(169e) Effect of Temperature Shift Around Critical Point on Liquid Production from Shales

Panja, P. - Presenter, University of Utah
Pathak, M., University of Utah
Deo, M., University of Utah

Light tight oil (LTO) production in US has seen a tremendous growth. The
properties of crude oil such as density, viscosity etc. which directly affect
the flow ability inside the porous rock depend on compositions of fluid and the
reservoir conditions mainly temperature and pressure. The pressure in the
reservoir declines in course of production as more hydrocarbons are extracted.
A reservoir can be assumed to be isothermal at a smaller reservoir scale but
variation in temperature can be observed in larger scale across same play such
as in Eagle Ford Play in Texas, USA. Temperature also changes along the fluid flow
pathway from sub-surface to surface facility. In this research, we investigated
the effect of temperature changes in the sub-surface reservoir on thermodynamic
fluid properties of hydrocarbons and consequently on their production.  The thermodynamic fluid properties can be
derived from its pressure-temperature diagram (PT- diagram).  In petroleum industry, it is very common to
determine the type of a fluid (dry gas, wet gas, gas-condensate, volatile oil
and black oil) from initial reservoir pressure and temperature using the PT-diagram
as shown in Figure 1. For same compositions, temperature is the deciding factor
to determine the type of fluid reside in the reservoir. For instance, if the
reservoir temperature is higher than critical point temperature, fluid is
gas-condensate, wet gas or dry gas. On the other hand, temperature lower than
critical point yields volatile oil and black oil.  Volatile oil and gas-condensate are the two
fluids which are the closest to the critical point but on the opposite sides
(Figure 1).

figure 1: P-T plot showing variation in fluid properties
with changing temperature and pressure of the reservoir

This fact causes
the temperature change near critical point more sensitive. In this study, 25OF
temperature variation near critical point is considered to make gas-condensate
(critical point+25OF) and volatile oil (critical point-25OF)
for the same composition. Eagle Ford, a prolific liquid play in the USA is good
example of this type of temperature variation. Volatile oil is initially liquid
with large amount of gas dissolved in it and when pressure drops below bubble
point pressure gas evolves out of liquid phase and causes two phases. In case
of gas-condensate, fluid is initially gas containing large amount of
volatilized oil, and eventually, the liquid hydrocarbon drops out from gaseous
phase when pressure declines below dew point pressure and causes two phase of
gas and liquid condensate (note that in case of gas-condensate, low pressure
causes liquid to form, it is counter intuitive, that’s why it is sometimes
called retrograde condensate). It desired to produce volatile oil in liquid
form and separate dissolved gas in the separator on the surface. In case of
condensate, gas containing volatilized oil should be produced and condensate
will be dropped out at separator by cooling and pressure drop.  In reality, pressure goes below saturation
pressure during production. Therefore, in either cases (volatile oil and
gas-condensate) two phase forms inside reservoir when pressure goes below saturation
pressure (bubble point or dew point pressure) during production. Gas being
lighter and more mobile than liquid oil, always dominates the two phases or
multiphase flow, suppressing the flow of liquid i.e., volatile oil and
condensate. Therefore, production rate of liquid drops drastically when
pressure drops below saturation pressure and a large amount of gas is produced
along with volatile oil or condensate on the surface. In the current work, the
recovery factor and liquid to gas ratio are mainly studied for five different
initial compositions (fluid 1, fluid2, fluid3, fluid4 and fluid5). Each fluid
is distinguished by different PT-diagram, critical point, saturation pressures,
initial liquid to gas ratio (LGR) etc. Fluid 1 is the
leanest in nature i.e, less oil and more gas (low LGR) and fluid 5 is the richest (high LGR).
The effect of temperature variation (in volatile oil and gas condensate
reservoir) for different reservoir permeabilities and operating pressures are
studied. It was observed using reservoir simulations that a higher amount of liquid
hydrocarbon was produced when temperature is higher than critical points i.e.,
when fluid is gas-condensate. Well could be operated at low bottom hole pressure in order to increase the total flow rate but
it is not always preferable. It is found in this study that the higher bottom
hole pressure (3000 psia) favors higher liquid recovery in 100 nD reservoir because of the fact that at lower bottom hole
pressure (1000 psia) , gas dominates the two phase flow.  Lower bottom hole
pressure (1000 psia) is advantageous for higher permeability reservoir (1000 nD).  Fluid with
higher liquid content (such as fluid 4 and fluid 5) are less affected by the
operating pressure. Recommendations based on reservoir scale simulation are
given in this work for increased production at higher rates in shale plays.