For many analyses in Organic Geochemistry laboratories, it is essential to isolate pure organic material by eliminating the mineral matrix. Kerogenatron is an equipment which allows isolation of organic content from sedimentary rocks by destroying carbonates and silicates without altering the organic matter. Furthermore, it is designed to increase the protection of the operators which are not exposed any more to corrosive vapour released during the successive acid etching. We can help you at PGGRC in this field.
The isolated kerogen can be used for a variety of geochemical purposes, including:
- Physical and chemical studies like elemental analysis, I.R., U.V. and NMR spectroscopy; pyrolysis and pyro-chromatography.
- Kinetic studies to obtain activation energies distribution without mineral matrix effects (i.e. in the case of low TOC content).
- Optical studies under transmitted and reflected light such as vitrinite reflectance and palynofacies examinations.
For some analyses, it is essential to extract the organic material from the rocks (i.e. the solvent-extractable portion of the sedimentary organic matter or the bitumen). Bitumen can be extracted by chloroform or by a mixture of methanol and dichloromethane in a soxhlet extractor. We can help you at PGGRC in this field.
PGGRC provides various analytical procedures for evaluation of petroleum source rocks using equipment such as Rock-Eval 6, S2 Analyzer, and gas chromatography. Information obtained from these instruments can be used for:
- Lithological Description
- Assessing petroleum generation potential of organic-rich units
- Defining the level of thermal maturity for source rocks
- Determining the quality and quantity of organic matter in source rocks
- Inferring about paloe-depositional environments of organic-rich strata
Initially recognized by coal petrologists, the reflectivity of vitrinite macerals increases with increasing thermal maturity. This has become the principle maturity scale in the petroleum industry, where various reflectance levels have been correlated to the various stages of oil and gas generation and expulsion. Typically, the rock or isolated kerogen is mounted on an epoxy plug, polished, and then examined under reflected light using a microscope equipped with a photometer. The reflectance of individual vitrinite fragments are measured and analyzed statistically. In addition, the overall composition and color of associated kerogen macerals, spores, pollens, etc. can provide valuable insight into the oil or gas prone nature of the original, immature kerogen. Our services at PGGRC can help you reliably assess thermal maturity in your prospect via:
- Kerogen microscopy package (includes vitrinite reflectance, kerogen type, TAI and all preparation)
- Kerogen microscopy on coal and whole rock samples
- Coal Maceral analysis and point counting
- Reflectance mount preparation
- TAI slide preparation
One of the first uses of biomarkers by the petroleum industry was for oil-oil and oil-source rock correlations. Originally, correlations were made by simple comparisons of the distributions of certain groups of compounds (usually steranes or hopanes). Geological considerations should also be included when making correlations. When examining data for possible oil-oil or oil-source correlations, other factors that could affect the chemistry of oils (e.g., maturity and biodegradation) must also be taken into account. In some cases, the effects of migration can make oil-source rock correlations more difficult than oil-oil correlations. In the case of biodegraded samples, only biomarkers can normally be used to make correlations. An additional complication is the possibility that an oil may be a mixture of hydrocarbons from more than one source rock.
Petroleum geochemistry provides an effective tool for identifying vertical and lateral fluid flow barriers within oil and gas fields. The technique is especially useful because it provides an independent line of evidence for evaluating the reservoir continuity independent of other data types. At PGGRC, we assess reservoir continuity by integrating geochemical and geological data to determine the sealing capacity of potential flow barriers. This approach is based on the proposition that oils from discrete reservoirs usually differ from one another in composition. The technique assesses whether or not two oils are in fluid communication by comparing for each oil the relative abundances of the several hundred "inter-paraffin" peaks identifiable on a whole oil gas chromatogram. Inter-paraffin peaks are those compounds that elute from the GC between the normal-paraffins. Values for these ratios for each sample are plotted on polar or "star plots". Star plots constructed in this way maximize the apparent differences between samples. To arrive at an assessment of reservoir continuity, these data must be integrated with any other available and relevant geological and/or engineering information (such as fault distributions, fault throws, fault shale/sand gouge ratios, lateral changes in reservoir lithology, RFT or DST pressure data, pressure decline curves, oil-water contact depths, etc.).
Oils from separate reservoirs tend to differ from one another in composition. When oils from discrete zones are commingled, chemical differences between the oils can be used to assess the contribution of each zone or each field to the commingled production. At PGGRC, we allocate production from multiple zones (two or more zones) using compound ratios. There are many advantages to using oil geochemistry (instead of production logging) to allocate commingled production. Our laboratory uses geochemical methods to solve two types of production allocation problems: we can assess the relative contributions from multiple pay zones in a given well and we can study contributions of multiple fields to commingled pipeline production stream.
The individual components of an oil or gas can serve as "natural tracers" that track the origin of produced fluids (i.e., specific reservoir interval) and the movement of fluids within an oilfield. This ability to track the source and movement of fluids is the basis for numerous oil geochemistry (oil fingerprinting) tools that address a variety of production problems. Solid reservoir bitumen (also called pyrobitumen, migrabitumen, gilsonite, tar, etc.) occurs in carbonate and siliciclastic oil and gas reservoirs in many basins throughout the world. Reservoir bitumen is different than source rock bitumen in that it is formed from petroleum in the reservoir through natural or artificial alteration processes such as thermal cracking of oil (pyrobitumen), gas deasphalting of oil (asphaltene precipitation), or by inspissation, water washing, or oxidation (tar). At PGGRC we can provide essential analytical services for oil fingerprinting. Some of the most important applications in this field can include:
- Using Oil Geochemistry to Identify Completion Problems
- Using Oil Geochemistry to Prevent Sludge/Asphaltene Deposition
- Assessing the Impact of Solid Reservoir Bitumen on production rates
Microorganisms biodegrade different classes of compounds in petroleum at different rates. As a result, the progressive biodegradation of an oil spill can be monitored by periodic analyses of various compounds in the oil-contaminated soil. The early stages of oil biodegradation (loss of paraffins and isoprenoids) can be readily detectable by gas chromatographic (GC) analysis. However, in heavily degraded samples, GC analysis alone cannot distinguish subtle differences in biodegradation due to interference of the unresolved complex mixture (UCM or hump) that dominates the GC traces. Fortunately, in heavily degraded oils, one can use gas chromatography-mass spectrometry (GC-MS) to quantify the concentrations of biomarkers with differing resistances to biodegradation, allowing the extent of biodegradation to be monitored over time. In an oil, the quantity of a biomarker that is resistant to biodegradation increases as the oil is biodegraded, because such a compound is "concentrated" in the oil by the loss from the oil of the other less-resistant compounds. Therefore, by comparing the concentration of such a resistant compound in a spill with the concentration of the same compound in the original oil, one can estimate how much of the oil has been degraded.
Natural gas can have two primary origins in sediments: methane produced by methanogenic bacteria (biogenic gas) and hydrocarbon gas produced by thermal alteration of sedimentary organic matter (thermogenic gas). Unlike thermogenic gas, biogenic gas is always very dry and does not contain significant ethane, propane or higher-molecular-weight homologues (i.e., wet gases). In addition, biogenic methane contains isotopically lighter carbon (i.e., is more depleted in 13C) compared to thermogenic methane. Geochemical analyses conducted at PGGRC can readily reveal if a gas seep represents thermogenic or biogenic gas and thereby help reduce exploration risks in poorly explored regions.
Origin of an oil spills can be constrained or pinpointed by sophisticated chemical analyses that distinguish between various oils. In this context, PGGRC offers reliable solutions to determine the origin of oil spills. Our analytical services include:
- Whole oil gas chromatography: Oils in the immediate area of the spill can be used to identify the origin of the spill. This approach requires collection and analysis of all nearby potential source oils for the spill. When a positive correlation of spilled oil and facility oil occurs, then the origin of the spill has been determined. If the spilled oil has undergone weathering, water washing, and/or biodegradation, then biomarker analysis and/or other techniques may be required to identify the spill source.
- Biomarkers: Since different potential sources of a spill may involve oils derived from different basins, biomarker distributions can be used to either rule out or rule in potential sources of a spill. More specifically, these compounds can be used to determine if oil in a contaminated area actually represents more than one spill.
- Polycyclic aromatic hydrocarbons (PAH): These are another group of compounds present in oil that are especially useful in identifying the source(s) of a spill. PAHs are resistant to biodegradation typically encountered in spill situations. They provide a useful tool for correlating a biodegraded oil to an it's non-degraded equivalent, and hence can be use to identify the source(s) of a petroleum release.
- Stable carbon isotope measurements: Different oils commonly have different carbon isotopic compositions. Therefore, carbon isotopic analyses of petroleum samples from a contaminated area can be used to constrain the source(s) of the contaminant in a contaminated area.