Alexander E. Gurevich

Origin of the formation fluid pressure distribution and ways of improving pressure prediction methods

Abstract The study of formation pressures has a history of more than 50 years. Still not all aspects and phenomena are investigated and taken into account. For example, pressure increase caused by vertical gas migration and liquid-gas redistribution may be a major factor during periods of intense gas generation and migration. Compaction of clays depends not only on the overburden or/and geodynamic loading but on reduction of strength and on temperature change. A deeper and more complete understanding of natural phenomena allows to extend the scope of pressure prediction methods. Pressure distribution and abnormality are caused by both gravitationally non-equilibrium distribution of fluid density (free convection) and fluid compression changes (forced convection), which are generated and influenced by different factors. To achieve better correlations, therefore, pressure can be divided, with a reasonable precision, into free convection and forced convection components and each component correlated with corresponding factors. Sets of characteristics, separately presenting the ability of fluid-filled rock to change pressure under external influence, the external influence itself, and permeability, should be used for correlations.

Numerical criterion and sensitivity analysis for time-dependent formation pressure in a sealed layer

Abstract Methodology and results of analysis of variation in time of a mean value of abnormal component of the formation pressure in a layered medium and its sensitivity analysis are presented. The abnormal component is defined as the difference between the actual and hydrostatic formation pressure. The model used by the writers is a combination of two layers of finite thickness. The upper layer is a seal (caprock) with low porosity and low permeability, whereas the lower layer has higher porosity and higher permeability. The methodology is based on the assumption that the process of sedimentation (accumulation of sediments) causes rock compaction, which in turn leads to increased flow of fluids from the underlying formations (shales, etc.) into the permeable layer. A single integral parameter is developed the values of which discriminate one of the three possible scenarios: formation pressure development, increased in time, remained unchanged, or decreased in time. Simple structure of the model allowed to obtain analytical expressions for sensitivity coefficients of the formation pressure and identify parameters of the medium to which characteristics of the formation pressure are most sensitive.

Abnormal pressures in Azerbaijan: A brief critical review and recommendations

Abstract The authors exhaustively reviewed Soviet publications on abnormal pressures in Azerbaijan. According to these data, pore pressures in shales are determined in Azerbaijan by a calculation using well-logging data; pore pressures in shales, even in thin beds, significantly exceed pore pressure in sand reservoirs. On the basis of their review, the authors recommend the following additional research work to achieve a higher efficiency of drilling and production operations in Azerbaijan. 1. (1) Differentiate causes of heaving and sloughing of different shales, in addition to that of the pressure abnormality, and identify cases when special formulations of drilling mud can be used instead of increasing mud density. 2. (2) Thoroughly evaluate the precision of pressure calculation using well-logging data for different shales and environments. 3. (3) Distinguish cases where pressure abnormality is due to other causes than undercompaction. 4. (4) Check the validity of indirect pressure measurements in thin shale beds. 5. (5) Analyze local and regional hydrodynamics of formations for better prediction of the difference between pore pressures in shales and sand reservoirs.

Chapter 4 Possible impact of subsidence on gas leakage to the surface from subsurface oil and gas reservoirs

Publisher Summary This chapter discusses the possible impact of subsidence on gas leakage to the surface from subsurface oil and gas reservoirs. Fractures in rocks in producing oil and gas fields are due to previous tectonic and diagenetic history, current tectonic and seismo-tectonic movements, and deformations caused by the compaction of reservoir rocks and the subsidence of overlying formations. The new deformations, both natural and man-induced, enhance previously formed fractures and form new ones. Fracturing modifies production, gives rise to upward gas migration, and damages surface and subsurface structures. A free-gas phase exists in natural gas reservoirs, oil reservoirs with a gas cap, and in underground gas storages. If there are paths for escape from a pool, free gas migrates to the surface, which may be a cause of explosions and fires. In areas subjected to earthquakes, the upward gas migration can be a major hazard. The basis to more effective solutions to this problem may be provided by a thorough and rigorous analysis of the nature of the processes involved.

Differential sensitivity analysis and multi-variant simulation of formation pressure and temperature in heterogeneous media

Abstract Methodology of differential sensitivity analysis and sensitivity-based aggregate simulation for formation pressure, temperature and fluid flow is developed here. It is aimed at estimation of variations of formation pressure, temperature and velocity field for fluid flow due to variations in the properties of the medium and fluids in the pores. It includes the use of the so-called “sensitivity functions” defined as partial derivatives of the formation pressure and temperature with respect to parameters of the rock and fluids in the pores. It is shown that the sensitivity functions are defined by the same system of equations as formation pressure and temperature fields with the right-hand side of the equations dependent on the type of sensitivity function. There are several important applications of the differential sensitivity analysis and sensitivity functions: (1) Sensitivity functions allow to estimate, under certain conditions, the magnitude of variation of formation pressure and temperature fields 1 (2) Using sensitivity function-based technique, it is possible to partially decouple the system of equations for formation pressure and temperature fields under conditions of slow variations of temperature or pressure in time. (3) Differential sensitivity analysis may serve as a basis for calculation of multiple versions (aggregate simulation) of formation pressure and temperature fields due to various changes in the parameters of the medium and pore fluids.

Force potential for non-uniform-density fluids

Abstract Force potential for all fluid particles coincides with the potential constructed as the sum of mechanical energies of a separate particle only when particles are indistinguishable, i.e., when density of a fluid is uniform or varies only with depth. An error caused by the application of a potential model to a non-potential flow (the indefiniteness of the integral due to the multiplicity of ways of integration when density varies on horizontal planes) can be easily determined as the area in the plot of specific weight/depth.

Bi-linear models for simultaneous estimation of a formation pressure and lithological characteristics in interbedded sands and shales

Abstract A new method for analysis of lithology variations in multi-layered geological formations and suppression of lithological components in formation pressure indicators is described. The key element of the methodology is the suggestion that several curves indicating variations with depth in formation pressure and in lithology may be presented as a sum of three basic components: (a) smooth components, slowly changing with depth; (b) a fast-changing component, and (c) random components, mutually uncorrelated at different curves. The smooth components in the recorded curves are assumed to be those strongly correlated with actual variations of the formation pressure. They may be either common or unique to each recorded indicator, depending on the type of model. Each of the recorded curves is described by two groups of parameters: variables defining properties of the basic components and factors with which the components are included in a given indicator. The models for formation pressure and lithological indicators are built as bi-linear functions of variables from those two groups. The methodology includes estimation of smooth components in all curves, estimation of factors, and extraction of the fast, lithological component via joint processing of several formation pressure and lithological indicators. This allows for correction of formation pressure indicators distorted by changing lithology in interbedded formations and for better detection of zones of abnormal pressure, characterized by an abrupt change in the corrected formation pressure indicator. An example of this methology is a joint use of information on drilling rate taken in the form of d c -exponent and information on the lithology taken in the form of the shale content in interbedded sands and shales.

Chapter 12 Mathematical modeling of abnormally high formation pressures

Publisher Summary The quantity of hydrocarbon accumulation is a function of generation, migration, entrapment, sealing, and preservation. All of these factors are affected by the history of fluid movement in a thermochemical setting. Fluid movement within a basin depends primarily on pressure variation. Thus, one can improve both hydrocarbon exploration and later oil production with a better understanding of the fluid pressure environment. As computers continue to become faster and more robust, all disciplines are moving from qualitative analysis to quantification. Modeling geological history is no exception. In view of latest developments in material science and irreversible thermodynamics, it has become important to discuss features that were previously considered to be beyond the scope of mathematical modeling. Modeling dynamic geochemical processes, such as paleotemperature and abnormal pressure of sedimentary basins, offers many challenges, as little experimental data are available to validate the laws of distribution, accumulation, and migration of hydrocarbons. The mathematical model requires initial boundary values that are difficult to define. A geological basin evolves over millions of years or even hundreds of millions of years, with a very large areal extent and thickness. Sedimentary processes determine the reservoir boundaries.

Chapter 3 Origin of formation fluid pressure distributions

Publisher Summary Although, the study of formation pressures has a history of more than 50 years, not all aspects and phenomena are investigated thoroughly enough and taken into account while studying many oilfields. For example, pressure increase caused by vertical gas migration and liquid–gas redistribution may be a major factor during periods of intense gas generation and migration. Compaction of clays depends not only on the overburden or/and geodynamic loading but also on reduction in strength, and on temperature change. A better understanding of natural phenomena allows extending the scope of pressure prediction methods. It is useful to emphasize that almost all mechanisms that produce pressure deviation from the hydrostatic one were well known, some 50 and more years ago in physics, soil mechanics, geochemistry, etc. The purpose of this chapter is to summarize concisely, current understanding of pressure distribution origin, to indicate areas that have not been fully studied and that have, therefore, a potential for new practical development, and to outline a possible new approach to the solution of the abnormal and subnormal pressure problem.