Rocks properties

In the future, it is expected to be possible to make more routine use of additional wave types, specifically shear or S waves (polarised to horizontal and vertical components) which have a transverse mode of propagation, and are sensitive to a different set of rock properties than P waves. The potential then exists for increasing the number of independent attributes measured in reflection surveys and increasing the resolution of the subsurface image. 

Keywords d rec methods, indirect methods, rock properties, coring, core barrel, standard core analysis, special core analysis, slabbed core, sidewall samples, direct indications, microfossils, sonde, logging unit, invasion, mudcake, formation pressure measurement, fluid sampling, measurement while drilling, formation evaluation while drilling. 

The timely acquisition of static and dynamic reservoir data is critical for the optimisation of development options and production operations. Reservoir data enables the description and quantification of fluid and rock properties. The amount and accuracy of the data available will determine the range of uncertainty associated with estimates made by the subsurface engineer. 

To gain an understanding of the composition of the reservoir rock, inter-reservoir seals and the reservoir pore system it is desirable to obtain an undisturbed and continuous reservoir core sample. Cores are also used to establish physical rock properties by direct measurements in a laboratory. They allow description of the depositional environment, sedimentary features and the diagenetic history of the sequence. 

Permeability (k) is a rock property, while viscosity (fi) is a fluid property. A typical oil viscosity is 0.5 cP, while a typical gas viscosity is 0.01 cP, water being around 0.3 cP. For a given reservoir, gas is therefore around two orders of magnitude more mobile than oil or water. In a gas reservoir underlain by an aquifer, the gas is highly mobile compared to the water and flows readily to the producers, provided that the permeability in the reservoir is continuous. For this reason, production of gas with zero water cut is common, at least in the early stages of development when the perforations are distant from the gas-water contact. 

For a single fluid flowing through a section of reservoir rock, Darcy showed that the superficial velocity of the fluid (u) is proportional to the pressure drop applied (the hydrodynamic pressure gradient), and inversely proportional to the viscosity of the fluid. The constant of proportionality is called the absolute permeability which is a rock property, and is dependent upon the pore size distribution. The superficial velocity is the average flowrate... 

Reservoir simulation is a technique in which a computer-based mathematical representation of the reservoir is constructed and then used to predict its dynamic behaviour. The reservoir is gridded up into a number of grid blocks. The reservoir rock properties (porosity, saturation, and permeability), and the fluid properties (viscosity and the PVT properties) are specified for each grid block. 

Migration 244. Accumulation 245. Structural Geology 246. Traps 251. Basic Engineering Rock Properties 254, Basic Etigineering Soil Properties 266. 

C.-C. Huang 1997, (Estimation of rock properties by NMR relaxation methods), MS Thesis, Rice University, 108-113. 

Swolf, H.S., Chemical effects of pore fluids on rock properties, in Symposium on Underground Waste Management and Environmental Implications, Houston, TX, Cook, T.D., Ed., American Association of Petroleum Geologists 18, 1972, pp. 224-234. 

Advances in knowledge and models of fluid flows in UGS have increased simultaneously. As a result of the increasing performance and falling costs of computer systems, calculations have been able to progress in terms of their accuracy, rapidity and cost. Fluid flow simulations give a clearer picture of how gas is distributed in the reservoir at any moment and any place, provided rock properties are known. In this way they allow the assessment of the working volume, the peak withdrawal rate, the number and location of new wells required and finally the minimum gas cushion to be injected to guarantee performances [5],... 

Rock properties should be examined at as many outcrops as possible, looking for friability, cementing, degree and nature of fractures and dissolution conduits, and animal burrowing (Figs. 2.3, 2.4, 2.8, and 3.2). However, one should bear in mind that rocks at exposures are altered by weathering and joint formation due to stress release and thus may poorly represent the rocks at depth. Similar observations may be conducted on drill cores, but these are expensive and their record is limited in size. Laboratory tests on cores provide semiquantitative data on the nature of rock pores and fissures and conductivities. 

Exercise 3.3 List rock properties that should be noticed and described in the field work, relevant to hydrological and hydrochemical studies. 

Although there has been considerable effort to calculate the mobility of foam in porous media from first principles, utilizing usually measured rock properties ( 6), a different approach is used here. In this research, major emphasis has been on measurement of the mobility of C02 foam in rock core samples. The... 

Diffusional transfers of potassium and silicon between sandstones and shales may be sufficient to accomplish feldspar dissolution, illitization, and quartz cementation (Thyne, 2001 Thyne et al, 2001). Losses of the magnitude observed for detrital carbonates in shales exceed the capacity of diffusion-mediated transfer. Large-scale advection seems required, although our understanding of shale permeabilities seems to preclude this (Bjprlykke, 1989, 1993 and Lynch, 1997). The possibility of convection driven by salinity heterogeneity within thick shale sequences has been demonstrated by Sharp et al (2001), who note that more information for rock properties and fluid compositions within deep basinal shales is needed before the generality of their results can be assessed. 

The data described above can be used to predict the location of better source rocks in vertically drained basins, especially in deltaic-type environments with relatively young source rocks. With long-distance vertical migration, some of the biomarker parameters may become skewed. A number of factors must first be considered before applying this approach first, some of the parameters vary with maturity second, C30 steranes are not present in lacustrine samples and so the approach will not work in that situation and finally, it will not work where the oils were deposited prior to land plant evolution, since no vitrinite was present at that time. Oils from mixed source rocks also complicate the issue. The ability to predict source rock properties on the basis of biomarker distributions in cmde oils is a very interesting concept, since most exploration efforts try to discover oil and not source rocks. 

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