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Home / Issue Archive / 2007 / August #8 / PVT Properties Determination for the Problem of Nonisothermic Filtration of High-Viscous Oil and Ways of its Solution

№ 8 (August 2007)

PVT Properties Determination for the Problem of Nonisothermic Filtration of High-Viscous Oil and Ways of its Solution

By Miroslav Budilin, Marat Yambayev

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With regard to their prospects in maintaining and increasing the oil production, many companies consider the possibility to develop high-viscosity oil fields. According to the specialists’ research, total volume of this oil in the world is estimated in the amount of 810 billion tons. Efficient development of such oil fields requires application of unconventional bed stimulation methods, such as polymer flooding, physical-chemical and microbiological treatment, as well as thermal methods. Thermal methods include fire flooding, thermal-gas method, thermal steam treatment, and hot water injection.

Today, it is a rare case when designing of a formation treatment process does not require the development of an oil-and-gas reservoir’s full-scale or sector model. Indeed, the development of oil properties’ (pVT) quality model is regarded as one of the most important problems in non-isothermic hydrodynamic modeling. The problem is significantly complicated by the necessity to consider the effect of free gas and phase transitions.

Oil and gas condensate mixtures are very complex systems, which include a large quantity of hydrocarbon and non-hydrocarbon components. That is why different methods are used to calculate phase behavior of oil and gas mixtures based on state equations and empirical relationships. Many simulators allow using different approaches to modeling of pVT oil and gas properties; however, despite the apparent variety of possibilities, a number of difficulties arise here. When simulating non-isothermic filtration, due to the problem complexity design engineers often apply the Black Oil notion and empirical relationships to describe oil properties. Yet, this approach is not always justified, and in consequence, the obtained results turn out to be incorrect.

Apparently, the absence of clear systematization of a set of parameters required to provide the correct description of the fluid properties’ behavior, as well as the lack of techniques for calculation of these properties when resolving specific hydrodynamic modeling problems may be considered the major problems.

Below, a summary table offers the descriptions of pVT model notions as different options of the non-isothermic modeling.
Where:

KHBI – The phase equilibrium state is not calculated as such; the equilibrium state is always supposed (the gas content is determined in an explicit form).

The oil and gas properties may be calculated by applying empirical relationships.

KHEE – The equilibrium state is calculated by a state equation (e.g., Peng-Robinson).

KHKT – The equilibrium state is presented explicitly by equilibrium constants tables (distribution ratios) for different thermobaric conditions.

KHKA – Analytical dependences to calculate equilibrium constants (distribution ratios) for different thermobaric conditions.

DHBI – Oil and gas density may be calculated by applying empirical relationships and presented as tables.

DHEE – Oil and gas density may be calculated by a state equation (e.g., Peng-Robinson).

DHCO – Multiple correlations may be used to calculate oil and gas density.

VHBI – Oil and gas viscosity may be calculated by applying empirical relationships and presented as tables.

VHTA – Analytical dependences may be used to calculate oil and gas viscosity.

VHLC – Correlations (e.g., Lohrentz Bray Clark) and critical parameters of hydrocarbon components may be used to calculate oil and gas viscosity.

THPA – Surface tension is calculated by a state equation.

THTT – Surface tension as a function of pressure and temperature is defined in the table in an explicit form.

HHTA – Analytical relationships are used to calculate oil and gas enthalpy.

The table shows that similar to solving problems in traditional (isothermic) form, three possible representations of oil and gas mixture models are identified for non-isothermic modeling:

Dead Oil – this representation is used to consider the oil filtration with dissolved gas, which is not released in the course of development (the gas cap is missing; the pressure exceeds bubble-point pressure). In case of a non-isothermic representation, it is usually high-viscosity dead oil with gas content lower than 5 cu. m/cu. m (the dissolved gas volume is negligible).

Black Oil (Live Oil) – oil with dissolved gas (gas content exceeds 5 cu. m/cu. m); gas liberation from oil or presence of gas cap are possible. Variation of oil and gas properties caused by phase transition is taken into account.
Compositional thermodynamic representation of the system.

The Dead Oil thermodynamic representation may be used both with vapor or without it (displacement with hot water); oil physical properties (such as density, viscosity, enthalpy) are defined either in an explicit form (as tables showing the parameter dependence on pressure and temperature), or in the form of analytical relationships, the constants of which may be derived from multiple correlations by selecting a necessary function, e.g., in the MS Excel package.
It should be noted that in case of simulation of a non-isothermic filtration, the Black Oil thermodynamic representation (with dissolved or free gas) may be used only under assumption of water vapor absence in the designed model. Just as for the Dead Oil’s thermodynamic context, oil and gas physical properties are defined in an explicit form.

Thus, it becomes possible to tackle the most complex problem in simulation of a non-isothermic filtration – namely, the development of an adequate compositional pVT model. Without application of a state equation option for compositional thermodynamic context, the problem is solved uniformly for cases of supposed presence or absence of water vapor. It should be noted that it is the only way to design a model of oil and gas properties in order to solve a non-isothermic problem with water vapor.

To analyze the solution of this problem, it is possible to use as an example a model of fluid properties designed for Russkoye oil and gas field. It is a complex field due to such factors as high-viscous (about 169 MPa*s) oil in the productive Cenomanian formations. The situation is aggravated by gas cap presence, as well as by active underlying water and disjunctive tectonic dislocations. Analysis of production tests and pilot production of the field’s pay bed proved inefficiency of the conventional flooding. That is why it seems expedient to consider an option with thermal methods of the oil recovery enhancement as an alternative method of the formation treatment, using either vapor or hot water as a heat carrier.

To be continued in the next issue.

AUTHORS’ BIO

Marat F. Yambayev, Chief Specialist for Field Development, LUKOIL Overseas
Service Ltd.

 

 

 

Miroslav N. Budilin, Leading Specialist of the Khantos-Vostok Fields Hydrodynamic Modeling Bureau, Scientific-analytical Department, Gazpromneft

 

 

 

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