American Oil and Gas Reporter - February 2015 - 81

production. This is because water relative permeability in waterwet inorganic matter is low and water is not able to establish its
way from the fracture to the matrix.
As production continues, pressure further decreases in the matrix and water starts invading the system from the sides, making
its way deeper into the matrix. As water saturation increases at
the matrix faces, its relative permeability increases and water movement into the matrix becomes easier. This water imbibition into
the shale matrix increases pressure at later simulation times.
Productive shale plays generally have higher TOC values. Organic richness in this model is reflected in the number of kerogen grid blocks. To see how TOC can affect flow dynamics in
shale, the study sensitized TOC's influence on hydrocarbon production by using three TOC values (6.0, 9.5 and 13.0 percent).
Results were analyzed in terms of average matrix pressure and
total oil and gas production.
Rather than the recovery factor (hydrocarbons produced divided by hydrocarbons in place for each case), the objective was
to compare the cumulative hydrocarbon production in each sensitivity case using "normalized cumulative production" calculated by normalizing the cumulative production in each case to a
constant total hydrocarbons in place. Higher normalized cumulative production simply means higher amounts of produced hydrocarbons, and normalizing all values to a constant number makes
the production values more comparable with one another.
The results show that the average shale matrix pressure followed
a similar trend for cases with different TOC values without any
noticeable differences. However, cumulative gas production increased with higher TOC. This is explained by the fact that as TOC
increases in shale, the number of kerogen grid blocks increases
in the system. High-porosity kerogen can store considerable
amounts of hydrocarbons. Compared to the liquid phase, gas phase
flow is more efficient in shale, considering its lower viscosity and
improved permeability, because of molecular slippage. For these
reasons, the higher-TOC cases produced more gas.
On the other hand, oil flow in shale matrix is restricted by the
ultralow permeability. The results showed that TOC values did
not alter oil production substantially, even though oil-in-place increased with TOC, because of the restricted oil flow in the lowpermeability shale matrix.
Ì
Editor's Note: For detailed information on the new microscale modeling technique using shale matrix subdivisions and liquids-rich shale modeling results, see SPE 170953, "How to Improve our Understanding of Gas and Oil Production Mechanisms
in Liquid-Shale," a technical paper the authors presented at the
2014 Society of Petroleum Engineers Annual Technical Conference & Exhibition, held Oct. 27-29 in Amsterdam.
The co-authors acknowledge Texas A&M post-graduate researchers Yang Cao, Cheng "Jack" An, Yuhe Wang and Jie He for
their contributions and assistance in developing and testing the
microscale modeling technology.

MASOUD
ALFI

Masoud Alfi is a doctoral candidate in the Harold Vance
Department of Petroleum Engineering at Texas A&M University. He holds an M.S. in petroleum engineering from
Texas A&M, and worked in the university's advanced petroleum fluid analysis laboratory before starting his Ph.D.
in 2012. He is the 2014 recipient of the Society of Petroleum Engineers' Star Fellowship. His research interests include mass and heat transfer simulation in ultralow-permeability shale reservoirs, enhanced oil recovery methods, and
phase behavior of petroleum fluids.

BICHENG
YAN

Bicheng Yan is a doctoral candidate in petroleum engineering at Texas A&M University. His research interests include reservoir simulation for unconventional reservoirs,
microscale modeling, and multiple-porosity modeling for
fractured reservoirs. Yan holds a B.S. in petroleum engineering from China University of Petroleum (Beijing) and
an M.S. in petroleum engineering from Texas A&M.

JOHN
KILLOUGH

John Killough is the Michael & Heidi Gatens Development Professor of Petroleum Engineering at Texas A&M
University. His research interests include reservoir simulation and high-performance computing, coupled surface/subsurface reservoir modeling, and hysteresis and relative permeability. Killough's student research group investigates
different aspects of reservoir simulation at various scales,
including microscale storage and flow mechanisms in shales
and fractured carbonates. He is the recipient of SPE's 2013
International Reservoir Description and Dynamics Award.
Killough holds a bachelor's and a master's in chemical engineering, and a Ph.D. in math sciences from Rice University.
FEBRUARY 2015 81

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