Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. Neutrons interact with hydrogen nuclei resulting in an energy loss that is converted to neutron porosity. All hydrocarbons and water contain hydrogen, but the formation usually does not. The amount of hydrogen in the gas affects the reading, so gas filled porosity shows a lower log porosity than oil or water filled porosity.
Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. A map created by post-processing conditional simulations. A threshold value is selected (e.g., 8% porosity), and the uncertainty map shows at each grid node the probability that porosity is either above or below the chosen threshold.
In the porous matrix type (the more common), most of the hydrocarbons are stored in the matrix porosity, and the fractures serve as the principal flow conduits. Such reservoirs typically are identified as "dual-porosity" systems. Some cherts exhibit dual porosity and have significant storage capacity in the matrix, but that contributes little to reserves. Such reservoirs frequently are associated with basement rocks. Examples include: When they occur in carbonates, fractures tend to facilitate extensive leaching and diagenesis, which may lead to the development of vugular, sometimes karstic, porosity. Fractured reservoirs pose formidable difficulties for estimating reserves.
Logs provide the most economical and complete source of data for evaluating layered, complex, low porosity, tight gas reservoirs. All openhole logging data should be preprocessed before the data are used in any detailed computations. The series of articles by Hunt et al. clearly describes the steps required to: To correctly compute porosity in tight, shaly (clay-rich) reservoirs, one of the first values to compute is the volume of clay in the rock. The clay volume is normally computed using either the self-potential (SP) or the GR log readings. The following equations are commonly used to compute the clay volume in a formation.
Tight gas is the term commonly used to refer to low permeability reservoirs that produce mainly dry natural gas. Many of the low permeability reservoirs that have been developed in the past are sandstone, but significant quantities of gas are also produced from low permeability carbonates, shales, and coal seams. Production of gas from coal seams is covered in a separate chapter in this handbook. In this chapter, production of gas from tight sandstones is the predominant theme. However, much of the same technology applies to tight carbonate and to gas shale reservoirs. Tight gas reservoirs have one thing in common--a vertical well drilled and completed in the tight gas reservoir must be successfully stimulated to produce at commercial gas flow rates and produce commercial gas volumes. Normally, a large hydraulic fracture treatment is required to produce gas economically.
Obtaining and analyzing cores is crucial to the proper understanding of any layered, complex reservoir system. To obtain the data needed to understand the fluid flow properties, the mechanical properties and the depositional environment of a specific reservoir requires that cores be cut, handled correctly, and tested in the laboratory using modern and sophisticated laboratory methods. Of primary importance is measuring the rock properties under restored reservoir conditions. The effect of net overburden pressure (NOB) must be reproduced in the laboratory to obtain the most accurate quantitative information from the cores. To provide all the data needed to characterize the reservoir and depositional system, a core should be cut in the pay interval and in the layers of rock above and below the pay interval.
The identification of a bed's lithology is fundamental to all reservoir characterization because the physical and chemical properties of the rock that holds hydrocarbons and/or water affect the response of every tool used to measure formation properties. Understanding reservoir lithology is the foundation from which all other petrophysical calculations are made. To make accurate petrophysical calculations of porosity, water saturation (Sw), and permeability, the various lithologies of the reservoir interval must be identified and their implications understood. Lithology means "the composition or type of rock such as sandstone or limestone." Lithology focuses on grains, while rock type focuses on pores. The list of rock types contains more than 250 classifications.
One role of the petrophysicist is to characterize the fluids encountered in the reservoir. Detection of a change in fluid type in the rocks while drilling is usually straightforward with the use of gas and chromatographic measurements. Gas shows and oil shows while drilling are time-honored indicators of zones that need further investigation through logs, testers, and cores. In the rare case of gas-bearing, high-permeability rock drilled with high overbalance, gas will be flushed from the rock ahead of the bit, will not be circulated to the surface in the mud, and will not produce a gas show. Because hydrocarbons are not always part of a water-based-mud formulation, sophisticated analytical chemical techniques can be used on the oil and gas samples circulated to the surface and captured to determine the properties of hydrocarbons in a given zone penetrated by the drill bit.
Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. A difference in porosities caused by the compressibility of gas in porosities estimated by the formation density log and the neutron density log.