halliburton Halliburton<br />
Chevron Chevron Chevron Chevron Chevron Chevron<br />
Schlumberger Schlumberger Schlumberger Schlumberger Schlumberger Schlumberger<br />
Anadarko Anadarko Anadarko Anadarko Anadarko<br />
Baker Hughes Baker Hughes Baker Hughes Baker Hughes Baker Hughes<br />
Nexen Nexen Nexen Nexen Nexen Nexen<br />
Economides Consulting<br />
IHS IHS IHS IHS IHS<br />
ExxonMobil ExxonMobil ExxonMobil ExxonMobil ExxonMobil<br />
Matador Resources<br />
Burlington<br />
Burlington<br />
Total Total Total Total Total Total<br />
Newfield Newfield Newfield Newfield Newfield Newfield<br />
Devon<br />
Devon<br />
BP BP BP BP BP<br />
ConocoPhillips ConocoPhillips ConocoPhillips ConocoPhillips ConocoPhillips ConocoPhillips<br />
Saudi Aramco Saudi Aramco Saudi Aramco<br />
El Paso El Paso El Paso<br />
BJ Services BJ Services BJ Services<br />
Marathon<br />
Shell<br />
Marathon<br />
Shell<br />
Repsol<br />
MI-Swaco<br />
ENI<br />
NETL-DOE<br />
Table 1. Membership History for the <strong>Crisman</strong> Institute.<br />
10<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Meetings<br />
Steering Committee Meeting<br />
» March 1, 2010<br />
One Day Technology Meetings/Center Meetings<br />
2010<br />
» June 1 - Enhanced Oil Recovery<br />
» May 27 - Environmentally Friendly Drilling Meeting<br />
» May 25 - Well Productivity Improvement<br />
» May 20 - Heavy Oil and IOR Research<br />
» May 18 - Shale Gas Meeting<br />
» February 23 - Environmentally Friendly Drilling<br />
Meeting in Houston, Texas<br />
<strong>2009</strong><br />
» December 15 - Shale Gas<br />
» October 16 - Technology Transfer Meeting on<br />
Unconventional Gas and Hydraulic Fracturing<br />
» October 4 - Heavy Oil and IOR Methods<br />
» June 24 - Role <strong>of</strong> Chemistry in Well Production<br />
» May 19 - Shale Gas<br />
» May 14 - Reservoir Performance for Enhanced Oil<br />
Recovery by CO 2 Injection<br />
» April 23 - Environmentally Friendly Drilling Meeting<br />
in Houston, Texas<br />
» April 14 - Acid Fracture Conductivity<br />
» March 18 - Chemical EOR and Water Shut-Off<br />
Using Chemical Means<br />
» February 18 - Advanced Hydraulic Fracturing<br />
2008<br />
» December 16 - Shale Gas Meeting<br />
» December 12 - Heavy Oil and IOR Methods Meeting<br />
» December 11 - Business Meeting and Unconventional<br />
Gas Reservoirs Advisory Meeting<br />
» November 5 - Environmentally Friendly Drilling<br />
» June 5 - Shale Gas<br />
» May 30 - Low Impact Access in Environmentally<br />
Sensitive Areas<br />
» May 21 - Acid Fracture Conductivity<br />
» May 20 - Unconventional Gas<br />
» May 19 - Hydraulic Fracturing in Tight Gas<br />
Formations (afternoon)<br />
» May 19 - Intelligent Completion and Applications<br />
(morning)<br />
» May 8 - Heavy Oil and IOR Methods<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
» May 5 - Gas Well Unloading<br />
2007<br />
» December 11 – Shale Gas Production Data<br />
Analyses<br />
» November 29 – Center for Energy Environmental,<br />
and Transportation Innovation<br />
» November 16 – Heavy Oil and Improved Recovery<br />
Methods<br />
» November 5 - Gas Well Unloading<br />
» October 25 - Acid Fracturing Conductivity<br />
» October 24 - Unconventional Gas Reservoirs &<br />
Resource Assessment<br />
» October 17 - Hydraulic Fracturing in Tight Gas<br />
Formation<br />
» October 9 - Advanced Drilling Technology<br />
» May 10 - Gas Well Unloading<br />
» May 9 - Tight Gas Sands Meeting<br />
» May 8 - Environmentally Friendly Drilling Meeting<br />
in Houston, Texas<br />
» April 26 - Fractured Shale Reservoirs Meeting<br />
» April 25 - Heavy Oil Recovery Meeting<br />
» April 11 - Intelligent Well Technology<br />
2006<br />
» November 9 - Halliburton Center<br />
» November 8 - Schlumberger Center<br />
» November 7 - Chevron Center<br />
» September 6 - Resource Assessment for<br />
Unconventional Reservoirs<br />
» September 6 - Fracture Fluid Damage and Cleanup<br />
» August 9 - Gas Well Deliquification<br />
» August 3 - Heavy Oil<br />
» May 25 - Halliburton Center<br />
» May 24 - Schlumberger Center<br />
» May 23 - Chevron Center<br />
2005<br />
» November 11 - Chevron Center<br />
» November 10 - Schlumberger Center<br />
» November 10 - Halliburton Center<br />
» May 26 - Halliburton Center<br />
» March 24 - Schlumberger Center<br />
» January 27 - Chevron Center<br />
11
12<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Casing Failure<br />
Objectives<br />
The objective is to develop a casing failure<br />
probabilistic model that describes casing behavior in<br />
the compacting reservoir. Depletion <strong>of</strong> pore pressure<br />
from oil production in an unconsolidated formation,<br />
or s<strong>of</strong>t formations such as sandstone, chalk, and<br />
diatomite, causes casing deformation, which can<br />
later turn to failure. Creating a probabilistic model<br />
can explain the relationship between failure and<br />
involved parameters. By matching the model results<br />
with field history, the model is corrected for each<br />
specific field. Thus, the model can be projected<br />
for future casing failure <strong>of</strong> each field. Mitigation<br />
strategies can be implemented to minimize the rate<br />
<strong>of</strong> future casing failure according to the results <strong>of</strong><br />
the model.<br />
Accomplishments<br />
Tests were done on the compression failure model.<br />
The results show that with a higher grade <strong>of</strong> casing<br />
the probability <strong>of</strong> failure decreases. Thus, increasing<br />
casing grade may help strengthen casing against<br />
compression failure. Well inclination is another<br />
factor that can decrease the probability <strong>of</strong> failure.<br />
For compression failure, vertical wells are more<br />
susceptible to failure than inclined wells, as shown<br />
in the results. Cementing plays an important role<br />
in compression failure. Slippage at the cementformation<br />
and cement-casing can reduce maximum<br />
casing strain subjected to reservoir compaction by<br />
30%-40%, which is also shown in the result. Also,<br />
the use <strong>of</strong> ductile cement can reduce the risk <strong>of</strong><br />
compression failure through cement properties.<br />
Future Work<br />
Acquire all casing properties and parameters, such as<br />
diameter and thickness. The magnitude <strong>of</strong> buckling<br />
failure could depend on the unsupported length <strong>of</strong><br />
casing. Run buckling failure model and analyze the<br />
results with different unsupported lengths. Compare<br />
the results <strong>of</strong> the unsupported with the supported<br />
to prove that buckling failure is likely to occur when<br />
casing is not laterally supported.<br />
CRISMAN INSTITUTE<br />
Project Information<br />
1.1.2 Reservoir Compaction and Casing Integrity in Texas<br />
Gulf <strong>of</strong> Mexico Coast, Part II<br />
Contacts<br />
Jerome Schubert<br />
979.862.1195<br />
jerome.schubert@pe.tamu.edu<br />
Catalin Teodoriu<br />
catalin.teodoriu@pe.tamu.edu<br />
Prasongsit Chantose<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
13
An Advisory System for Selecting Drilling Technologies and Methods in Tight Gas<br />
Reservoirs<br />
Objectives<br />
The main objective <strong>of</strong> this research project is to<br />
develop a computer program dedicated to applying<br />
the drilling technologies and methods selection for<br />
drilling tight gas sandstone formations that have<br />
been documented as best practices in the petroleum<br />
literature. We have created an advisory module<br />
for tight gas that is part <strong>of</strong> a general Drilling &<br />
Completion Advisor for unconventional formations.<br />
This Drilling & Completion Advisory Module, along<br />
two other programs called BASIN (basin analogy)<br />
and PRISE (resource evaluation) is part <strong>of</strong> the<br />
UGR (unconventional gas resources) Advisor under<br />
development at Texas A&M by a team <strong>of</strong> graduate<br />
students and pr<strong>of</strong>essors.<br />
Approach<br />
To complete the Drilling Advisory Module for tight<br />
gas reservoirs, we have identified and reviewed<br />
relevant data in worldwide literature on tight gas<br />
reservoirs with a strong emphasis on the latest<br />
drilling technologies, such as: casing drilling,<br />
underbalanced drilling, managed pressure drilling,<br />
horizontal drilling, directional S-shaped drilling (well<br />
clusters) and coiled tubing drilling. We have analyzed<br />
under which critical parameters one technology<br />
has been preferred or is currently being applied in<br />
comparison with other drilling techniques. Further,<br />
we have extracted key criteria and have developed<br />
decision charts, which mimic the thinking process <strong>of</strong><br />
an expert. We have written Visual Basic programs<br />
using Micros<strong>of</strong>t Visual Studio implementing all the<br />
decisions charts created during this research. Finally,<br />
we will test and validate the Drilling Advisory Module<br />
with U.S. tight gas real cases.<br />
Accomplishments<br />
Our results have led to the following accomplishments:<br />
» A drilling advisory system has been designed and<br />
programmed for a Windows O.S. environment in<br />
order to capture the industry best drilling practices<br />
from tight gas reservoirs.<br />
» The advisory system has been divided into<br />
several sub-modules to guide the user through<br />
the multiple steps to make decision selecting<br />
drilling technologies and methods to drill tight gas<br />
reservoirs. Each <strong>of</strong> the sub-modules deals with<br />
a specific topic (well data, drilling parameters,<br />
drilling time, drilling cost, ranking). Each dataset<br />
can be loaded or saved in a text file for analysis<br />
or post-processing using other s<strong>of</strong>tware (Micros<strong>of</strong>t<br />
Excel).<br />
» The advisory system is designed with a user-friendly<br />
interface, to help select efficient and successful<br />
drilling technologies and drilling methods.<br />
» The drilling advisory system outputs more than<br />
one feasible solution for a given well or field.<br />
» The logic behind the advisory system, mainly based<br />
on decision charts developed by collecting relevant<br />
data from the petroleum engineering literature<br />
and discussions with industry drilling experts, is a<br />
good approach to mimic expert decision-making.<br />
» This project has illustrated several examples that<br />
happen to match the current industry drilling best<br />
practices or anticipate upcoming drilling practices<br />
in the studied area. These simulations showed that<br />
the drilling advisory system could deliver similar<br />
recommendations in comparison with a team <strong>of</strong><br />
experienced drilling experts.<br />
» Drilling time, drilling cost estimation and ranking<br />
technologies, and methods sub-modules provide<br />
the user with an extended decision making tool<br />
when several solutions are feasible.<br />
» The drilling advisory system has been designed<br />
and programmed for easy integration within the<br />
Unconventional Gas Resources Advisor. It can be<br />
further upgraded with other drilling sub-modules<br />
or new drilling technologies when they are mature<br />
on the market.<br />
Project Information<br />
1.1.12 Developing an Expert System for Well Completions<br />
in Tight Gas Reservoirs Worldwide<br />
Related Publications<br />
Pilisi, N.: <strong>2009</strong>. An Advisory System for Selecting Drilling<br />
Technologies and Methods in Tight Gas Reservoirs. MS<br />
thesis, Texas A&M U., College Station, Texas.<br />
Contacts<br />
Stephen A. Holditch<br />
979.845.2255<br />
holditch@tamu.edu<br />
Catalin Teodoriu<br />
catalin.teodoriu@pe.tamu.edu<br />
Nicolas Pilisi<br />
CRISMAN INSTITUTE<br />
14<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Assessment <strong>of</strong> API Thread Connections under Tight Gas Well Conditions<br />
Introduction<br />
The modern oil and gas industry <strong>of</strong> America has seen<br />
most <strong>of</strong> the high quality, easily obtainable resources<br />
already produced, thus causing wells to be drilled<br />
deeper in search <strong>of</strong> unconventional resources. This<br />
means Oil Country Tubular Goods (OCTG) must<br />
improve in order to withstand harsher conditions,<br />
such as tight gas sand wells, especially the ability<br />
<strong>of</strong> connections to effectively create leak-tight seals.<br />
gas reservoirs around the world produced average<br />
reservoir properties, which can be used as guidelines<br />
when deciding which type <strong>of</strong> connections to be used.<br />
Objective<br />
This study investigated the use and sealing <strong>of</strong> API<br />
long thread connections in tight gas wells.<br />
Approach<br />
A review <strong>of</strong> previous works on the capabilities and<br />
limitations <strong>of</strong> thread connections was done. This<br />
review identified several experiments and studies<br />
done on API connections to determine the limits<br />
<strong>of</strong> their capabilities, and covered simulations done<br />
on API connections using Finite Element Method<br />
(FEM) analysis and the importance <strong>of</strong> their findings.<br />
Experiments conducted to test the performance <strong>of</strong><br />
thread compounds were also reviewed.<br />
The average values obtained represent the minimum<br />
values API connections should be able to seal. These<br />
values can also be used in experiments designed to<br />
test the leakage <strong>of</strong> thread connections, namely the<br />
grooved plate method. The experiment can be done<br />
under these conditions <strong>of</strong> temperature and pressure<br />
and the results can signify the possible behavior <strong>of</strong><br />
thread compounds and thread connections in tight<br />
gas fields.<br />
(continued on next page)<br />
In order to have an idea <strong>of</strong> the type <strong>of</strong> conditions<br />
present in tight gas reservoirs, published data from<br />
around the world was also reviewed, with a focus on<br />
reported reservoir properties and drilling plans.<br />
In addition, this study will measure the viscosity<br />
<strong>of</strong> thread compounds. Because thread compound<br />
is essential to the function <strong>of</strong> thread connections,<br />
the knowledge <strong>of</strong> its viscosity can help choose<br />
the most suitable compound. Some viscosity<br />
measurements were conducted on several samples<br />
<strong>of</strong> thread compounds to identify actual values for<br />
thread compound at certain conditions following<br />
the guidelines set down by ASTM D 2196 (American<br />
Society <strong>of</strong> Testing and Materials). This information<br />
will be useful in predicting the behavior <strong>of</strong> the<br />
thread compound inside the helical paths within the<br />
connection. Also, knowing the value <strong>of</strong> the viscosity<br />
<strong>of</strong> a thread compound can also be used to form an<br />
analytical assessment <strong>of</strong> the grooved plate method<br />
by providing a means to calculate a pressure gradient<br />
which impacts the leakage.<br />
Accomplishments<br />
A survey <strong>of</strong> many drilling projects done in tight<br />
Project Information<br />
1.1.17 Assessment <strong>of</strong> API LTC Wellbore Integrity for Tight<br />
Gas Sands<br />
Contacts<br />
Jerome Schubert<br />
979.862.1195<br />
jerome.schubert@pe.tamu.edu<br />
Catalin Teodoriu<br />
catalin.teodoriu@pe.tamu.edu<br />
Dwayne Bourne<br />
CRISMAN INSTITUTE<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
15
A procedure to measure the viscosity <strong>of</strong> thread<br />
compound was established and used to measure<br />
the viscosities <strong>of</strong> three different samples <strong>of</strong> thread<br />
compound at various temperatures. Viscosity values<br />
are shown below:<br />
The experiment known as the grooved plate method<br />
can be carried out using the results from the tight<br />
gas reservoirs as test parameters to identify leak<br />
parameters <strong>of</strong> API round thread connections.<br />
The slot flow approximation can be used as an<br />
analytical method to reinforce experimental data<br />
or be used instead <strong>of</strong> conducting lengthy and costly<br />
experiments.<br />
The data above was fitted to a function and<br />
extrapolated to find the viscosity at the average<br />
reservoir temperature found from the review <strong>of</strong> tight<br />
gas projects. The viscosities <strong>of</strong> each <strong>of</strong> the thread<br />
compounds at 256°F are shown below. These values<br />
represent the expected viscosity <strong>of</strong> thread compound<br />
in tight gas reservoirs.<br />
The thread viscosities found above can be used<br />
in conjunction with the slot flow approximation to<br />
provide a means <strong>of</strong> finding a pressure gradient along<br />
the grooves <strong>of</strong> the grooved plate used in the groove<br />
plate method. This pressure gradient can be used to<br />
simulated results by applying the pressure gradient<br />
to determine leak pressure before the experiment<br />
is actually conducted. This can be used as a check<br />
<strong>of</strong> experimental results to validate experimental<br />
procedure.<br />
Future Work<br />
The measurement <strong>of</strong> the viscosity <strong>of</strong> the thread<br />
compound samples can be repeated using the<br />
average temperatures, which can better represent<br />
downhole conditions <strong>of</strong> tight gas wells.<br />
16<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Gas Shales – Geomechanics/Completions<br />
Introduction<br />
The Woodford shale gas is an ultra-low permeability<br />
reservoir (0.000001 md to 0.001 md). Commercial<br />
gas production is made possible by hydraulic fracture<br />
stimulation. Optimum hydraulic fracture treatment<br />
design needs to consider geomechanical principles<br />
in fracture initiation and propagation <strong>of</strong> multiple<br />
transverse fractures in horizontal wells. Often,<br />
Woodford shale reservoir development is achieved<br />
by drilling multiple parallel horizontal wells (on N-S<br />
azimuth), with approximately 600 ft spacing. Each<br />
treatment stage in a well is designed to create a<br />
stimulated volume, defined as the rock volume<br />
contacted by treatment fluid and proppant, which<br />
experiences a desired enhancement to permeability.<br />
For reservoir optimization, the collective network <strong>of</strong><br />
stimulations should affect the maximum volume,<br />
with minimal (optimal) overlap <strong>of</strong> adjacent treatment<br />
stages.<br />
Objectives<br />
The problem has several related components: the<br />
selection <strong>of</strong> an appropriate perforation scheme–for<br />
open and cased hole–for initiating multiple fractures<br />
within a fracture stage and the determination <strong>of</strong> an<br />
optimum fracture treatment spacing for a 1000 ft<br />
section <strong>of</strong> a well using fracture mechanics models.<br />
The latter should consider the interaction between<br />
neighboring wells in generating a stimulated volume.<br />
In this research, we present a survey <strong>of</strong> state-<strong>of</strong>-theart<br />
practices with reference to the above issues to<br />
assist in selecting the best strategy for the Woodford<br />
shale reservoir.<br />
Approach<br />
In wells with low to medium permeability like<br />
Woodford’s, transverse fractures that extend<br />
sideways provide drainage for a larger area <strong>of</strong> the<br />
formation, experiencing a long-term production<br />
increase.<br />
A major concern in designing the perforation clusters<br />
for transverse fracturing design is the stressshadow<br />
effect. When a hydraulic fracture is opened,<br />
the resulting compression will increase the amount<br />
<strong>of</strong> minimum horizontal stress because <strong>of</strong> the net<br />
fracturing pressure existence. If this compressional<br />
stress is big enough, it can turn minimum horizontal<br />
stress into maximum horizontal stress, thus changing<br />
a transverse fracture into a longitudinal one.<br />
By reducing the number <strong>of</strong> clusters per stage,<br />
stress interference can be minimized, which will<br />
reduce the likelihood <strong>of</strong> having improper fracture<br />
propagation. However, this reduction will increase<br />
the number <strong>of</strong> stages per well, which means more<br />
completion costs. Therefore, the number <strong>of</strong> stages<br />
and the spacing between the perforation clusters<br />
are the result <strong>of</strong> optimization between the cost <strong>of</strong><br />
having more stages and reducing the stress shadow<br />
effect. For our cemented horizontal wells, the best<br />
completion strategy is to limit the number <strong>of</strong> stages<br />
and stimulate two or three perforation clusters per<br />
stage.<br />
Accomplishments<br />
Our study on stress shadow shows that it becomes<br />
quite small at an <strong>of</strong>fset distance equal to about<br />
two times the fracture height (2H). This minimum<br />
spacing (2H) is required to effectively minimize the<br />
conflicts between two transverse fractures. Also<br />
the perforation-cluster lengths should not be longer<br />
than four times the wellbore diameter. This is to<br />
prevent the creation <strong>of</strong> competing multiple fractures.<br />
Considering the fracture height <strong>of</strong> 250 ft to 280 ft for<br />
Woodford shale formation (Vulgamore et al., 2007),<br />
and a horizontal lateral diameter <strong>of</strong> 7 in, the best<br />
option will be to have three perforation clusters with<br />
maximum lengths <strong>of</strong> 2 ft that are stimulated in a<br />
single stage for each 1000 ft <strong>of</strong> horizontal lateral.<br />
To align perforations with the preferred fracture<br />
plane, they should be oriented 0°/180° phasing.<br />
The other alternative is 60° phasing when used in<br />
conjunction with an acid-soluble cement system.<br />
Both perforation strategies have shown to be<br />
effective (Ketter et al., 2008).<br />
CRISMAN INSTITUTE<br />
Project Information<br />
1.1.18 Gas Shales – Geomechanics/Completions<br />
Contacts<br />
Ahmad Ghassemi<br />
979.845.2206<br />
ahmad.ghassemi@pe.tamu.edu<br />
Babak Akbarnejad<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
17
PRISE – Petroleum Resource Investigation Summary and Evaluation<br />
Introduction<br />
As conventional resources are depleted,<br />
unconventional gas resources (UGRs) are becoming<br />
increasingly important to the U.S and world energy<br />
supply. The volume <strong>of</strong> UGRs is generally unknown<br />
in most international basins. However, in 25<br />
mature U.S. basins, UGRs have been produced for<br />
decades and are well characterized in the petroleum<br />
literature. The objective <strong>of</strong> this work was to develop<br />
a method for estimating technically recoverable<br />
UGRs in target, or exploratory, basins. The method<br />
was based on quantitative relations between known<br />
conventional and unconventional hydrocarbon<br />
resource types in mature U.S. basins.<br />
hydrocarbon resources are conventional oil and gas,<br />
and 90% are from unconventional resources.<br />
Significance<br />
PRISE may be used to estimate the volume <strong>of</strong><br />
technically recoverable hydrocarbon resources<br />
in any basin worldwide and, hopefully, assist<br />
early economic and development planning. PRISE<br />
methodology for estimating UGRs should be further<br />
tested in diverse sedimentary basin types.<br />
Conventional is 0–9% greater<br />
10/13/<strong>2009</strong><br />
than in previous calculation From Old, <strong>2009</strong><br />
Objectives<br />
The primary objective <strong>of</strong> developing PRISE<br />
was to establish a methodology for estimating<br />
unconventional technically recoverable resources<br />
in basins with no, or very little, unconventional<br />
resource development or data. A second objective<br />
was to create a system the industry can use to<br />
better understand the potential <strong>of</strong> unconventional<br />
resources in the target basins around the world.<br />
Armed with such estimates and understanding, the<br />
industry can better justify its future development<br />
activities or, in some cases, change course. For<br />
this study, published resource information from the<br />
USGS, PGC, NPC, EIA, and GTI were used to quantify<br />
recoverable resources in seven North American<br />
basins.<br />
1<br />
Quantified Recoverable Resources – 7 N.A. Basins (Old, <strong>2009</strong>).<br />
Accomplishments<br />
To develop the methodology to estimate resource<br />
volumes, we used data from the U.S. Geological<br />
Survey, Potential Gas Committee, Energy<br />
Information Administration, National Petroleum<br />
Council, and Gas Technology Institute to evaluate<br />
relations among hydrocarbon resource types in the<br />
Appalachian, Black Warrior, Greater Green River,<br />
Illinois, San Juan, Uinta-Piceance, and Wind River<br />
basins. PRISE can be used to predict technically<br />
recoverable UGRs for target basins, on the basis <strong>of</strong><br />
their known conventional resources. Input data for<br />
PRISE are cumulative production, proved reserves,<br />
growth, and undiscovered resources. We use<br />
published data to compare cumulative technically<br />
recoverable resources for each basin. For the seven<br />
basins studied, we found that 10% <strong>of</strong> the recoverable<br />
Project Information<br />
1.1.20 Continued Development <strong>of</strong> PRISE<br />
Contacts<br />
Stephen A. Holditch<br />
979.845.2255<br />
holditch@tamu.edu<br />
Walter B. Ayers<br />
979.458.0721<br />
walt.ayers@pe.tamu.edu<br />
Kun Cheng<br />
CRISMAN INSTITUTE<br />
18<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
An Investigation <strong>of</strong> Regional Variations <strong>of</strong> Barnett Shale Reservoir Properties, and<br />
Resulting Variability <strong>of</strong> Hydrocarbon Composition and Well Performance<br />
Objectives<br />
Although the Barnett is one <strong>of</strong> the most prolific gas<br />
plays in the U.S., fundamental controls on variable<br />
gas productivity <strong>of</strong> individual wells and different<br />
regions are poorly understood. The Barnett shale<br />
is very heterogeneous; formation thickness and<br />
lithology, thermal maturity, structural setting,<br />
reservoir fluids, etc. vary greatly throughout the<br />
basin. The objectives <strong>of</strong> this research are to:<br />
» clarify the stratigraphic and regional variations <strong>of</strong><br />
Barnett Shale reservoir and geologic properties;<br />
and<br />
» evaluate the controls that these properties exert<br />
on Barnett Shale gas well performance.<br />
maps (best monthly production, first 12 month<br />
cumulative production, etc.) to assess controls on<br />
reservoir performance. There were four phases to<br />
this project.<br />
First, we correlated reservoir facies to assess vertical<br />
and lateral variability <strong>of</strong> Barnett shale. The Barnett<br />
Shale was subdivided into 13 reservoir sequences<br />
that were then upscaled into four reservoir units<br />
(Fig. 1). Second, we mapped and analyzed regional<br />
variations <strong>of</strong> oil and gas production rates and gas/<br />
oil ratios. Third, we evaluated shale geochemistry<br />
parameters, including organic richness, thermal<br />
maturity, and fluid types. We used petrophysical<br />
evaluations to estimate geochemical parameters<br />
from well logs and to estimate reservoir property <strong>of</strong><br />
the four reservoir units. Finally, we integrated the<br />
above to assess reservoir controls on production<br />
rates <strong>of</strong> individual wells and different regions <strong>of</strong> the<br />
Fort Worth Basin. Structural settings and thermal<br />
maturity are dominantly controls on regional<br />
production variations. Local variations in Barnett<br />
production primarily vary with the perforation<br />
interval targeted in Barnett Shale.<br />
Significance<br />
The study lends insights to reservoir controls on<br />
well performance and should assist operators with<br />
optimization <strong>of</strong> development strategies and gas<br />
recovery. The approach used in this study may be<br />
applicable to other developing shale gas plays, such<br />
as the Marcellus and Haynesville Shales.<br />
CRISMAN INSTITUTE<br />
Fig. 1. Type well log showing Barnett Shale stratigraphy and reservoir<br />
units mapped in this study.<br />
Approach<br />
This is an integrated study using well log and<br />
production data to evaluate geologic and engineering<br />
controls on reservoir performance. We used raster<br />
image logs to correlate and map Barnett Shale facies,<br />
and we used digital logs to assess petrophysical<br />
properties. Facies and petrophysical properties<br />
maps were compared to reservoir performance<br />
Project Information<br />
1.2.3 Assessment <strong>of</strong> API LTC Wellbore Integrity for Tight<br />
Gas Sands<br />
Related Publications<br />
Tian, Y. and Ayers, W. Regional Stratigraphic and Sedimentary<br />
Facies Analyses, Barnett Shale, Fort Worth Basin, Texas.<br />
Paper 0919 presented at the <strong>2009</strong> International Coalbed<br />
and Shale Gas Symposium, Tuscaloosa, Alabama, 18-22<br />
May.<br />
Contacts<br />
Walter B. Ayers<br />
979.458.0721<br />
walt.ayers@pe.tamu.edu<br />
Yao Tian<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
19
Gas Shales Simulation and Production Data Analysis<br />
Objectives<br />
Rate decline forecasting <strong>of</strong> wells in tight gas/shale<br />
gas reservoirs using modern decline curve analysis<br />
can result in dramatic overestimation <strong>of</strong> reserves.<br />
The cause for this error is usually incorrect<br />
interpretation <strong>of</strong> transient flow data (i.e., data which<br />
are NOT affected by reservoir boundaries).<br />
The extremely low permeability <strong>of</strong> shale gas and<br />
tight gas reservoirs causes the transient flow period<br />
to last years or decades. Additionally, the physics<br />
<strong>of</strong> transport and storage controlling the gas flow in<br />
shale gas systems is complex and varies markedly<br />
between reservoirs. Finally, posing yet another<br />
complication, most wells in these reservoir types<br />
are drilled horizontally and hydraulically fractured<br />
multiple times.<br />
the flow concept <strong>of</strong> van Kruijsdijk and Dullaert, and<br />
showed how production data analysis can be used to<br />
identify these flow regimes.<br />
In <strong>2009</strong>, TAMSIM was used to study the effects <strong>of</strong><br />
variation <strong>of</strong> numerous reservoir and completion<br />
parameters on well performance. One paper<br />
(SPE 124961: A Numerical Study <strong>of</strong> Tight Gas<br />
and Shale Gas Reservoir Systems) published this<br />
year served to characterize the effects <strong>of</strong> sorption,<br />
fracture conductivity, fracture spacing, and matrix<br />
permeability for various assumptions <strong>of</strong> single- and<br />
dual-porosity reservoirs, with and without laterally<br />
conductive layers. This work was presented at the<br />
The objectives <strong>of</strong> this research project have been to<br />
build a numerical simulator for shale gas reservoir<br />
systems and to study the complex flow regimes<br />
found around horizontal wells with multiple hydraulic<br />
fractures and enable identification and interpretation<br />
<strong>of</strong> these regimes through production data analysis.<br />
Approach<br />
Our approach has been to determine the proper<br />
theoretical foundation for creating a tight gas/shale<br />
gas simulator, and to implement these concepts<br />
into the purpose-built numerical simulator TAMSIM,<br />
which is descended from the TOUGH+ family <strong>of</strong><br />
numerical simulators.<br />
To determine a sound theoretical basis, we<br />
undertook a literature search, focusing on the<br />
physics and simulation <strong>of</strong> coalbed methane, tight<br />
gas, and shale gas reservoirs. This literature review<br />
also entailed research into specific storage and<br />
transport mechanisms such as flow in naturally and<br />
hydraulically fractured porous media, diffusion in<br />
porous media, and surface sorption.<br />
In 2008, work was focused on implementation and<br />
validation <strong>of</strong> the capability to accurately simulate<br />
horizontal wells with multiple transverse hydraulic<br />
fractures. This part <strong>of</strong> the functionality has been<br />
validated against various other methods, and used<br />
to provide synthetic cases for study and history<br />
matching. Through simulation, we created clear<br />
visualizations <strong>of</strong> the progression <strong>of</strong> flow according to<br />
The progression <strong>of</strong> flow regimes in multiple fractured horizontal wells<br />
(van Kruysdijk and Dullaert [1989])<br />
Project Information<br />
1.2.5 Shale Gas Reserves Estimation<br />
Contacts<br />
Tom Blasingame<br />
979.845.2292<br />
t-blasingame@tamu.edu<br />
C. Matt Freeman<br />
CRISMAN INSTITUTE<br />
20<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
<strong>2009</strong> SPE ATCE in New Orleans. A second paper (A<br />
Numerical Study <strong>of</strong> Microscale Flow Effects in Tight<br />
Gas and Shale Gas Reservoir Systems) concerning<br />
the micro- and nano-scale flow effects caused by<br />
extremely fine pore structure in shale was presented<br />
at the TOUGH Symposium at Lawrence Berkeley<br />
National Laboratory.<br />
Additionally, several other capabilities have been<br />
added to TAMSIM, though not yet rigorously<br />
validated. These include multiphase flow and<br />
multicomponent diffusion. Work on TAMSIM<br />
continues in collaboration with Dr. George Moridis.<br />
Significance<br />
The significance <strong>of</strong> the work to this point has been<br />
to provide clear visualization and diagnostic tools<br />
for identification <strong>of</strong> the complex flow regimes found<br />
near horizontal wells with multiple fractures in tight<br />
gas reservoirs, and to deliver insight into the effects<br />
<strong>of</strong> reservoir and completion parameters on the<br />
behavior <strong>of</strong> these pr<strong>of</strong>iles. Properly accounting for<br />
the flow regime effects <strong>of</strong> inter-fracture interference<br />
on production data will enable the engineer to<br />
constrain rate decline predictions.<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
21
Characterization <strong>of</strong> Rock Transport Properties in Tight Gas and Shale<br />
Objectives<br />
The objective <strong>of</strong> this work is to determine transport<br />
properties such as permeability, porosity, and<br />
fracture characteristics in very low permeability<br />
rocks such as tight gas sandstone and shale. Further,<br />
we would be characterizing stress-induced changes<br />
in permeability in these low permeability rocks.<br />
This would be done using the pulse permeameter<br />
and steady-state measurements using under<br />
triaxial stress. Generally, “Pressure Pulse Test”<br />
is recommended in tight gas and shale reservoirs<br />
instead <strong>of</strong> conventional “Steady State Permeability<br />
Test”. The “Pressure Pulse Permeameter” machine<br />
in Rock Mechanics Lab can be a good tool for<br />
determining rock properties.<br />
permeability/porosity check plugs to make sure the<br />
values are precise. After calibrations and validations,<br />
we will be ready to measure permeability/porosity<br />
<strong>of</strong> the tight core samples.<br />
Approach<br />
During this month and the last month, we focused<br />
on the accuracy <strong>of</strong> the transducers and found out<br />
that a part <strong>of</strong> the measured leakage rate came from<br />
the fluctuations in the outputs <strong>of</strong> the transducers.<br />
The downstream differential transducer had a larger<br />
rate <strong>of</strong> fluctuations. We tested the leakage rate<br />
in different system pressures using impermeable<br />
core plugs and determined that the leakage rates<br />
in upstream and downstream transducers are<br />
consistent, which means the leakage comes from a<br />
point which connects both sections.<br />
Accomplishments<br />
To reduce the data fluctuation in the downstream<br />
part, we changed the downstream transducer, then<br />
calibrated and tested again. The leakage rate in the<br />
downstream part decreased from 1.6 psi/hr to ~ 1.1<br />
psi/hr. Then, since the shortest route that connects<br />
upstream and downstream sections to each other is<br />
the core holder, we inspected the core holder again<br />
and wrapped the outer diameter <strong>of</strong> the rubber sleeve<br />
inside the core holder with extra aluminum foil. It<br />
covered the torn parts <strong>of</strong> the previously wrapped<br />
foil, which had been generated due to shrinkage and<br />
extension <strong>of</strong> the rubber sleeve. With these changes<br />
made, we tested the leakage and the rates were<br />
now 0.3 psi/hr for upstream and 0.36 psi/hr for<br />
downstream, which are reasonable.<br />
Future Work<br />
Since the machine has had several changes and<br />
manipulations, for the next month we should calibrate<br />
the volumes and (if possible) test it with known<br />
Project Information<br />
1.2.6 Transport Properties Characterization <strong>of</strong> Tight Gas<br />
Shales<br />
Contacts<br />
Ahmad Ghassemi<br />
979.845.2206<br />
ahmad.ghassemi@pe.tamu.edu<br />
Vahid Serajian<br />
CRISMAN INSTITUTE<br />
22<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Rate Transient Analysis in Shale Gas Reservoirs with Transient Linear Behavior<br />
Introduction<br />
Many hydraulically fractured shale gas horizontal<br />
wells in the Barnett shale have been observed to<br />
exhibit transient linear behavior, characterized by<br />
a one-half slope on a log-log plot <strong>of</strong> rate against<br />
time. This transient linear flow regime is believed to<br />
be caused by transient drainage <strong>of</strong> low permeability<br />
matrix blocks into adjoining fractures, and is the only<br />
flow regime available for analysis in many wells.<br />
Objectives<br />
A hydraulically fractured horizontal shale gas<br />
well will be modeled as a horizontal well draining<br />
a rectangular geometry containing a network <strong>of</strong><br />
fractures separated by matrix blocks (dual-porosity<br />
system). The solutions presented by El-Banbi for<br />
a linear dual porosity model will be extended and<br />
applied to this system. The effects <strong>of</strong> desorption<br />
and diffusion will be assumed negligible in this<br />
paper since they will not be important at reservoir<br />
pressures <strong>of</strong> interest in the Barnett shale.<br />
The objectives <strong>of</strong> this research are:<br />
» To develop mathematical models to analyze these<br />
multi-stage hydraulically fractured horizontal wells<br />
» To develop a rate transient analysis procedure for<br />
analyzing these wells to enable the determination<br />
<strong>of</strong> reservoir characteristics, drainage volume/<br />
original gas-in-place (OGIP), fracture network<br />
characteristics and assessment <strong>of</strong> the effectiveness<br />
<strong>of</strong> different hydraulic fracture treatments.<br />
Accomplishments<br />
The hydraulically fractured shale gas reservoir system<br />
was described by a linear dual porosity model which<br />
consisted <strong>of</strong> a bounded rectangular reservoir with<br />
slab matrix blocks draining into adjoining fractures<br />
and subsequently to a horizontal well in the center.<br />
The well fully penetrates the rectangular reservoir.<br />
Convergence skin is incorporated into the linear<br />
model to account for the presence <strong>of</strong> the horizontal<br />
wellbore.<br />
Five flow regions were identified with this model.<br />
Region 1 is due to transient flow only in the<br />
fractures. Region 2 is bilinear flow and occurs when<br />
the matrix drainage begins simultaneously with<br />
the transient flow in the fractures. Region 3 is the<br />
response for a homogeneous reservoir. Region 4<br />
is dominated by transient matrix drainage and is<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
the transient flow regime <strong>of</strong> interest. Region 5 is<br />
the boundary dominated transient response. New<br />
working equations were developed and presented<br />
for analysis <strong>of</strong> Regions 1 to 4. No equation was<br />
presented for Region 5 as it requires a combination<br />
<strong>of</strong> material balance and productivity index equations<br />
beyond the scope <strong>of</strong> this work.<br />
It is concluded that the transient linear region<br />
observed in field data occurs in Region 4, drainage <strong>of</strong><br />
the matrix. A procedure was presented for analysis.<br />
The only parameter that can be determined with<br />
available data is the matrix drainage area, Acm.<br />
It was demonstrated that the effect <strong>of</strong> skin under<br />
constant rate and constant bottomhole pressure<br />
conditions is not similar for a linear reservoir, as<br />
the constant bottomhole pressure shows a gradual<br />
diminishing effect <strong>of</strong> skin. A new analytical equation<br />
was presented to describe this situation<br />
It was also demonstrated that different shape<br />
factor formulations (Warren and Root, Zimmerman<br />
and Kazemi) result in similar Region 4 transient<br />
linear response provided that the appropriate f(s)<br />
modifications consistent with lAc calculations are<br />
conducted. It was also demonstrated that different<br />
matrix geometry exhibit the same Region 4 transient<br />
linear response when the area-volume ratios are<br />
similar.<br />
Project Information<br />
1.2.8 Modeling and Analysis <strong>of</strong> Linear Transient Flow<br />
Regime in Shale Gas Reservoirs<br />
Related Publications<br />
El-Banbi, A.H.: 1998, Analysis <strong>of</strong> Tight Gas Wells. PHD<br />
dissertation, Texas A&M<br />
U., College Station, Texas.<br />
Bello, R.O.: <strong>2009</strong>, Rate Transient Analysis in Shale Gas<br />
Reservoirs with Transient Linear Behavior. PHD dissertation,<br />
Texas A&M U., College Station, Texas.<br />
Contacts<br />
Bob Wattenbarger<br />
979.845.0173<br />
bob.wattenbarger@pe.tamu.edu<br />
Rasheed Bello<br />
CRISMAN INSTITUTE<br />
23
An Analytical Approach to Model Shale Gas Reservoir Flow Including Desorption<br />
Effects<br />
Objectives<br />
The objective <strong>of</strong> this work is to develop a semianalytical<br />
model to represent the pressure-time<br />
performance <strong>of</strong> shale gas reservoirs including<br />
desorption. To achieve this goal, we have developed<br />
a suite <strong>of</strong> simulation cases to study the effect <strong>of</strong><br />
the desorption term, reservoir properties (primarily<br />
permeability), and gas flowrates. We have<br />
formulated a “dimensionless” form <strong>of</strong> the viscositycompressibility<br />
product as a mechanism to visualize<br />
and characterize the non-linear behavior <strong>of</strong> this<br />
case.<br />
Approach<br />
The “diffusivity equation” including desorption (as<br />
an effective compressibility, c e<br />
) is given as:<br />
1 p<br />
p gicei<br />
g ce<br />
p<br />
r<br />
<br />
r r<br />
r<br />
k <br />
gicei<br />
<br />
t<br />
Where<br />
c <br />
m gSC<br />
VL<br />
pL<br />
ce<br />
cg<br />
<br />
<br />
2<br />
[ p p]<br />
We use numerical simulation to generate a suite<br />
<strong>of</strong> constant rate pressure-time responses for an<br />
infinite-acting circular reservoir. The behavior <strong>of</strong><br />
the nonlinearity (i.e., μ g<br />
c e<br />
) was studied for specific<br />
reservoir properties and flowrate. Using these<br />
results we developed an appropriate dimensionless<br />
time function (t D<br />
) to account for the effects due to<br />
desorption and formation permeability.<br />
In addition to a dimensionless time function, we<br />
also created a dimensionless rate function (q D<br />
),<br />
which accounts for permeability and flowrate. In<br />
Fig. 1 we present the overall “correlation” <strong>of</strong> the<br />
non-linear term as functions <strong>of</strong> dimensionless time<br />
and rate.<br />
Significance<br />
» The non-linear desorption term can be expressed<br />
as an effective compressibility term in the gas<br />
diffusivity equation.<br />
» The effects <strong>of</strong> desorption can be incorporated into<br />
an appropriately defined dimensionless time.<br />
» The effects <strong>of</strong> reservoir properties and flowrate<br />
can be incorporated in an appropriately defined<br />
dimensionless rate.<br />
g<br />
L<br />
p<br />
Fig. 1. Overall “correlation” <strong>of</strong> the non-linear term, presented as functions<br />
<strong>of</strong> dimensionless time and rate.<br />
» For higher values <strong>of</strong> the flowrate (or dimensionless<br />
flowrate), the non-linear term becomes more<br />
dominant (deviates from liquid flow theory).<br />
Future Work<br />
» Develop an exhaustive sequence <strong>of</strong> cases to<br />
investigate the non-linear behavior caused by<br />
pressure-dependent gas expansion and gas<br />
desorption.<br />
» Develop a semi-analytical solution for the pressuretime<br />
behavior <strong>of</strong> this case based on the correlation<br />
<strong>of</strong> the non-linearity.<br />
Project Information<br />
1.2.9 Modeling Shale Gas Reservoir Performance<br />
Related Publications<br />
Bumb, A.C. and McKee, C.R. Gas-Well Testing in the<br />
Presence <strong>of</strong> Desorption for Coalbed Methane and Devonian<br />
Shale. SPEFE (March 1988): 179-185.<br />
Contacts<br />
Tom Blasingame<br />
979.845.2292<br />
t-blasingame@tamu.edu<br />
Sonia Jam<br />
CRISMAN INSTITUTE<br />
24<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Water Production Issues in the Barnett Shale<br />
Objectives<br />
The objectives <strong>of</strong> this research project were as<br />
follows:<br />
» Determine in a quantitative sense the effect <strong>of</strong><br />
water production on gas production in gas shales.<br />
» Identify the different water producing mechanisms<br />
in the Barnett Shale and characterize them based<br />
on production data.<br />
» Determine the relationship between well location,<br />
reservoir, fracturing treatment/completion data<br />
and water production.<br />
Our focus was an analysis <strong>of</strong> data available from<br />
the Barnett Shale using descriptive statistical and<br />
virtual intelligence techniques.<br />
Approach<br />
A Barnett Shale water production dataset from<br />
approximately 11,000 completions was analyzed<br />
using conventional statistical techniques. Additionally,<br />
a water-hydrocarbon ratio and first derivative<br />
diagnostic plot technique developed elsewhere for<br />
conventional reservoirs was extended to analyze<br />
Barnett Shale water production mechanisms. In<br />
order to determine hidden structure in well and<br />
production data, self-organizing maps and the<br />
k-means algorithm were used to identify clusters<br />
in data. A competitive learning based network<br />
was used to predict the potential for continuous<br />
water production from a new well. A feed-forward<br />
neural network was used to predict average water<br />
production for wells drilled in the Denton and Parker<br />
Counties <strong>of</strong> the Barnett Shale (Fig. 1).<br />
Self organized maps<br />
K-means algorithm<br />
Competitive learning<br />
Vector quantizer<br />
Neural networks<br />
Enable us see how<br />
data are clustered<br />
Enable us determine optimum<br />
number <strong>of</strong> clusters<br />
Enable us partition dataset<br />
into class <strong>of</strong> water producers<br />
and non-water producers<br />
Prediction <strong>of</strong> average<br />
water/gas production<br />
Fig. 1. Utility <strong>of</strong> various virtual intelligence routines.<br />
Accomplishments<br />
Using conventional techniques, we conclude that<br />
for wells <strong>of</strong> the same completion type, location is<br />
more important than time <strong>of</strong> completion or hydraulic<br />
fracturing strategy. Liquid loading has the potential<br />
to affect vertical more than horizontal wells (Fig.<br />
2). A MATLAB-based neural network tool was<br />
Flowing wellhead pressure (psia)<br />
2500<br />
2000<br />
1500<br />
1000<br />
500<br />
Minimum Required Flow Rate (Mcfd) vs WHP (psi)<br />
0<br />
0 200 400 600 800 1000 1200 1400 1600 1800 2000<br />
Average vertical<br />
well in Denton<br />
No Liquid Loading<br />
Minimum Required Flow Rate to prevent liquid loading (Mcfd)<br />
Fig. 2. Predictive Chart for onset <strong>of</strong> liquid loading in the Barnett Shale.<br />
(continued on next page)<br />
Liquid Loading<br />
region<br />
Average vertical<br />
well in Parker<br />
Average horizontal<br />
well in Denton<br />
CRISMAN INSTITUTE<br />
Project Information<br />
1.2.10 Shale Gas Water Production Issues<br />
Average horizontal<br />
well in Parker<br />
Related Publications<br />
Awoleke, O.O. <strong>2009</strong>. Analysis <strong>of</strong> Data from the Barnett<br />
Shale with Conventional Statistical and Virtual Intelligence<br />
Techniques. MS Thesis. Texas A&M U., College Station,<br />
Texas.<br />
Awoleke, O.O., Lane, R.H. Analysis <strong>of</strong> Data from the Barnett<br />
Shale Using Conventional Statistical and Virtual Intelligence<br />
Techniques. SPE Paper 127919 to be presented at the 2010<br />
SPE International Symposium and Exhibition on Formation<br />
Damage Control, Lafayette, Louisiana, 10–12 February.<br />
Contacts<br />
Robert Lane<br />
979.862.7654<br />
robert.lane@pe.tamu.edu<br />
Obadare Awoleke<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
25
P90<br />
P50<br />
P10<br />
Fig. 3. P10, P50 and P90 predictions <strong>of</strong> water production for horizontal<br />
wells drilled in the Parker County <strong>of</strong> the Barnett Shale.<br />
developed to predict average water production for<br />
Barnett Shale wells in Denton and Parker Counties<br />
(Fig. 3). The average prediction error for the tool<br />
varied between 10-26%, depending on well type<br />
and location.<br />
Significance<br />
Results from this work can be utilized to mitigate<br />
risk <strong>of</strong> water problems in new Barnett Shale wells<br />
and predict water issues in other shale plays.<br />
Engineers are provided a tool to predict potential<br />
for water production in new wells. The methodology<br />
used to develop this tool can be used to solve similar<br />
challenges in new and existing shale plays.<br />
26<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Enhanced Oil Refining Technology through E-Beam Thermal Cracking<br />
Objectives<br />
One <strong>of</strong> the critical problems with heavy oil and bitumen<br />
is that they require large amounts <strong>of</strong> thermal energy<br />
and expensive catalysts to upgrade. This research<br />
demonstrates that electron beam (E-Beam) heavy<br />
oil upgrading, which uses unique features <strong>of</strong> E-Beam<br />
irradiation, may be used to improve conventional<br />
heavy oil upgrading. E-Beam processing lowers the<br />
thermal energy requirements and could sharply<br />
reduce the investment in catalysts. The design <strong>of</strong><br />
the facilities can be simpler and will contribute to<br />
lowering the costs <strong>of</strong> transporting and processing<br />
heavy oil and bitumen. The main objective <strong>of</strong> this<br />
research is to investigate the effects <strong>of</strong> E-Beam<br />
irradiation on hydrocarbons and evaluate economics<br />
and potential applications <strong>of</strong> E-Beam technology<br />
throughout petroleum industry.<br />
a preliminary economic analysis based on energy<br />
consumption and comparing the economics <strong>of</strong><br />
E-Beam upgrading with conventional upgrading.<br />
Accomplishments<br />
We studied pure n-C 16<br />
, a naphtha cut, a combination<br />
<strong>of</strong> a well-defined hydrocarbon group, and asphaltene<br />
to evaluate the effect <strong>of</strong> radiation on heavy and<br />
very viscous components. To estimate the energy<br />
transfer mechanism in the system, we conducted<br />
two simulations: heat transfer simulation using<br />
computational fluid dynamics (CFD), and radiation<br />
transport Monte-Carlo simulation. With the results<br />
we obtained from the laboratory investigations, we<br />
proposed potential applications <strong>of</strong> this technology.<br />
In addition, we conducted a preliminary economic<br />
evaluation to compare E-Beam upgrading and<br />
conventional upgrading based on the energy used<br />
in each process.<br />
Significance<br />
The results <strong>of</strong> our study are very encouraging. From<br />
the experiments, we found that E-Beam effect on<br />
hydrocarbon is significant. We used less thermal<br />
(continued on next page)<br />
CRISMAN INSTITUTE<br />
A conceptual design <strong>of</strong> pipeline heavy oil upgrading. Electrons with high<br />
kinetic energy are generated by two E-Beam machines. These electrons<br />
enter the heavy oil and break the heavy molecules <strong>of</strong> the heavy oil.<br />
Approach<br />
Based on an intensive brainstorming with experts<br />
in the industry and an extensive literature review<br />
<strong>of</strong> past and current research, we set up three<br />
major stages to evaluate the applicability <strong>of</strong><br />
E-Beam for heavy oil upgrading. First, we planned<br />
laboratory experiments to investigate the effects <strong>of</strong><br />
E-Beam on hydrocarbons. We used a Van de Graff<br />
accelerator, which generates the high kinetic energy<br />
<strong>of</strong> electrons, and a laboratory scale apparatus to<br />
investigate extensively what effect radiation has<br />
on hydrocarbons. Second, we planned to study the<br />
energy transfer mechanism <strong>of</strong> E-Beam upgrading<br />
to optimize the process. Third, we planned to make<br />
Project Information<br />
1.3.4 Enhanced Oil Refining Technology through E-Beam<br />
Thermal Cracking<br />
Related Publications<br />
Yang, D., Kim, J., Silva, P., Barrufet, M. Moreira, R., and<br />
Sosa, J. Laboratory Investigation <strong>of</strong> E-Beam Heavy Oil<br />
Upgrading. Paper SPE 121911, presented at the <strong>2009</strong><br />
SPE Latin American and Caribbean Petroleum Engineering<br />
Conference, Cartagena, Columbia, 31 May-3 June.<br />
Yang, D.: <strong>2009</strong>. Heavy Oil Upgrading from Electron Beam<br />
(E-Beam) Irradiation. MS thesis. Texas A&M U., College<br />
Station, Texas.<br />
Contacts<br />
Maria Barrufet<br />
979.845.0314<br />
maria.barrufet@pe.tamu.edu<br />
Daegil Yang<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
27
Density distribution from heat transfer simulation and corresponding<br />
radiation amount distribution <strong>of</strong> multiphase n-C16 at 2.0 cm (a), 4.0 cm<br />
(b), and 6.0 cm (c) from the bottom <strong>of</strong> the reactor.<br />
energy for distillation <strong>of</strong> n-hexadecane (n-C 16<br />
) and<br />
naphtha with E-Beam. The results <strong>of</strong> experiments<br />
with asphaltene indicate that E-Beam enhances<br />
the decomposition <strong>of</strong> heavy hydrocarbon molecules<br />
and improves the quality <strong>of</strong> upgraded hydrocarbon.<br />
From the study <strong>of</strong> energy transfer mechanism, we<br />
estimated heat loss, fluid movement, and radiation<br />
energy distribution during the reaction. The results<br />
<strong>of</strong> our economic evaluation show that E-Beam<br />
upgrading appears to be economically feasible<br />
in petroleum industry applications. These results<br />
indicate significant potential for the application<br />
<strong>of</strong> E-Beam technology throughout the petroleum<br />
industry, particularly near production facilities,<br />
transportation pipelines, and refining industry.<br />
28<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Experimental Investigation <strong>of</strong> Caustic Steam Injection for Heavy Oils<br />
Introduction<br />
Heavy oil is a part <strong>of</strong> the unconventional petroleum<br />
reserve. Heavy oil does not flow very easily and<br />
is classified as heavy because <strong>of</strong> its high specific<br />
gravity. With increasing demand for oil and with<br />
depleting light oil resources, it is essential to explore<br />
the unconventional petroleum reserve <strong>of</strong> which<br />
heavy oil constitutes a major part, about 15% <strong>of</strong> the<br />
world’s remaining oil reserves.<br />
Objectives<br />
An experimental study was conducted to compare<br />
the effect <strong>of</strong> steam injection and caustic steam<br />
injection in improving the recovery <strong>of</strong> San Ardo and<br />
Duri heavy oils.<br />
Approach<br />
A 67 cm long x 7.4 cm O.D (outer diameter),<br />
steel injection cell was used in the study. Six<br />
thermocouples were placed at specific distances<br />
in the injection cell to record temperature pr<strong>of</strong>iles<br />
and thus the steam front velocity. The injection cell<br />
was filled with a mixture <strong>of</strong> oil, water and sand.<br />
Steam was injected at superheated conditions <strong>of</strong><br />
238°C with the cell outlet pressure set at 200 psig,<br />
the cell pressure similar to that found in San Ardo<br />
field. The pressure in the separators was kept at 50<br />
psig. The separator liquid was sampled at regular<br />
intervals. The liquid was centrifuged to determine<br />
the oil and water volumes, and oil viscosity, density<br />
and recovery. Acid number measurements were<br />
made by the titration method using a pH meter and<br />
measuring the EMF values. The interfacial tensions<br />
<strong>of</strong> the oil for different concentrations <strong>of</strong> NaOH were<br />
also measured using a tensionometer.<br />
Accomplishments<br />
Experimental results show that for Duri oil, the<br />
addition <strong>of</strong> caustic results in an increase in recovery<br />
<strong>of</strong> oil from 52% (steam injection) to 59% (caustic<br />
steam injection). However, caustic has little effect<br />
on San Ardo oil where oil recovery is 75% (steam<br />
injection) and 76 % (caustic steam injection).<br />
Significance<br />
Oil production acceleration is seen with steam-caustic<br />
injection. With steam caustic injection there is also a<br />
decrease in the produced oil viscosity and density for<br />
both oils. Sodium hydroxide concentration <strong>of</strong> 1 wt%<br />
is observed to give the lowest oil-caustic interfacial<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
tension. The acid numbers for San Ardo and Duri oil<br />
are measured as 6.2 and 3.57 respectively.<br />
Future Work<br />
The following are the main recommendations for<br />
future research:<br />
» To study further the effect <strong>of</strong> sodium hydroxide<br />
on different kinds <strong>of</strong> oils and to understand the<br />
effect <strong>of</strong> the acids present in the oil in reducing<br />
interfacial tension.<br />
» To conduct the experiments on previously<br />
waterflooded sandpacks for very heavy oils like<br />
San Ardo.<br />
» Core flooding would also be helpful in understanding<br />
the process <strong>of</strong> alkaline steam flooding with both<br />
heavy and lighter oils.<br />
» To test the combination <strong>of</strong> sodium hydroxide<br />
with additives which form the basis for alkaline<br />
surfactant process–as in Alkaline Surfactant<br />
Polymer (ASP) injection-in improving the recovery<br />
<strong>of</strong> oil.<br />
» To test non-thermal means <strong>of</strong> caustic flooding for<br />
heavy oils.<br />
Project Information<br />
1.3.12 Experimental and Simulation Studies <strong>of</strong> Heavy Oil<br />
Recovery using Steam and Steam Additives<br />
Related Publications<br />
Madhaven, R.: <strong>2009</strong>. Experimental Investigation <strong>of</strong> Caustic<br />
Steam Injection for Heavy Oils. MS thesis. Texas A&M U.,<br />
College Station, Texas.<br />
Contacts<br />
Daulat Mamora<br />
979.845.2962<br />
daulat.mamora@pe.tamu.edu<br />
Rajiv Madhaven<br />
CRISMAN INSTITUTE<br />
29
Experimental and Simulation Modeling Studies <strong>of</strong> Steam Assisted Gravity<br />
Objectives<br />
Our main research objectives are to conduct<br />
experimental and simulation modeling studies to<br />
investigate oil recovery mechanisms and steam<br />
injection efficiency during production <strong>of</strong> heavy oil<br />
under Steam Assisted Gravity Drainage (SAGD).<br />
Additionally, the research will also investigate the<br />
feasibility <strong>of</strong> petroleum distillates as steam additives<br />
to improve SAGD efficiency.<br />
Approach<br />
A 2-D scaled physical model made <strong>of</strong> Teflon has been<br />
fabricated and successfully pressure tested. The<br />
physical model will contain the sand mix, consisting<br />
<strong>of</strong> sand and heavy oil (Athabasca oil). Expansion<br />
<strong>of</strong> the steam chamber, its shape and area, and<br />
temperature distribution (Fig.1) will be visualized<br />
using a thermal (infra-red) video camera. Isotherms<br />
and steam chamber interface will be analyzed to<br />
study oil recovery and drainage mechanisms. Other<br />
data including model pressure, steam injection rate,<br />
oil and water production volumes will be recorded<br />
using a data logger and a personal computer.<br />
Simulation will be conducted to investigate the effect<br />
<strong>of</strong> different solvent types and ratios on production<br />
performance.<br />
efficiency and steam injections. Co-injecting low<br />
concentration ratios <strong>of</strong> multi-component solvents can<br />
deliver higher production rates and recovery factors<br />
along with taking advantage <strong>of</strong> both vaporized and<br />
liquid solvents.<br />
Experimental work will be continued to investigate<br />
SAGD performance and steam injection efficiency<br />
using Athabasca oil. Pure steam injection, coinjecting<br />
different solvent, including pure solvent<br />
and solvent mixture, and different solvent ratio<br />
conditions will be studied.<br />
Fig. 2. SAGD simulation shows the effect <strong>of</strong> different solvent types and<br />
ratios on oil displacement.<br />
CRISMAN INSTITUTE<br />
Fig. 1. Typical photo captured by thermal (infra-red) video camera to<br />
show steam chamber temperature distribution.<br />
Accomplishments<br />
Simulation <strong>of</strong> SAGD using CMG has been performed.<br />
Results show solvent types and ratios affect<br />
production performance (Fig.2). Meanwhile,<br />
vaporized solvent can be delivered by steam to<br />
the entire steam chamber to reduce the bitumen<br />
viscosity. Liquid solvent accelerates near-well bore<br />
flow, and so improves the mobility oil drainage<br />
Project Information<br />
1.3.13 Experimental and Analytical Modeling Studies <strong>of</strong><br />
Steam Assisted Gravity Drainage (SAGD) with NaOH and<br />
Petroleum Distillate as Steam Additives<br />
Related Publications<br />
Butler, R.M. 1991 Thermal Recovery <strong>of</strong> Oil & Bitumen, 285-<br />
359. Prentice Hall Inc., New Jersey.<br />
Nasr, T.N., Beaulieu, G., Golbeck, H. and Heck, G. Novel<br />
expanding solvent-SAGD process “ES-SAGD”. January<br />
2003. J. Cdn. Pet. Tech. 42 (1): 13-16<br />
Contacts<br />
Daulat Mamora<br />
979.845.2962<br />
daulat.mamora@pe.tamu.edu<br />
Weiqiang Li<br />
30<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
In-Situ Oil Upgrading using Tetralin (C 10<br />
H 12<br />
) Hydrogen Donor and Fe(acac) 3<br />
Catalyst at Steam Injection Pressure and Temperature<br />
Objectives<br />
In-situ upgrading has advantages over conventional<br />
surface upgrading technology. First, in-situ upgrading<br />
enhances oil recovery, increases well production,<br />
and lowers lifting and transportation costs from<br />
reservoir to refinery. It eliminates the cost <strong>of</strong> building<br />
catalytic reactors or vessels. The in-situ process can<br />
be applied onshore or <strong>of</strong>fshore as well as in remote<br />
locations where surface facilities may be prohibited.<br />
Second, in-situ upgrading can be applied on a wellto-well<br />
basis, and thus can be adjusted for declining<br />
production rates whereas surface processing are<br />
designed for a specified range <strong>of</strong> crude volume.<br />
Third, implementation <strong>of</strong> in-situ upgrading reduces<br />
energy consumption since the same energy from<br />
steam injection is used to produce and upgrade the<br />
oil. Finally, in-situ upgrading is more environmentally<br />
friendly, yielding lower quantities <strong>of</strong> byproducts that<br />
reduce disposal expenditures.<br />
The main objectives <strong>of</strong> the research are as follows:<br />
» Follow up on research by Ahmad Mohammad, for<br />
example, in-situ oil upgrading using tetralin (C 10<br />
H 12<br />
)<br />
and Fe(CH 3<br />
COCHCOCH 3<br />
) 3<br />
[i.e., Fe(acac) 3<br />
] catalyst<br />
at steam injection pressure and temperature as<br />
found in the field.<br />
» Make runs in which we inject a slug or slugs <strong>of</strong><br />
tetralin/catalyst followed by steam injection.<br />
» Simulate longer injection periods in the experiments<br />
by making runs for several days, stopping at the<br />
end <strong>of</strong> each day.<br />
» Make runs using a reactor cell and synthetic oil<br />
made <strong>of</strong> several pure components (similar to<br />
Ramirez’s PhD research). Analyze any change<br />
in synthetic oil composition by GC analysis. This<br />
type <strong>of</strong> experiment will help us determine which<br />
components are upgraded by tetralin/catalyst, and<br />
then extrapolate the results to actual oil.<br />
» For both displacement and reactor cell experiments,<br />
investigate the effect <strong>of</strong> steam-surfactant injection<br />
to lower IFT and thus increase recovery factor.<br />
Approach<br />
For reactor cell experiments, one single hydrocarbon<br />
component will be used for each run. The hydrocarbon<br />
component, water, tetralin, and catalyst are<br />
mixed in the cell and then pressurized and heated<br />
to reservoir steam flooding conditions for a period<br />
<strong>of</strong> time. At the end <strong>of</strong> the run, a sample <strong>of</strong> the<br />
liquid from the cell is removed and its composition<br />
analyzed using a GC.<br />
For injection tests, the experimental apparatus (Fig<br />
1) is made up <strong>of</strong> four main parts: injection cell, fluid<br />
injection system, fluid production system, and data<br />
recording system.<br />
The experimental procedure is as follows:<br />
(1) Prepare sand/water/oil mixture, (2) Tamp<br />
mixture into injection cell and pressure test, (3)<br />
Install injection cell into vacuum jacket and pressure<br />
test whole system, (4) Set heating jacket to reservoir<br />
temperature and leave overnight, (5) Condition<br />
steam generator and pressurize injection cell, (6)<br />
Start tetralin or tetralin-catalyst injections (only for<br />
injection runs), and (7) Start steam injection and<br />
collect samples.<br />
Accomplishments<br />
Set up reactor cell, GC and other equipment, and<br />
investigated chemical requirements for research.<br />
Reviewed papers and books on oil upgrading using<br />
tetralin/catalyst.<br />
(continued on next page)<br />
Project Information<br />
1.3.17 Experimental Studies <strong>of</strong> Non-Thermal EOR Methods<br />
for Heavy and Light Oil Recovery<br />
Related Publications<br />
Mohammad, A. A. and Mamora, D. D. In-Situ Upgrading <strong>of</strong><br />
Heavy Oil under Steam Injection with Tetralin and Catalyst,<br />
Paper presented at the 2008 International Thermal<br />
Operations and Heavy Oil Symposiums, Calgary, Alberta,<br />
Canada, 20-23 October.<br />
Contacts<br />
Daulat Mamora<br />
979.845.2962<br />
daulat.mamora@pe.tamu.edu<br />
Zhiyong Zhang<br />
CRISMAN INSTITUTE<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
31
Fig. 1. Set up <strong>of</strong> displacement apparatus.<br />
32<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Artificial Geothermal Energy Potential <strong>of</strong> Steam-Flooded Heavy Oil Reservoirs<br />
Objectives<br />
The concept <strong>of</strong> harnessing geothermal potential<br />
<strong>of</strong> heavy oil reservoirs with the coproduction <strong>of</strong><br />
incremental oil recovery using hot water injection<br />
will be investigated. Rather than abandon the<br />
heavy oil field once it becomes uneconomic,<br />
remaining geothermal energy from a steamflood<br />
or hot waterflood process that has been trapped<br />
in reservoir rock could be recovered. Preliminary<br />
results <strong>of</strong> a study <strong>of</strong> geothermal energy harvesting<br />
in a synthetic model using numerical reservoir<br />
simulation showed possible achievement <strong>of</strong> this<br />
concept. We will analyze economics <strong>of</strong> the overall<br />
project composed <strong>of</strong> reservoirs, wells, and surface<br />
facilities to show the feasibility <strong>of</strong> this project to<br />
extend the life <strong>of</strong> a heavy-oil field by means <strong>of</strong> the<br />
heat-recovery phase after the oil-recovery phase.<br />
Approach<br />
We have developed the synthetic reservoir model<br />
representing the analogue field from classical heavy<br />
oil fields. The model represents a pattern <strong>of</strong> inverted<br />
five-spot steamflood process in the heavy oil reservoir<br />
with homogenous properties. We have investigated<br />
the production and heat pr<strong>of</strong>iles in the period <strong>of</strong> hot<br />
water injection after 90% water cut is observed. We<br />
have conducted the sensitivity analysis to identify<br />
the effect <strong>of</strong> reservoir/design parameters on heat<br />
recovery. Also, we have estimated the possible<br />
range <strong>of</strong> heat recovery, pressure, and temperature<br />
at bottomhole conditions resulting from hot water<br />
injection. Those outputs will be used to model<br />
heat loss in the injection and production well by<br />
using typical well completions for thermal process.<br />
Then, we will integrate the wellbore model with the<br />
reservoir simulation model to quantify the overall<br />
heat efficiency based on heat input from hot water<br />
injection. Finally, the economic evaluation will be<br />
conducted to verify whether this proposed concept<br />
is feasible.<br />
Accomplishments<br />
Sensitivity analysis <strong>of</strong> reservoir/design parameters<br />
focused on five group parameters: reservoir<br />
geometry, reservoir rock properties, reservoir<br />
initial condition, oil viscosity, and steam injection<br />
conditions. Based on our analog field, the range <strong>of</strong><br />
heat recovery at bottomhole conditions could vary<br />
from 70% to 95% by using <strong>of</strong> hot waterflood to<br />
extract residual heat from the steamflood process.<br />
Besides, we have observed heavier oil components<br />
resided at the very bottom <strong>of</strong> the reservoir, resulting<br />
from gravitational segregation effects by thermal<br />
processes. This allows performing the horizontal<br />
infill drilling to improve the economics <strong>of</strong> the project.<br />
The result from a reservoir simulation study will be<br />
integrated with the wellbore model to investigate<br />
the heat transfer inside the well at the later stage.<br />
Energy efficiency (%)<br />
95<br />
90<br />
base<br />
87%<br />
85<br />
80<br />
75<br />
70<br />
Sensitivity <strong>of</strong> parameters to energy efficiencies during hot water flooding period<br />
Res.<br />
Geometries<br />
300<br />
2<br />
5<br />
Area (acre)<br />
50<br />
Thickness (ft)<br />
25<br />
35<br />
Porosity (%)<br />
Rock<br />
Properties<br />
5000<br />
1000<br />
Permeability (md)<br />
Sensitivity analysis indicates that we could recover the heat at least 70%<br />
<strong>of</strong> heat inputs by using hot water injection.<br />
CRISMAN INSTITUTE<br />
Project Information<br />
1.3.19 Harnessing the Geothermal Energy Potential <strong>of</strong><br />
Heavy Oil Reserves<br />
Contacts<br />
Gioia Falcone<br />
979.847.8912<br />
gioia.falcone@pe.tamu.edu<br />
Catalin Teodoriu<br />
catalin.teodoriu@pe.tamu.edu<br />
Akkharachai Limpasurat<br />
SS<br />
LS<br />
Lithology<br />
Res. Initial<br />
Condition<br />
600<br />
100<br />
Initial reservoir<br />
pressure (psi)<br />
90<br />
130<br />
Initial reservoir<br />
temperature (°F)<br />
Viscosity<br />
1000<br />
4484<br />
viscosity (cp)<br />
500<br />
250<br />
Steam injection rate<br />
(BCWE/day)<br />
Steam Injection<br />
Condition<br />
500<br />
250<br />
Steam injection<br />
temperature (°F)<br />
2500<br />
1500<br />
Steam injection<br />
pressure (psi)<br />
dry<br />
wet<br />
Steam quality<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
33
Study <strong>of</strong> Solvent-Based Emulsion Injection to Improve Sweep and Displacement<br />
Efficiency in Heavy Oil Reservoir<br />
Introduction<br />
About two-thirds <strong>of</strong> the original oil in reservoirs is left<br />
behind, even after gas injection or water-flooding.<br />
However most <strong>of</strong> the oil contacted by a solvent<br />
may be recovered, as a solvent is miscible with<br />
reservoir oil. Unfortunately, the low solvent viscosity<br />
results in unfavorable mobility ratio and poor sweep<br />
efficiency particularly in heavy oil reservoirs. Thus<br />
this research investigates residual oil reduction<br />
by solvent and sweep efficiency improvement by<br />
emulsion.<br />
Objectives<br />
This research has two parts:<br />
Experimental research<br />
Main objectives are as follows:<br />
» Investigate the feasibility <strong>of</strong> solvent-based<br />
emulsion flooding to improve displacement and<br />
sweep efficiency in heavy oil reservoirs<br />
» Conduct core-flood experiments to compare<br />
recovery efficiency using various emulsions after<br />
water-flooding.<br />
Fig. 1. Emulsion ternary phase diagram.<br />
the ternary phase diagram shown in Fig. 1. Emulsion<br />
containing 5wt% silica nanoparticles shows a higher<br />
viscosity than emulsion without nanoparticles (Fig.<br />
2). Cores have been scanned to measure porosity<br />
and initial oil and water saturations (Fig. 3).<br />
Simulation study<br />
Main research objectives are as follows:<br />
» Perform history matching <strong>of</strong> the experimental<br />
results using CMG<br />
» Conduct simulation study <strong>of</strong> sweep efficiency in a<br />
5-spot well pattern.<br />
Approach<br />
This research has two parts, namely, experiments<br />
and simulation study. First, a bench test is performed<br />
to get the emulsion system properties, such as<br />
viscosity, IFT, and ternary phase diagram. Based on<br />
the bench test results, the optimized emulsions are<br />
chosen to perform the core flooding experiments.<br />
Second, different core flooding experiments are<br />
conducted to investigate the effect <strong>of</strong> these emulsions<br />
on oil recovery. The aluminum coreholder will be<br />
x-ray CT scanned to measure residual oil saturation<br />
in the core. Lastly, a simulation will be conducted<br />
to history match the experiment results to enable a<br />
study <strong>of</strong> sweep efficiency for a 5-spot well pattern.<br />
Accomplishments<br />
The bench tests have been completed. The results<br />
showing micro- and macro-emulsions are plotted in<br />
34<br />
Project Information<br />
1.3.20 Microemulsion-Solvent Injection to Improve Sweep<br />
and Displacement Efficiency <strong>of</strong> Heavy and Light Oil<br />
Related Publications<br />
Willhite, G.P., Green, D.W., Okoye, D.M., and Looney, M.D.<br />
A Study <strong>of</strong> Oil Displacement by Microemulsion Systems:<br />
Mechanisms and Phase Behavior. SPE-7580.<br />
Contacts<br />
Daulat Mamora<br />
979.845.2962<br />
daulat.mamora@pe.tamu.edu<br />
Fangda Qiu<br />
CRISMAN INSTITUTE<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
1000<br />
Viscosity vs Shear Rate<br />
Emulsion with 5wt% nanoparticles<br />
Emulsion without nanoparticles<br />
Viscosity (cp)<br />
100<br />
10<br />
1<br />
0.1<br />
1<br />
10<br />
Shear Rate (sec -1 )<br />
100<br />
1000<br />
Fig. 2. Emulsion rheology diagram.<br />
Fig. 3. CT-scan <strong>of</strong> dry core.<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
35
Investigation <strong>of</strong> Hybrid Steam-Solvent Processes to Increase Efficiency <strong>of</strong> Thermal<br />
Oil Recovery Methods<br />
Objectives<br />
Steam assisted gravity drainage (SAGD) has received<br />
considerable attention as a proven technique to<br />
recover heavy oil and bitumen which are immobile<br />
at reservoir conditions. The main drawbacks <strong>of</strong> this<br />
process are high energy intensity (steam generation<br />
requirements) and environmental issues.<br />
The addition <strong>of</strong> light hydrocarbon solvents to steam is<br />
the simplest and most important approach to improve<br />
SAGD process and reduce potential problems. Main<br />
benefits possibly obtained by a hybrid steam solvent<br />
process include: reduced Steam Oil Ratio, reduced<br />
environmental impact, increased recovery via<br />
reduced S or<br />
, reduced capital to startup and enhanced<br />
well productivity. Principal challenges are the choice<br />
<strong>of</strong> solvent and concentration and operating strategy.<br />
Our main research objective is to reduce energy<br />
intensity <strong>of</strong> SAGD process by using solvents<br />
and investigate the effect <strong>of</strong> different operating<br />
strategies. Key tasks are to evaluate the effect on<br />
oil recovery <strong>of</strong> the following:<br />
» Solvents, (e.g., butane, hexane and condensates)<br />
» Solvent concentration<br />
» Injection types (e.g., cyclic steam solvent injection)<br />
Fig. 1. Simulation results <strong>of</strong> oil recovery.<br />
with increasing concentration. The aluminum 2D<br />
cylindrical model is under construction. The sandmix<br />
space has an inner radius <strong>of</strong> 4 in, 1-in thickness, and<br />
10-in height, and will be lined with insulating Teflon<br />
layers (Fig. 2). The experimental set up is shown<br />
in Fig. 3.<br />
Approach<br />
Experiments will be carried out in a scaled 2D<br />
cylindrical cell to evaluate the effect <strong>of</strong> steam-solvent<br />
processes. Pujol and Boberg’s scaling method has<br />
been used to design the model. Advantages <strong>of</strong> the<br />
cylindrical model are the relatively high pressure<br />
capability without a pressure jacket, the use <strong>of</strong> inner<br />
thermal insulation, and the ability to conduct gravity<br />
drainage experiments (e.g., VAPEX, SAGD). Oil and<br />
water production, gas composition, and temperature<br />
would be measured and analyzed. Numerical<br />
simulation will be used for parametric studies.<br />
Accomplishments<br />
Compositional reservoir simulation studies <strong>of</strong> Cold<br />
Lake bitumen were performed to investigate the<br />
effect <strong>of</strong> solvent type and concentration on recovery<br />
under SAGD at 220°C and 3100 kpa (450 psia)<br />
(Fig. 1). With C5-C7 as solvents, bitumen recovery<br />
increases to about 80% at 20 wt%. C2 and C3<br />
however exist as vapor and act as thermal insulators<br />
at the steam-bitumen interface, reducing recovery<br />
Project Information<br />
1.3.22 Investigation <strong>of</strong> Hybrid Steam-Solvent Injection to<br />
Increase Efficiency <strong>of</strong> Thermal Oil Recovery Processes<br />
Related Publications<br />
Nasr T.N., and Ayodele O.R. New Hybrid Steam-Solvent<br />
Processes for the Recovery <strong>of</strong> Heavy Oil and Bitumen.<br />
Paper SPE 101717, presented at the 2006 International<br />
Petroleum Exhibition and Conference, Abu Dubai, UAE, 5-8<br />
November.<br />
Ayodele, O.R., et al. Laboratory Experimental Testing<br />
and Development <strong>of</strong> an Efficient Low Pressure ES-SAGD<br />
Process. <strong>2009</strong>. J. Cdn Pet. Tech. 48 (9).<br />
Contacts<br />
Daulat Mamora<br />
979.845.2962<br />
daulat.mamora@pe.tamu.edu<br />
Mojtaba Ardali<br />
CRISMAN INSTITUTE<br />
36<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Fig. 2. Scaled 2D cylindrical cell.<br />
Fig. 3. Schematic diagram <strong>of</strong> experimental set up.<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
37
Experimental Studies <strong>of</strong> Steam Injection with Surfactant for Enhancing Heavy Oil<br />
Recovery after Waterflooding<br />
Objectives<br />
Steam injection with added surface active chemicals<br />
is an EOR process aimed at recovering residual oil<br />
after primary production. Researchers have shown<br />
that after waterflooding, the oil swept area can be<br />
increased by steam surfactant due to reduced steam<br />
override effect and reduced interfacial tension<br />
between oil and water in the formation.<br />
was tamped into the cell.<br />
A 3.0 wt% nonionic surfactant Triton X-100 was coinjected<br />
with the steam superheated to 200°C and<br />
pressured to 100 psig. For the vertical cell runs,<br />
steam injection rates were 5.5 ml/min and 2.5 ml/<br />
min TX-100; for the horizontal cell runs, steam<br />
injection rates were 4.0 ml/min and 1.0 ml/min TX-<br />
100 solution.<br />
The main objective <strong>of</strong> this research is to evaluate the<br />
effect on oil recovery <strong>of</strong> steam surfactant injection<br />
compared to that <strong>of</strong> pure steam injection. The<br />
experimental study will use a 1D displacement cell<br />
containing a sand mix <strong>of</strong> 20.5°API California oil.<br />
Approach<br />
Two experimental models were used: a vertical<br />
cylindrical cell 67 cm long x 7.4 cm ID (Fig. 1) and<br />
Fig. 2. Horizontal cell.<br />
CRISMAN INSTITUTE<br />
Fig. 1. Vertical cell.<br />
a horizontal cell 110.5 cm long x 3.5 cm ID (Fig. 2).<br />
The horizontal smaller diameter cell is less subject to<br />
channeling and is therefore more representative <strong>of</strong><br />
one-dimensional steam injection process. A uniform<br />
mixture <strong>of</strong> sand, water and 20.5°API California oil<br />
Project Information<br />
1.3.23 Experimental Study <strong>of</strong> Steam Injection with<br />
Surfactants for Enhancing Heavy Oil Recovery<br />
Contacts<br />
Daulat Mamora<br />
979.845.2962<br />
daulat.mamora@pe.tamu.edu<br />
Dinmukhamed Sunnatov<br />
38<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Accomplishments<br />
The main conclusions <strong>of</strong> the study are made based<br />
on the horizontal cell runs.<br />
» For the two runs with steam surfactant, average<br />
oil recovery was 55% OIP compared to an average<br />
48% OIP with pure steam injection (Fig. 3).<br />
That is, the average incremental oil recovery with<br />
steam surfactant flood was 7.0% OIP above that<br />
with pure steam injection.<br />
» As the run progressed, viscosity at 23°C <strong>of</strong><br />
produced oil decreased from 497 cp to 13.4 cp<br />
(steam injection) and to 1.7 cp (steam surfactant<br />
injection). The oil gravity increased from 19.1°API<br />
to 35.0°AIP (steam injection) and to 36.6°API<br />
(steam-surfactant injection).<br />
60<br />
60<br />
50<br />
50<br />
SI oil recovery, % OIP<br />
40<br />
30<br />
20<br />
10<br />
cum. oil production SI<br />
cum. oil production 5<br />
cum. oil production 6<br />
40<br />
30<br />
20<br />
10<br />
SSI oil recovery, % OIP<br />
0<br />
0<br />
0 0.4 0.8 1.2 1.6 2.0<br />
Steam injected, PV<br />
Fig. 3. Oil recovery with steam-surfactant injection (55%) is 7% OIP<br />
more than that with steam injection (48%).<br />
Note that IFT’s for the average produced oil and<br />
water are smaller when compared to that <strong>of</strong> the<br />
original oil and water.<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
39
Combustion Assisted Gravity Drainage (CAGD): An In-Situ Combustion Method<br />
to Recover Heavy Oil and Bitumen from Geologic Formations using a Horizontal<br />
Injector-Producer Pair<br />
Objectives<br />
In-situ combustion (ISC) is a recovery process<br />
particularly suitable for heavy oil reservoirs at<br />
depths greater than 3500 ft when steam injection<br />
is not feasible due to severe wellbore heat losses.<br />
We have developed a method in which a horizontal<br />
air injector is placed above a horizontal producer<br />
(Fig. 1). In this Combustion Assisted Gravity<br />
Drainage (CAGD) method, a heated chamber is<br />
created that would more uniformly transfer heat<br />
from the combustion front. Mobilized oil is produced<br />
by gravity drainage to the lower horizontal well.<br />
Gravity segregation enhances air flow to propagate<br />
the combustion front. Main research objectives are<br />
as follows:<br />
» Assess CAGD using Computer Modelling Group<br />
(CMG) simulator<br />
» Conduct experiments using a scaled 3D physical<br />
model to test viability <strong>of</strong> CAGD for heavy oil and<br />
Cold Lake bitumen<br />
» Compare CAGD and toe-to-heel air injection<br />
(THAI) processes<br />
» Using CMG simulator, history-match laboratory<br />
CAGD results and scale up to field conditions<br />
experimental results and scale up to field conditions<br />
and evaluate CAGD.<br />
Accomplishments<br />
A 50 cm x 15 cm x 35 cm Cartesian simulation<br />
model was constructed representing the half<br />
symmetry element <strong>of</strong> a 750 m long x 56 m width x<br />
35 m thick drainage volume; we placed the injector<br />
at 7 m above the reservoir base with a producer<br />
5 m below the injector. The model was based on<br />
typical Athabasca oil and rock properties. Runs<br />
were made to compare CAGD with steam assisted<br />
gravity drainage (SAGD) and THAI. Results indicate<br />
CAGD to have the highest oil production with the<br />
lowest energy consumption (Figs. 2 and 3).<br />
The physical model, measuring 60 cm x 40 cm x 15<br />
cm, is nearly completed (Fig. 4). The steel sides<br />
will be lined with ceramic fiber insulation. Seventy<br />
two thermocouples will measure temperature in the<br />
sandmix with an operating pressure at about 30<br />
psig.<br />
CRISMAN INSTITUTE<br />
Fig. 1. Schematic illustration <strong>of</strong> CAGD.<br />
Approach<br />
We will conduct a simulation using CMG for a<br />
preliminary evaluation <strong>of</strong> CAGD. If simulation<br />
results show CAGD to be promising, we will conduct<br />
experimental runs using a physical model to evaluate<br />
performance <strong>of</strong> CAGD. We will also history match<br />
40<br />
Project Information<br />
1.3.24 Combustion Assisted Gravity Drainage (CAGD):<br />
An In-Situ Combustion Method to Recover Heavy Oil and<br />
Bitumen from Geologic Formations using a Horizontal<br />
Injector-Producer Pair<br />
Related Publications<br />
Greaves, M., Xia, T.X. and Turta, A.T. Stability <strong>of</strong> THAI<br />
Process-Theoretical and Experimental Observations. Paper<br />
presented at the 2007 Canadian International Petroleum<br />
Conference, Calgary, Alberta, 12-14 June.<br />
Contacts<br />
Daulat Mamora<br />
979.845.2962<br />
daulat.mamora@pe.tamu.edu<br />
Hamid Rahnema<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Fig. 2. Oil production rate for CAGD,THAI and SAGD.<br />
Fig. 3. Cumulative energy/oil ratio for CAGD,THAI and SAGD.<br />
Fig. 4. Scaled CAGD physical model.<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
41
Well Spacing and Infill Drilling in Coalbed Methane Reservoirs<br />
Objectives<br />
Reservoir simulation has been used to describe<br />
the mechanism <strong>of</strong> gas desorption and diffusion in<br />
coal to reflect the response <strong>of</strong> the reservoir system<br />
and the relationship among coalbed methane<br />
reservoir properties, operation procedures, and<br />
gas production. The objective <strong>of</strong> this work is to<br />
investigate well spacing and completion design<br />
practices under various development scenarios by<br />
using reservoir simulation.<br />
In a coal bed methane reservoir there is a natural<br />
fracture system which conducts the fluid flow to the<br />
wellbore and matrix system where essentially all<br />
gas is stored. Instead <strong>of</strong> gas being compressed in<br />
the pore space, most is adsorbed on the surface <strong>of</strong><br />
it. Considering the small pore size in this reservoir<br />
system, the Klinkenberg effect or slippage factor<br />
could effect the permeability change during<br />
reservoir depletion. The amount <strong>of</strong> gas adsorbed is<br />
quantified by an adsorption curve (isotherm curve)<br />
<strong>of</strong> the Langmuir equation. As the reservoir pressure<br />
declines during production from the fracture system,<br />
gas desorbs from the coal surfaces. Flow gas from<br />
the coal matrix to the fracture system is a molecular<br />
diffusion, expressed by Fick’s law rather that Darcy’s<br />
law. Because <strong>of</strong> the adsorption curve’s convex shape,<br />
it becomes very important to attain low reservoir<br />
pressure; this is a much more important factor than<br />
in conventional reservoirs. After long dewatering,<br />
water production will decrease and gas production<br />
increase and peak after water production has<br />
significantly declined from its original rate. Predicting<br />
the time and magnitude <strong>of</strong> this peak is a large part<br />
<strong>of</strong> the early evaluation <strong>of</strong> the wells. Eventually the<br />
wells decline and have a more conventional rate<br />
pattern. In the later stage <strong>of</strong> depletion (effective<br />
fracture permeability increasing during matrix<br />
desorption at lower pressure), this rock mechanic<br />
can be described by the Palmer-Mansoori effect.<br />
Approach<br />
A reservoir simulator will be developed to determine<br />
the effect <strong>of</strong> various spacing and completion<br />
decisions on recovery for particular scenarios <strong>of</strong><br />
reservoir properties/description. The outcome <strong>of</strong><br />
the simulation and history matching will typify the<br />
reservoir <strong>of</strong> interest and will be used to develop<br />
further analysis, such as:<br />
» Determine where the Palmer-Mansoori permeability<br />
and the Klinkenberg effect are important in<br />
42<br />
reservoir mechanics<br />
» Demonstrate the importance <strong>of</strong> various parameters<br />
on spacing<br />
» Determine desirability and expected performance<br />
<strong>of</strong> either vertical or horizontal wells<br />
» Develop well spacing correlations to determine<br />
optimum well spacing for new reservoir<br />
development and guideline for several practical<br />
circumstances<br />
Accomplishments<br />
A single well, 2D, single phase reservoir simulator<br />
has been developed using Macros Visual Basic.<br />
Reservoir simulation results for different sorption<br />
pressure cases are presented in Fig. 1. The work is<br />
still being continued to accommodate multiphase,<br />
Klinkenberg effect, and Palmer-Mansoori effect.<br />
Gas Rate (SCFD)<br />
1.E+07<br />
1.E+06<br />
Project Information<br />
1.4.4 Effects <strong>of</strong> Infill Drilling Coalbed-Methane Reservoirs<br />
Contacts<br />
Bob Wattenbarger<br />
979.845.0173<br />
bob.wattenbarger@pe.tamu.edu<br />
Pahala D. Sinurat<br />
Simulation Result for Constant Pressure Case<br />
1.E+05<br />
0.1 1 10 100 1000<br />
Time (days)<br />
Sorption Pressure = 1103.20 psi<br />
Sorption Pressure = 882.56 psi<br />
Sorption Pressure = 661.92 psi<br />
Fig. 1. Reservoir simulation results for various sorption pressure.<br />
Significance<br />
Residual method can be applied in developing a<br />
reservoir simulator for coalbed methane reservoirs<br />
to provide a rapid screening approach looking at the<br />
prospect <strong>of</strong> development or purchase or production<br />
improvement.<br />
CRISMAN INSTITUTE<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Drilling through Gas Hydrate Formations<br />
Objectives<br />
The modern petroleum industry meets highly complex<br />
technical challenges with an increasing demand <strong>of</strong><br />
operations in deepwater <strong>of</strong>fshore and onshore arctic<br />
environments, where greater emphasis should<br />
be placed on quantifying the hazards to drilling<br />
operations caused by gas hydrates. As progress<br />
is aimed towards ultradeep waters, it becomes<br />
important for future drilling operations to be able to<br />
identify ahead <strong>of</strong> time when problems are likely to<br />
occur.<br />
The objective <strong>of</strong> this research is to develop a<br />
comprehensive numerical algorithm for the<br />
estimation <strong>of</strong> risks while drilling through hydratebearing<br />
sediments.<br />
Approach<br />
We divided the problem into three “sub-problems.”<br />
The hydrate dissociation possibility will be separately<br />
analyzed at first in a drilled formation, then at the bit,<br />
and finally in the wellbore. The available field data<br />
will be gathered to assess heat transfer phenomena<br />
in the reservoir and the wellbore.<br />
bottomhole temperature using a numerical model<br />
for temperature distribution in the wellbore while<br />
drilling. On average, the radius <strong>of</strong> the formation<br />
affected by drilling was 500 m. The estimated size <strong>of</strong><br />
the problem was used to build a model for numerical<br />
calculations.<br />
Temperature (K)<br />
294<br />
293<br />
292<br />
291<br />
290<br />
289<br />
288<br />
287<br />
0.10<br />
0.15<br />
Temperature Pr<strong>of</strong>ile<br />
0.20<br />
0.25<br />
Radial heat transport from hot drilling fluid in wellbore into the formation<br />
(J.Yang).<br />
0.30<br />
0.35<br />
Distance from Wellbore Center (m)<br />
0.40<br />
at 0.139 hr<br />
at 0.278 hr<br />
at 2.78 hr<br />
at 5.56 hr<br />
at 6.94 hr<br />
at 8.33 hr<br />
CRISMAN INSTITUTE<br />
Project Information<br />
1.5.5 Design <strong>of</strong> Fluids for Drilling Though Hydrates<br />
Related Publications<br />
Peterson, J. Computing the Danger <strong>of</strong> Hydrate Formation<br />
using a Modified Dynamic Kick Simulator. Paper presented<br />
at the 2005 Asia Pacific Oil and Gas Conference, Jakarta,<br />
Indonesia, 5-7 April.<br />
Gas-hydrate related problems.<br />
Accomplishments<br />
Using an analytical model <strong>of</strong> hydrate dissociation<br />
under changing pressure and temperature,<br />
we estimated how far into the formation initial<br />
conditions will be changed due to drilling. For<br />
boundary conditions, we obtained bottomhole<br />
pressure from the measurements and we calculated<br />
Tan, C.P., et al. Managing Wellbore Instability Risk in Gas-<br />
Hydrate-Bearing Sediments. Paper presented at the 2005<br />
Asia Pacific Oil and Gas Conference, Jakarta, Indonesia,<br />
5-7 April.<br />
Contacts<br />
Gioia Falcone<br />
979.847.8912<br />
gioia.falcone@pe.tamu.edu<br />
Catalin Teodoriu<br />
catalin.teodoriu@pe.tamu.edu<br />
Tagir Khabibullin<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
43
Experimental and Numerical Simulation Studies to Evaluate Improvement <strong>of</strong> Light<br />
Oil Recovery by WACO 2<br />
and SWACO 2<br />
in Fractured Carbonate Reservoirs<br />
Objectives<br />
Oil recovery from mature fields deteriorates with<br />
time and significant oil in place is then left behind.<br />
Also, large economical hydrocarbon discoveries<br />
have become rarer in recent years. Therefore, the<br />
need to increase the reserves by improving recovery<br />
techniques has become essential. Water alternating<br />
gas (WAG) and simultaneous water and gas injection<br />
(SWAG) have been proposed and applied with varying<br />
results. However, extensive studies to examine<br />
the latter have not been carried out, especially in<br />
carbonate reservoirs and fractured rocks. Therefore,<br />
this study will investigate the effect on oil recovery<br />
and reservoir fluids by injecting water and CO 2<br />
in<br />
different modes.<br />
This research project will study four injection<br />
modes: waterflooding, continuous gas (CGI), water<br />
alternating gas (WAG), and simultaneous water<br />
and gas (SWAG). These modes will be injected in<br />
two different sets <strong>of</strong> carbonate cores, fractured<br />
and unfractured. The study aims to examine the<br />
influence <strong>of</strong> these different modes <strong>of</strong> injection on<br />
incremental light oil recovery and changes in rock<br />
and fluid properties. Comparison parameters would<br />
be as follows:<br />
» Oil recovery versus time<br />
» Residual oil saturation in the core matrix and the<br />
fracture using X-Ray CT scanning<br />
» Displacement efficiency improvement by the<br />
addition <strong>of</strong> NaI to the injected water<br />
Approach<br />
This research uses a core flood apparatus which<br />
contains high-grade aluminum to allow for X-Ray<br />
CT scanning. The core is connected to a 40-ft<br />
slimtube coil that will provide the necessary length<br />
to achieve miscibility, Figs. 1 and 2. The carbonate<br />
core measures 6 in long by 2 in OD on which the<br />
two scenarios will be investigated. The fracture will<br />
be created by sawing the core and placing a 1 mm<br />
spacer in the fracture to keep it open, and putting<br />
the fractured core in the coreflood cell. Injection<br />
pressures will be at 1900 psi to simulate downhole<br />
conditions and ensure miscibility between injectant<br />
gases and oil in place. Numerical simulation (CMG)<br />
will be conducted to model the experimental results.<br />
Accomplishments<br />
A fit-to-purpose experimental apparatus was<br />
designed. The minimum miscibility pressure (MMP)<br />
between west Texas light oil and CO 2<br />
has been<br />
measured using the industry standard method,<br />
slimtube, and numerical simulation. It was found<br />
that the core will not permit multiple contact<br />
miscibility to occur as tested by the slimtube. This is<br />
because <strong>of</strong> the core’s short length and heterogeneity<br />
CRISMAN INSTITUTE<br />
Project Information<br />
1.7.3 Analytical Modeling and Experimental Studies<br />
to Evaluate Improvement and Recovery <strong>of</strong> Light Oil in<br />
Carbonate Reservoirs by Simultaneous Water Alternating<br />
Gas (SWAG)<br />
Related Publications<br />
Mamora, D.D.. and Seo, J. G. Enhanced Gas Recovery by<br />
Carbon Dioxide Sequestration in Depleted Gas Reservoirs.<br />
Paper 77347, presented at the 2002 SPE-ATCE, San<br />
Antonio, Texas, 29 September – 2 October.<br />
Silva, Carlos F. R.: 2003. Water Alternating Enriched Gas<br />
Injection to Enhance Oil Production and Recovery from<br />
San Francisco Field, Colombia. MS thesis, Texas A&M U.,<br />
College Station, Texas.<br />
Contacts<br />
Daulat Mamora<br />
979.845.2962<br />
daulat.mamora@pe.tamu.edu<br />
Fig. 1. Coreholer connected to slimtube.<br />
Ahmed Aleidan<br />
44<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Fig. 2. CT scanning <strong>of</strong> 6” long by 2” diameter carbonate core yields<br />
porosity and saturation.<br />
compared to the slimtube. To overcome the lack<br />
<strong>of</strong> length, a 40-ft slimtube coil is placed ahead <strong>of</strong><br />
the core to pre-equilibrate the oil with CO 2<br />
. With<br />
this arrangement, three types <strong>of</strong> injections have<br />
conducted on unfractured core: waterflood alone,<br />
CGI, and CGI followed by water injection after<br />
CO 2<br />
depletion. Injecting water after CO 2<br />
depletes<br />
the core showed promising results <strong>of</strong> 18% OOIP<br />
incremental recovery.<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
45
Enhanced Oil Recovery <strong>of</strong> Viscous Oil by Injection <strong>of</strong> Water-in-Oil Emulsions<br />
Objectives<br />
Water-in-Oil (W/O) emulsions have been used for<br />
enhancing oil recovery by improving the mobility<br />
ratio, thus sweep efficiency, and by miscibility with<br />
the reservoir oil, thus reducing residual oil. Heavy<br />
crude oil has been used to make W/O emulsions<br />
(with addition <strong>of</strong> nanoparticles) to recover the<br />
same oil with very good recovery in a core flooding<br />
experiment. However, crude oil emulsions become<br />
much more viscous as more water is added, resulting<br />
in poor injectivity.<br />
Our research objectives are therefore as follows:<br />
» Find an oil that can be used to make a moderately<br />
viscous emulsion system.<br />
» Make stable W/O emulsions out <strong>of</strong> this oil without<br />
the addition <strong>of</strong> expensive components (e.g.,<br />
surfactant).<br />
» Verify the performance <strong>of</strong> the emulsion by core<br />
flooding experiments.<br />
Approach<br />
We will make emulsions by adding water into<br />
different types <strong>of</strong> oil, and blending them with a<br />
blender. Nanoparticles might be mixed into the oil<br />
prior to the addition <strong>of</strong> water. If a stable emulsion is<br />
obtained, its viscosity will be measured at different<br />
water content, shear rate, and temperature.<br />
Accomplishments<br />
Used engine oil is found to be a very good candidate<br />
to make stable emulsions (Fig. 1) for several<br />
reasons:<br />
» Existing soot provides perfect oleophilic<br />
nanoparticles to stabilize the W/O emulsion.<br />
» Moderate oil viscosity allows moderately high<br />
viscosity achievement for the emulsion (Fig. 2).<br />
» Stable and well behaved emulsions are obtained<br />
simply by blending in water, without extra<br />
surfactant or nanoparticles needed.<br />
» Used engine oil is produced in large quantities (~1<br />
billion gallons/year) and needs to be recycled–it is<br />
therefore relatively cheap.<br />
Significance<br />
A simple formulated stable emulsion system is<br />
obtained, with high potential use as a displacement<br />
fluid for heavy oil EOR.<br />
46<br />
Fig. 1. W/O emulsion with used Pennzoil 5W-30 is stable with water<br />
content up to 70%.<br />
Viscosity (cp)<br />
100000<br />
10000<br />
1000<br />
100<br />
Project Information<br />
1.7.4 Experimental Study <strong>of</strong> Polymer-Solvent Injection for<br />
Enhanced Oil<br />
Related Publications<br />
Bragg, J.R. 1999. Oil Recovery Method Using an Emulsion.<br />
US Patent 5,885,243.<br />
D’Elia, S. R. and Ferrer, G. J. Emulsion Flooding <strong>of</strong> Viscous<br />
Oil Reservoirs. Paper SPE 4674, presented at the 1973<br />
annual meeting <strong>of</strong> SPE <strong>of</strong> AIME, Las Vegas, Nevada, 30<br />
September.<br />
Johnson, C. E. Jr. Status <strong>of</strong> Caustic and Emulsion Methods.<br />
JPT (January 1976) 85-92.<br />
Contacts<br />
Daulat Mamora<br />
979.845.2962<br />
daulat.mamora@pe.tamu.edu<br />
Xuebing Fu<br />
10<br />
0<br />
50 100 150<br />
Shear rate (s -1 )<br />
200<br />
CRISMAN INSTITUTE<br />
0% water<br />
20% water<br />
40% water<br />
50% water<br />
60% water<br />
70% water<br />
Fig. 2. Viscosity at 25ºC <strong>of</strong> W/O emulsion with used Pennzoil 5W-30<br />
engine oil.<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Managed Pressure Drilling Candidate Selection<br />
Introduction<br />
Managed Pressure Drilling (MPD), now at the<br />
pinnacle <strong>of</strong> the ‘Oil Well Drilling’ evolution tree, has<br />
itself been coined in 2003. It is an umbrella term for<br />
a few new drilling techniques and some preexisting<br />
drilling techniques, all <strong>of</strong> them aiming to solve several<br />
drilling problems, including non-productive time<br />
and/or drilling flat time issues. These techniques,<br />
now sub-classifications <strong>of</strong> MPD, are referred to as<br />
‘Variations’ and ‘Methods’ <strong>of</strong> MPD.<br />
Objectives<br />
Although using MPD for drilling wells has several<br />
benefits, not all wells that seem a potential candidate<br />
for MPD, need MPD. The drilling industry has<br />
numerous simulators and s<strong>of</strong>tware models to perform<br />
drilling hydraulics calculations and simulations.<br />
Most <strong>of</strong> them are designed for conventional well<br />
hydraulics, while some can perform Underbalanced<br />
Drilling (UBD) calculations, and a select few can<br />
perform MPD calculations. Most <strong>of</strong> the few available<br />
MPD models are modified UBD versions that fit MPD<br />
needs. However, none <strong>of</strong> them focus on MPD and its<br />
candidate selection alone.<br />
Perform Hydraulic<br />
Analysis<br />
Are<br />
BHP & Ann Pr No<br />
Inside the PP &<br />
FP Window<br />
?<br />
Are<br />
All Project<br />
Objectives<br />
Met<br />
?<br />
Yes<br />
Yes<br />
MPD is not Required<br />
START<br />
Procure Information & Define Project Objectives<br />
Change Design<br />
Parameters<br />
No<br />
Is<br />
Rheology /<br />
MW / Other<br />
Design Variations<br />
Possible<br />
?<br />
MPD is not Useful<br />
STOP<br />
Perform Hydraulic<br />
Analysis<br />
Is<br />
an MPD<br />
Variation Available,<br />
Meeting the<br />
Criterion<br />
?<br />
MPD is Applicable<br />
Example <strong>of</strong> MPD candidate selection flow diagram.<br />
Yes<br />
No<br />
No<br />
Yes<br />
Are<br />
All the<br />
Constraints &<br />
Project Objectives<br />
Met<br />
?<br />
Yes<br />
Change Design<br />
Parameters<br />
No<br />
Yes<br />
Is<br />
Another<br />
Method Available or<br />
Perameter Change<br />
Possible<br />
?<br />
No<br />
MPD is not Useful<br />
A ‘Managed Pressure Drilling Candidate Selection<br />
Model and s<strong>of</strong>tware’ that can act as a preliminary<br />
screen to determine the utility <strong>of</strong> MPD for potential<br />
candidate wells will be developed as a part <strong>of</strong> this<br />
research dissertation.<br />
Approach<br />
A model and a flow diagram are needed to identify<br />
the key steps in candidate selection. The s<strong>of</strong>tware<br />
will perform the basic hydraulic calculations and<br />
provide useful results in the form <strong>of</strong> tables, plots<br />
and graphs that would help in making better<br />
engineering decisions. An additional MPD worldwide<br />
wells database with basic information on a few<br />
MPD projects will also been compiled that can act<br />
as a basic guide on the MPD variation and project<br />
frequencies and aid in MPD candidate selection.<br />
Accomplishments<br />
Finished the MPD Candidate Selection Flow Diagram,<br />
Worldwide MPD wells database and the MPD<br />
Candidate Selection Thesis.<br />
CRISMAN INSTITUTE<br />
Project Information<br />
2.1.1 Managed Pressure Drilling Candidates Selection Model<br />
Related Publications<br />
Nauduri, S., Medley, G.H., and Schubert, J.J. MPD: Beyond<br />
Narrow Pressure Windows. IADC/SPE Paper Number<br />
122276-PP, presented at the <strong>2009</strong> IADC/SPE, Managed<br />
Pressure Drilling and Underbalanced Operations Conference<br />
and Exhibition, San Antonio, Texas, 12-13 February.<br />
Contacts<br />
Jerome Schubert<br />
979.862.1195<br />
jerome.schubert@pe.tamu.edu<br />
Hans Juvkam-Wold<br />
979.845.4093<br />
juvkam-wold@tamu.edu<br />
Anantha Nauduri<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
47
Alternate Power and Energy Storage/Reuse for Drilling Rigs: Reduced Cost and<br />
Lower Emissions Provide Lower Footprint for Drilling Operations<br />
Introduction<br />
Diesel engines operating the rig pose the problems<br />
<strong>of</strong> low efficiency and large amount <strong>of</strong> emissions. In<br />
addition the rig power requirements vary a lot with<br />
time and ongoing operation. Therefore it is in the<br />
best interest <strong>of</strong> operators to research on alternate<br />
drilling energy sources which can make entire drilling<br />
process economic and environmentally friendly. One<br />
<strong>of</strong> the major ways to reduce the footprint <strong>of</strong> drilling<br />
operations is to provide more efficient power sources<br />
for drilling operations. There are various sources<br />
<strong>of</strong> alternate energy storage/reuse. A quantitative<br />
comparison <strong>of</strong> physical size and economics shows<br />
that rigs powered by the electrical grid can provide<br />
lower cost operations, emit fewer emissions, are<br />
quieter, and have a smaller surface footprint than<br />
conventional diesel powered drilling.<br />
with significantly lower emissions, quieter operation,<br />
and smaller size well pad.<br />
Objectives<br />
This project describes a study to evaluate the<br />
feasibility <strong>of</strong> adopting technology to reduce the size<br />
<strong>of</strong> the power generating equipment on drilling rigs<br />
and to provide “peak shaving” energy through the<br />
new energy generating and energy storage devices<br />
such as flywheels.<br />
Approach<br />
An energy audit was conducted on a new generation<br />
light weight Huisman LOC 250 rig drilling in South<br />
Texas to gather comprehensive time stamped<br />
drilling data. A study <strong>of</strong> emissions during drilling<br />
operation was also conducted during the audit. The<br />
data was analyzed using MATLAB and compared to a<br />
theoretical energy audit.<br />
Accomplishments<br />
The study showed that it is possible to remove<br />
peaks <strong>of</strong> rig power requirement by a flywheel<br />
kinetic energy recovery and storage (KERS) system<br />
and that linking to the electrical grid would supply<br />
sufficient power to operate the rig normally. Both<br />
the link to the grid and the KERS system would fit<br />
within a standard ISO container.<br />
Significance<br />
A cost benefit analysis <strong>of</strong> the containerized system<br />
to transfer grid power to a rig, coupled with the KERS<br />
indicated that such a design had the potential to save<br />
more than $10,000 per week <strong>of</strong> drilling operations<br />
Project Information<br />
2.1.5 Rig Energy Efficiency Study<br />
Related Publications<br />
Verma, A.: <strong>2009</strong>. Alternate Power and Energy Storage/<br />
Reuse for Drilling Rigs: Reduced Cost and Lower Emissions<br />
Provide Lower Footprint for Drilling Operations. MS thesis.<br />
Texas A&M U., College Station, Texas.<br />
Contacts<br />
David Burnett<br />
979.845.2274<br />
david.burnett@pe.tamu.edu<br />
Ankit Verma<br />
CRISMAN INSTITUTE<br />
48<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Cement Fatigue Failure and HPHT Well Integrity<br />
Objectives<br />
There have been a lot <strong>of</strong> experimental investigations<br />
on the mechanism <strong>of</strong> fatigue failure <strong>of</strong> structures<br />
like buildings and bridges but the fatigue behavior <strong>of</strong><br />
well cement is still relatively unknown to engineers.<br />
This research tries to give a better understanding<br />
<strong>of</strong> cement fatigue and failure, especially for high<br />
pressure, high temperature (HPHT) wells. Through<br />
the development <strong>of</strong> equations specific to well<br />
cement from experimental data, we will test new<br />
failure mechanism, crack initiation, and propagation<br />
and failure theories, and then predict the fatigue life<br />
<strong>of</strong> cement as related to HPHT wells.<br />
Approach<br />
Based on the experimental method carried out by<br />
other fields, such as civil engineering, we will design<br />
a specific experiment related to HPHT cementing.<br />
The experiment involves the following steps:<br />
specimen fabrication, test specimen preparation,<br />
static compression tests, fatigue tests, and data<br />
analysis. Water-cement ratio, temperature, and<br />
pressure are the three variables to be considered.<br />
According to obtained data, we will then develop the<br />
failure theory and predict the fatigue life <strong>of</strong> cement.<br />
Accomplishments<br />
Based on the background research, the research<br />
methods can be divided into two categories: lab<br />
test and finite element methods. For the field <strong>of</strong> lab<br />
testing, our representatives are K.J. Goodwin and<br />
D. Stiles. In 1992, Goodwin built a test model for<br />
determining conditions for cement sheath failure.<br />
The study clearly shows that sealants that are<br />
stiffer or possess a high Young’s modulus are more<br />
susceptible to damage when subjected to changes<br />
in pressure and temperature. In 2006, Stiles built<br />
another model for testing the long term HPHT<br />
condition on the properties <strong>of</strong> cements. For finite<br />
element method analysis, FEM models are easy to<br />
carry out. The right input data and choosing the<br />
right FEM model are the most important parts <strong>of</strong><br />
FEM analysis. Martin Bosma and Kris Ravi did the<br />
research on this. Their work showed that, in order<br />
to help reduce the risk <strong>of</strong> cement failure, the cement<br />
under downhole conditions should be compensated<br />
for hydration volume reduction and rendered less<br />
stiff and more resilient than conventional oilwell<br />
cements.<br />
The best way to study the HPHT well cement failure<br />
was to combine the lab test and FEM methods, using<br />
the lab data to improve and verify the FEM model<br />
results.<br />
Significance<br />
Using the theory <strong>of</strong> probability, the high pressure<br />
cement failure study showed that:<br />
» Both cement systems show the same failure<br />
characteristic. Without cycle load, both systems<br />
fail in tensile strength. At this time the shear<br />
failure and compressive failure probability is zero.<br />
» If the tensile failure probability is high, the system<br />
failure probability is much higher than the fatigue<br />
failure probability.<br />
» Compressive strength should not be the most<br />
important parameter when designing the<br />
cement system. Latex modified cement shows<br />
better behavior than conventional cement,<br />
though conventional cement has a much higher<br />
compressive strength.<br />
Project Information<br />
2.3.5 Reducing the Risk <strong>of</strong> Cement Failure in High Pressure,<br />
High Temperature (HPHT) Conditions, Rock Mechanics<br />
Aspects through Analytical and Finite Element Method<br />
Approaches<br />
Contacts<br />
Jerome Schubert<br />
979.862.1195<br />
jerome.schubert@pe.tamu.edu<br />
Catalin Teodoriu<br />
catalin.teodoriu@pe.tamu.edu<br />
Zhaoguang Yuan<br />
CRISMAN INSTITUTE<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
49
Propagation <strong>of</strong> Induced Hydraulic Fractures near Pre-Existing Fractures<br />
Objectives<br />
Hydraulic fracturing is a widely used technology<br />
for stimulating oil and gas wells. The intersection<br />
<strong>of</strong> hydraulic fractures with natural fractures or<br />
other discontinuities in a rock mass can give rise to<br />
significant changes to fracture growth. The objective<br />
<strong>of</strong> this project is to study the potential propagation<br />
behaviors <strong>of</strong> hydraulic fractures near pre-existing<br />
fractures considering linear and non-linear fault<br />
behavior and poroelastic effects.<br />
Approach<br />
We use 2D boundary element method to model<br />
the stress field ahead <strong>of</strong> a hydraulic fracture in the<br />
vicinity <strong>of</strong> a pre-existing fracture. A unified structural<br />
criterion is used to predict the crack propagation<br />
behavior. The work initially considers fractures in an<br />
elastic media. Poroelastic effects, which arise from<br />
coupling <strong>of</strong> rock deformation and fluid flow inside the<br />
fracture, are considered next. Propagation behaviors<br />
<strong>of</strong> single pressurized crack and interaction between<br />
multiple cracks are studied. And finally, interaction<br />
between hydraulic fractures and natural fractures in a<br />
homogeneous poroelastic media will be investigated.<br />
Accomplishments<br />
A 2D real DD boundary element method has been<br />
developed and used to simulate fracture propagation<br />
trajectories for single and multiple cracks. Parametric<br />
studies are carried out for different crack propagation<br />
Y, m<br />
0.3<br />
0.2<br />
0.1<br />
0<br />
-0.2<br />
-0.1<br />
0<br />
X, m<br />
Crack A<br />
Crack B<br />
v = 1.e-1m/s, c/ t<br />
= 1.1<br />
v = 1.e-3m/s, c/ t<br />
= 1.1<br />
v = 1.e-1m/s, c/ t<br />
= 1.5<br />
v = 1.e-3m/s, c/ t<br />
= 1.5<br />
Crack propagation path near an inclined crack at different crack propagation<br />
speeds (S H<br />
= 1 MPa, S h<br />
= 0.5 MPa, p = 3.5 MPa, c/σ t<br />
= 1.1).<br />
0.1<br />
0.2<br />
speeds, far field stresses, rock cohesion and internal<br />
fluid pressures to investigate the influential factors<br />
on fracture propagation in a poroelastic rock and the<br />
results are compared with those given by an elastic<br />
model. We find that matrix pore-pressure increase<br />
could change crack propagation mode and direction.<br />
Significance<br />
This study will enable us to predict the potential<br />
fracture patterns that can arise from the intersection<br />
<strong>of</strong> a fluid-driven hydraulic crack with a pre-existing<br />
fracture. The results will assist us in design <strong>of</strong><br />
fracture treatments in complex geo-mechanical<br />
environment. Future work will consider various joint<br />
properties, fluid injection rates as well as the impact<br />
<strong>of</strong> reservoir depletion.<br />
Project Information<br />
2.4.2 Studies <strong>of</strong> Propagation <strong>of</strong> Induced Hydraulic Fractures<br />
through Pre-Existing Fractures<br />
Related Publications<br />
Ghassemi, A., Zhang, Q. 2006. Poro-thermoelastic<br />
Response <strong>of</strong> a Stationary Crack using the Displacement<br />
Discontinuity Method. ASCE J. Engineering Mechanics 132<br />
(1): 26-33.<br />
Koshelev, V., Ghassemi, A. Complex Variable BEM for<br />
Stationary Thermoelasticity and Poroelasticity. J. Eng.<br />
Anal. with Boundary Elements 28 (2004) 825-832.<br />
Xue, W., Ghassemi, A. Poroelastic Analysis <strong>of</strong> Hydraulic<br />
Fracture Propagation. Paper 129, presented at the Asheville<br />
Rocks <strong>2009</strong>, 43rd US Rock Mechanics Symposium, Asheville,<br />
North Carolina, 28 June–1 July.<br />
Contacts<br />
Ahmad Ghassemi<br />
979.845.2206<br />
ahmad.ghassemi@pe.tamu.edu<br />
Wenxu Xue<br />
CRISMAN INSTITUTE<br />
50<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Using Downhole Temperature Measurement to Assist Reservoir Characterization<br />
and Optimization<br />
Introduction<br />
Downhole temperature distribution in horizontal<br />
wells can be an important source <strong>of</strong> information that<br />
helps us characterize the reservoir and understand<br />
the bottom-hole flow conditions. The temperature<br />
measurements are obtained from permanent<br />
monitoring systems such as downhole temperature<br />
gauges and fiber optic sensors. Also, production<br />
history and bottomhole pressures are usually<br />
readily available and are routinely used for history<br />
matching to improve the initial geological models.<br />
Combining the downhole temperature distribution<br />
and the production history, we can extract more<br />
reliable information about the reservoir permeability<br />
distribution and bottomhole flow conditions that help<br />
us optimize the wellbore performance, particularly<br />
in horizontal wells.<br />
Objectives<br />
We will use a thermal model and a transient, 3D,<br />
multiphase flow reservoir model to characterize the<br />
reservoir and horizontal well flow pr<strong>of</strong>ile.<br />
Approach<br />
Earlier work has shown that downhole temperature<br />
interpretation can provide a coarse-scale reservoir<br />
permeability distribution (Li and Zhu, <strong>2009</strong>). The<br />
question we address here is how to incorporate this<br />
information for geologic modeling and production<br />
history matching. There are two potential approaches,<br />
possibly among others. The first is to incorporate the<br />
coarse-scale permeability information as ‘secondary’<br />
information while constructing the prior geologic<br />
model. This model can then be history matched<br />
to further update the geologic model. The second<br />
approach would be to include the temperaturederived<br />
coarse-scale permeability as a penalty<br />
function during the history matching process. We<br />
will adopt the former approach.<br />
Fig. 1 shows an outline <strong>of</strong> an integrated approach<br />
that combines the temperature interpretation and<br />
production history matching for dynamic reservoir<br />
characterization and modeling. It includes four<br />
major steps as follows:<br />
» Use temperature interpretation method to match<br />
the observed temperature data, and obtain a<br />
coarse-scale permeability distribution.<br />
» Generate a high-resolution geologic model<br />
constrained to the coarse-scale permeability<br />
estimate. This is accomplished using Sequential<br />
Gaussian Simulation with Block Kriging, much<br />
along the line <strong>of</strong> seismic data integration into<br />
geologic models.<br />
» Use the geologic model as the prior model for<br />
production history matching. The history matching<br />
is carried out using a fast streamline-based<br />
approach that is well-suited for the high resolution<br />
model.<br />
No<br />
Project Information<br />
2.4.5 Production Monitoring and Control with Intelligent<br />
Technology<br />
Related Publications<br />
Li, Z. and Zhu, D. Predicting Flow Pr<strong>of</strong>ile <strong>of</strong> Horizontal<br />
Well by Downhole Pressure and DTS Data for Water-Drive<br />
Reservoir. Paper SPE 124873, presented at the <strong>2009</strong> SPE<br />
<strong>Annual</strong> Technical Conference and Exhibition, New Orleans,<br />
Louisiana, 4-7 October.<br />
Contacts<br />
Ding Zhu<br />
979.458.4522<br />
ding.zhu@pe.tamu.edu<br />
Zhuoyi Li<br />
Temperature interpretation<br />
Obtain a coarse-scale<br />
perm distribution<br />
Downscale the coarsescale<br />
permeability via<br />
sequential Gaussian<br />
simulation with block kriging<br />
Temperature<br />
data match?<br />
Finish<br />
Yes<br />
Yes<br />
Prior geologic model<br />
for history matching<br />
Forward simulation for<br />
reservoir pressure and<br />
saturation<br />
Calculation <strong>of</strong> production<br />
data misfit<br />
Production<br />
data match?<br />
No<br />
Calculation <strong>of</strong> sensitivity<br />
coefficients from streamline<br />
Updating permeability<br />
via minimizing production<br />
data misfit<br />
Fig. 1. Integrated workflow for incorporating temperature data into history<br />
matching.<br />
(continued on next page)<br />
CRISMAN INSTITUTE<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
51
» Use forward modeling <strong>of</strong> wellbore temperature<br />
to cross-check that the history matched model<br />
reproduces the temperature data. If the updated<br />
model reproduces the wellbore temperature<br />
measurements within a pre-specified tolerance,<br />
we accept the refined permeability distribution.<br />
Otherwise, we go back to step two and repeat the<br />
process.<br />
Accomplishments<br />
We presented several synthetic cases to illustrate<br />
the procedure. The results show that with only<br />
production history matching without distributed<br />
data along the wellbore, the water entry location in<br />
horizontal wells cannot be detected satisfactorily.<br />
Combining production history matching with the<br />
temperature distribution in the wellbore, we can get<br />
an improved geological model that can match the<br />
production history and also locate the water entry<br />
correctly. Based on the downhole flow conditions and<br />
the updated geological model, we can now optimize<br />
the well performance by controlling the inflow rate<br />
distribution, such as shutting the high water inflow<br />
sections. Fig.2 shows an example <strong>of</strong> the procedure<br />
developed from this project.<br />
Fig. 2. Example <strong>of</strong> using temperature interpretation and history match to<br />
characterize reservoir and downhole flow.<br />
52<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Optimization <strong>of</strong> Horizontal Well Performance in Low-Permeability Gas Reservoirs<br />
Objectives<br />
The objective <strong>of</strong> this research is to develop an<br />
approach to evaluate horizontal well performance for<br />
fractured or unfractured gas wells, and to conduct a<br />
sensitivity study <strong>of</strong> gas well performance in a low<br />
permeability formation. Different mathematical<br />
model approaches will be used, including analytical<br />
solutions, Point/Line source method, and Distributed<br />
Volumetric Source (DVS) method for numerical<br />
simulation. The methods will predict a production<br />
index for horizontal wells. In addition, permeability,<br />
well trajectory, fracture geometry, and in-situ<br />
stresses <strong>of</strong> formations, which are critical parameters<br />
for horizontal well and hydraulic fracturing design,<br />
will also be studied.<br />
Approach<br />
Analytical Solution<br />
Many horizontal well models have been developed<br />
for both steady-state flow and pseudo-steady<br />
flow. However, for tight gas formation, the flow is<br />
more likely to have a longer transient period. The<br />
performance <strong>of</strong> transient flow for horizontal gas<br />
wells should be studied in this research.<br />
to decide the horizontal well length and the numbers<br />
<strong>of</strong> fractures.<br />
Accomplishments<br />
» Slab source method has been developed to<br />
calculate the horizontal well, which has a good<br />
match with Babu and Odel’s method.<br />
» Horizontal well with one or two fractures has been<br />
solved for both transient and pseudo-steady state<br />
conditions.<br />
» For finite conductivity boundary conditions, we<br />
divided the fracture into several segments, and<br />
the pressure drop can be calculated.<br />
Future Work<br />
The ultimate goal <strong>of</strong> this project is to develop an<br />
Expert system. This system will help in calculating the<br />
performances <strong>of</strong> oil/gas horizontal wells, with other<br />
aspects conducted in the performances <strong>of</strong> fractures.<br />
By integrating these two topics, a system can be<br />
created to aid the industry to develop hydraulic<br />
fracture horizontal wells more economically and<br />
efficiently.<br />
Point/Line Source Solution<br />
A line source solution for horizontal well has been<br />
developed by Kamkom (2007). Investigate the<br />
possibility <strong>of</strong> using point source to represent fracture<br />
performance.<br />
Slab Source Solution<br />
The research will use the slab source method to<br />
predict well performance <strong>of</strong> a single fracture and<br />
multiple fractures. By comparing results with line<br />
source solution, the difference will be discussed<br />
Numerical Simulation<br />
The model built from the research will be combined<br />
with a commercial simulator (ECLIPSE) and a<br />
fine grid fracture to build a model for a tight gas<br />
horizontal well with and without fractures.<br />
Significance<br />
This project is a major initiative to review current<br />
fractured horizontal well performance in analytical<br />
theory. The results <strong>of</strong> this project allow comparing<br />
different fluid types and different boundary<br />
conditions reservoir to select an optimization method<br />
Project Information<br />
2.4.10 Optimization <strong>of</strong> Horizontal Well Performance in Low-<br />
Permeability Gas Reservoirs<br />
Contacts<br />
Ding Zhu<br />
979.458.4522<br />
ding.zhu@pe.tamu.edu<br />
Jiajing Lin<br />
CRISMAN INSTITUTE<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
53
Decision Matrix for Liquid Loading in Gas Wells for Cost/Benefit Analyses <strong>of</strong> Lifting<br />
Options (Part 2)<br />
Objectives<br />
Liquid loading is one <strong>of</strong> the main drawbacks <strong>of</strong><br />
gas well production. Although there are literature<br />
reviews available regarding solutions to liquid loading<br />
problems in gas wells, a tool capable <strong>of</strong> helping an<br />
operator select the best option for a specific field<br />
case still does not exist.<br />
The ultimate goal <strong>of</strong> this project is to fulfill the<br />
decision matrix tool initiated by a previous graduate<br />
student. Developing the tool itself and adding<br />
more available water unloading options and more<br />
limitations in each technique, using both technical<br />
and economic factors, will complete the full cycle for<br />
this project.<br />
Approach<br />
This project develops and expands the existing<br />
decision matrix tool used to evaluate and screen<br />
the possible available alternatives for dealing with<br />
liquid loading in gas wells. Limitations <strong>of</strong> liquid<br />
unloading techniques from literature reviews and<br />
practical actual data from the industries will be<br />
collected to become a database. A full cycle analysis<br />
<strong>of</strong> a production simulation will then be performed,<br />
emphasizing technical and economic impacts. First,<br />
simulation <strong>of</strong> gas production will be done using a<br />
material balance method. From this, production<br />
pr<strong>of</strong>iles and gas decline rates can be obtained. A<br />
decline curve analysis will also be done if the data<br />
available to confirm the results from the simulation<br />
exist. Then a cash flow analysis consisting <strong>of</strong> the cost<br />
and the benefits <strong>of</strong> each technique will be performed<br />
to obtain economic yardsticks such as NPV or IRR.<br />
Using these yardsticks should provide the most<br />
optimum (practical and economical) unloading<br />
technique to be selected.<br />
Significance<br />
By using this decision matrix tool as a preliminary<br />
screening tool, companies can determine which<br />
technique is the best fit for their conditions. The<br />
operators can also save time and money usually<br />
wasted when considering and trying many different<br />
liquid unloading techniques by themselves.<br />
Future Work<br />
The completed decision matrix is the ultimate goal <strong>of</strong><br />
this project, therefore the types <strong>of</strong> liquid unloading<br />
techniques, the limitations <strong>of</strong> each technique,<br />
the actual set <strong>of</strong> production data from the oil and<br />
gas companies, and the results from production<br />
simulations have to be applied to the decision matrix<br />
codes as much as possible to make this program<br />
provide a good representation <strong>of</strong> each alternative.<br />
Flow diagram for Decision Matrix.<br />
Project Information<br />
2.4.13 Decision Matrix for Liquid Loading in Gas Wells for<br />
Cost/Benefit Analyses <strong>of</strong> Lifting Options (Part 2)<br />
Related Publications<br />
Park, Han-Young: 2008, Decision Matrix for Liquid Loading<br />
in Gas Wells for Cost/Benefit Analyses <strong>of</strong> Lifting Options.<br />
MS thesis, Texas A&M U., College Station, Texas.<br />
Contacts<br />
Gioia Falcone<br />
979.847.8912<br />
gioia.falcone@pe.tamu.edu<br />
Nitsupon Soponsakulkaew<br />
Evaluation Start<br />
Preliminary Screening<br />
- Well information - Production status<br />
- Fluid properties - Reservoir properties<br />
- Power supply<br />
Technical Evaluation using Decision Matrix<br />
- Technical Efficiency - Reserves information<br />
- Production pr<strong>of</strong>iles - Production Decline Rate<br />
Economic Evaluation<br />
- Economic yardsticks (NPV, IRR)<br />
Final Selection and Ranking<br />
CRISMAN INSTITUTE<br />
54<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Investigation <strong>of</strong> Swirl Flows Applied to the Oil and Gas Industry<br />
Introduction<br />
Swirl flow (or vortex flow) is a fluid stream which has<br />
a rotational velocity as well as a linear velocity (Fig.<br />
1). It typically occurs in cyclones, hydrocyclones,<br />
spray dryers, heat exchangers with twisted-tape<br />
inserts, and vortex burners. It is also the basic<br />
principle behind foam-breaking or de-foaming<br />
separators, which have received significant industrial<br />
attention in recent years. Current research at Texas<br />
A&M University is studying the various applications<br />
<strong>of</strong> swirl flow to help mitigate particular problems<br />
in the oil and gas industry. Among the swirl flow<br />
applications under investigation are liquid unloading<br />
in gas wells and wet gas metering.<br />
Swirling Flow<br />
For the purpose <strong>of</strong> the analysis presented here, the<br />
expansion/contraction section and the venturi were<br />
excluded from the simulations in order to allow focus<br />
on the effects <strong>of</strong> the swirling device.<br />
In prior described experiments (Falcone et al.,<br />
2003), the actual length <strong>of</strong> straight pipe upstream<br />
<strong>of</strong> the swirler was about 10 m. This resulted in fully<br />
developed annular flow prior to the fluid reaching<br />
the swirler. To simulate this correctly with the CFD<br />
model while minimizing the mesh requirements<br />
(and hence the running times), a sensitivity analysis<br />
was performed on the length <strong>of</strong> pipe to be modeled<br />
before the swirler. It was found that a length <strong>of</strong> 2<br />
m in the model yielded annular flow upstream the<br />
swirler. The final model used for the CFD simulations<br />
is shown in Fig. 2.<br />
(continued on next page)<br />
Axial Flow<br />
Direction<br />
Fig. 1. Schematic <strong>of</strong> a swirl flow, showing a particle’s helical path.<br />
Objectives<br />
A commercial CFD s<strong>of</strong>tware package will be used<br />
in this study, with the objective <strong>of</strong> investigating<br />
the efficiency <strong>of</strong> the liquid separation at high gas<br />
fraction and evaluating the persistence <strong>of</strong> the swirl<br />
downstream <strong>of</strong> the flow conditioning device. These<br />
features are essential to understand not only the<br />
efficiency <strong>of</strong> in-line separation devices used for wet<br />
gas metering purposes, but also that <strong>of</strong> downhole<br />
tools for liquid unloading in gas wells.<br />
Approach<br />
A commercial CFD s<strong>of</strong>tware package was used.<br />
A model <strong>of</strong> the ANUMET meter was built and<br />
simulations were run using the input data from the<br />
reported experiments (Falcone, 2006). The pipe<br />
diameter was increased from 31.8 mm to 32.1 mm,<br />
which provided a 0.15 mm thick inflation boundary<br />
on the pipe walls that helped to capture the film<br />
thickness more efficiently than tetrahedral elements.<br />
Project Information<br />
2.4.17 Investigation <strong>of</strong> Swirl Flows Applied to the Oil and<br />
Gas Industry<br />
Related Publications<br />
Falcone, G., Hewitt, G.F., Lao, L., Richardson, S.M. ANUMET:<br />
A Novel Wet Gas Flowmeter. Paper SPE 84504 presented at<br />
the 2003 SPE <strong>Annual</strong> Technical Conference and Exhibition,<br />
Denver, Colorado, 5-8 October.<br />
Surendra, M., Falcone, G., Teodoriu, C. Investigation <strong>of</strong><br />
Swirl Flows Applied to the Oil and Gas Industry. Paper<br />
SPE 115938 presented at the 2008 SPE <strong>Annual</strong> Technical<br />
Conference and Exhibition, Denver, Colorado, 21-24<br />
September.<br />
Contacts<br />
Gioia Falcone<br />
979.847.8912<br />
gioia.falcone@pe.tamu.edu<br />
Catalin Teodoriu<br />
catalin.teodoriu@pe.tamu.edu<br />
Meher Surendra<br />
CRISMAN INSTITUTE<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
55
fractions involved, a detailed sensitivity analysis<br />
<strong>of</strong> the model used for this work would be required<br />
to assess the effects <strong>of</strong> varying the liquid content<br />
and also the operating pressure and the phase flow<br />
rates.<br />
Fig. 2. CFD model <strong>of</strong> the section <strong>of</strong> interest <strong>of</strong> the ANUMET meter. The<br />
flow is along the Z axis.<br />
Significance<br />
The preliminary results confirm that the twisted tape<br />
induces a swirling motion that results in a separated<br />
flow downstream <strong>of</strong> the device. The liquid flows<br />
along the pipe walls, although there remains some<br />
entrainment within the gas core. The distribution <strong>of</strong><br />
the phases across the pipe section is not the same<br />
at different locations downstream <strong>of</strong> the swirler.<br />
In particular, it appears that the efficiency <strong>of</strong> the<br />
separation is highest at the furthermost location<br />
from the device. However, due to the particular<br />
geometry investigated, this study has not been able<br />
to verify how far from the twisted tape the swirling<br />
motion persists, and whether this is accompanied<br />
by an efficient separation <strong>of</strong> the phases. It is in fact<br />
believed that, due mainly to gravity effects, there is<br />
a point where the vortex motion becomes negligible.<br />
Future Work<br />
For the ANUMET wet gas meter application, it is<br />
important to understand where the maximum<br />
liquid deposition occurs, so that the measured<br />
film thickness would be most representative <strong>of</strong> the<br />
total liquid hold up in the pipe. For downhole liquid<br />
unloading applications, it is important to understand<br />
whether the swirling motion induced by vortex<br />
devices can actually persist up to the wellhead. More<br />
work is needed to prove the actual flow dynamics<br />
through these devices and the relationship between<br />
tool configuration, flow rates, operating pressure,<br />
well geometry (length, diameter and orientation)<br />
and swirl persistence. Also, because <strong>of</strong> the high gas<br />
56<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Potential for CO 2<br />
Sequestration and Enhanced Coalbed Methane Production, NW<br />
Black Warrior Basin<br />
Objectives<br />
This project is going to assess the potential for<br />
CO 2<br />
sequestration and enhanced coalbed methane<br />
(ECBM) production <strong>of</strong> the Pottsville formation coals.<br />
The ultimate goal is to rank Black Warrior basin CBM<br />
fields by their potential for pr<strong>of</strong>itability and to select<br />
a pilot site that is suitable for injection <strong>of</strong> CO 2<br />
at a<br />
commercial scale <strong>of</strong> up to 50 MMcf/d. The assessment<br />
will address technical issues, such as CO 2<br />
injection<br />
rates, injection volumes and pressures, number <strong>of</strong><br />
wells, and well spacing.<br />
as evaluation <strong>of</strong> the CO 2<br />
sequestration and ECBM in<br />
this area becomes more commercial.<br />
Approach<br />
We will design study cases to optimize the production<br />
and the sequestration, which includes well spacing,<br />
completion layers, dewatering time, injecting rate,<br />
etc. We will collect the data for the Blue Creek field.<br />
We will also specify the reservoir properties and set<br />
up the model <strong>of</strong> the formation.<br />
Accomplishments<br />
Our simulation study was based on a 5-spot well<br />
pattern 40-ac well spacing. For the entire Blue<br />
Creek field <strong>of</strong> the Black Warrior basin, if 100% CO 2<br />
is injected into the Pratt, Mary Lee and Black Creek<br />
coal zones, enhanced methane resources recovered<br />
are estimated to be 0.3 Tcf, with a potential CO 2<br />
sequestration capacity <strong>of</strong> 0.88 Tcf. The methane<br />
recovery factor is estimated to be 68.8%, if the three<br />
coal zones are completed but produced one by one.<br />
Approximately 700 wells may be needed in the field.<br />
For multi-layered completed wells, the permeability<br />
and pressure are important in determining the<br />
breakthrough time, methane produced, and CO 2<br />
injected. Dewatering and soaking do not benefit<br />
the CO 2<br />
sequestration process, but do allow higher<br />
injection rates. Permeability anisotropy affects CO 2<br />
injection and enhanced methane recovery volumes<br />
<strong>of</strong> the field.<br />
We recommend a 5-spot pilot project with a maximum<br />
well BHP <strong>of</strong> 1,000 psi at the injector, a minimum<br />
well BHP <strong>of</strong> 500 psi at the producer, a maximum<br />
injection rate <strong>of</strong> 70 Mscf/D, and a production rate <strong>of</strong><br />
35 Mscf/D.<br />
Significance<br />
For environmental and economical factors, it is<br />
feasible to have several ECBM programs in Black<br />
Warrior Basin. These programs are win-win projects<br />
Coalbed methane fields in the Black Warrior Basin, Alabama (from Pashin<br />
et al. 2004).<br />
Project Information<br />
2.4.22 Evaluation <strong>of</strong> Potential for CO 2<br />
Sequestration and<br />
CO 2<br />
ECBM, Pottsville Formation, Black Warrior Basin<br />
Contacts<br />
Walter B. Ayers<br />
979.845.2447<br />
walt.ayers@tamu.edu<br />
Maria Barrufet<br />
979.845.0314<br />
maria.barrufet@pe.tamu.edu<br />
Ting He<br />
CRISMAN INSTITUTE<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
57
Transient Multiphase Sand Transport in Horizontal Wells<br />
Introduction<br />
Multiphase technology solutions have enabled the<br />
process industries, such as the petroleum industry,<br />
mining industry and nuclear industry, to improve their<br />
production performance, extend their operation,<br />
and address previously insoluble problems.<br />
Objectives<br />
The objective <strong>of</strong> the dissertation is to develop a<br />
dynamic simulation tool for sand transport and<br />
control in oil-gas and oil-water multiphase flow<br />
systems through horizontal and vertical wellbores,<br />
pipelines, and production rises.<br />
Approach<br />
Unsteady state multiphase flow and optimal sand<br />
transport control models will be developed based on<br />
a multi-fluid modeling approach in the CFX Ansys,<br />
STAR CCM+ and MATLAB platforms to predict sand<br />
particle transport and hydrodynamic behavior under<br />
various system, operation, and geometric conditions.<br />
New data from sand transport and entrainment<br />
experimental flow loops will be used to validate<br />
the developed model(s) and to achieve a better<br />
understanding, and to improve project performance<br />
and value creation. The new design and engineering<br />
analysis tool will provide best practices guidelines<br />
and performance assessment <strong>of</strong> gas-oil-sand and<br />
oil-water-sand multiphase flow system design<br />
options and optimal operational methodologies.<br />
Accomplishments<br />
» Reviewed literature <strong>of</strong> current multiphase models<br />
and their limitations<br />
» Developed a mechanistic model for predicting<br />
effect on the pressure drop <strong>of</strong> sand transport in<br />
horizontal wells<br />
» Placed a purchasing order for flange gaskets to be<br />
used in the flow loop facility in Room 601.<br />
Future Work<br />
» Continue with the literature review <strong>of</strong> sand<br />
transport and multiphase models.<br />
» Jump-start the flow loop in Room 601.<br />
» Modify the flow loop to accommodate sand<br />
transport mechanism.<br />
CRISMAN INSTITUTE<br />
Project Information<br />
2.4.23 Transient Multiphase Sand Transport in Horizontal<br />
Wells<br />
Contacts<br />
Gioia Falcone<br />
979.847.8912<br />
gioia.falcone@pe.tamu.edu<br />
Ime Udong<br />
58<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Performance Driven Hydraulic Fracture Design for Deviated Wells<br />
Introduction<br />
Unrestricted fracturing, long-established for lowpermeability<br />
reservoirs, is not applicable to highpermeability<br />
formations where the resulting width<br />
would be far less than indicated by rigorous design<br />
approaches such as the Unified Fracture Design<br />
(UFD). Thus, tip screenout (TSO) treatments are<br />
necessary, in which the lateral migration <strong>of</strong> the<br />
fracture is arrested followed by inflation <strong>of</strong> the<br />
fracture to the desired/optimum width. The term<br />
high-performance fracturing (HPF) better reflects<br />
the high performance standard targeted by this<br />
completion technique.<br />
Connectivity between the well and the fracture is<br />
a very important issue and has been addressed<br />
repeatedly in the literature. Because HPF’s dominate<br />
Gulf <strong>of</strong> Mexico well completions where well deviation<br />
angles established for extended reach drilling are<br />
maintained through the productive zone, the issue<br />
<strong>of</strong> well to fracture connectivity becomes even more<br />
serious. Ehlig-Economides et al. introduced a new<br />
model for hydraulically fractured wells, hypothesizing<br />
that only those perforations in the intersection<br />
between the far field hydraulic fracture plane and the<br />
wellbore actually connect flow through the fracture<br />
to the well. In turn, Zhang et al. introduced a new<br />
model allowing for flow both through the fracture<br />
and bypassing the fracture through perforation that<br />
are not connected to the fracture.<br />
Objectives<br />
This research is intended to provide new<br />
computational tools to quantify how the presence<br />
<strong>of</strong> the deviated wellbore open to flow impacts the<br />
expected performance <strong>of</strong> the hydraulic fracture,<br />
allowing a design <strong>of</strong> the system “deviated wellbore<br />
open to flow + transverse hydraulic fracture” to<br />
maximize overall productivity.<br />
Approach<br />
The problem is approached by combining the UFD<br />
technique with the “Method <strong>of</strong> Distributed Volumetric<br />
Sources” (DVS). We are developing a convenient<br />
implementation/methodology that will iteratively<br />
find the optimal fracture geometry that would result<br />
in a maximum productivity index <strong>of</strong> the deviated<br />
and fractured wells.<br />
Future Work<br />
We intend to carry on the following three main tasks:<br />
» Provide analytical/empirical expression(s) for<br />
the mechanical skin that includes all contributing<br />
factors such as well deviation, perforation density,<br />
phasing, penetration depth, diameter, minimum<br />
in-situ stress direction, proppant permeability,<br />
halo effect, production rate, and turbulence beta<br />
factors.<br />
» Provide analytical/empirical expression(s) for the<br />
composite productivity index (J D<br />
) that includes all<br />
previously mentioned major contributing factors.<br />
» Generate simplified correlations and benchmarking<br />
plots for the composite productivity index (J D<br />
)<br />
versus well deviation and reservoir permeability.<br />
CRISMAN INSTITUTE<br />
Project Information<br />
2.4.24 Hydraulically Fractured Well Performance in High<br />
Rate Wells<br />
Related Publications<br />
Economides, M. J., Oligney, R.E., and Valkó, P.P. 2002.<br />
Unified Fracture Design (hardbound). Houston: Orsa Press.<br />
Ehlig-Economides, C.A., Tosic, S., and Economides, M.J.<br />
Foolpro<strong>of</strong> Completions for High-Rate Production Wells.<br />
Paper SPE 111455, presented at the 2008 SPE International<br />
Symposium and Exhibition on Formation Damage Control,<br />
Lafayette, Louisiana, 13-15 February.<br />
Zhang, Y., Marongiu-Porcu, M., Ehlig-Economides, C.A.,<br />
Tosic, S., and Economides, M.J. Comprehensive Model for<br />
Flow Behavior <strong>of</strong> High-Performance Fracture Completions.<br />
Paper SPE 124431, presented at the ATCE <strong>2009</strong> SPE<br />
<strong>Annual</strong> Technical Conference and Exhibition, New Orleans,<br />
Louisiana, 4-7 October.<br />
Valko, P.P., and Amini, S. Method <strong>of</strong> Distributed Volumetric<br />
Sources for Calculating the Transient and Pseudosteady<br />
State Productivity Index <strong>of</strong> Complex Well-fracture<br />
Configurations. Paper SPE 106279, presented at the 2007<br />
SPE Hydraulic Fracturing Technology Conference, College<br />
Station, Texas, 29-31 January.<br />
Contacts<br />
Christine Ehlig-Economides<br />
979.458.0797<br />
c.economides@pe.tamu.edu<br />
Matteo Porcu<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
59
Carbonate Heterogeneity and Acid Fracture Performance<br />
Objectives<br />
The objective <strong>of</strong> this work is to evaluate the expected<br />
performance <strong>of</strong> acid fracturing for two wells in the<br />
Hugoton field. Permeability data from cores and<br />
outcrops as well as mineralogical descriptions <strong>of</strong><br />
the sampled rock will be used to characterize the<br />
carbonate heterogeneity. Specifically, the standard<br />
deviation <strong>of</strong> permeability, vertical correlation length,<br />
and horizontal correlation length will be defined.<br />
These geostatistical parameters are inputs for an acid<br />
fracture simulator developed by Mou et al. (<strong>2009</strong>)<br />
that incorporates an intermediate-scale acid etching<br />
model. This work will be combined with a model <strong>of</strong><br />
fracture surface deformation behavior under closure<br />
stress developed by Deng et al. (<strong>2009</strong>), and the<br />
overall acid fracture conductivity will be determined<br />
for the case in the Hugoton field.<br />
Approach<br />
Determination <strong>of</strong> the vertical correlation length will<br />
depend on permeability measurements taken on<br />
cores from the productive zones <strong>of</strong> the Hugoton<br />
field. The horizontal correlation length will primarily<br />
depend on permeability data from outcrops, but<br />
may also be supported with well and field data,<br />
analogues, and literature on carbonates in the<br />
Chase Group. Mou’s acid fracture simulator, along<br />
with Deng’s model <strong>of</strong> fracture conductivity under<br />
closure stress, will be applied to this case.<br />
Accomplishments<br />
Core permeability data was collected every inch<br />
over ten feet in three productive zones for two wells<br />
in the Hugoton field. From this data, the vertical<br />
correlation length can be derived through analysis<br />
<strong>of</strong> each vertical semivariogram (Fig. 1). Numerous<br />
Chase Group outcrop locations have been identified<br />
in Kansas for collection <strong>of</strong> horizontal permeability<br />
and mineralogy data.<br />
Future Work<br />
The models developed by Mou and Deng will be<br />
combined to produce one overall acid fracture<br />
simulator. The Hugoton case will serve as a test<br />
case by which the practicality <strong>of</strong> the simulator will<br />
be evaluated and improved as needed.<br />
(h)<br />
250<br />
200<br />
150<br />
100<br />
50<br />
CRISMAN INSTITUTE<br />
Project Information<br />
2.5.1 Acid Fracture Performance – Scale-Up <strong>of</strong> Fracture<br />
Conductivity<br />
Related Publications<br />
Deng, J., Hill, A.D. and Zhu, D. A Theoretical Study <strong>of</strong><br />
Acid Fracture Conductivity Under Closure Stress. Paper<br />
SPE-124755, presented at the <strong>2009</strong> SPE <strong>Annual</strong> Technical<br />
Conference and Exhibition, New Orleans, Louisiana, 4-7<br />
October.<br />
Mou, J., Zhu, D. and Hill, A.D. A New Acid-Fracture<br />
Conductivity Model Based on the Spatial Distributions <strong>of</strong><br />
Formation Properties. Paper SPE-127935 presented at the<br />
2010 SPE International Symposium on Formation Damage<br />
Control, Lafayette, Louisiana, 10-12 February.<br />
Mou, J., Zhu, D. and Hill, A.D. Acid-Etched Channels<br />
in Heterogeneous Carbonates—A Newly Discovered<br />
Mechanism for Creating Acid Fracture Conductivity.<br />
Paper SPE-119619 presented at the <strong>2009</strong> SPE Hydraulic<br />
Fracturing Technology Conference, The Woodlands, Texas,<br />
19-21 January.<br />
Contacts<br />
Dan Hill<br />
979.845.2278<br />
dan.hill@pe.tamu.edu<br />
Ding Zhu<br />
979.458.4522<br />
ding.zhu@pe.tamu.edu<br />
Flower Well Towanda Member Semivariogram<br />
0<br />
0 20 40 60 80 100 120<br />
h<br />
Fig. 1. Semivariogram for the Flower Well in the Towanda Member, illustrating<br />
a vertical correlation length <strong>of</strong> approximately 5 inches.<br />
Cassandra Beatty<br />
60<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Modeling and Analysis <strong>of</strong> Reservoir Response to Stimulation by Water Injection<br />
Objectives<br />
The distributions <strong>of</strong> pore pressure and stresses<br />
around a fracture are <strong>of</strong> interest in conventional<br />
hydraulic fracturing operations, fracturing during<br />
water-flooding <strong>of</strong> petroleum reservoirs, shale gas,<br />
and injection/extraction operations in a geothermal<br />
reservoir. During the operations, the pore pressure<br />
will increase with fluid injection into the fracture<br />
and leak <strong>of</strong>f to surround the formation. The pore<br />
pressure increase will induce the stress variations<br />
around the fracture surface. This can cause the<br />
slip <strong>of</strong> weakness planes in the formation and cause<br />
the variation <strong>of</strong> the permeability in the reservoir.<br />
Therefore, the investigation on the pore pressure<br />
and stress variations around a hydraulic fracture in<br />
petroleum and geothermal reservoirs has practical<br />
applications. With the pore pressure distribution,<br />
the failed reservoir volume can be estimated by<br />
considering the failure <strong>of</strong> rock mass.<br />
Y, ft<br />
3000<br />
2400<br />
1800<br />
1200<br />
(psi)<br />
6558.00<br />
600<br />
6148.33<br />
5738.67<br />
0<br />
5329.00<br />
4919.33<br />
-600<br />
4509.67<br />
4100.00<br />
-1200<br />
-1800<br />
-2400<br />
-3000 -2400 -1800 -1200 -600 0 600 1200 1800 2400<br />
X, ft<br />
Fig. 1. Pore Pressure Distribution around a Hydraulic Fracture.<br />
Approach<br />
In our study, we built up a model (FracJStim model)<br />
to calculate the pore pressure distribution around a<br />
fracture <strong>of</strong> a given length under the action <strong>of</strong> applied<br />
internal pressure and in-situ stresses as well as their<br />
variation due to cooling and pore pressure changes<br />
(Fig. 1). In the FracJStim model, the Structural<br />
Permeability Diagram (Fig. 2) is used to estimate<br />
the required additional pore pressure to reactivate<br />
the joints in the rock formations <strong>of</strong> the reservoir. By<br />
estimating the failed reservoir volume and comparing<br />
it with the actual stimulated reservoir volume, the<br />
enhanced reservoir permeability in the stimulated<br />
zone can be approximated.<br />
0<br />
270 90<br />
180<br />
Fig. 2. Structural Permeability Diagram for Barnett Shale.<br />
P<br />
(psi/ft)<br />
0.50<br />
0.06<br />
Significance<br />
This work is <strong>of</strong> interest in interpretation <strong>of</strong> microseismicity<br />
in hydraulic fracturing and in assessing<br />
permeability variation around a stimulation zone.<br />
The work can also be used to assess the accuracy <strong>of</strong><br />
more complex numerical models.<br />
Future Work<br />
We will continue developing the model to three<br />
Dimensions, including the stresses variations and<br />
heterogeneous conditions. We will also improve<br />
the application <strong>of</strong> this work by simulating multiple<br />
fractures.<br />
CRISMAN INSTITUTE<br />
Project Information<br />
2.5.10 Pore Pressure and Stress Distributions around an<br />
Injection-Induced Fracture<br />
Contacts<br />
Ahmad Ghassemi<br />
979.845.2206<br />
ahmad.ghassemi@pe.tamu.edu<br />
Jun Ge<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
61
Fracture Aperture Variation Caused by Reactive Transport <strong>of</strong> Silica and<br />
Poro-Thermoelastic Effect<br />
Introduction<br />
Poro-thermo-mechanical processes and<br />
mineral precipitation/dissolution change the<br />
fracture aperture and thus affect the fluid<br />
flow pattern in the fracture.<br />
a.<br />
t =3 months<br />
b.<br />
t =3 months<br />
Different aspects <strong>of</strong> thermal and mechanical<br />
processes have been studied (e.g. Ghassemi<br />
and Zhang, 2004; Ghassemi et al., 2005,<br />
2007, 2008, and <strong>2009</strong>). The thermoelastic<br />
effects are dominant near the injection when<br />
compared to those <strong>of</strong> poroelasticity. Under<br />
some conditions, silica reactivity tends to<br />
dominate permeability (Kumar and Ghassemi,<br />
2007). Experimental studies (Carroll et al.,<br />
1998; Johnson et al., 1998; Dobson et al.,<br />
2003) also show that chemical precipitation<br />
and dissolution <strong>of</strong> minerals significantly affect<br />
fracture aperture.<br />
c. t =3 months<br />
d.<br />
t =3 months<br />
Objectives<br />
We will study this phenomenon by the<br />
development and application <strong>of</strong> a threedimensional<br />
poro-thermoelastic model<br />
incorporating mineral dissolution/precipitation<br />
effects.<br />
Approach<br />
Simulating the poro-thermoelastic chemical<br />
mechanisms usually requires solving a coupled set<br />
<strong>of</strong> equations (e.g., fluid flow, heat transport, solute<br />
transport/reactions and elastic response <strong>of</strong> the<br />
reservoir). These processes are coupled and nonlinear.<br />
In this work, the solid mechanics aspect <strong>of</strong><br />
the problem is treated using poro-thermoelastic<br />
displacement discontinuity method (Ghassemi et<br />
al., <strong>2009</strong>), while reactive flow and heat transport in<br />
the fracture is solved using finite element method.<br />
Similarly, the solution system in the reservoir rock<br />
is obtained using the boundary element method. We<br />
focus on single-component mineral reactivity and<br />
its transport in the fracture. The solute reactivity<br />
and solubility in fracture plane is considered using a<br />
temperature dependent formulation (e.g., Robinson,<br />
1982, and Rimstidt and Barnes, 1980).<br />
Significance<br />
We apply the model to simulate the process <strong>of</strong><br />
low-temperature fluid injection and production <strong>of</strong><br />
high-temperature fluid in a hot-rock-reservoir, and<br />
a. Flow vector in planar fracture; b. Contour plot <strong>of</strong> the temperature (K) distribution;<br />
c. Contour plot <strong>of</strong> silica concentration (ppm) in the fracture; d. Ratio <strong>of</strong><br />
current fracture aperture to the initial fracture aperture.<br />
thus its impact on mineral mass distribution, pore<br />
pressure and thermal stress. Recent computations<br />
include temporal evolution <strong>of</strong> mineral concentration<br />
and its dissolution/precipitation, temperature, and<br />
fluid pressure in the fracture.<br />
Project Information<br />
2.5.14 Fracture Aperture Variation due to Reactive Transport<br />
<strong>of</strong> Silica and Poro-Thermoelastic Effect<br />
Related Publications<br />
Rawal C. and Ghassemi A. A 3-D Analysis <strong>of</strong> Solute<br />
Transport in a Fracture in Hot- and Poro-elastic Rock. Paper<br />
to be presented at the 2010 44th U.S. Rock Mechanics<br />
Symposium, ARMA, Salt Lake City, Utah, 27-30 June.<br />
Rawal C. and Ghassemi A. Reactive Flow in a Natural<br />
Fracture in Poro-thermoelastic Rock. Paper presented at<br />
the 2010 35th Stanford Geothermal Workshop. Stanford,<br />
California, 1-3 February.<br />
Contacts<br />
Ahmad Ghassemi<br />
979.845.2206<br />
ahmad.ghassemi@pe.tamu.edu<br />
Chakra Rawal<br />
CRISMAN INSTITUTE<br />
62<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Rheological Properties <strong>of</strong> a New Class <strong>of</strong> Viscoelastic Surfactant<br />
Objectives<br />
Surfactant-based acid systems were developed over<br />
the last few years for diversion, to overcome the<br />
severe problems caused by polymer residue and<br />
crosslinker precipitate after polymer-based system<br />
treatments during matrix and fracture acidizing.<br />
Surfactant molecules can form rod-like micelles and<br />
significantly increase the viscosity in the presence <strong>of</strong><br />
salts. After acid treatments, the surfactant gel can<br />
be broken by mixing with hydrocarbons, external<br />
breakers, or internal breakers or by reducing the<br />
concentration <strong>of</strong> salts via dilution with water. Acid<br />
additives and Fe (III) contamination can influence<br />
the formation <strong>of</strong> the rod-shaped micelles and result<br />
in different rheological properties from what we<br />
want. A new class <strong>of</strong> viscoelastic surfactant (VES)-<br />
amidoamine oxide has been tested in this study.<br />
The effects <strong>of</strong> acid additives, Fe (III) contamination,<br />
temperatures and shear rates need to be examined<br />
on the rheological properties <strong>of</strong> this new surfactant.<br />
Approach<br />
Acid additives studied included corrosion inhibitors,<br />
mutual solvents, non-emulsifying surfactants, iron<br />
control agents and a hydrogen sulfide scavenger.<br />
The Grace Instrument M5600 HPHT Rheometer was<br />
used to measure the apparent viscosity <strong>of</strong> live and<br />
spent acids under different conditions. The wetted<br />
material is Hastelloy C-276, which is acid-resistant.<br />
Measurements were made at temperatures from 75-<br />
220°F, and 300 psi at various shear rates from 0.01-<br />
935 s -1 . An Orion 950 analytical titrator was used to<br />
measure HCl concentration. The centrifuge used in<br />
this study was Z 206 A from Labnet International.<br />
Apparent Viscosity (cp)<br />
1200<br />
1000<br />
800<br />
600<br />
400<br />
200<br />
0<br />
5<br />
10<br />
15<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
C HCl<br />
(wt%)<br />
20<br />
8<br />
10<br />
12<br />
15<br />
18<br />
20<br />
25<br />
28<br />
Acid Concentration (wt%)<br />
Viscosity (cp)<br />
108.8632<br />
706.438<br />
984.783<br />
175.0444<br />
12.1892<br />
5.8126<br />
2.8148<br />
2.896<br />
25 30<br />
Fig. 1. Apparent viscosity (10 s -1 ) <strong>of</strong> surfactant-based live acids that contained<br />
4 wt% surfactant, 1 wt% CI-A and various HCl concentrations.<br />
Apparent Viscosity (cp)<br />
1800<br />
1600<br />
1400<br />
1200<br />
1000<br />
800<br />
600<br />
400<br />
200<br />
Accomplishments<br />
Calcium chloride increased the apparent viscosity<br />
<strong>of</strong> live acids. Concentration <strong>of</strong> HCl in the live acid<br />
system affected its apparent viscosity. Live acid<br />
Project Information<br />
2.5.15 Reaction <strong>of</strong> Organic Acids with Calcite<br />
Related Publications<br />
Li, L., Nasr-El-Din, H.A., Crews, J.B., and Cawiezel, K.E.<br />
2010. Impact <strong>of</strong> Organic Acids/Chelating Agents on<br />
Rheological Properties <strong>of</strong> Amidoamine Oxide Surfactant.<br />
Paper SPE 128091 will be presented at the 2010 SPE<br />
International Symposium on Formation Damage Control,<br />
Lafayette, Louisiana, 10-12 February.<br />
Li, L., Nasr-El-Din, H.A., and Cawiezel, K.E. <strong>2009</strong>.<br />
Rheological Properties <strong>of</strong> a New Class <strong>of</strong> Viscoelastic<br />
Surfactant. Paper SPE 121716 presented at the <strong>2009</strong><br />
SPE International Symposium on Oilfield Chemistry, The<br />
Woodlands, Texas, 20-22 April.<br />
Contacts<br />
Hisham A. Nasr-El-Din<br />
979.862.1473<br />
hisham.nasreldin@pe.tamu.edu<br />
Lingling Li<br />
-1<br />
Shear Rate = 10 s<br />
P = 300 psi<br />
0<br />
50 70 90 110 130 150 170 190 210 230<br />
Temperature (°F)<br />
only CI-A<br />
0.1 wt% FeCl3<br />
0.5 wt% H2S scavenger<br />
0.5 wt% demulsifier<br />
Fig. 2. Effect <strong>of</strong> some acid additives on the apparent viscosity <strong>of</strong> spent<br />
acids (pH = 4 ~ 5). All solutions contained CI-A.<br />
(continued on next page)<br />
CRISMAN INSTITUTE<br />
63
that contained 12 wt% HCl showed the highest<br />
apparent viscosity. Low concentrations <strong>of</strong> Fe (III)<br />
caused an increase in the apparent viscosity. Two<br />
immiscible liquids and then a precipitate were noted<br />
as the concentration <strong>of</strong> ferric ion was increased in<br />
live acids. Iron control agents reduced the apparent<br />
viscosity <strong>of</strong> surfactant-based acids. The impact <strong>of</strong><br />
lactic acid on the apparent viscosity was significant,<br />
especially at high lactic acid concentrations. Citric<br />
acid also reduced the viscosity <strong>of</strong> surfactant based<br />
acids, but cannot be used at concentrations greater<br />
than 0.5 wt% because <strong>of</strong> this precipitation <strong>of</strong><br />
calcium citrate. Ethylenediaminetetraacetic acid<br />
(EDTA) slightly reduced the viscosity <strong>of</strong> surfactant<br />
based acids, but the solubility <strong>of</strong> EDTA in 20 wt%<br />
HCl is very low. Up to 1 wt% methanol can be used<br />
with this spent acid system at temperatures below<br />
175°F. Higher concentrations <strong>of</strong> methanol caused<br />
significant reduction in the apparent viscosity.<br />
Future Work<br />
Simple organic acids and iron control agents<br />
(α-hydroxyl carboxylic acids) can interfere with<br />
micelle shape and reduce the apparent viscosity<br />
<strong>of</strong> VES-based acids, therefore their influences will<br />
be tested in the future. A transmission electron<br />
microscope (TEM) will also be used to examine the<br />
effects <strong>of</strong> acids on micelle shapes.<br />
64<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Acid Hydrolysis <strong>of</strong> Carboxybetaine Viscoelastic Surfactant<br />
Objectives<br />
Viscoelastic surfactants (VES) are recognized by<br />
their unique ability to form gel in-situ, and thus<br />
have been widely applied in acid diverting and<br />
fracturing treatments. Several types <strong>of</strong> VES have<br />
been used, including carboxybetaine surfactants.<br />
However, when mixed with hydrochloric acid under<br />
high temperatures, this particular type <strong>of</strong> VES is<br />
subjected to acid hydrolysis and may lose its viscoelastic<br />
property.<br />
The objective <strong>of</strong> this study is to examine the impact<br />
<strong>of</strong> acid hydrolysis <strong>of</strong> carboxybetaine surfactants on<br />
their performance in various field applications.<br />
Approach<br />
Hydrolysis experiments were conducted on HCl<br />
solutions that contained 7 wt% VES at various<br />
temperatures, acid concentrations and time. These<br />
fluids were heated to the temperature <strong>of</strong> interest,<br />
held for different periods <strong>of</strong> time, cooled to room<br />
temperature, neutralized by CaCO 3<br />
and their<br />
viscosity was measured as a function <strong>of</strong> shear rate<br />
using a Grace Instrument M3600 viscometer.<br />
Accomplishments<br />
It was found that these VES fluids lost viscosity<br />
significantly after hydrolysis, and the viscosity <strong>of</strong> the<br />
hydrolyzed sample was influenced by temperature,<br />
acid concentration, and time. Moreover, an oily<br />
phase was separated from the aqueous phase in the<br />
hydrolyzed samples.<br />
Significance<br />
The observations from the experiments indicated<br />
that when carboxybetaine VES is mixed with HCl at<br />
high temperature, it may lose its ability to increase<br />
fluid viscosity; and further more, the two phase<br />
mixture after hydrolysis may cause formation<br />
damage. Current research work will be conducted<br />
to investigate what factors affect acid hydrolysis <strong>of</strong><br />
carboxybetaine surfactants, and how they affect it.<br />
At the end <strong>of</strong> this research, recommendations will be<br />
given on how to use these surfactants in the field.<br />
CRISMAN INSTITUTE<br />
Project Information<br />
2.5.16 Quantitative Analysis <strong>of</strong> Amphoteric Surfactant<br />
Related Publications<br />
Yu, M. and Nasr-El-Din, H. Quantitative Analysis <strong>of</strong> an<br />
Amphoteric Surfactant in Acidizing Fluids and Coreflood<br />
Effluent. Paper SPE 121715 presented at the <strong>2009</strong> SPE<br />
Symposium on Oilfield Chemistry, Woodlands, Texas, 20-<br />
22 April.<br />
Contacts<br />
Hisham Nasr-El-Din<br />
979.862.1473<br />
hisham.nasreldin@pe.tamu.edu<br />
Meng Yu<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
65
Evaluation <strong>of</strong> Polymer-Based In-Situ Gelled Acids during Well Stimulation<br />
Introduction<br />
An in-situ gelled system based on a polymer that is<br />
stable in an aqueous acid environment can be crosslinked<br />
in the presence <strong>of</strong> ferric ions or zirconium ions<br />
at a pH <strong>of</strong> about 2 or greater. The polymer should<br />
contain carboxyl groups; such polymers include<br />
acrylamide and acrylamide copolymers. Initial<br />
spending <strong>of</strong> the live acid, during leak-<strong>of</strong>f and wormholing,<br />
produces a rise in pH to a value <strong>of</strong> above,<br />
or about, 2, which initiates cross-linking <strong>of</strong> the<br />
polymer (resulting in a rapid increase in viscosity).<br />
This increase in viscosity creates the diversion<br />
from wormholes, from fissures, and from within<br />
the matrix. As the acid spends further and the pH<br />
continues to rise, the reducing agent converts the<br />
ferric ions to ferrous ions. The gel structure will<br />
collapse and the acid system reverts back to a low<br />
viscosity fluid.<br />
Approach<br />
Three commercial acid systems from three different<br />
companies were evaluated under normal and<br />
severe contamination <strong>of</strong> iron and salt. Experimental<br />
studies were conducted to measure the rheological<br />
properties for in-situ gelled acid using an oscillation<br />
rheometer and a rotational viscometer. To the best <strong>of</strong><br />
our knowledge, this is the first time that the elastic<br />
properties were measured for these acids. Finally,<br />
a coreflood study was conducted using Indiana<br />
limestone cores (1.5 in diameter, 20 in long) at<br />
250°F. Propagation <strong>of</strong> the acid, polymer, and crosslinker<br />
inside the long cores was examined for the<br />
first time in detail.<br />
Objectives<br />
In-situ gelled acids that are based on polymers have<br />
been used in the field for several years, and were the<br />
subject <strong>of</strong> many lab studies. There are conflicting<br />
opinions about using these acids. These acids were<br />
used in the field, with mixed results, yet recent lab<br />
work indicated that these acids can cause damage<br />
under certain conditions. There is no agreement<br />
on when this system can be successfully applied in<br />
the field, therefore the objective <strong>of</strong> this research is<br />
to recommend the best conditions where polymerbased<br />
acids can be used.<br />
Normalized Pressure Drop<br />
12<br />
10<br />
8<br />
6<br />
4<br />
2<br />
0<br />
Shear Rate, s -1<br />
743<br />
1288<br />
1780<br />
2161<br />
0 1 2 3 4 5 6<br />
Cumulative Injected Volume, PV<br />
Normalized Pressure Drop for the four experiments conducted at different<br />
shear rate, T = 250°F.<br />
CRISMAN INSTITUTE<br />
Project Information<br />
2.5.17 Viscosity <strong>of</strong> Polymer-Based In-Situ Gelled Acids<br />
during Well Stimulation<br />
Related Publications<br />
Gomaa, A.M., and Nasr-El-Din, H.A. Rheological Properties<br />
<strong>of</strong> Polymer-Based In-Situ Gelled Acids: Experimental and<br />
Theoretical Studies. Paper SPE 128057, presented at the<br />
2010 Oil and Gas India Conference and Exhibition, Mumbai,<br />
India, 20–22 January.<br />
Gomaa, A.M., Mahmoud, M., and Nasr-El-Din, H.A. When<br />
Polymer-based Acids can be used? A Core Flood Study.<br />
Paper TPTC 13739, presented at the <strong>2009</strong> SPE International<br />
Petroleum Technology Conference, Doha, Qatar, 7–9<br />
December.<br />
Gomaa, A.M., Nasr-El-Din, H.A. Viscosity <strong>of</strong> Polymer-<br />
Based In-Situ Gelled Acids during Well Stimulation. Paper<br />
SPE 121728, presented at the <strong>2009</strong> SPE International<br />
Symposium on Oilfield Chemistry held in The Woodlands,<br />
Texas, 20–22 April.<br />
Contacts<br />
Hisham A. Nasr-El-Din<br />
979.862.1473<br />
hisham.nasreldin@pe.tamu.edu<br />
Ahmed Gomaa<br />
66<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Determination <strong>of</strong> CT number for gel residue.<br />
Future Work<br />
A parallel coreflood study will be conducted using<br />
multistage acid injection. Propagation <strong>of</strong> each acid<br />
stage, polymer, and cross-linker inside the long<br />
cores will be examined in detail. Also, reaction<br />
rate measurement for the in-situ gelled acid using<br />
a rotating disk apparatus will be conducted under<br />
different conditions.<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
67
Modeling <strong>of</strong> Discrete Fracture Network using Voronoi Grid System<br />
Objectives<br />
Dual-porosity (DP) is the most common model to<br />
simulate fluid flow through fractured media. This<br />
model comprises several limitations (i.e., it is not<br />
well suited to accurately model fracture networks<br />
with multiple orientations). On the other hand, a<br />
single-porosity model with conventional gridding<br />
techniques requires an excessive number <strong>of</strong> grids to<br />
model fractures explicitly.<br />
The objectives <strong>of</strong> this work are to develop a<br />
reservoir simulator (DFNSIM) along with a novel<br />
gridding technique based on Voronoi algorithm to<br />
allow fracture networks represented explicitly into<br />
reservoir model.<br />
Approach<br />
It requires two different domains to represent<br />
fractures explicitly in a simulation model: geometrical<br />
and computational (Fig. 1). In the geometrical<br />
domain, the fracture is represented as a line. The<br />
volume and permeability <strong>of</strong> each fracture segment<br />
are calculated based on a given fracture aperture<br />
distribution (i.e. log-normal distribution from X-Ray<br />
CT Scan) in the computational domain.<br />
(a) Geometrical domain<br />
(b) Computational domain<br />
(a) Unfractured<br />
(b) Fractured<br />
Fig. 2. Grid generation for unfractured and fractured systems.<br />
by Chong et al. However, the governing equation <strong>of</strong><br />
the simulator was similar to DFNSIM (CVFD).<br />
Prior to using DFNSIM in modeling reservoirs with<br />
fractures including their apertures distribution,<br />
the simulator was validated against commercial<br />
simulators. The simulator provides results in close<br />
agreement with those <strong>of</strong> reference finite-difference<br />
simulators (SPE-1 comparative solutions; after Aziz<br />
& Odeh, SPEJ, 1981).<br />
CRISMAN INSTITUTE<br />
Project Information<br />
3.1.19 Modeling <strong>of</strong> Discrete Fracture Network using Voronoi<br />
Grid System<br />
Related Publications<br />
Chong, E., Syihab, Z., Putra, E., Hidayati, D.T., Schechter,<br />
D. A New Grid Block System for Reducing Grid Orientation<br />
Effect, Journal <strong>of</strong> Petroleum Science and Technology.<br />
(November 2007) London, UK.<br />
Fig. 1. Fracture representation (geometrical and computational domains).<br />
Accomplishments<br />
Two major accomplishments were achieved from<br />
this work: (1) fracture network gridding and (2)<br />
development <strong>of</strong> a control volume finite-difference<br />
numerical simulatior (CVFD), which can be used for<br />
both fractured and unfractured systems (Fig. 2).<br />
The unstructured grid (without fracture) was initially<br />
tested to reduce the grid orientation effect. The<br />
grid model was constructed by a combination <strong>of</strong><br />
rectangular, hexagonal, and triangle shapes. The<br />
test was run using a separate simulator developed<br />
Tae, H. K. and Schechter, D.S. Estimation <strong>of</strong> Fracture<br />
Porosity <strong>of</strong> Naturally Fractured Reservoirs with No Matrix<br />
Porosity Using Fractal Discrete Fracture Networks. Paper<br />
SPE presented at the 2007 SPE <strong>Annual</strong> Technical Conference<br />
and Exhibition, Anaheim, California, 11–14 November.<br />
Syihab, Zuher.: <strong>2009</strong>. Simulation <strong>of</strong> Discrete Fracture<br />
Network Using Flexible Voronoi Gridding. PhD dissertation.<br />
Texas A&M U., College Station, Texas.<br />
Contacts<br />
David Schechter<br />
979.845.2275<br />
david.schechter@pe.tamu.edu<br />
Zuher Syihab<br />
68<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
After successful validation, a fractal discrete fracture<br />
network (FDFN) model was generated based on a<br />
real outcrop data from Bridger Gap, Wyoming (Fig.<br />
3). The model was compared with a system with no<br />
fractures to observe the impact <strong>of</strong> the fractures on<br />
sweep efficiency (Fig. 4).<br />
The grid model <strong>of</strong> the fracture network is depicted in<br />
Fig. 2b and Fig. 3c.<br />
(a) Rose Diagram <strong>of</strong> FDFN<br />
120<br />
90<br />
6<br />
60<br />
4<br />
150<br />
2<br />
30<br />
180 0<br />
(b) Fracture network map<br />
(c) Grid system<br />
210<br />
330<br />
240<br />
270<br />
300<br />
Oil producer<br />
Fig. 3. (a) Rose diagram, (b) fracture network map, and (c) grid system<br />
<strong>of</strong> an outcrop at Bridger Gap, Wyoming.<br />
(a) Connected fractures<br />
(b) No fracture<br />
Fig. 4. Gas saturation at 730 days (fractured and unfractured systems).<br />
Significance<br />
A numerical simulator was developed in this work<br />
that allows direct input and simulation <strong>of</strong> discrete<br />
fracture networks. This work solved the problem<br />
<strong>of</strong> how to grid fracture intersections. We now have<br />
the capability <strong>of</strong> modeling connected fracture<br />
networks thus bypassing conventional dual porosity<br />
simulation.<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
69
Thermo-Poroelastic Finite Element Analysis <strong>of</strong> Rock Deformation and Damage<br />
Introduction<br />
Stress change and permeability variations caused<br />
by rock failure play an important role in geothermal<br />
reservoir development, particularly in understanding<br />
stimulation outcomes and induced seismicity.<br />
Cold water injection causes significant change in<br />
temperature, pore pressure, and thus the stresses<br />
near the wellbore and in the reservoir which, in turn<br />
influence rock permeability.<br />
Permeability (md)<br />
22<br />
20<br />
18<br />
16<br />
14<br />
12<br />
10<br />
8<br />
6<br />
1 sec<br />
10 sec<br />
30 sec<br />
Objectives<br />
In this work, we present the development <strong>of</strong> a fullycoupled<br />
thermo-poro-mechanical finite element<br />
model with damage mechanics and stress dependent<br />
permeability for simulating rock response to cold<br />
water injection.<br />
4<br />
2<br />
0<br />
1<br />
2<br />
3<br />
r/a<br />
Permeability distributions around the wellbore.<br />
14<br />
4<br />
5<br />
Stress (MPa)<br />
140<br />
120<br />
100<br />
80<br />
60<br />
1.0<br />
0.8<br />
0.6<br />
0.4<br />
Damage<br />
Pore Pressure (MPa)<br />
12<br />
10<br />
8<br />
6<br />
4<br />
1 sec<br />
30 sec<br />
ref-1 sec<br />
ref-30 sec<br />
40<br />
0.2<br />
Stress<br />
20<br />
Damage<br />
0<br />
0.005 0.010 0.015 0.020 0.025 0.030<br />
r/a<br />
Finite element simulations <strong>of</strong> a triaxial test. Green line: brittle behavior<br />
<strong>of</strong> strain-stress relationships; red line: damage evolution when stresses<br />
satisfy the failure criterion.<br />
Approach<br />
Both conductive and convective heat transport are<br />
considered in the thermo-poroelastic formulation.<br />
The model is used to perform a series <strong>of</strong> numerical<br />
experiments to study the influence <strong>of</strong> cold water<br />
injection on rock damage and permeability<br />
enhancement. The rock damage is reflected in the<br />
alteration <strong>of</strong> its elastic modulus and permeability.<br />
Accomplishments<br />
The results show that damage propagation is<br />
accompanied by a relaxation <strong>of</strong> the effective stress<br />
in the damage zone and its concentration in the<br />
intact rock near the interface with the damage zone.<br />
2<br />
0<br />
1<br />
2<br />
Pore pressure distributions around the wellbore. Solid lines represent<br />
pore pressure distributions for damage; Dashed lines give the results for<br />
the reference case with no damage.<br />
Significance<br />
The model provides a tool for the analysis <strong>of</strong> stress<br />
induced micro-seismicity and fracture propagation<br />
in geothermal and petroleum reservoirs.<br />
CRISMAN INSTITUTE<br />
Project Information<br />
3.1.21 Reservoir Geomechanics: Thermo-Poroelastic<br />
Analysis <strong>of</strong> Rock Deformation and Damage<br />
Contacts<br />
Ahmad Ghassemi<br />
979.845.2206<br />
ahmad.ghassemi@pe.tamu.edu<br />
3<br />
r/a<br />
4<br />
5<br />
Sang Hoon Lee<br />
70<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Application <strong>of</strong> Adaptive Gridding and Upscaling for Improved Tight Gas Reservoir<br />
Simulation<br />
Objectives<br />
The objective <strong>of</strong> this research is to improve the<br />
flow simulation <strong>of</strong> tight gas reservoirs through the<br />
application <strong>of</strong> unstructured upscaling <strong>of</strong> detailed 3D<br />
geo-cellular models. The techniques are designed<br />
to preserve the high resolution well productivity<br />
and connectivity <strong>of</strong> the reservoir description while<br />
at the same time reducing the cost <strong>of</strong> the reservoir<br />
simulation computation.<br />
Accomplishments<br />
We have completed the conversion <strong>of</strong> the tight gas<br />
Eclipse field model (made available to us through<br />
an MCERI project) to the VIP and Nexus simulators.<br />
We have provided our own high resolution<br />
transmissibility upscaling algorithms for simple grid<br />
coarsening geometries as a pre-requisite to more<br />
difficult upscaling problems. We have also compared<br />
our transmissibility upscaling algorithms with the<br />
VIP and Nexus simulators’ cell property-based<br />
upscaling, to determine under what circumstances<br />
the high resolution algorithms provide better flow<br />
characterization.<br />
Detailed View <strong>of</strong> the High Resolution 375 Layer 3D Geologic Model, giving<br />
a better perspective <strong>of</strong> the variation <strong>of</strong> sand thickness associated with the<br />
individual simulation layers.<br />
Future Work<br />
We will work on the understanding <strong>of</strong> VIP/Nexus’s<br />
underlying theory for the upscaling, and replace<br />
its upscaled properties (transmissibility and well<br />
index) with our own upscaled properties to get more<br />
accurate results.<br />
Medium Resolution 75 Layer 3D Geologic Model <strong>of</strong> the 10 x 10 x 375 test<br />
volume <strong>of</strong> a Tight Gas Reservoir. This model was developed using the VIP<br />
simulator’s built-in grid and property coarsening algorithms, here for 1 x<br />
1 x 5 coarsening. Our research project will provide improved coarsened<br />
representations <strong>of</strong> the fine scale reservoir model that better preserve the<br />
reservoir connectivity and properties.<br />
CRISMAN INSTITUTE<br />
High Resolution 375 Layer 3D Geologic Model <strong>of</strong> a 10 x 10 test area <strong>of</strong> a<br />
Tight Gas Reservoir. This model shows the intermittent connectivity associated<br />
with the fluvial nature <strong>of</strong> these reservoirs.<br />
Project Information<br />
3.1.22 Application <strong>of</strong> Adaptive Gridding and Upscaling for<br />
Improved Tight Gas Reservoir Simulation<br />
Contacts<br />
Michael King<br />
979.845.1488<br />
mike.king@pe.tamu.edu<br />
Yijie Zhou<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
71
Measurement and Correlation <strong>of</strong> Gas Viscosities at High Pressures and High<br />
Temperatures<br />
Introduction<br />
High-pressure and high-temperature (HPHT) gas<br />
reservoirs are defined as having pressures greater<br />
than 10,000 psia and temperatures over 300°F.<br />
Modeling the performance <strong>of</strong> these reservoirs<br />
requires the understanding <strong>of</strong> gas behavior at<br />
elevated pressure and temperature. An important<br />
fluid property is gas viscosity, as it is used to model<br />
the gas mobility in the reservoir and can have a<br />
significant impact on reserves estimation during field<br />
development planning. Accurate measurements <strong>of</strong><br />
gas viscosity at HPHT conditions are both extremely<br />
difficult and expensive, thus this fluid property is<br />
typically estimated from published correlations<br />
based on laboratory data. Unfortunately, the<br />
correlations available today do not have a sufficiently<br />
broad range <strong>of</strong> applicability in terms <strong>of</strong> pressure and<br />
temperature, so their accuracy may be doubtful for<br />
the prediction <strong>of</strong> gas viscosity at HPHT conditions.<br />
Objectives<br />
This project will review the databases <strong>of</strong> hydrocarbon<br />
gas viscosity that are available in the public domain,<br />
and discuss the validity <strong>of</strong> published gas viscosity<br />
correlations based on their applicability range.<br />
Approach<br />
A falling body viscometer was used to measure the<br />
HPHT gas viscosity in the laboratory. This system is<br />
very common for the measurement <strong>of</strong> liquid viscosity<br />
and, in some specific circumstances (lubrication or<br />
small percentage <strong>of</strong> liquid phase), can also measure<br />
low viscosities. The decision to use such a viscometer<br />
was based on the consideration that it is the only<br />
device built to withstand extreme high pressure at<br />
an acceptable cost. The instrument was calibrated<br />
with nitrogen and then, to represent reservoir gas<br />
behavior more faithfully, pure methane was used.<br />
The subsequently measured data, recorded over a<br />
wide range <strong>of</strong> pressure and temperature, was then<br />
used to evaluate the reliability <strong>of</strong> the most commonly<br />
used correlations in the petroleum industry. The<br />
results <strong>of</strong> the comparison suggest that at pressures<br />
higher than 8000 psia, the laboratory measurements<br />
drift from the National Institute <strong>of</strong> Standards and<br />
Technology (NIST) values by up to 7.48%.<br />
Finally, a sensitivity analysis was performed to<br />
assess the effect <strong>of</strong> gas viscosity estimation errors<br />
on the overall gas recovery from a synthetic HPHT<br />
reservoir, using numerical reservoir simulations. The<br />
result shows that a -10% error in gas viscosity can<br />
produce an 8.22% error in estimated cumulative<br />
gas production, and a +10% error in gas viscosity<br />
can lead to a 5.5% error in cumulative production.<br />
Significance<br />
The preliminary results indicate that the accuracy<br />
<strong>of</strong> gas viscosity estimation can have a significant<br />
impact on reserves evaluation.<br />
Future Work<br />
This project has led to the following conclusions:<br />
» Accurate measurements <strong>of</strong> natural gas viscosity<br />
under HPHT conditions are yet to be obtained,<br />
» Gas viscosity correlations derived from data<br />
obtained at low to moderate pressures and<br />
temperatures cannot be confidently extrapolated<br />
to HPHT conditions,<br />
» Gas viscosity correlations currently available to<br />
the petroleum industry were derived from data<br />
obtained with limited impurities, and so their<br />
accuracy for use with gases containing large<br />
quantities <strong>of</strong> impurities is unknown,<br />
» Laboratory investigations performed using<br />
nitrogen showed a consistently negative error<br />
when compared to the NIST reported values.<br />
Preliminary results stress the importance <strong>of</strong><br />
obtaining an exhaustive range <strong>of</strong> measurements <strong>of</strong><br />
the viscosity <strong>of</strong> natural gases under HPHT conditions<br />
in order to ensure better reserves estimations. To<br />
this aim, further tests are ongoing.<br />
Project Information<br />
3.2.4 Measurement and Correlation <strong>of</strong> Gas Viscosities at<br />
High Pressures and High Temperatures<br />
Contacts<br />
Gioia Falcone<br />
979.847.8912<br />
gioia.falcone@pe.tamu.edu<br />
Catalin Teodoriu<br />
catalin.teodoriu@pe.tamu.edu<br />
Ehsan Davani<br />
CRISMAN INSTITUTE<br />
72<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Measurement <strong>of</strong> Gas Viscosity at High Pressures and High Temperatures<br />
Introduction<br />
Gas viscosity is an important fluid property in<br />
petroleum engineering due to its impact in oil<br />
and gas production and transportation where it<br />
contributes to the resistance to the flow <strong>of</strong> a fluid<br />
both in porous media and pipes. Although this<br />
property has been studied thoroughly at low to<br />
intermediate pressures and temperatures, there is a<br />
lack <strong>of</strong> detailed knowledge <strong>of</strong> gas viscosity behavior<br />
at high pressures and high temperatures (HPHT) in<br />
the oil and gas industry.<br />
The need to understand and be able to predict<br />
gas viscosity at HPHT has become increasingly<br />
important as exploration and production has moved<br />
to ever deeper formations where HPHT conditions<br />
are more likely to be encountered. Knowledge <strong>of</strong><br />
gas viscosity is required for fundamental petroleum<br />
engineering calculations that allow one to optimize<br />
the overall management <strong>of</strong> an HPHT gas field and<br />
to better estimate reserves. Existing gas viscosity<br />
correlations are derived using measured data at low<br />
to moderate pressures and temperatures, i.e. less<br />
than 10,000 psia and 300°F, and then extrapolated<br />
to HPHT conditions. No measured gas viscosities at<br />
HPHT are currently available, and so the validity <strong>of</strong><br />
this extrapolation approach is doubtful due to the<br />
lack <strong>of</strong> experimental calibration.<br />
Objectives<br />
The National Institute <strong>of</strong> Standards and Technology<br />
(NIST) has developed a computer program that<br />
predicts thermodynamic and transport properties<br />
<strong>of</strong> hydrocarbon fluids, which allows comparison<br />
<strong>of</strong> its values with those from correlations and<br />
gives an insight into the current understanding <strong>of</strong><br />
gas viscosity correlations. Note that Viswanathan<br />
modified the Lee, Gonzalez, and Eakin correlation<br />
by using NIST values. The above review <strong>of</strong> existing<br />
gas viscosity correlations reveals that there are<br />
no measurements available at HPHT conditions.<br />
Correlations derived from data at low to moderate<br />
pressures and temperatures should not be simply<br />
extrapolated to HPHT conditions without validation<br />
against experimental measurements.<br />
Our objectives are to measure the viscosity <strong>of</strong> four<br />
naturally occurring hydrocarbon gases at various<br />
pressures and temperatures, with emphasis on high<br />
pressures and temperatures; use the measured<br />
viscosities to check and extend an existing correlation<br />
proposed by Lee et al.; use gas compressibility<br />
factors to check and extend the gas compressibility<br />
correlation equation proposed by Piper et al.; and<br />
develop a new correlation to predict viscosity as a<br />
function <strong>of</strong> composition, pressure, and temperature.<br />
Approach<br />
Our facility consists <strong>of</strong> a gas source, a gas booster<br />
system, a measuring system, and a data acquisition<br />
system. The measuring system is the Cambridge<br />
SPL440 High Pressure Research Viscosity Sensor<br />
that is tailored to measure gas viscosities at<br />
HPHT conditions. This technology is based on an<br />
electromagnetic concept, with two coils moving a<br />
piston back and forth magnetically at a constant<br />
force. The piston’s two-way travel time is then<br />
related to the fluid’s viscosity by a proprietary<br />
equation. The viscosity range for the system is 0.02<br />
to 0.2 cp, with a reported accuracy <strong>of</strong> 1% <strong>of</strong> full<br />
scale. The maximum operating pressure is 25,000<br />
psig. The Cambridge ViscoLab PVT s<strong>of</strong>tware was<br />
used to record the measurements.<br />
(continued on next page)<br />
Project Information<br />
3.2.4 Measurement and Correlation <strong>of</strong> Gas Viscosities at<br />
High Pressures and High Temperatures<br />
Contacts<br />
Gioia Falcone<br />
979.847.8912<br />
gioia.falcone@pe.tamu.edu<br />
Catalin Teodoriu<br />
catalin.teodoriu@pe.tamu.edu<br />
Kegang Ling<br />
CRISMAN INSTITUTE<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
73
The falling body viscometer is selected to measure gas<br />
viscosity for a pressure range <strong>of</strong> 3,000 to 24,500 psia<br />
and temperature range <strong>of</strong> 100 to 415°F. Nitrogen was<br />
used to calibrate the instrument and to account for<br />
the fact that the concentrations <strong>of</strong> non-hydrocarbons<br />
are observed to increase dramatically in HPHT<br />
reservoirs. Then methane viscosity is measured to<br />
reflect the fact that, at HPHT conditions, the reservoir<br />
fluids will be very lean gases, typically methane with<br />
some degree <strong>of</strong> impurity. The experiments showed<br />
that while the correlation <strong>of</strong> Lee et al. accurately<br />
estimates gas viscosity at low to moderate pressure<br />
and temperature, it does not provide a good match<br />
to gas viscosity at HPHT conditions.<br />
higher than the values provided by the NIST and<br />
by previous investigators. The difference increases<br />
as temperature decreases, and it increases as<br />
pressure increases. These preliminary results stress<br />
the importance <strong>of</strong> obtaining an exhaustive range<br />
<strong>of</strong> measurements <strong>of</strong> the viscosity <strong>of</strong> natural gases<br />
under HPHT conditions in order to ensure better<br />
reserves estimation. To this aim, further tests are<br />
ongoing at Texas A&M University.<br />
Accomplishments<br />
Comparing our result with NIST values and data at<br />
low to moderate pressure and temperature from<br />
previous investigators showed that:<br />
» Nitrogen viscosity—The lab data matched the<br />
NIST values as well as those reported by other<br />
investigators at low to moderate pressures, while<br />
they are lower at high pressure. The difference<br />
between measured data and NIST values increases<br />
as temperature decreases; this difference also<br />
increases as pressure increases.<br />
» Methane viscosity—New lab data matched the<br />
NIST values at low to moderate pressure, but the<br />
new experimental viscosities are higher at high<br />
pressure. The mismatch decreases as temperature<br />
increases, and increases as pressure increases.<br />
Significance<br />
Gas viscosity correlations derived from data obtained<br />
at low to moderate pressures and temperatures cannot<br />
be confidently extrapolated to HPHT conditions. The<br />
gas viscosity correlations that are currently available<br />
to the petroleum industry were derived from data<br />
obtained with gases with limited impurities, and so<br />
their accuracy for use with gases containing large<br />
quantities <strong>of</strong> impurities is unknown.<br />
The laboratory investigations performed at TAMU<br />
show that, at high pressure, the experimental<br />
nitrogen viscosities are lower than the values<br />
provided by the NIST and by previous investigators.<br />
The observed mismatch increases as temperature<br />
decreases, and it increases as pressure increases.<br />
For methane, the TAMU investigations show that,<br />
at high pressure, the experimental viscosities are<br />
74<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Numerical Modeling <strong>of</strong> Fracture Permeability Change in Naturally Fractured<br />
Reservoirs using a Fully Coupled Displacement Discontinuity Method<br />
Introduction<br />
Pressure depletion in a naturally fractured reservoir<br />
can result in effective stress change that, in turn,<br />
can affect fracture aperture and the reservoir<br />
permeability. The dependence <strong>of</strong> fracture aperture and<br />
reservoir permeability on stress must be considered<br />
in modeling a naturally fractured reservoir. The<br />
dependence involves coupled interactions among<br />
fluid, porous matrix, and fracture. The previous<br />
methods on the dependence <strong>of</strong> fracture permeability<br />
on the pressure depletion did not consider the fully<br />
coupled interactions <strong>of</strong> fluid, porous matrix, and<br />
fracture or the real deformation mechanism <strong>of</strong><br />
fracture.<br />
Approach<br />
We developed a new approach to solve the fluid<br />
pressure, stress change, and fracture aperture<br />
change in fractures simultaneously. We did this<br />
by combining a finite difference method (FDM) to<br />
solve the fluid diffusion in fractures a fully coupled<br />
displacement discontinuity method (DDM) to<br />
build the global relation <strong>of</strong> fracture deformation,<br />
and a nonlinear Barton-Bandis model <strong>of</strong> fracture<br />
deformation to build the local relation <strong>of</strong> fracture<br />
deformation. The fully coupled DDM is based on<br />
Biot’s theory <strong>of</strong> poroelasticity which is a linear<br />
elastic theory to account for the coupled interactions<br />
between porous matrix and fluid in a porous medium<br />
saturated with a compressible fluid. The analytical<br />
solution <strong>of</strong> induced stress and pore pressure by the<br />
deformation <strong>of</strong> a finite thin fracture in an infinite<br />
elastic porous medium is provided. The influences<br />
<strong>of</strong> deformation <strong>of</strong> complicated fracture network are<br />
obtained by the superposition <strong>of</strong> the fundamental<br />
analytical solution. The stress acting on the fracture<br />
surface and the deformation <strong>of</strong> the fracture also must<br />
comply with the fracture deformation model (e.g.<br />
Barton-Bandis model). The fluid flow in the fracture<br />
network is solved by an FDM. The interface flow<br />
rate between the fracture and matrix is implicitly<br />
included in the fully coupled DDM. As a result, the<br />
approach is able to model the fracture deformation<br />
due to reservior pressure change in naturally<br />
fractured reservoirs by considering the fully coupled<br />
interactions <strong>of</strong> fluid, porous matrix, and fractures.<br />
Application<br />
This method has been applied to model the fracture<br />
permeability change for a two-dimensional regular<br />
Fig. 1. Pore pressure (psi) distribution after 360 days production.<br />
fractured network (Fig. 1) in a compressible<br />
single-phase fluid-saturated porous medium. Under<br />
isotropic in-situ stress conditions, the fracture<br />
permeability decreases with the pressure reduction<br />
during production (Fig. 2). But at high anisotropic<br />
stress conditions, the fracture permeability could<br />
be enhanced by production due to shear dilation<br />
(Fig. 3).<br />
(continued on next page)<br />
Project Information<br />
3.2.10 Well Test Models for Caves in a Karstic Carbonate<br />
Reservoir<br />
Contacts<br />
Christine Ehlig-Economides<br />
979.458.0797<br />
c.economides@pe.tamu.edu<br />
Qingfeng Tao<br />
CRISMAN INSTITUTE<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
75
Fracture permeability (md)<br />
12<br />
10<br />
8<br />
6<br />
4<br />
2<br />
0<br />
Fracture intersected<br />
by the Well<br />
Fracture at the Boundary<br />
0 1000 2000 3000 4000 5000 6000 7000 8000 9000<br />
Time (hr)<br />
Fig. 2. Fracture permeability declines with time.<br />
Fig. 3. Distribution <strong>of</strong> fracture permeability and shear displacement<br />
(shown with arrows) after 360 days production for the case fractures are<br />
already yielded before production.<br />
76<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Improved Permeability Predictions using Multivariate Analysis Methods<br />
Introduction<br />
Predicting rock permeability from well logs<br />
in uncored wells is an important task in<br />
reservoir characterization. Due to the high<br />
costs <strong>of</strong> coring and laboratory analysis,<br />
typically cores are acquired in only a few<br />
wells. Since most wells are logged, the<br />
common practice is to estimate permeability<br />
from logs using correlation equations<br />
developed from limited core data. Most<br />
commonly, permeability is estimated from<br />
various well logs using statistical regression.<br />
For sandstone reservoirs, the logarithm <strong>of</strong><br />
permeability can be correlated with porosity,<br />
but in carbonate reservoirs the porositypermeability<br />
relationship tends to be much<br />
more complex and erratic.<br />
Objectives<br />
In order to improve the permeability estimation in<br />
complex carbonate reservoirs, several statistical<br />
regression techniques have been tested in previous<br />
work to correlate permeability with different well<br />
logs (Lee, Arun and Datta-Gupta, 2002; Mathisen,<br />
Lee, and Datta-Gupta, 2003). It has been shown<br />
that statistical regression for data correlation is quite<br />
promising, but using all the possible well logs to<br />
predict permeability may not be appropriate because<br />
the possibility <strong>of</strong> spurious correlation increases as<br />
more well logs are used. Therefore, the objective<br />
<strong>of</strong> this study is to further improve permeability<br />
prediction by selecting appropriate well logs for data<br />
correlation via variable selection procedures.<br />
Approach<br />
In statistics, variable selection is used to remove<br />
unnecessary independent variables and give a more<br />
robust prediction. We will apply variable selection<br />
methods to the permeability prediction procedure<br />
to improve permeability estimation. Specifically,<br />
we have proposed a new method combining the<br />
stepwise regression with Alternating Conditional<br />
Expectation (ACE) techniques and will compare the<br />
proposed method with two other methods: the tree<br />
regression and the Multivariate Adaptive Regression<br />
Splines (MARS) method.<br />
Accomplishments<br />
Three methods are tested and compared using data<br />
from a complex carbonate reservoir in west Texas:<br />
Predicted vs. Measured<br />
MSE=1.9728 MAE=1.0682 =0.68227<br />
10 -2 10 -1 10 0 10 1 10 2 10 3<br />
Measured permeability<br />
the Salt Creek Field Unit (SCFU). The results <strong>of</strong><br />
SCFU show that the stepwise regression with the<br />
ACE method outperforms the other two methods in<br />
permeability prediction. The figure shows the result<br />
<strong>of</strong> the stepwise regression with the ACE method vs.<br />
true permeability for a blind test data set.<br />
Project Information<br />
3.2.13 Improved Permeability Predictions using Multivariate<br />
Analysis Methods<br />
Related Publications<br />
Lee, S. H. and Datta-Gupta, A. 2002. Electr<strong>of</strong>acies<br />
Characterization and Permeability Predictions in Carbonate<br />
Reservoirs: Role <strong>of</strong> Multivariate Analysis and Non-parametric<br />
Regression. SPE Reservoir Evaluation and Engineering 5<br />
(3): 237-248. DOI 10.2118/78662-PA.<br />
Mathisen, T., Lee S. H., and Datta-Gupta, A. 2003.<br />
Improved Permeability Estimates in Carbonate Reservoirs<br />
Using Electr<strong>of</strong>acies Characterization: A Case Study <strong>of</strong> the<br />
North Robertson Unit, West Texas SPE Reservoir Evaluation<br />
and Engineering 6 (3): 176-184.<br />
Contacts<br />
Akhil Datta-Gupta<br />
979.847.9030<br />
a.datta-gupta@pe.tamu.edu<br />
Jiang Xie<br />
Depth<br />
6220<br />
6240<br />
6260<br />
6280<br />
6300<br />
6320<br />
6340<br />
6360<br />
6380<br />
6400<br />
6420<br />
Measured<br />
permeability<br />
Permeability vs. Depth<br />
CRISMAN INSTITUTE<br />
Predicted<br />
permeability<br />
Permeability Predictions from Well logs Using Stepwise Regression with ACE (Alternating<br />
Conditional Expectations) for the Salt Creek Field Unit, West Texas.<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
77
CO 2<br />
Mobility Control using Cross-Linked Gel and CO 2<br />
Viscosifiers<br />
Objectives<br />
1. Investigate and test different approaches in the<br />
laboratory to control CO 2<br />
mobility during CO 2<br />
flooding to increase the overall efficiency.<br />
2. Develop a simulation model which would<br />
incorporate the CO 2<br />
viscosity relationship<br />
with pressure, then use this model to predict<br />
viscosified CO 2<br />
flooding efficiency in comparison<br />
with pure CO 2<br />
flooding.<br />
Accomplishments<br />
The visualization <strong>of</strong> CO 2<br />
flow within core using CT-<br />
Scanning provides us with a more direct observation<br />
for the CO 2<br />
flood fronts in the core. We have studied<br />
two approaches to control CO 2<br />
mobility: HPAM/<br />
Cr(III) gel conformance control treatment, and the<br />
direct increase <strong>of</strong> CO 2<br />
viscosity using viscosifier<br />
chemicals (PVAc or Polysiloxanes).<br />
For the study <strong>of</strong> gel conformance control, crosslinked<br />
HPAM/Cr(III) gel was applied to fractured cores<br />
in order to get incremental oil recovery. We have<br />
tested 10,000 ppm <strong>of</strong> high concentration gel and<br />
found out it had a better stability when compared<br />
with the 3,000 ppm gel we used previously. The<br />
10,000 ppm gel appeared to be more stable and<br />
also gave a higher pressure drop in CO 2<br />
flooding,<br />
which means better mobility control.<br />
For the study <strong>of</strong> CO 2<br />
viscosifiers, a controlled CO 2<br />
flooding experiment using pure CO 2<br />
was conducted<br />
and the expected low recovery was obtained due to<br />
rapid breakthrough <strong>of</strong> CO 2<br />
through the fracture. The<br />
first low molecular weight viscosifier was studied<br />
and we observed significant differences in CO 2<br />
flood<br />
front images. A more uniform, piston-like CO 2<br />
flood<br />
front was formed in the viscosifier case, suggesting<br />
a reduction in CO 2<br />
viscosity. Higher oil recovery was<br />
also observed using viscosified CO 2<br />
.<br />
A black-oil pseudo-miscible model for an oil field in<br />
Peru was developed using data from one <strong>of</strong> the wells.<br />
To account for the increase in CO 2<br />
viscosity, new<br />
viscosity/pressure relationships were integrated into<br />
the simulation model. We are currently simulating<br />
viscosified cases to develop cost benefit relations.<br />
Future Work<br />
More viscosifier chemical structures will be studied<br />
to compare the efficiency differences between low<br />
78<br />
and high molecular weight viscosifiers. The injection<br />
scheme will be altered to reflect field sequence <strong>of</strong><br />
events: we will begin with pure CO 2<br />
until no more<br />
oil is recovered, and then we will begin injecting<br />
viscosified CO 2<br />
to determine the incremental<br />
recovery caused by viscosified CO 2<br />
after pure CO 2<br />
injection. We will also develop simulation tools<br />
capable <strong>of</strong> accounting for viscosified CO 2<br />
cases.<br />
End <strong>of</strong> Coreflood for 3000 ppm gel:<br />
End <strong>of</strong> Coreflood for 10,000 ppm gel:<br />
Gel Strength Study - (red/yellow color shows gel distribution after CO 2<br />
flooding, blue color is the sandstone matrix. The sandstone core is fractured<br />
both horizontally and vertically. CO 2<br />
injection from right to left.)<br />
Pure CO 2<br />
flood image (after 1.6 PV CO 2<br />
injected)<br />
Viscosified CO 2<br />
flood image (after 1.3 PV CO 2<br />
injected)<br />
Comparison <strong>of</strong> pure CO 2<br />
flood front and viscosified CO 2<br />
flood front. The<br />
pure CO 2<br />
flood case has most <strong>of</strong> the CO2 concentrated in the fracture<br />
region. A more stable piston-like displacement is observed in the viscosified<br />
CO 2<br />
case.<br />
Project Information<br />
3.4.4 Application <strong>of</strong> X-Ray CT for Investigating Fluid Flow<br />
and Conformance Control during CO 2<br />
Injection in Highly<br />
Heterogenous Systems<br />
Contacts<br />
David Schechter<br />
979.845.2275<br />
david.schechter@pe.tamu.edu<br />
Shuzong Cai<br />
CRISMAN INSTITUTE<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Stochastic History Matching, Forecasting, and Production with the Ensemble<br />
Kalman Filter<br />
Introduction<br />
The data assimilation process <strong>of</strong> adjusting variables<br />
in a reservoir simulation model to honor observations<br />
<strong>of</strong> field data is known as ‘history matching’ and<br />
has been extensively studied for few decades.<br />
However, despite the progress that has been made,<br />
development <strong>of</strong> more accurate and efficient history<br />
matching techniques that produce geologically<br />
realistic outcomes (reservoir models) is still one<br />
<strong>of</strong> the main challenges for reservoir engineers,<br />
mainly due to the high complexity <strong>of</strong> the problem,<br />
data scarcity, and computational demand for field<br />
applications. Because <strong>of</strong> the insufficient information<br />
about reservoir spatial property distribution,<br />
history matching <strong>of</strong> heterogeneous reservoirs is<br />
an inherently ill-posed inverse problem; that is,<br />
it is possible to obtain several reservoir models<br />
that honor observed measurements but have<br />
geologically distinct features and provide incorrect<br />
predictions. Two common approaches to deal with<br />
ill-posed history matching problems are either to<br />
constrain the structural form <strong>of</strong> acceptable solutions<br />
(regularization) or to reduce the number <strong>of</strong> unknown<br />
parameters (reparameterization). While these<br />
methods have been successfully used as effective<br />
strategies to improve the solution <strong>of</strong> ill-posed inverse<br />
problems, they may not provide accurate solutions<br />
where a simple structural assumption can be defined<br />
for features with more complex geometry.<br />
for incorporating dynamic flow measurements into<br />
multipoint pattern simulation with the Single Normal<br />
Equation SIMulation (SNESIM) algorithm.<br />
Accomplishments<br />
The generated probability map represents the main<br />
information in the nonlinear dynamic measurements<br />
and can be easily integrated into the SNESIM<br />
algorithm to simulate an updated ensemble <strong>of</strong><br />
conditional facies (Fig. 1b). We have illustrated<br />
the effectiveness <strong>of</strong> this approach through several<br />
experiments. The results <strong>of</strong> development have been<br />
summarized into a manuscript that is currently<br />
being reviewed in the Computational Geosciences<br />
Journal. Figure 1 shows a simple example from the<br />
manuscript that is undergoing review.<br />
Future Work<br />
We are currently working to advance the<br />
implementation <strong>of</strong> our approach to deal with<br />
uncertainty in the training image that is used for<br />
pattern simulation and to address some <strong>of</strong> the<br />
limitations <strong>of</strong> the EnKF-based implementation <strong>of</strong> our<br />
algorithm.<br />
(continued on next page)<br />
Objectives<br />
The ensemble Kalman filter (EnKF) has recently<br />
been introduced to reservoir engineering literature<br />
as a promising history matching technique. It is easy<br />
to implement, provides considerable flexibility for<br />
describing reservoir model uncertainty, and supplies<br />
valuable information about reservoir performance<br />
prediction uncertainty. Among the limitations <strong>of</strong> the<br />
EnKF is its covariance-based (second order) model<br />
updating scheme that restricts its application to<br />
estimate discrete geological objects that are not<br />
amenable to covariance-based descriptions. When<br />
the standard EnKF implementation is used to update<br />
facies permeability values in each grid block (Fig.<br />
1a), the connectivity between the existing features<br />
is not preserved even when facies description is<br />
parameterized to encourage continuity.<br />
In this project, by using the EnKF to generate a<br />
probability map to describe the spatial distribution <strong>of</strong><br />
facies, we are developing a more consistent approach<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
CRISMAN INSTITUTE<br />
Project Information<br />
3.6.6 Stochastic History Matching, Forecasting, and<br />
Production with the Ensemble Kalman Filter<br />
Contacts<br />
Behnam Jafarpour<br />
979.845.0666<br />
behnam.jafarpour@pe.tamu.edu<br />
Morteza Khodabakhshi<br />
79
(a) Standard EnKF for permeability estimation<br />
True Perm.<br />
(b) Prob. Map estimation with EnKF<br />
initial<br />
3 months<br />
6 months<br />
18 months<br />
36 months<br />
initial<br />
3 months<br />
6 months<br />
18 months<br />
36 months<br />
ens. mean<br />
ens. mean<br />
sample 5<br />
prob. map<br />
sample 5<br />
sample 4<br />
sample 4<br />
sample 3<br />
sample 3<br />
sample 2<br />
sample 2<br />
sample 1<br />
sample 1<br />
Fig. 1. Facies estimation from production data using the standard EnKF implementation (a), and application <strong>of</strong> EnKF<br />
to update the probability map <strong>of</strong> facies distribution (b). In (a), the First to Fifth rows show the evolution <strong>of</strong> sample<br />
permeability fields in time (after update steps) with the mean <strong>of</strong> 300 samples shown in the Sixth row. In (b), the<br />
update to the probability map is shown in the First row while the resulting permeability facies from the SNESIM algorithm<br />
are shown in the Second to Sixth rows. The last row contains the mean <strong>of</strong> the 300 sample permeabilities.<br />
80<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Sustainable Carbon Sequestration<br />
Introduction<br />
Concerns that CO 2<br />
emissions from the combustion<br />
<strong>of</strong> fossil fuel are causing global climate change have<br />
led to research that focuses on various ways in<br />
which CO 2<br />
can be captured, sequestered and stored<br />
permanently in deep saline aquifers. The majority<br />
<strong>of</strong> CO 2<br />
produced in the US comes from coal-fired<br />
power plants which account for about 50% <strong>of</strong> the<br />
electricity generation. At the rate in which CO 2<br />
is<br />
produced from a typical power plant, it will require<br />
multiple injection wells, and each well will have a<br />
finite injection well area.<br />
Objectives<br />
Bulk CO 2<br />
injection in a finite volume increases the<br />
pressure <strong>of</strong> the aquifer. To avoid breeching the<br />
aquifer seal, the injection well pressure must not<br />
exceed the formation fracture pressure. The result<br />
is a need for many wells and a prohibitively large<br />
aquifer area. Alternatively, it may be possible to<br />
avoid pressurizing the aquifer area and increase CO 2<br />
storage efficiency by producing the same volume<br />
<strong>of</strong> brine as is injected as CO 2<br />
. This transforms the<br />
problem from CO 2<br />
storage to water handling.<br />
brine displacement with and without saturated brine<br />
injection. Finally, insights gained from the conceptual<br />
modeling phase will be used to develop optimization<br />
methods for improving CO 2<br />
sweep efficiency.<br />
Significance<br />
The significance <strong>of</strong> this approach lies in its potential<br />
advantages over processes currently envisioned.<br />
Aquifer pressurization that may lead to breaching<br />
the integrity <strong>of</strong> the reservoir seal is avoided, and the<br />
CO 2<br />
storage efficiency is increased compared to bulk<br />
CO 2<br />
injection.<br />
V z<br />
This study will investigate options for CO 2<br />
storage<br />
management, including evaluating the feasibility <strong>of</strong><br />
desalinating produced brine.<br />
Approach<br />
Previous studies have addressed issues related<br />
to sequestration <strong>of</strong> CO 2<br />
in closed aquifers and the<br />
risk associated with aquifer pressurization. In this<br />
study, we will produce brine to relieve the pressure<br />
in the aquifer. First, we begin by extending known<br />
(waterflooding) conceptual models to apply to the<br />
CO 2<br />
/brine displacement process. This will help in<br />
the determination <strong>of</strong> well completion geometries,<br />
spacing, and flow rates that optimize CO 2<br />
storage<br />
efficiency. Next, we will extend the work <strong>of</strong> Anchliya,<br />
<strong>2009</strong>, such that the brine injector will inject saturated<br />
brine from the desalination process. Anchliya<br />
intended that injected brine would help curtail CO 2<br />
breakthrough while increasing CO 2<br />
trapping, as seen<br />
in Fig. 1. The conceptual models will be calibrated<br />
using rigorous numerical models. For this work,<br />
it will also be the mechanism to handle saturated<br />
brine from the desalination process.<br />
We will evaluate the economic feasibility <strong>of</strong> CO 2<br />
/<br />
Fig. 1. Conceptual case <strong>of</strong> a horizontal CO2 and a brine injector and two<br />
horizontal brine producers (Anchliya, <strong>2009</strong>).<br />
CRISMAN INSTITUTE<br />
Project Information<br />
4.1.7 Sustainable Carbon Sequestration<br />
Related Publications<br />
Anchliya, A., and Ehlig-Economides, C.A. Aquifer<br />
Management to Accelerate CO 2<br />
Dissolution and Trapping.<br />
Paper SPE 126688, presented at the <strong>2009</strong> International<br />
Conference on CO 2<br />
Capture, Storage, and Utilization, San<br />
Diego, California, 2-4 November.<br />
Contacts<br />
Christine Ehlig-Economides<br />
979.458.0797<br />
c.economides@pe.tamu.edu<br />
Oyewande Akinnikawe<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
81
Aquifer Management for CO 2<br />
Sequestration<br />
Objectives<br />
Among various possible solutions to mitigate the<br />
increasing concentration <strong>of</strong> “greenhouse gases” in<br />
the atmosphere, geological sequestration seems the<br />
most attractive and promising one. This research<br />
explores carbon dioxide sequestration in deep saline<br />
aquifers, and will study issues related to aquifer<br />
pressurization, monitoring, and risk mitigation using<br />
a numerical reservoir simulator that models the<br />
multiphase flow physics <strong>of</strong> CO 2<br />
process using the<br />
Peng-Robinson equation <strong>of</strong> state (EOS).<br />
Approach<br />
Simulations clearly indicated that bulk CO 2<br />
injection<br />
into a single well could rarely inject the volume <strong>of</strong><br />
CO 2<br />
produced by the power plant in a typical aquifer,<br />
and that multiple wells would be required. In an<br />
array <strong>of</strong> injection wells, the aquifer volume allotted<br />
to each injection well is limited by interference with<br />
other injection wells. Therefore, modeling <strong>of</strong> CO 2<br />
injection must consider a closed outer boundary,<br />
and bulk injection in a closed system will pressurize<br />
the aquifer. Simulations confirm this conclusion.<br />
An analytical model developed for this study extends<br />
a previously published one for an open aquifer to<br />
a closed aquifer. A spreadsheet model provides<br />
similar results to detailed simulation in a fraction <strong>of</strong><br />
the time, enabling systematic determination <strong>of</strong> the<br />
aquifer volume and the number <strong>of</strong> wells required to<br />
sequester the target amount <strong>of</strong> CO 2<br />
. Results indicate<br />
that, depending on the aquifer properties, the<br />
sequestration operation would require thousands <strong>of</strong><br />
square miles <strong>of</strong> aquifer area or hundreds <strong>of</strong> wells or<br />
both. In either case, the aquifer must be pressurized,<br />
and CO 2<br />
would accumulate at the top <strong>of</strong> the aquifer,<br />
leading to an unacceptable risk <strong>of</strong> leakage.<br />
Over 30 years <strong>of</strong> simulations on injection have<br />
demonstrated the value <strong>of</strong> regular pressure fall<strong>of</strong>f<br />
monitoring <strong>of</strong> CO 2<br />
injection wells. Fall<strong>of</strong>f responses<br />
provide ongoing indications <strong>of</strong> the dry zone and<br />
two-phase zone radii over time and quantification<br />
<strong>of</strong> the zone mobility values. For the case studied,<br />
these responses also provided reasonable estimates<br />
for the ongoing average aquifer pressure used<br />
for material balance analysis. In turn, analysis<br />
<strong>of</strong> average pressure over time can indicate if the<br />
behavior is that <strong>of</strong> an open or closed aquifer and an<br />
estimation <strong>of</strong> the aquifer size. Alternatively, average<br />
pressure over time can signal the presence <strong>of</strong> an leak<br />
and provide an estimation <strong>of</strong> how much fluid may<br />
be leaking from the aquifer and whether the leak is<br />
predominantly CO 2<br />
or brine. These results suggest<br />
that bulk CO 2<br />
injection is neither economically nor<br />
environmentally acceptable.<br />
To avoid pressurization and to reduce the number<br />
<strong>of</strong> wells required to sequester the CO 2<br />
, brine should<br />
be produced from the aquifer as a volume equal to<br />
that <strong>of</strong> the injected CO 2<br />
. This approach addresses<br />
the pressurization risk, but not the problem <strong>of</strong> CO 2<br />
accumulating at the top <strong>of</strong> the aquifer.<br />
Significance<br />
An engineered system is proposed to both<br />
avoid aquifer pressurization and accelerate CO 2<br />
dissolution and trapping. This system would position<br />
a horizontal brine injection well above and parallel<br />
to a horizontal CO 2<br />
injection well with the brine<br />
production wells drilled parallel to the CO 2<br />
injection<br />
well at a specified lateral spacing. Simulations show<br />
that this configuration prevents CO 2<br />
accumulation at<br />
the top <strong>of</strong> the aquifer during injection, where 90% <strong>of</strong><br />
the CO 2<br />
is permanently dissolved or trapped during<br />
injection after 50 years, including the 30 years <strong>of</strong><br />
injection. This approach would greatly reduce the<br />
risk <strong>of</strong> CO 2<br />
leakage both during and forever after<br />
injection.<br />
CRISMAN INSTITUTE<br />
Project Information<br />
4.1.8 Aquifer Management for CO 2<br />
Sequestration<br />
Related Publications<br />
Anchliya, A.: <strong>2009</strong>. Aquifer Management for CO 2<br />
Sequestration. MS thesis. Texas A&M U., College Station,<br />
Texas.<br />
Anchliya, A., Ehlig-Economides, C.A. Aquifer Management<br />
to Accelerate CO 2<br />
Dissolution and Trapping. Paper<br />
SPE 126688, presented at the <strong>2009</strong> SPE International<br />
Conference on CO 2<br />
Capture, Storage, and Utilization, San<br />
Diego, California, 2-4 November.<br />
Contacts<br />
Christine Ehlig-Economides<br />
979.458.0797<br />
c.economides@pe.tamu.edu<br />
Abhishek Anchliya<br />
82<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
Pretreatment Options to Allow Re-Use <strong>of</strong> Frac Flowback and Produced Brine<br />
(Desalination Process)<br />
Objectives<br />
Our objective is to identify a reliable and cost-effective<br />
pre-treatment method which allows the treatment<br />
and re-use <strong>of</strong> field-produced brine and fracture flowback<br />
waters. The project aims to develop a mobile<br />
and multifunctional water treatment specifically for<br />
“pre-treatment” <strong>of</strong> field waste brine. The project is<br />
part <strong>of</strong> the multi-sponsor Environmentally Friendly<br />
Drilling (EFD) program.<br />
Approach<br />
This project seeks to identify, develop, and<br />
demonstrate cost-effective technologies that will<br />
achieve volume reduction <strong>of</strong> liquid wastes while<br />
simultaneously producing effluents that could be<br />
re-used in oil-field applications, thereby reducing<br />
environmental impacts <strong>of</strong> waste water disposal and<br />
cost. Some <strong>of</strong> the key contaminants in produced<br />
water are suspended and entrained solids (TSS)<br />
and membrane rejection <strong>of</strong> such solids is one <strong>of</strong> our<br />
goals.<br />
Accomplishments<br />
We tested different samples <strong>of</strong> produced water and<br />
frac flowback water from various sources using a<br />
GE Sepa osmotic cell with nano-membranes and<br />
ultra-filtration membranes. Data obtained allowed<br />
for comparison between the membrane and further<br />
testing to be carried out on the field using a<br />
combination <strong>of</strong> membranes to determine the best<br />
result/analysis <strong>of</strong> permeate obtained while at the<br />
same time matching this with cost. Table 1 shows<br />
the TSS removal effectiveness <strong>of</strong> this membrane filter<br />
at a low pressure. This solids removal is a significant<br />
step in the overall process train <strong>of</strong> removing oil,<br />
solids, hardness, and salinity.<br />
Significance<br />
A quantitative comparison <strong>of</strong> the analysis <strong>of</strong> the<br />
permeate is obtained at the end <strong>of</strong> filtration, from<br />
which an evaluation <strong>of</strong> membrane filtration as a way<br />
to remove suspended and entrained particles in frac<br />
flowback or produced water to create re-useable<br />
effluents can be determined.<br />
Sample<br />
Filter Used<br />
Designation<br />
Turbidity<br />
(NTU)<br />
TDS<br />
Calcium<br />
concentration<br />
(ppm)<br />
Chloride<br />
concentration<br />
(ppm)<br />
Advanced<br />
Hydrocarbons<br />
Produced<br />
Water<br />
Untreated 454 49.35 1501.54 42.3<br />
Advanced<br />
Hydrocarbon:<br />
Pretreated<br />
Advanced<br />
Hydrocarbon:<br />
Average<br />
Permeate<br />
Result<br />
Percent<br />
Reduction<br />
5micron<br />
cartridge<br />
JW<br />
ultrafilter<br />
201 43.4 1461.1 42.115<br />
CRISMAN INSTITUTE<br />
Pressure<br />
In (Psig)<br />
Pressure<br />
Out<br />
(Psig)<br />
26.85 44.55 1471.9 42.05 97.5 88.75<br />
86% 8% 2% 0%<br />
Table 1. Analysis <strong>of</strong> suspended solids removal from produced water<br />
sample. The pressure in and out shown above are average pressures for<br />
all rounds <strong>of</strong> permeate collection.<br />
Project Information<br />
4.2.9 Low Impact Oil & Gas Activity; Environmentally<br />
Friendly Drilling Systems<br />
Related Publications<br />
Oluwaseun, O., Burnett, D., Hann, R., and Haut, R.<br />
Application <strong>of</strong> Membrane Filtration Technologies to Drilling<br />
Wastes. Paper SPE 115587, presented at the 2008 SPE<br />
<strong>Annual</strong> Technical Conference and Exhibition, Denver,<br />
Colorado, 21-24 September.<br />
Contacts<br />
David Burnett<br />
979.845.2274<br />
david.burnett@pe.tamu.edu<br />
Gene Beck<br />
979.862.1138<br />
gene.beck@pe.tamu.edu<br />
Uche Eboagwu<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
83
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<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
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2007<br />
» Abdullayev, Azer; Effects <strong>of</strong> Petroleum Distillate on Viscosity, Density, and Surface Tension <strong>of</strong> Intermediate<br />
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<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
85
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2006<br />
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86<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
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» Mago, Alonso Luis; Adequate Description <strong>of</strong> Heavy Oil Viscosities and a Method to Assess Optimal Steam<br />
Cyclic Periods for Thermal Reservoir Simulation, MS 2006, Barrufet.<br />
» Malpani, Rajgopal Vijaykumar; Selection <strong>of</strong> Fracturing Fluid for Stimulating Tight Gas Reservoirs, MS 2006,<br />
Holditch.<br />
» Martin, Matthew Daniel; Managed Pressure Drilling Techniques and Tools, MS 2006, Juvkam-Wold.<br />
» Matus, Eric; A Top-Injection Bottom-Production Cyclic Steam Stimulation Method for Enhanced Heavy Oil<br />
Recovery, MS 2006, Mamora.<br />
» Ozobeme, Charles Chinedu; Evaluation <strong>of</strong> Water Production in Tight Gas Sands in the Cotton Valley<br />
Formation in the Caspiana, Elm Grove and Frierson Fields, MS 2006, Holditch.<br />
» Ramazanova, Rahila; Sequence Stratigraphic Interpretation methods for Low-Accommodation, Alluvial<br />
Depositional Sequences: Applications to Reservoir Characterization <strong>of</strong> Cut Bank Field, Montana, PhD 2006,<br />
Ayers/Rabinowitz.<br />
» Singh, Kalwant; Basin Analog Approach Answers Characterization Challenges <strong>of</strong> Unconventional Gas<br />
Potential in Frontier Basins, MS 2006, Holditch.<br />
» Tanyel, Emre; Formation Evaluation using Wavelet Analysis on Logs <strong>of</strong> the Chinji and Nagri Formations,<br />
Northern Pakistan, MS 2006, Jensen.<br />
» Viloria Ochoa, Marilyn; Analysis <strong>of</strong> Drilling Fluid Rheology and Tool Joint Effect to Reduce Errors in Hydraulics<br />
Calculations, PhD 2006, Juvkam-Wold.<br />
» Zou, Chunlei; Development and Testing <strong>of</strong> an Advanced Acid Fracture Conductivity Apparatus, MS 2006,<br />
Zhu.<br />
2005<br />
» Al Harbi, Mishal Habis; Streamline-based Production Data Integration in Naturally Fractured Reservoirs,<br />
PhD 2005, Datta-Gupta.<br />
» Ameripour, Sharareh; Prediction <strong>of</strong> Gas-Hydrate Formation Conditions in Production and Surface Facilities,<br />
MS 2005, Barrufet.<br />
» Bolen, Matthew; A New Methodology for Analyzing and Predicting U.S. Liquefied Natural Gas Imports Using<br />
Neural Networks, MS 2005, Startzman.<br />
» Chakravarthy, Deepak; Application <strong>of</strong> X-Ray CT for Investigating Fluid Flow and Conformance Control<br />
During CO2 Injection in Highly Heterogeneous Media, MS 2005, Schechter.<br />
» Chandra, Suandy; Improved Steamflood Analytical Model, MS 2005, Mamora/Wattenbarger.<br />
» Cheng, Hao; Fast History Matching Using Streamline Derived Sensitivities for Field Scale Applications, PhD<br />
2005, Datta-Gupta.<br />
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» Diyashev, Ildar; Problems <strong>of</strong> Fluid Flow in a Deformable Reservoir, PhD 2005, Holditch.<br />
» Furrow, Brendan; Analysis <strong>of</strong> Hydrocarbon Removal Methods for the Management <strong>of</strong> Oilfield Brines and<br />
Produced Waters, MS 2005, Barrufet.<br />
» Gao, Hui; Rapid Assessment <strong>of</strong> Infill Drilling Potential Using a Simulation-Based Inversion Approach, PhD<br />
2005, McVay.<br />
» Garcia Quijada, Marylena; Optimization <strong>of</strong> a CO2 Flood Design: Wasson Field, West Texas, MS 2005,<br />
Schechter.<br />
» Gasimov, Rustam; Modification <strong>of</strong> the Dykstra-Parsons Method to Incorporate Buckley-Leverett Displacement<br />
Theory for Waterfloods, MS 2005, Mamora.<br />
» Gaviria Garcia, Ricardo; Reservoir Simulation <strong>of</strong> CO2 Sequestration and Enhanced Oil Recovery in the<br />
Tensleep Formation, Teapot Dome Field, MS 2005, Schechter.<br />
» Kulchanyavivat, Sawin; The Effective Approach for Predicting Viscosity <strong>of</strong> Saturated and Undersaturated<br />
Reservoir Oil, PhD 2005, McCain.<br />
» Liu, Jin; Investigation <strong>of</strong> Trace Amounts <strong>of</strong> Gas on Microwave Water-Cut Measurement. MS 2005, Scott.<br />
» Nogueira, Marjorie; Effect <strong>of</strong> Flue Gas Impurities on the Process <strong>of</strong> Injection and Storage <strong>of</strong> Carbon Dioxide<br />
in Depleted Gas Reservoirs, MS 2005, Mamora.<br />
» Ogele, Chile; Integration and Quantification <strong>of</strong> Uncertainty <strong>of</strong> Volumetric and Material Balance Analyses<br />
Using a Bayesian Framework, MS 2005, McVay.<br />
» Okeke, Amarachukwu; Sensitivity Analysis <strong>of</strong> Modeling Parameters that Affect the Dual Peaking Behaviour<br />
in Coalbed Methane Reservoirs, MS 2005, Wattenbarger.<br />
» Paknejad, Amir; Foam Drilling Simulator, MS 2005, Schubert.<br />
» Perez Garcia, Laura; Integration <strong>of</strong> Well Test Analysis into a Naturally Fractured Reservoir Simulation, MS<br />
2005, Schechter.<br />
» Romero Lugo, Analis A.; Temperature Behavior in the Build Section <strong>of</strong> Multilateral Wells, MS 2005, Hill.<br />
» Shahri, Mehdi Abbaszadeh; Detecting and Modeling Cement Failure in High Pressure/High Temperature<br />
Wells, using Finite-Element Method, MS 2005, Schubert.<br />
» Simangunsong, Roly; Experimental and Analytical Modeling Studies <strong>of</strong> Steam Injection with Hydrocarbon<br />
Additives to Enhance Recovery <strong>of</strong> San Ardo Heavy Oil, MS 2005, Mamora.<br />
» Tschirhart, Nicholas R.; The Evaluation <strong>of</strong> Waterfrac Technology in Low-Permeability Gas Sands in the East<br />
Texas Basin, MS 2005, Holditch.<br />
» Wang, Wenxin; Methodologies and New User Interfaces to Optimize Hydraulic Fracturing Design and<br />
Evaluate Fracturing Performance for Gas Wells, MS 2005, Valko.<br />
» Yuan, Chengwu; An Efficient Bayesian Approach to History Matching, MS 2005, Datta-Gupta.<br />
» Zhakupov, Mansur; Application <strong>of</strong> Convolution and Average Pressure Approximation for Solving Non-Linear<br />
Flow Problems. Constant Pressure Inner Boundary Condition for Gas Flow, MS 2005, Blasingame.<br />
2004<br />
» Al-Meshari, Ali; New Strategic Method to Tune Equation-<strong>of</strong>-State to Match Experimental Data for<br />
Compositional Simulation, PhD 2004, McCain.<br />
» Sandoval, Jorge; A Simulation Study <strong>of</strong> Steam and Steam-Propane Injection using a Novel Smart Horizontal<br />
Producer to Enhance Oil Production, MS 2004, Mamora.<br />
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List <strong>of</strong> Articles/Papers/<strong>Report</strong>s<br />
2010<br />
» Awoleke, O.O., Lane, R.H. Analysis <strong>of</strong> Data from the Barnett Shale Using Conventional Statistical and<br />
Virtual Intelligence Techniques. SPE Paper 127919 presented at the 2010 SPE International Symposium<br />
and Exhibition on Formation Damage Control, Lafayette, Louisiana, 10–12 February.<br />
» Bello, R. and Wattenbarger, R.A. Multi-stage Hydraulically Fractured Shale Gas Rate Transient Analysis.<br />
Paper SPE 126754, presented at the 2010 SPE North Africa Technical Conference and Exhibition, Cairo,<br />
Egypt, 14–17 February.<br />
» Currie, S.M., Ilk, D., Blasingame, T.A. Continuous Estimation <strong>of</strong> Ultimate Recovery. Paper SPE 132352<br />
presented at the 2010 SPE Unconventional Gas Conference, Pittsburgh, Pennsylvania, 23-25 February.<br />
» Freeman, C.M., Ilk, D., Blasingame, T.A., and Moridis, G.J. A Numerical Study <strong>of</strong> Tight Gas/Shale Gas<br />
Reservoirs - Effects <strong>of</strong> Transport and Storage Mechanisms on Well Performance. Paper SPE 131583 to be<br />
presented at the 2010 IOGCEC International Oil & Gas Conference and Exhibition, Beijing, China, 8-10<br />
June.<br />
» Gomaa, A.M., and Nasr-El-Din, H.A. Rheological Properties <strong>of</strong> Polymer-Based In-Situ Gelled Acids:<br />
Experimental and Theoretical Studies. Paper SPE 128057 presented at the 2010 Oil and Gas India<br />
Conference and Exhibition, Mumbai, India, 20–22 January.<br />
» Li, L., Nasr-El-Din, H.A., Crews, J.B., and Cawiezel, K.E. 2010. Impact <strong>of</strong> Organic Acids/Chelating Agents<br />
on Rheological Properties <strong>of</strong> Amidoamine Oxide Surfactant. Paper SPE 128091 presented at the 2010 SPE<br />
International Symposium on Formation Damage Control, Lafayette, Louisiana, 10-12 February.<br />
» Mou, J., Zhu, D. and Hill, A.D. A New Acid-Fracture Conductivity Model Based on the Spatial Distributions<br />
<strong>of</strong> Formation Properties. Paper SPE-127935 presented at the 2010 SPE International Symposium on<br />
Formation Damage Control, Lafayette, Louisiana, 10-12 February.<br />
» Rawal C. and Ghassemi A. A 3-D Analysis <strong>of</strong> Solute Transport in a Fracture in Hot- and Poro-elastic Rock.<br />
Paper to be presented at the 2010 44th U.S. Rock Mechanics Symposium, ARMA, Salt Lake City, Utah,<br />
27-30 June.<br />
» Rawal C. and Ghassemi A. Reactive Flow in a Natural Fracture in Poro-thermoelastic Rock. Paper presented<br />
at the 2010 35th Stanford Geothermal Workshop. Stanford, California, 1-3 February.<br />
<strong>2009</strong><br />
» Anchliya, A., and Ehlig-Economides, C.A. Aquifer Management to Accelerate CO2 Dissolution and Trapping.<br />
Paper SPE 126688, presented at the <strong>2009</strong> SPE International Conference on CO2 Capture, Storage, and<br />
Utilization, San Diego, California, 2-4 November.<br />
» Bello, R., and Wattenbarger, R.A. Modeling and Analysis <strong>of</strong> Shale Gas Production with a Skin Effect. Paper<br />
CIPC <strong>2009</strong>-082, presented at the <strong>2009</strong> Canadian International Petroleum Conference, Calgary, Alberta,<br />
16–18 June.<br />
» Boulis, A., Ilk, D., and Blasingame, T.A. A New Series <strong>of</strong> Rate Decline Relations Based on the Diagnosis<br />
<strong>of</strong> Rate-Time Data. Paper CIM <strong>2009</strong>-202 presented at the <strong>2009</strong> 60th <strong>Annual</strong> Technical Meeting <strong>of</strong> the<br />
Petroleum Society, Calgary, Alberta, 16-18 June.<br />
» Davani, E., Ling, K., Teodoriu, C., McCain, W.D., Falcone, G. More Accurate Gas Viscosity Correlation for<br />
Use at HP/HT Conditions Ensures Better Reserves Estimation. Paper SPE 124734, presented at the <strong>2009</strong><br />
SPE <strong>Annual</strong> Technical Conference and Exhibition, New Orleans, Louisiana, 4-7 October.<br />
» Deng, J., Hill, A.D. and Zhu, D. A Theoretical Study <strong>of</strong> Acid Fracture Conductivity Under Closure Stress.<br />
Paper SPE-124755, presented at the <strong>2009</strong> SPE <strong>Annual</strong> Technical Conference and Exhibition, New Orleans,<br />
Louisiana, 4-7 October.<br />
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» Freeman, C.M., Ilk, D., Moridis, G.J., and Blasingame, T.A. A Numerical Study <strong>of</strong> Performance for Tight<br />
Gas and Shale Gas Reservoir Systems. Paper SPE 124961 presented at the <strong>2009</strong> SPE <strong>Annual</strong> Technical<br />
Conference and Exhibition, New Orleans, Louisiana, 4–7 October <strong>2009</strong>.<br />
» Freeman, C.M., Moridis, G.J., and Blasingame, T.A. A Numerical Study <strong>of</strong> Microscale Flow Behavior in<br />
Tight Gas and Shale Gas Reservoir Systems. Paper presented at the <strong>2009</strong> TOUGH Symposium, Berkeley,<br />
California, 14–16 September.<br />
» Gomaa, A.M., Mahmoud, M., and Nasr-El-Din, H.A. When Polymer-based Acids can be used? A Core Flood<br />
Study. Paper TPTC 13739 presented at the <strong>2009</strong> SPE International Petroleum Technology Conference,<br />
Doha, Qatar, 7–9 December.<br />
» Gomaa, A.M., Nasr-El-Din, H.A. New Insights into the Viscosity <strong>of</strong> Polymer-Based In-Situ Gelled Acids. Paper<br />
SPE 121728, presented at the <strong>2009</strong> SPE International Symposium on Oilfield Chemistry, The Woodlands,<br />
Texas, 20–22 April.<br />
» Gomaa, A.M., Nasr-El-Din, H.A. Acid Fracturing: The Effect <strong>of</strong> Formation Strength on Fracture Conductivity.<br />
Paper SPE 119623 presented at the <strong>2009</strong> SPE Hydraulic Fracturing Technology Conference, The Woodlands,<br />
Texas, 19–21 January.<br />
» Ilk, D., Rushing, J.A., and Blasingame, T.A. Decline-Curve Analysis for HP/HT Gas Wells: Theory and<br />
Applications. Paper SPE 125031 presented at the <strong>2009</strong> SPE <strong>Annual</strong> Technical Conference and Exhibition,<br />
New Orleans, Louisiana, 4–7 October.<br />
» Johnson, N.L., Currie, S.M., Ilk, D., Blasingame, T.A. A Simple Methodology for Direct Estimation <strong>of</strong> Gas-inplace<br />
and Reserves Using Rate-Time Data. Paper SPE 123298 presented at the <strong>2009</strong> SPE Rocky Mountain<br />
Technology Conference, Denver, Colorado, 14-16 April.<br />
» Li, L., Nasr-El-Din, H.A., and Cawiezel, K.E. <strong>2009</strong>. Rheological Properties <strong>of</strong> a New Class <strong>of</strong> Viscoelastic<br />
Surfactant. Paper SPE 121716 presented at the <strong>2009</strong> SPE International Symposium on Oilfield Chemistry,<br />
The Woodlands, Texas, 20-22 April.<br />
» Li, W., Jensen, J.L., Ayers, W.B., Hubbard, S.M., and Heidari, M.R. <strong>2009</strong>, Comparison <strong>of</strong> Interwell Connectivity<br />
Predictions using Percolation, Geometrical, and Monte Carlo Models. Journal <strong>of</strong> Petroleum Science and<br />
Engineering. (<strong>2009</strong>) 180-186.<br />
» Li, Z. and Zhu, D. Predicting Flow Pr<strong>of</strong>ile <strong>of</strong> Horizontal Well by Downhole Pressure and DTS Data for<br />
Water-Drive Reservoir. Paper SPE 124873, presented at the <strong>2009</strong> SPE <strong>Annual</strong> Technical Conference and<br />
Exhibition, New Orleans, Louisiana, 4-7 October. DOI: 10.2118/124873-MS.<br />
» Ling, K., Teodoriu, C., Davani, E., Falcone, G. Measurement <strong>of</strong> Gas Viscosity at High Pressures and High<br />
Temperatures. Poster 13528, presented at the <strong>2009</strong> International Petroleum Technology Conference,<br />
Doha, Qatar, 7-9 December.<br />
» Liu, C., and McVay, D.A. Continuous Reservoir Simulation Model Updating and Forecasting Using a Markov<br />
Chain Monte Carlo Method. Paper SPE 119197, presented at the <strong>2009</strong> SPE Reservoir Simulation Symposium,<br />
The Woodlands, Texas, 2-4 February.<br />
» Mou, J., Zhu, D. and Hill, A.D. Acid-Etched Channels in Heterogeneous Carbonates—A Newly Discovered<br />
Mechanism for Creating Acid Fracture Conductivity. Paper SPE-119619 presented at the <strong>2009</strong> SPE Hydraulic<br />
Fracturing Technology Conference, The Woodlands, Texas, 19-21 January.<br />
» Nauduri, S., Medley, G.H., and Schubert, J.J. MPD: Beyond Narrow Pressure Windows. IADC/SPE Paper<br />
Number 122276-PP, presented at the <strong>2009</strong> IADC/SPE, Managed Pressure Drilling and Underbalanced<br />
Operations Conference and Exhibition, San Antonio, Texas, 12-13 February.<br />
» Park, H.Y., Falcone, G., Teodoriu, C. <strong>2009</strong>. Decision Matrix for Liquid Loading in Gas Wells for Cost/Benefit<br />
Analyses <strong>of</strong> Lifting Options. Journal <strong>of</strong> Natural Gas Science and Engineering 1 (3): 72-83.<br />
» Rawal C. and Ghassemi A. A 3-D Thermoelastic Analysis <strong>of</strong> Reactive Flow in a Natural Fracture. Paper<br />
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<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong>
presented at the 43rd U.S. Rock Mechanics Symposium, <strong>2009</strong>, Asheville, North Carolina, 28 June-1 July.<br />
» Surendra, M., Falcone, G., Teodoriu, C. <strong>2009</strong>. Investigation <strong>of</strong> Swirl Flows Applied to the Oil and Gas<br />
Industry. SPE Projects, Facilities & Construction Journal 4 (1): 1-6.<br />
» Tian, Y. and Ayers, W. Regional Stratigraphic and Sedimentary Facies Analyses, Barnett Shale, Fort<br />
Worth Basin, Texas. Paper 0919 presented at the <strong>2009</strong> International Coalbed and Shale Gas Symposium,<br />
Tuscaloosa, Alabama, 18-22 May.<br />
» Wang, Y., Holditch, S.A., and McVay, D.A. Modeling Fracture Fluid Cleanup in Tight Gas Wells. Paper SPE<br />
119624, presented at the <strong>2009</strong> SPE Hydraulic Fracturing Technology Conference held in Woodlands, Texas,<br />
19-21 January.<br />
» Wei, Y., Holditch, S.A. Computing Estimated Values <strong>of</strong> Optimal Fracture Half Length in the Tight Gas Sand<br />
Advisor Program. Paper SPE 119374 (<strong>2009</strong>).<br />
» Xue, W., Ghassemi, A. Poroelastic Analysis <strong>of</strong> Hydraulic Fracture Propagation. Paper 129, presented at the<br />
Asheville Rocks <strong>2009</strong>, 43rd US Rock Mechanics Symposium, Asheville, North Carolina, 28 June–1 July.<br />
» Yang, D., Kim J., Silva, P., Barrufet, M., Moreira, R., and Sosa, J. Laboratory Investigation <strong>of</strong> E-Beam Heavy<br />
Oil Upgrading. Paper SPE 121911, presented at the <strong>2009</strong> SPE Latin American and Caribbean Petroleum<br />
Engineering Conference, Cartagena, Columbia, 31 May-3 June.<br />
» Yu, M. and Nasr-El-Din, H. Quantitative Analysis <strong>of</strong> an Amphoteric Surfactant in Acidizing Fluids and<br />
Coreflood Effluent. Paper SPE 121715 presented at the <strong>2009</strong> SPE Symposium on Oilfield Chemistry,<br />
Woodlands, Texas, 20-22 April.<br />
» Zhang, Y., Marongiu-Porcu, M., Ehlig-Economides, C.A., Tosic, S., and Economides, M.J. Comprehensive<br />
Model for Flow Behavior <strong>of</strong> High-Performance Fracture Completions. Paper SPE 124431, presented at the<br />
ATCE <strong>2009</strong> SPE <strong>Annual</strong> Technical Conference and Exhibition, New Orleans, Louisiana, 4-7 October.<br />
2008<br />
» Bello, R.O. and Wattenbarger, R.A. Rate Transient Analysis in Naturally Fractured Reservoirs. Paper SPE<br />
114591 presented at the 2008 CIPC/SPE Gas Technology Symposium, Calgary, Canada, 16-19 June.<br />
» Catalin Teodoriu, Schubert, J., Vivek G., Ibeh C. Investigations to Determine the Drilling Fluid Rheology<br />
Using Constant Shear Rate Conditions. Presented at the 2008 IADC World Drilling Conference & Exhibition,<br />
Berlin, Germany, 11-12-June.<br />
» Chava, G., Falcone, G., and Teodoriu, C. Development <strong>of</strong> a New Plunger-Lift Model Using Smart Plunger (*)<br />
Data. Paper SPE 115934 presented at the 2008 SPE <strong>Annual</strong> Technical Conference and Exhibition, Denver,<br />
Colorado, 24-26 September.<br />
» Grover, T., Moridis, G., and Holditch, S.A. Analysis <strong>of</strong> Reservoir Performance <strong>of</strong> the Messoyahka Gas Hydrate<br />
Reservoir. Proceedings <strong>of</strong> the 2008 SPE ATCE, Denver, Colorado, 21-24 September.<br />
» Haut, R.C., Burnett, D. B., Rogers, J. L., Williams, T. E. Determining Environmental Trade<strong>of</strong>fs Associated<br />
with Low Impact Drilling Systems. Paper SPE 114592, presented at the 2008 <strong>Annual</strong> Technical Conference<br />
and Exhibit, Denver, Colorado, 21-24 September.<br />
» Ibeh, C, Schubert, J.J., Teodoriu, C. Methodology for Testing Drilling Fluids under Extreme HP/HT Conditions.<br />
Paper No. AADE-08-DF-HO-14, presented at the 2008 AADE Fluids Technical Conference and Exhibit,<br />
Houston, Texas, 8-9 April.<br />
» Ibeh, C., Schubert, J., Teodoriu, C., Gusler, W., and Harvey, F. Investigation on the Effects <strong>of</strong> Ultra-High<br />
Pressure and Temperature on the Rheological Properties <strong>of</strong> Oil-based Drilling Fluids. Paper No. AADE-08-<br />
DF-HO-13, Presented at the 2008 AADE Fluids Technical Conference and Exhibit, held in Houston, Texas,<br />
8-9 April.<br />
» Mohammad, A. A. and Mamora, D. D. In Situ Upgrading <strong>of</strong> Heavy Oil Under Steam Injection with Tetralin<br />
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and Catalyst. Paper presented at the 2008 International Thermal Operations and Heavy Oil Symposiums,<br />
Calgary, Alberta, 20-23 October.<br />
» Oluwaseun, O., Burnett, D., Hann, R. and Haut, R. HARC.Application <strong>of</strong> Membrane Filtration Technologies<br />
to Drilling Wastes. SPE 115587.<br />
» Rutqvist, J., Moridis, G., Grover, T., and Holditch, S. Coupled Hydrological, Thermal and Geomechanical<br />
Analysis <strong>of</strong> Wellbore Stability in Hydrate-Bearing Sediments. Paper OTC-19572 presented at the 2008<br />
Offshore Technology Conference held in Houston, Texas, 4-8 May.<br />
» Surendra, M., Falcone, G., Teodoriu, C. Investigation <strong>of</strong> Swirl Flows Applied to the Oil and Gas Industry.<br />
Paper SPE 115938 presented at the 2008 SPE <strong>Annual</strong> Technical Conference and Exhibition held in Denver,<br />
Colorado, USA, 21–24 September.<br />
» Verma, A., Burnett, D. Alternate Power and Energy Storage/Reuse for Drilling Rigs: Reduced Cost and<br />
Lower Emissions Provide Lower Footprint for Drilling Operations. SPE 122885<br />
» Wang,T., Holditch, S. A., McVay, D. Simulation <strong>of</strong> Gel Damage on Fracture Fluid Cleanup and Long-term<br />
Recovery in Tight Gas Reservoirs. Paper SPE 117444, presented at the 2008 SPE Eastern Regional/AAPG<br />
Eastern Section Joint Meeting held in Pittsburgh, Pennsylvania, 11-15 October.<br />
» Yu, O.-Y., Guikema, S. D., Bickel, J. E., Briaud, J.-L. and Burnett, D. Systems Approach and Quantitative<br />
Decision Tools for Technology Selection in Environmentally Friendly Drilling. SPE 120848.<br />
2007<br />
» Badicioiu, M., Teodoriu, C. Sealing Capacity <strong>of</strong> API Connections - Theoretical and Experimental Results.<br />
Paper SPE 106849 presented at the 2007 SPE Productions and Operations Symposium, Oklahoma City,<br />
Oklahoma, 31 March-3 April.<br />
» Chandra, S. and Mamora, D. D. Improved Steamflood Analytical Model. SPE 97870 accepted for publication<br />
in SPE Reservoir Evaluation & Engineering (December 2007).<br />
» Cheng, Y. Lee, J., and McVay, D. Improving Reserve Estimates from Decline Curve Analysis <strong>of</strong> Tight and<br />
Multilayer Gas Wells. Paper SPE 108176, presented at the 2007 SPE Hydrocarbon Economics and Evaluation<br />
Symposium, Dallas, Texas, 1-3 April.<br />
» Haghshenas, A., Schubert, J., Paknejad, A., and Rehm, B. Pressure Transient Lag Time Analysis During<br />
Aerated Mud Drilling. Paper presented at the 2007 AADE National Technical Conference & Exhibition held<br />
in Houston, Texas, 10-12 April.<br />
» Holditch, S., Hill, A. D., and Zhu, D. Advanced Hydraulic Fracturing Technology for Unconventional Tight<br />
Gas Reservoirs. Final research report to DOE DE-FC26-06NT42817, August, 2007.<br />
» Holmes, J.C., McVay, D.A. and Senel, O. A System for Continuous Reservoir Simulation Model Updating<br />
and Forecasting. Paper SPE 107566, presented at the 2007 SPE Digital Energy Conference and Exhibition,<br />
Houston, Texas, 11-12 April.<br />
» Jaiswal, N. and Mamora, D.D. Distillation Effects in Heavy Oil Recovery under Steam Injection with<br />
Hydrocarbon Additives. Paper SPE 110712, presented at 2007 SPE <strong>Annual</strong> Technical Conference and<br />
Exhibition, Anaheim, California, 11-14 November.<br />
» Kamkom, R., Zhu, D., Bond, A. Predicting Undulating Well Performance. Paper SPE 109761, presented<br />
at the 2007 SPE <strong>Annual</strong> Technical Conference and Exhibition held in Anaheim, California, U.S.A., 11–14<br />
November 2007.<br />
» Magalhaes, F., Zhu, D., Amini, S., and Valko, P. Optimization <strong>of</strong> Fractured Well Performance <strong>of</strong> Horizontal<br />
Gas Wells. Paper SPE 108779, presented at the 2007 International Oil Conference and Exhibition in Mexico<br />
held in Veracruz, Mexico, 27–30 June 2007.<br />
» Melendez, M.G., Pournik, M., Zhu, D., and Hill, A. D. The Effects <strong>of</strong> Acid Contact Time and the Resulting<br />
92<br />
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Weakening <strong>of</strong> the Rock Surfaces on Acid Fracture Conductivity. Paper SPE 107772, presented at 7th SPE<br />
European Formation Damage Conference in Scheveningen, The Netherlands, 2007, 30 May - 1 June.<br />
» Morlot, C. and Mamora, D. D. TINBOP Cyclic Steam Injection Enhances Oil Recovery in Mature Steamfloods.<br />
Paper CIPC 2007-158, presented at proceedings CIPC 58th Ann. Tech. Mtg., Calgary, 2007, 12-14 June.<br />
» Mou, J., Hill, A.D., and Zhu, D. The Velocity Field and Pressure Drop Behavior in a Rough-Walled Fracture.<br />
Paper SPE 105182 presented at the 2007 SPE Hydraulic Fracturing Technology Conference, College Station,<br />
Texas, 29–31 January.<br />
» Paknejad, A., Amani, M., and Schubert, J. Foam Drilling Simulator. Paper SPE 105338, presented at the<br />
2007 Latin American & Caribbean Petroleum Engineering Conference held in The Buenos Aires, Argentina,<br />
15-18 April.<br />
» Paknejad, A., Schubert, J., Amani, M., and Teodoriu, C. Sensitivity Analysis <strong>of</strong> Key Parameters in Foam<br />
Drilling Operations. SPE 150 Years <strong>of</strong> the Romanian Petroleum Industry, held in Bucharest, Romania, 14-<br />
17 October, 2007.<br />
» Paknejad, A., Schubert, J., and Haghshenas, A. A New and Simplified Method for Determination <strong>of</strong><br />
Conductor/Surface Casing Setting Depths in Shallow Marine Sediments (SMS). Paper presented at the<br />
2007 AADE National Technical Conference & Exhibition held in Houston, TX., 10-12 April.<br />
» Paknejad, A., Schubert, J., and Amani, M. A New Method to Evaluate Leak-Off Tests in Shallow Marine<br />
Sediments. Paper SPE 110953 presented at the 2007 SPE Technical Symposium held in Dhahran, Saudi<br />
Arabia, 7-8 May.<br />
» Pournik, M., Zuo, C., Malagon Nieto, C., Melendez, M., Zhu, D., Hill, A. D. and Weng, X. Small-Scale<br />
Fracture Conductivity Created by Modern Acid Fracture Fluids. Paper presented at 2007 Hydraulic Fracturing<br />
Technology Conference, in College Station, TX, SPE 106272, 29-31 January.<br />
» Rivero, J.A., and Mamora, D.D. Oil Production Gains for Mature Steamflooded Oil Fields Using Propane as<br />
a Steam Additive and a Novel Smart Horizontal Producer. Paper SPE 110538, presented 2007 SPE-ATCE,<br />
Anaheim, California, 11-14 November.<br />
» Teodoriu, C., Falcone, G., Espinel, A. Letting Off Steam and Getting Into Hot Water – Harnessing the<br />
Geothermal Energy Potential <strong>of</strong> Heavy Oil Reservoirs. Paper presented at the 20th World Energy Congress<br />
- Rome 2007, Rome, Italy, 11-15 November.<br />
» Valko, P.P., and Amini, S. Method <strong>of</strong> Distributed Volumetric Sources for Calculating the Transient and<br />
Pseudosteady-State Productivity <strong>of</strong> Complex Well-Fracture Configurations. Paper SPE 106279 presented at<br />
the 2007 SPE Hydraulic Fracturing Technology Conference, College Station, 29-31 January.<br />
» Yoshioka, K., Dawkrajai, P., Romero, A., Zhu, D., Hill, A. D., and Lake, L. W. A Comprehensive Statistically-<br />
Based Method To Interpret Real-Time Flowing Well Measurements. Final research report to DOE DE-FC26-<br />
03NT15402, January, 2007.<br />
» Yoshioka, K., Zhu, D., and Hill, A. D. A New Inversion Method to Interpret Flow Pr<strong>of</strong>iles from Distributed<br />
Temperature and Pressure Measurements in Horizontal Wells. Paper SPE 109749, presented at the 2007<br />
SPE <strong>Annual</strong> Technical Conference and Exhibition held in Anaheim, California, U.S.A., 11–14 November.<br />
» Zhu, D., Magalhaes, F., and Valko, P. Predicting the Productivity <strong>of</strong> Multiple-Fractured Horizontal Gas Wells.<br />
Paper SPE 106280, presented at 2007 Hydraulic Fracturing Technology Conference, in College Station,<br />
Texas, 29-31 January.<br />
2006<br />
» Bond, A., Zhu, D., and Kamkom, R. The Effect <strong>of</strong> Well Trajectory on Horizontal Well Performance. Paper<br />
SPE 104183, presented at the 2006 International Oil Conference and Exhibition in Beijing, China, 5-7<br />
December.<br />
» Izgec, B., Kabir, C.S., Zhu, D. and Hasan, A.R. Transient Fluid and Heat Flow Modeling in Coupled Wellbore/<br />
Reservoir Systems. Paper SPE 102070, presented at the 2006 SPE <strong>Annual</strong> Technical Conference and<br />
<strong>Crisman</strong> <strong>Annual</strong> <strong>Report</strong> <strong>2009</strong><br />
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Exhibition, San Antonio, Texas, 24-27 September.<br />
» Kamkom, R. and Zhu, D. Generalized Horizontal Well Inflow Relationships for Liquid, Gas or Two-Phase<br />
Flow. Paper SPE 99712 presented at the 2006 SPE/DOE Symposium on Improved Oil Recovery held in<br />
Tulsa, Oklahoma, 22–26 April.<br />
» Malagon Nieto, M., Pournik, M., and Hill, A. D. The Texture <strong>of</strong> Acidized Fracture Surfaces – Implications for<br />
Acid Fracture Conductivity. Paper SPE 102167, presented at 2006 SPE <strong>Annual</strong> Technical Conference and<br />
Exhibition, San Antonio, Texas, 24-27 September.<br />
» Simangunsong, R., Jaiswal, N. and Mamora, D.D. Improved Analytical Model and Experimentally Calibrated<br />
Studies <strong>of</strong> Steam Injection with Hydrocarbon Additives to Enhance Heavy Oil Recovery. Paper SPE 100703,<br />
presented at 2006 SPE <strong>Annual</strong> Technical Conference and Exhibition, San Antonio, 24-27 September.<br />
» Yoshioka, K., Zhu, D., Hill, A. D., Dawkrajai, P., and Lake, L. W. Detection <strong>of</strong> Water or Gas Entries in<br />
Horizontal Wells from Temperature Pr<strong>of</strong>iles. Paper SPE 100209, presented at the 2006 SPE Europec/EAGE<br />
<strong>Annual</strong> Conference and Exhibition held in Vienna, Austria, 12-15 June.<br />
» Zhu, D. and Furui, K. Optimizing Oil and Gas Production by Intelligent Technology. Paper SPE 102104,<br />
presented at 2006 SPE <strong>Annual</strong> Technical Conference and Exhibition, San Antonio, Texas, 24-27 September.<br />
2005<br />
» Mamora, D. and Sandoval, J. Investigation <strong>of</strong> a Smart Steamflood Pattern to Enhance Production from<br />
San Ardo Field, California. Paper SPE 95491, presented at the 2005 SPE <strong>Annual</strong> Technical Conference and<br />
Exhibition, Dallas, Texas, 9-12 October.<br />
» Yoshioka, K., Zhu, D., Hill, A. D., and Lake, L. W. Interpretation <strong>of</strong> Temperature and Pressure Pr<strong>of</strong>iles<br />
Measured in Multilateral Wells Equipped with Intelligent Completions. Paper SPE 94097, presented at the<br />
2005 14th Europec Piennial Conference, Madrid, Spain, 13-16 June.<br />
» Yoshioka, K., Zhu, D., Hill, A. D., Dawkrajai, P., and Lake, L. W. A Comprehensive Model <strong>of</strong> Temperature<br />
Behavior in a Horizontal Well. Paper SPE 95656, presented at the 2005 SPE <strong>Annual</strong> Technical Conference<br />
and Exhibition, Dallas, Texas, 9-12 October.<br />
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