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

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.).

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.

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

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

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.

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.

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.