Effect of Temperature Shift Around Critical Point on Liquid Production from Shales

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, 25^OF temperature variation near critical point is considered to make gas-condensate (critical point+25^OF) and volatile oil (critical point-25^OF) 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.