Gas Chromatography Fingerprinting Research Articles

FTIR and SUVF spectroscopy applied to reservoir compartmentalization: a comparative study with gas chromatography fingerprints results

The purpose of this study was to evaluate reservoir continuities and geochemical evolution of oils from individual reservoirs by using gas chromatography (GC) fingerprints method and to compare the results with those obtained from Fourier transform infra red (FTIR) and synchronous ultra violet fluorescence (SUVF) spectroscopy techniques. Six crude oils which belong to different levels of exploitation were selected from Alam El Bueib (AEB) oil field (Western Desert, Egypt). The samples studied belong to three different reservoir units in different wells. The results show that the all-independent techniques provide results in good agreement and that the oils characteristics and their evolution in the reservoir can be described similarly by fingerprints GC, FTIR and SUVF spectroscopy. The FTIR and SUVF spectroscopy techniques therefore constitute a rapid and non-expensive alternative for reservoir organic geochemistry studies.

Improved identification of pay zones through integration of geochemical and log data: A case study from Upper Assam basin, India

The upper Paleocene-lower Eocene clastic reservoirs constitute one of the most important hydrocarbon-producing horizons in the Upper Assam basin of northeast India. These reservoirs are characterized by the presence of (1) normal gravity oil (23-31° API), (2) low to intermediate gravity oil (13-23° API), and (3) gas and light oil/condensate (> 31° API). The sandstone reservoirs show complex wire-line log signatures, which are commonly misleading. The main impediments to understanding the nature of reservoir fluid include (1) distinguishing low gravity, intermediate gravity, and normal gravity oil-bearing zones and (2) resolving the problem of density (RHOB)-neutron porosity (NPHI) crossover for gas-bearing, as well as oil-bearing, reservoirs. Geochemical analyses of sidewall core extracts by thin layer chromatography with flame ionization detection (TLC-FID) and gas chromatography (GC) provide valuable, cost-effective input for reservoir fluid characterization. The important parameters needed to identify the nature and composition of the reservoir fluid include (1) the bulk composition of the sidewall core extract (i.e., % saturated hydrocarbons, % aromatic hydrocarbons, and % resins + asphaltenes), (2) amount of extract in mg/g of rock, (3) GC fingerprint, and (4) the ratio of pristane to n-C17. These parameters, integrated with geological and geophysical (wire-line logs) evidence, yield more accurate and reliable formation evaluation criteria. The technique is simple and inexpensive and may find application as an additional formation evaluation tool in any geological setting.

Comparison of Monterey formation kerogens from the Salinas Basin and Santa Barbara area, California

Unweathered Monterey kerogens from surface samples and wells in the Santa Barbara area and the Salinas Basin (approximately 125 miles apart), are oil-prone good to excellent potential oil source rocks deposited under marine anoxic to suboxic conditions. The kerogens in the surface samples are somewhat similar when viewed through the microscope and the differences result from the depositional conditions (anoxic vs suboxic) and the original organic matter that formed the amorphinite (alginite vs exinite). The bitumens extracted from these samples have similar carbon isotope values and gas chromatography fingerprints. In the Santa Barbara area, mudstones from the lower calcareous facies of the Monterey Formation contain greater than 90% fluorescent marine, Amorphinite II kerogen, that is oil prone (Type II and mixed Type II and III) based on Rock-Eval and TOC analysis. In the Salinas Basin, kerogens from the calcerous Sandholdt Member of the Monterey Formation (equivalent to the lower calcareous facies) also contain greater than 90% amorphous, highly oil-prone Amorphinite II. The upper siliceous Monterey Formation in the Santa Barbara area also contains large amounts of oil-prone, Amorphinite II and is compared to the weathered siliceous Hames Member in the Salinas Basin that contains a large amount of Alginite. The kerogens in the lower calcerous facies in both areas are thermally immature but contain solid bitumen and/or oil droplets in the residues at low levels of vitrinite reflectance and TAI (mean R o values from 0.3 to 0.4% and TAI values from 2.2 to 2.5).

Volatile “Fingerprint” Profile of Raw Peanuts as an Indicator of Quality

Abstract The 1980 peanut crop suffered severe losses because of the drought in the United States, and in many cases, the peanuts that were harvested had off-flavors. Peanuts were imported from several foreign countries to offset crop losses. Many raw samples, both imported and US-grown, were examined by direct gas chromatography fingerprint method and by sensory techniques for flavor quality. The volatile profiles obtained were used as an indicator of quality. Based on the volatile profiles from numerous raw peanut samples examined, indicators of suspect peanuts were found that could provide a means of dividing the peanuts into several different groups, e.g. peanuts that had possibly undergone fermentation, oxidation, or external contamination. The volatile profiles of each of these groups and several high grade controls were correlated to peanut quality. In general, as the volatile profile increased, the quality decreased.

Pyrolysis-Gas Chromatography as an Exploration Tool for Geochemical Evaluation of Source-Rock Potential: ABSTRACT

A pyrolysis system was developed to identify the possible production type (oil, condensate, and gas) and the presence of contamination (by migrated oil or drilling additives) in rock samples. This is accomplished by incorporating gas chromatography (GC) in the pyrolysis system so that a direct analysis can be made of the hydrocarbons in the pyrolysis products from sediments samples. This analytical capability of making a positive identification of pyrolysis products is one of the important advantages of this system. Because of this additional feature, this pyrolysis system can overcome problems related to the interpretation of indirect production type indicators such as the oxygen and hydrogen indices used by the commercially available ROCK-EVAL system. The productive type is recognized either qualitatively by GC fingerprint traces or quantitatively by hydrocarbon composition (C1-C4, C5-C14, and C15+) from the kerogen (Peak II) pyrolysate. Oil-prone sediments are recognized by GC traces with a full spectrum of C1 to C28 hydrocarbons, or by high amounts of C15+ hydrocarbons. In contrast, gas-prone sediments are characterized by the predominance of light hydrocarbons from C1 to C7 in the GC trace, or by low amounts of C5-C14 and C15+ hydrocarbons. Condensate or mixed type production is intermediate in character between the two. Migrated oil or liquid contaminants are detected by a stepwise heating of the rock samples and GC analysis or Peak I (solvent extractables) and Peak II (kerogen decomposition) products. The application of this pyrolysis system over the past four years as a rapid method for evaluation of organic richness, maturation, and production type using well or outcrop samples along with the limitations of the techniques will also be discussed. End_of_Article - Last_Page 582------------