Formation evaluation, for this discussion, is the process of:
Many data are interpreted to evaluate a petroleum-bearing formation, and we discuss the interpretations of data acquired through surface data logging in terms of the rock formation and fluid properties they help determine.
Contents
Fluid type
The logging engineer or geologist gets information about the formation fluids directly from fluids that are released into the wellbore while drilling and circulating out suspended immiscibly in the drill fluid or remaining in the pores of larger cuttings that may not have been flushed. They receive information indirectly from remnants of the fluid that remain in pores of rock cuttings, as stains on the grain surface, or in solution in the drilling fluid.
Oil may be identified as a sheen on the surface of water-based drilling fluid. If the circulating fluid density is sufficiently low as to render an underbalanced drilling condition, oil may be produced in large enough quantities that a sample may be skimmed off a whole mud sample. Similarly, the underbalanced penetration of a gas-bearing formation yielding only a small quantity of free gas in the mud system at the bit will expand according to the real gas law as it is circulated to the surface, where it may be detected and possibly sampled (although, in an uncontrolled situation, this results in hazardous safety and environmental conditions). These are all fairly obvious, direct indicators.
The ratio of various mud-gas components (e.g., the molar or volumetric ratio of methane to ethane) may be crossplotted or correlated with fluid type. The modified Pixler method, for example, plots ratios of methane (C1) to, respectively, ethane (C2), propane (C3), butanes and heavier (C4+), and pentanes and heavier (C5+):
....................(1)
....................(2)
....................(3)
and 
....................(4)
....................(4)
Through a correlated analysis, ranges of these ratio values had been determined that were representative of productive and nonproductive gas and oil (see Fig. 1).
The Haworth et al. "wetness" method defines several correlatable ratios: wetness, Wh; balance, Bh; and character, Ch.
*100....................(5)
....................(6)
....................(7)
The values of these ratios determine, through the interpretation shown in Fig. 2, whether the hydrocarbon is gas or oil, very dry gas, and, with enough data, whether the oil is tending towards being a light oil, heavy oil, or residual oil.
These ratio methods tend to work robustly only within the basins in which they are calibrated, the number and quality of data from the basin within which they are calibrated, and the errors inherent in obtaining the calibration set as well as the unknown data set. Examples of these inherent errors include the unknown or varying extraction efficiency at the gas trap and the accuracy of the gas-measurement system. Normalization techniques, either against an internal standard or other parameters, can improve the consistency and robustness of the ratios.
Fluid properties
If determining fluid type is difficult because of errors and unknowns in measuring the composition of formation hydrocarbons entrained in the drilling fluid, even more difficulty can be anticipated in estimating the fluid properties, such as viscosity or API gravity. The more robust methods involve either quantitatively measuring the methane-through-pentane composition of the drilling fluid returns and correlating these with the HC fluid properties or involve spectroscopy techniques to get particular spectra and correlating these to oil properties or type.
The QGM™ process involves the use of a gas-trap extractor that was characterized and field tested extensively. This trap, when used in a controlled fashion, can give a quantitative measurement of gas-trap extraction efficiency when calibrated with a measurement of thermally extracted mud-gas composition. With proper control and calibration, this process gives highly accurate gas-in-mud compositions. With these, correlations have been developed that relate composition parameters to oil properties.
An enhanced quantitative UV-fluorescence technique monitors the intensity of two emission wavelengths resulting from exciting an oil sample with UV radiation. The ratio of the intensities varies according to the oil composition or, more exactly, according to the concentrations of certain aromatic compounds in the oil sample.
Formation porosity
Formation porosity is estimated by visually inspecting rock cuttings, which requires a sufficient description and classification of the rocks. Several references supply discussion. The requirement of rock fragments with intact pore systems eliminates the use of this method when drilling poorly consolidated or unconsolidated sands and when bit types, such as the PDC, reduce most of the potential reservoir cuttings to grain-sized fragments.
The method described by Boone calculates the rock porosity that would be required to liberate the specific amount of gas measured when a set volume of formation is drilled. This assumes low fluid spurt loss while drilling (near-zero flushing of the rock ahead of the bit), which is frequently violated except in near-balance drilling and low-permeability formations.
Formation permeability
The formation permeability may be estimated visually by the logger from the grain size and sorting. At best, this may give order of magnitude estimates, but, frequently, the smaller, clay-sized particles, which may control the permeability if present in appreciable amounts, cannot be quantified with any confidence. Another limitation occurs because the cutting sample is acquired over a relatively large depth interval, and "smearing" of the data occurs in zones where grain size, sorting, and clay content vary significantly.
Pore pressure
Pore-pressure variations, particularly transitions from normal to geopressures, trend with several measurable parameters. These parameters are discussed more in the Drilling section.
Geological or petrophysical information
The correlation of geologic strata relies on determining certain characteristic properties or constituents of a particular geologic formation. Geologists use these properties in one of several techniques to correlate formations from well to well within a field as well as in broader, basin-wide studies. Particular formations may serve as "markers" by having one or a set of distinguishing characteristics. Mud-logging services provide rock-cutting samples for the determination of these characteristics and, in some cases, may acquire the data on site. The acquisition of cuttings samples for these tests may impact the cuttings sampling or preparation techniques and should be considered when specifying a mud-logging service.
Microscopic fossils identified and correlated by paleontologists yield "biomarkers," which become the working data for biostratigraphy. These biomarkers frequently appear in the cuttings in very low quantities because of the grinding and abrasion the cuttings see under the action of the drill bit and transport uphole in the returning mud stream. Their preparation calls for consistently applied cleaning with the use of a screen or sieve with openings small enough to retain the microfossils.
Specific mineral assemblages may be present in a particular geologic formation with compositions nearly constant or in relative abundances that are nearly constant over an extensive areal. The use of such mineral compositions as stratigraphically correlatable parameters is called chemostratigraphy. The ratio of concentrations of these certain minerals, as well as of other compounds associated with the deposition and diagenisis of the particular formation, must then be determined relatively quickly and cheaply. It has been shown that the ratios Ca/Al, Na/Al, and K/Al are related to clay mineral concentration ratios, and that relative amounts of such elements as Ti, Cr, and Zr are frequently associated with the clay minerals. Chemostratigraphers determine the amounts of these elements using laboratory or rig-based instruments such as inductively coupled plasma spectrometry and laser-induced breakdown spectroscopy.
Pore fluids present during diagentic processes become crystallographically trapped in small volumes called fluid inclusions. These tiny drops of fluids, sealed in cavities typically 2 to 20 μm in size, are thought to be representative of the pore fluid composition that existed at the time of their formation. After appropriately cleaning portions of the drill cuttings, geologists chose grain samples containing fluid inclusions for analysis, which includes heating to volatize the fluids and rupture the inclusion walls. Liberated vapor passes to an MS, which measures fluid composition for hydrocarbons, and other geochemical species such as:
Occasionally, a crude-oil fluid inclusion volume may be large enough to characterize the crude sufficiently to assess physical properties and the degree of biodegradation and thermal alteration. Fluid inclusion stratigraphy, which uses included-fluid composition as the correlating parameter, has been proposed to assess the location of fluid contacts, identify migration pathways, characterize compartmentalization, and determine distance to pay zones.
Nomenclature
| Bh | = | balance ratio |
| C1 | = | methane |
| C2 | = | ethane |
| C3 | = | propane |
| C4+ | = | butanes and heavier |
| C5+ | = | pentanes and heavier |
| Ch | = | character ratio |
| Wh | = | wetness ratio |
No comments:
Post a Comment