Introduction

Diagenesis of buried organic materials within sedimentary rocks generates petroleum reservoirs. For improving estimation of reserves, predicting reservoir performance, increasing production and making decisions regarding the development of a petroleum reservoir, the reservoir should be characterized and studied. Petroleum reservoir study starts with reservoir characterization—i.e., gathering data (geological, geophysical, drilling and production) and building a geological model. The geological model (fine model) is upscaled and then initialized subject to initial conditions of the reservoir. The dynamic model is run by a reservoir simulator and the model results are then compared with observed (field) data. This chapter summarizes petroleum reservoir properties, volumetric calculations in a petroleum reservoir, reservoir heterogeneity and then introduces reservoir modeling and experimental design.

Keywords

Petroleum Reservoir; Reservoir Characterization; Reservoir Heterogeneity; Volumetric Calculation; Reservoir Modeling

1.1 Petroleum reservoirs

Most petroleum geologists believe that crude oil is a result of diagenesis (process of rock compaction that leads to change in physical and chemical properties of the rock) of buried organic materials and therefore is a vital characteristic of sedimentary rocks, not of volcanic rocks. Based on the views of petroleum geologists, the following five conditions generate petroleum traps [Selley, 1998]:

Theoretically, any sedimentary rock could be a hydrocarbon reservoir; however, in reality only sandstone (clastic sedimentary rocks composed mainly of quartz) and carbonate (rocks composed of calcite or dolomite) rocks are the main hydrocarbon resources in the world. There are also shale (a fine-grained rock composed of clay) oil and gas fields in some regions.

In contrast to sandstone reservoirs, carbonate reservoirs are sensitive to diagenesis processes and their reservoir qualities strongly depend on certain factors carried out during the diagenesis. Diagenesis processes in carbonate rocks cause fracturing, dolomitization, dissolution and cementation. Some of these processes, such as fracturing and dolomitization, improve reservoir qualities. In general, sandstone reservoirs have higher reservoir qualities in comparison to carbonate and shale reservoirs.

1.2 Petroleum rock properties

Different properties of reservoir rocks are characterized when a petroleum reservoir is studied. These properties are: mineralogy, grain size, porosity, permeability, acoustic properties, electrical properties, radioactive properties, magnetic properties, and mechanical properties.

Mineralogy and grain size: Quartz and calcite are the most common minerals in reservoir rocks. Trace minerals are often present as individual grains or as cement. Grain size and sorting can vary considerably; however, reservoir quality tends to decrease with decreased grain size. Accordingly, very finely grained rocks (such as shale) tend to have sealing properties.

Acoustic properties: Acoustic measurements include sonic and ultrasonic ranges. The primary and most routine use of acoustic measurement in reservoir engineering is porosity determination.

Electrical properties: Studies of electrical properties in rocks are mainly performed for determination of formation resistivity and water saturation.

Radioactive properties: Geological age of a formation and the volume of shale in the formation are estimated by measuring radioactivity in rocks. The gamma logs (a tool for measuring the natural radioactivity from potassium, thorium, and uranium isotopes in the earth) are used as a shaliness indicator in petroleum reservoir studies.

Magnetic properties: Nuclear magnetic resonance (NMR), a subcategory of electromagnetic logging, measures the induced magnetic moment of hydrogen nuclei contained within the fluid-filled pore space of porous media (reservoir rocks). NMR provides information about: the volume (porosity) and distribution (permeability) of the rock pores, rock composition, and type and quantity of fluid hydrocarbons.

Mechanical properties: Mechanical properties of rocks are important in formation evaluation, drilling, development planning and production. These properties are useful in borehole stability analysis, sand production prediction, hydraulic fracture design and optimization, compaction/subsidence studies, drill bit selection, casing point selection and casing design.

Porosity: Usually petroleum rock pores are filled with connate water and hydrocarbons. Porosity is the ratio of pore volume to bulk volume and is usually reported as percentage. Two porosity values are usually measured: total porosity and effective porosity. Total porosity is the fraction of rock bulk volume that is void, whether the individual pores are interconnected or not. Effective porosity is the ratio of connected void space to rock bulk volume. It is the effective porosity that reservoir engineers are interested in and, in almost all cases, the porosity measured in the laboratory is the effective porosity.

Uniformity of grain size, degree of cementation, amount of compaction during and after deposition, and methods of packing are the factors governing the magnitude of porosity [Tiab and Donaldson, 2004].

Porosities are measured in core laboratories, as well as by using the sonic-acoustic log, the formation density log, and the neutron porosity log [Tiab and Donaldson, 2004]:In the core laboratory bulk volume, pore volume, rock matrix volume, and irreducible water saturation are measured. By knowing these parameters, total porosity and effective porosity are calculated. Commonly, mercury injection and gas compression/expansion are used to determine total porosity and effective porosity, respectively.

In the sonic log, the time required for a sound wave to travel through one foot of formation is measured. This transiting time is then correlated to the porosity.

In the formation density log, the bulk density of the reservoir rock is measured. Using bulk density, matrix density and average density of fluids filling the formation, porosity is evaluated.

The neutron log is sensitive to the amount of hydrogen atoms in a formation. In the neutron log, a neutron source is employed to measure the ratio of the concentration of hydrogen atoms in the material, to that of pure water at 75°F. This ratio (called hydrogen index, HI) is directly related to porosity.

Permeability: The second main property of a reservoir rock, after porosity, is permeability. Porous medium is not sufficient for a reservoir rock—the pores must be connected to each other. Permeability is a measure of the rock’s capability to transport fluids. Primary work on permeability was done by Darcy in 1856. Darcy’s law is formulated as:

=k(P1−P2)μL (1.1a)

The unit of permeability (k) is the darcy, which is the permeability of a rock transporting a fluid of 1 cp viscosity (μ) with a velocity (U) of 1 cm per second and 1 atmosphere pressure drop (P1−P2) along a rock of 1 cm length (L). Permeability of most hydrocarbon reservoirs is much less than one darcy, so the unit of millidarcy (0.001 darcy, abbreviated “md”) is usually applied.

For laminar gas flow through porous media, Darcy’s law is shown as:

=k(P12−P22)/(2μ·L·Pave) (1.1b)

The permeability of a hydrocarbon reservoir is measured (or estimated) using one of the methods described in the following paragraphs.

The first method is by using well testing data. In a well test, by changing the flow rate of a well, variation in well bottom-hole pressure is recorded as a function of time. The flow rate of a well is changed by increasing or decreasing the rate. The pressure change is analyzed by plotting the recorded pressure and its derivative versus time. The two most common tests are the buildup and drawdown tests. In a buildup test the well is shut in after a period of production and then its pressure is measured. In a drawdown test the pressure is measured in a well that is open after a period of well shutting in.

The second method is measuring the permeability in a core laboratory. A known gas (air or nitrogen) is injected into a core (or a plug) at controlled velocity and then the pressure drop is measured. Using Darcy’s law (Eq. 1.1b), permeability is calculated and it is then extrapolated to the zero value of the reciprocal pressure (1/p) to estimate liquid (oil or water) permeability.

In the presence of more than one fluid, permeability is referred to as the effective permeability. In this case, the ratio of effective permeability of any phase to the absolute permeability of the rock is called the relative permeability (kr) of that phase....