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In this issue:
Fall Crisman Meeting 1
New Crisman Projects
Announced
1
Molecular Simulation
of Fluid Phase
Behavior in Shale
Systems
4
Experimental
Investigation of Flow
Reversal to
Characterize Liquid-
Loading Conditions
6
Issue 3, October 2014
October Newsletter
The Fall Crisman Meeting will take place December 10-11 in the Richardson Building,
room 910.
The first day topics will include: Nanoscale Fluid Behavior and Rock-Fluid
Interactions
The second day topics include talks on projects in: EOR in Unconventional
Reservoirs, Rock and Fracture Characterization, and Well Flow and Artificial Lift
Optimization in Unconventional Reservoirs
The formal agenda for the two-day event will be emailed and posted as soon as it is
available.
If you know of someone in your company who would be interested in receiving these
emails, please forward the information to Laura Vann, the new Crisman administrative
assistant at [email protected]. If you would like to have your email removed
from the mailing list, let her know that as well.
Fal l Cr isman Meet ing
Based on member company evaluations of faculty-generated proposals, five new
Crisman projects were funded as of 1 September 2014. We are very pleased that two-
thirds of our members provided evaluations of the proposals. These new projects join
ten ongoing projects to provide a broad spectrum of research in unconventional
reservoirs. If funding allows there will be additional projects funded in January 2015.
Titles and Principal Investigators for the newly-funded projects are listed below. We
are very pleased that most of the projects are multidisciplinary in nature, with multiple
principal investigators, including some from other departments.
Bob Lane (Continued on page 2)
New Crisman Projects Announced
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Projects Funded as of 1 September 2014:
Project 2.5.25:Analysis of Fracturing Behavior of Ultra-Tight Geologic Media Across
Spatial Scales: From Fundamental Studies to Field Applications
Principal Investigators:
George J. MORIDIS, Lawrence Berkeley Labs and TAMU/PETE (Visiting Professor)
Thomas A. BLASINGAME, TAMU PETE
Eduardo GILDIN, TAMU PETE.
David SCHECTER, TAMU PETE
Peter VALKO, TAMU PETE
Three years duration. Three Ph.D students
This investigation will develop statistical models associating fracture trajectory with the
spatial distribution and mechanical strength of nano- to micro-fractures and
inclusions. The statistical models will be used to develop mathematical models of
fracture initiation and propagation accounting for these factors, and will be tested in
laboratory-scale studies. Finally, the mathematical models will be incorporated into
numerical simulators of coupled flow/geomechanics describing hydraulic fracturing.
Project 2.4.27: Using Acoustic Sensor Data to Diagnose Multi-Stage Hydraulic
Fracture Treatments
Principal Investigators:
Ding Zhu (TAMU PETE)
Yong-Joe Kim (TAMU Mechanical Engineering)
Two years duration. Two Ph.D. students
This investigation will develop models to simulate acoustic signals as functions of fluid
property and flow behavior during fracture treatment and during production for oil, gas
and water producing wells based on fundamental physical principles.
Project 3.2.21: Experimental Study of Confinement Effects on Hydrocarbon Phase
Behavior in Nano-Scale Capillaries
Principal Investigators:
Hadi Nasrabadi (TAMU PETE)
Yucel Akkutlu (TAMU PETE),
Debjyoti Banerjee (TAMU Mechanical Engineering and PETE)
Jodie Lutkenhaus (TAMU Chemical Engineering),
Hung-Jue Sue (TAMU Material Science and Engineering)
Three years duration. Two Ph.D. students
(Continued on page 3)
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A special TAMU research team will investigate the phase change in nano-scale
capillaries using two experimental approaches based upon selected “model” porous
materials: combination of a nanochannel device and epi-fluorescence microscopy, and
modulated differential scanning calorimetry. The model’s material surface will be
modified chemically and topographically, and molecular simulation will be used to gain
insight into the experimental results.
Project 2.4.28: Novel Artificial Lift Methods to Increase Reserves in Shale and Tight
Sand Gas Reservoirs
Principal Investigator(s):
Rashid Hasan (TAMU PETE)
Ding Zhu (TAMU PETE)
Three years duration. One Ph.D. student
The project objectives are to develop novel approaches to artificial lift of vertical,
horizontal and inclined wells in tight sand and shale gas reservoirs. We will study the
suitability of available artificial lift methods to optimally unload liquids. We will
integrate the lift methods with well structure design for vertical, horizontal and inclined
wells, will develop models that consider the complex flow conditions in typical shale
gas and tight sand producing wells, and will develop novel approaches for artificial lift
design to efficiently and economically produce from unconventional resources.
Project 3.2.22: Multi-phase Flow in Nano-capillaries using NEMD
Principal Investigator:
Yucel Akkutlu (TAMU PETE)
Two years duration. One Ph.D. student.
In this project, we are going to develop an understanding of the reservoir fluid behavior
and obtain constitutive relationship for the transport parameters of the reservoir
simulation.
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Introduction
Phase behavior in shale remains a challenging problem in the petroleum industry due to
many complexities. One complexity is due to strong surface-fluid interactions in shale
nano-scale pores. These interactions can lead to heterogeneous distribution of
molecules. Conventional bulk-phase thermodynamics cannot describe this
heterogeneous molecular distribution. The majority of current models for phase
behavior in shale are based on bulk-phase thermodynamics.
In this project, we will use molecular simulation methods to accurately model the effect
of solid-fluid and fluid-fluid interactions in shale. We have modeled bulk pressure/
volume/temperature (PVT) properties for pure hydrocarbons, and will continue to
model their mixtures where there are significant experimental data to validate our
simulations. We will then extend our model to shale systems where experimental data
are currently scarce.
Objectives
The main outcome of this project will be a software package (mPVT) to predict the
phase behavior of petroleum fluids in shale rocks. The inputs of the software will be
pressure, temperature, fluid composition, pore size distribution, pore-wall material, and
bulk PVT properties of a petroleum fluid. The output will be corresponding confined
PVT properties in the shale systems.
Approach
In this project, we propose to use molecular simulation to calculate the phase behavior
of petroleum fluids for the shale reservoirs. We use the Gibbs Ensemble Monte Carlo
(GEMC) simulation technique for the calculation of phase coexistence at conditions far
from critical point. We use the Grand Canonical Monte Carlo (GCMC) simulation
technique to accurately predict the phase behavior of petroleum fluids close to the
critical point. We use the canonical simulation technique to study the boundary effect
on the interface. We plan to include the surface charge of pore structure and partial
charge of molecules such as CO2. In all steps of the
project, we will compare the molecular simulation
results with experimental data (if available) and
predictions of the most popular equations of state.
Accomplishments
In this period, we get the property for pure system by
GCMC simulation, in which the chemical potential, the
volume and the temperature are kept as a constant in one
simulation box. This method can be used to study the
liquid vapor equilibrium by combining it with the
histogram reweighting method. For the Ethane, we can
get the accurate results comparing with the experimental
data from NIST, as shown in Fig. 1. The GCMC (Continued on page 5)
Molecular Simulat ion of Fluid Phase Behavior in
Shale Systems
3.1.25 Molecular Simulation of
Fluid Phase Behavior in Shale
Systems
Advisors
Hadi Nasrabadi
Student
Bikai Jin
Fig. 1–Temperature – density diagram for Ethane.
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simulation can be used at the condition near critical point, which is not possible for
GEMC.
We get the phase equilibrium diagram for binary system (C1+C2) from NPT-GEMC
method. As shown in Fig. 2, the NPT-GEMC method can provide accurate results when
the temperature is far away from the critical point. When approaching critical point, the
simulation error is increasing and the result is not acceptable.
Future Work
In the next period, we will continue our work on properties of phase coexistence in bulk
phase behavior for hydrocarbon mixtures from different methods. We will then extend
the application to multicomponent hydrocarbon mixtures in inorganic nano-pores by
introducing the boundary effect.
Fig. 2–Pressure – composition diagram for C1+C2 system.
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Introduction
This work focuses on situations of particular significance in natural gas producing
wells, when annular to churn flow-pattern transition brings about drastic hold-up
increase, leading to a rich group of phenomena in the field known as "liquid loading."
Under circumstances believed to precede liquid loading, the still steady-state and stable
liquid holdup may be several folds larger than the inlet volumetric fraction of the liquid,
due to partial flow reversal. This leads to increased resistance in the pathway of the
produced gas, triggering instability in the coupled well-reservoir system and ultimately
causing the end of the natural flow of gas from the reservoir. Extensive studies have
been conducted in this particular area, where the actual choice is to accept the
hypotheses of critical rate correlation derived using data solely from actual producing
wells. However, the richness of the related phenomena in the gas field comes from the
interaction of multi-phase flow in the well and in the underlying porous media.
In this study, we investigate the flow reversal phenomena, its
consequence to the hold-up value, and the corresponding
countercurrent flow. Furthermore, the results can be used in coupled
modeling of well-reservoir systems.
Objectives
Investigate the performance of various liquid hold-up prediction
methods in the presence of partial flow reversal.
Investigate the characteristic of flow reversal and the amount of
liquid flowing downward with various gas and liquid mass fluxes.
Develop a new hold-up prediction method, specifically designed
for gas wells experiencing annular to churn flow transition, when flow
reversal occurs.
Investigate the chaotic behavior (oscillation) of the flow during
annular to churn flow transition.
Approach
Two groups of two-phase flow experiments, namely hold-up and flow
reversal experiments, are performed in a modified transparent 42-m
long, 0.048-m ID vertical tube system (Tower Lab, shown in Fig. 1). In
the first experiment, volumetric liquid hold-up is measured by closing
inlet and outlet valves in a synchronized manner during the stabilized
state, trapping the liquid inside the test section. In the second
experiment, we investigate the flow in both sections above and below
the entry point, located at z = 7 m, as well as the amount of liquid
flowing downward. In both experiments, absolute pressures and liquid film thickness
are measured at several vertical locations with various sampling frequencies. The gas
and liquid mass flux intervals correspond to possible situations in natural gas producing
wells where volumetric liquid rates are moderate or low, and (initial) volumetric gas
rates are high, while mass fluxes are of the same order.
(Continued on page 7)
Experimental Invest igat ion of F low Reversal to
Character ize Liquid -Loading Condi t ions
2.4.26 Experimental
Investigation of Flow Reversal to
Characterize Liquid-Loading
Conditions (TowerLab Facility)
Advisors
Peter Valko
Rashid Hasan
Student
Ardhi Lumban Gaol
Fig. 1–Schematic of Tower Lab, a large scale two-
phase flow facility.
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Accomplishments
The modifications of Tower Lab have been conducted where the recent facility
provides more accurate hold-up measurement and allows flow reversal investigation. A
set of data containing 46 liquid hold-up measurements has been
collected and will be used as a basis for the development of a new
hold-up prediction method. In the presence of partial flow reversal,
standard two-phase correlations have difficulties in reproducing hold-
up observations. Measured hold-up is also compared to the two-fluid
model (OLGA), as shown in Fig. 2.
As many as 53 flow reversal experiments have been conducted, the
results are particularly new and further analysis will be performed.
Significance
This research will help us to understand the flow reversal phenomena,
which may have a strong relationship to the occurrence of liquid
loading. The new hold-up model derived from the larger scale
experimental facility can be then used in coupled modeling of the
well/reservoir system with automatic determination of flow direction.
Future Work
The new hold-up prediction method specifically developed for conditions affected by
partial flow reversal will be proposed and validated against existing hold-up data from
various sources. Time-series analysis will be conducted, where time and frequency
distributions, as well as topological statistics, may provide insight into the actual
phenomena. The morphology of the flow interpreted from visual observation will also
be utilized as a compliment for the time-series analysis.
References and Related Publications
Limpasurat, A., Valkó, P.P., and Falcone, G. 2013 A New Concept of Wellbore
Boundary Condition for Modelling Liquid Loading in Gas Wells. Paper SPE 166199
presented in the SPE Annual Technical Conference and Exhibition, New Orleans,
Lousiana, USA, 30 September–2 October.
Lumban-Gaol, A., Valkó, P.P. 2014. Liquid holdup correlation for conditions affected
by partial flow reversal, International Journal of Multiphase Flow 67 (December
2014):149-159. http://dx.doi.org/10.1016/j.ijmultiphaseflow.2014.08.014
Skopich, A., Pereyra, E.J., Sarica, C., et al. 2013. Pipe Diameter Effect on Liquid
Loading in Vertical Gas Wells. Paper SPE 164477 presented in the SPE Production and
Operation Symposium, Oklahoma City, Oklahoma, USA, 23-26 March.
Turner, R.G., Hubbard, M.G., Dukler, A.E. 1969. Analysis and prediction of minimum
flow rate for the continuous removal of liquids from gas wells. SPE J Pet Technol 21:
1475-1482
(Continued on page 8)
Fig. 2–Comparison of measured hold-up and that
predicted with OLGA, with various gas and mass fluxes.
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For more information on other
research projects, please visit
the Crisman website.
Robert Lane, Director
Nancy H. Luedke, Editor
Laura Vann, Editor
Email: [email protected]
Harold Vance Department of Petroleum Engineering
3116 TAMU
College Station TX 77843-3116
979.845.1450
© 2014 Harold Vance Department of Petroleum Engineering at Texas A&M
University. All rights reserved.
Newsletter Information
Wallis, G. B. 1969. One-dimensional Two-phase Flow. New York: McGraw-Hill.
Waltrich, P. 2012. Onset and Subsequent Transient Phenomena of Liquid Loading in
Gas Wells: Experimental Investigation Using a Large Scale Flow Loop. PhD
dissertation, Texas A&M University, College Station, Texas.
Waltrich, P., Falcone, G., Barbosa, J.R. 2013. Axial Development of Annular, Churn
and Slug Flows in a Long Vertical Tube. Int. J. Multiph. Flow 57 (0): 38-48.
Zabaras, G., Dukler, A.E., Moalem-Maron, D. 1986. Vertical Upward Co-current Gas-
liquid Annular Flow. AIChE Journal 32 (5): 829-843.