Reservoir rock assessment

Although test oils can provide information on compositional changes within a reservoir, high frequency sampling of rock is the usual mode of investigation. The best rock samples are from core (chips or plugs), although swc is also useful, because of well-constrained depth. Cuttings can also be used, although depth control may be severely restricted. If studies of gas intervals are required, molecular and C isotopic distributions can be determined from test, mud or headspace gas samples.

Contamination can be a major factor, depending upon the composition of drilling muds and coring lubricants used. Organic contaminants cannot be removed by extraction (thermal or solvent) without adversely affecting migrated hydrocarbons. Where core plugs have been taken for poroperm or other analyses, the immediately adjacent core may be infiltrated with lubricant and is best avoided for organic analysis. If core plugs are to be taken, water lubricant is desirable for organic analyses, but not for inorganic analyses of formation water (ionic composition or RSA).

For organic analyses, general guidelines for sample sizes should be followed. For residual salt analysis (RSA) 2–3 cm³ of the central part of pristine consolidated core section is required. Formation water samples for inorganic analyses should be at least 1 mL.

Because compositional variations can be subtle, all samples in a study should be analysed on the same instrument and ideally in the same batch, or within a short period, to minimise the influence of analytical variation. This is particularly important for the detailed analyses below, which rely on subtle compositional changes. Results should be compared with other data, such as PVT, dew point and owc depths.

Basic screening for the presence of hydrocarbons can involve:

• fluorescence scanning
• Rock-Eval pyrolysis (traditional or reservoir mode)
• solvent extraction (or centrifugation) & Iatroscan analysis

These analyses provide indications of the presence of migrated hydrocarbons. Correlation of results with wireline logs is recommended, and indications of segregation and other contacts can be confirmed by the more detailed analyses listed below.

The fluorescence scanning provides means of rapid, non-destructive qualitative and quantitative logging of petroleum shows in conventionally slabbed drill cores or even cuttings. The combination of fluorescence intensity and wavelength can distinguish between broad types of hydrocarbons and estimate saturation levels, as well as identify various contacts (GOC, OWC and potential barriers). Similar, also necessarily less precise, evaluation of cuttings can be undertaken using a hand-held scanner, operating on the same principles.

Traditional Rock-Eval screening can identify the presence of migrated liquid hydrocarbons (oil and condensate) by way of the S1 measurement. In reservoir mode more detailed compositional information is obtained upon both the vaporisable material (equivalent to S1) and the pyrolysable material (aiding identification of tar mats), and possible pyrobitumen can also be determined.

Solvent extraction yields provide an indication of oil saturation of reservoir samples, but SARA data from Iatroscan give more information on the presence of oil from total hydrocarbon content and sat:aro ratio, and on tar mat presence from the proportion of resins.

Although not offered by APT, a technique termed Fluid Inclusion Stratigraphy (FIS) is available from FIT, which provides a relatively rapid screening of cuttings, core or outcrop for the presence of hydrocarbons. It purports to clean up the outside of cuttings so that, upon decrepitation, only the content of fluid inclusions is analysed, and the resulting broad compositional characteristics can be used to assess the relationship of the a particular depth interval to petroleum movement and accumulation.

Some indication of where barriers might exist may be apparent from the above screening techniques, such as indications of tar mats from SARA analysis, but other methods provide definitive evidence:

• residual salt analysis (RSA, from Sr stable isotopes)
• formation water dD and d¹⁸O values
• alkylbenzenes (oils)
• whole-oil/extract GC
• biomarker distributions (oils) – compartmentalisation and production allocation
• C₁–C₅ distributions and d¹³C values (gas)
• fluid inclusions – primarily filing history
• relative secondary migration distance (oils)

SrRSA provides a particular sensitive measure of compositional variation in formation water by means of the strontium stable isotope ratio, ⁸⁷Sr/⁸⁶Sr, in isolated water samples, or salts precipitated in cores during storage. Further evidence of communication between compartments or different reservoirs may be obtained from formation water dD and d18O values, together with information on diagenetic alteration of reservoir rocks involving mineral-water exchange.

The C₂ and C₃ alkylbenzenes in extracted bitumen are particularly useful for investigating reservoir continuity because they are very sensitive to alteration processes.

GC of oils/extracts can provide general information upon the type of hydrocarbons present and differences in the relative distributions of the major components. More detailed investigation of variations in minor compounds that elute between the n-alkanes, even when their identity is unknown, can provide a means to evaluate reservoir segregation. GC-MS analysis of biomarker distributions in the bitumen can allow detection of more subtle differences, so can also be used to investigate homogeneity of oil within a reservoir, as well as providing information about sources of organic matter, depositional environment, maturity and alteration processes.

For gas filled intervals, standard analyses of molecular and isotopic compositional variation can provide useful information on reservoir continuity.

Fluid inclusions can provide information on reservoir segregation, based on textural relationships between hydrocarbon filled inclusions of different compositions (determined by fluorescence spectrometry) and diagenetic processes. However, the main purpose of detailed optical analysis of inclusions is usually to investigate filling history, through determination of homogenisation temperatures. It is an expensive and time-consuming process, but potentially offers extremely valuable information. Detailed chemical analysis of oil in isolated inclusions is possible, but is not currently offered by APT.

It has been suggested that relative secondary migration distances may be compared using the rates at which related molecules may move – depending upon factors such as size, shape and polarity – resulting in concentration of the more readily migrating molecules. Although such indicators do sometimes appear to work, they do not always do so, probably as a result of saturation of the migration pathway over time and multiple charges of varying composition. Benzocarbazoles are one such class of compound that can be used.

Processes involved in diagenesis within a reservoir are generally reflected in the ionic composition of formation waters. APT offers routine concentration determination of 12 major ions.

Information is also obtained from optical fluid inclusion studies.

APT can also offer determination of dD and dO in water, which can yield information on reservoir chemistry, including changes during production.

Monitoring the relative contributions of individual streams to production flow, to enable allocation of production from different wells within the same reservoir unit, or from wells completed in different reservoir zones, is an important engineering consideration. Changes over time that may lead to undesirable problems (e.g. deasphalting or wax deposition), which need to be spotted in time to take avoiding action.

Chemical analyses potentially provide a means of achieving this without the requirement for expensive downhole meters.

APT have developed APT Allomon to assist you with your production allocation and monitoring needs.

Anomalous similarities or differences in composition, leading to incorrect conclusions about reservoir segregation, can result from:

• unusual filling history – e.g. earlier communication between compartments
• very young reservoirs – not yet homogeneous
• gravitationally segregated oil columns – measurements progressively change with depth
• actively biodegrading reservoirs – extent greatest near owc
• very tight reservoir – effectively not continuously connected, so heterogeneous
• drilling mud components can affect aqueous trace element compositions – this adversely affects interpretation of reservoir diagenesis

Production allocation can be problematic if there are many streams and end-member compositions are not available.