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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 laura.vann@pe.tamu.edu. 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

hadi.nasrabadi@pe.tamu.edu

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

peter.valko@pe.tamu.edu

Rashid Hasan

rashid.hasan@pe.tamu.edu

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: laura.vann@pe.tamu.edu

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.