Reservoir Exploitation and Management
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