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Fractured reservoirs have been observed in most producing areas of the world, in all of the following:

  • Igneous/metamorphic rocks
  • Sandstones
  • Carbonates
  • Shales
  • Cherts

Definition of fractured reservoirs

The two broad categories of fractured reservoirs are[1]:

  • Those with a porous matrix
  • Those with a nonporous matrix

Porous matrix

In the porous matrix type (the more common), most of the hydrocarbons are stored in the matrix porosity, and the fractures serve as the principal flow conduits. Such reservoirs typically are identified as “dual-porosity” systems. Examples include:

  • Many of the Iranian fields
  • Ekofisk (North Sea)
  • Palm Valley (Australia)
  • Spraberry (Texas, US)

Nonporous matrix

Some cherts exhibit dual porosity and have significant storage capacity in the matrix, but that contributes little to reserves. Fractured reservoirs with a nonporous matrix occur in:

  • Fractured igneous and/or metamorphic rocks
  • Fractured shales
  • Fractured cherts

Such reservoirs frequently are associated with basement rocks.[2] Examples include:

  • Bach Ho field (offshore Vietnam)
  • Augila field (Libya)
  • Edison field (California, US)
  • Big Sandy gas field (Kentucky, US)
  • Santa Maria basin fields (California, US)

When they occur in carbonates, fractures tend to facilitate extensive leaching and diagenesis, which may lead to the development of vugular, sometimes karstic, porosity. Examples include:

  • Albion Scipio trend (Michigan, US)
  • Rospo Mare field (offshore Italy)

Considerations for reserves estimation

Fractured reservoirs pose formidable difficulties for estimating reserves. These difficulties are attributable to the heterogeneity of the reservoir formation, which causes substantial uncertainties in estimates of oil-/gas-in-place (O/GIP) and in reserves estimates (REs). Because of uncertainties in determining the flow characteristics of dual-porosity systems, estimates of reserves using volumetric methods are subject to substantial uncertainty. When feasible, compare such estimates with observed recovery in analogous reservoirs.

In general, the following scenarios cause problems:

  • Boreholes frequently are severely washed out, making log interpretation difficult or impossible.
  • Core recovery frequently is fragmental, at best.
  • Even in good-quality boreholes, detection of fractures and measurement of fracture porosity using logging devices is highly empirical, although significant improvements have been made using formation imaging tools.
  • In accumulations with a severe loss of circulation, operators typically stop drilling at the top of the reservoir section, a practice that, while necessary for safe operations, precludes characterization of the objective section.
  • Well performance frequently is strongly influenced by proximity to major fractures, which can extend surprising distances. Because of this, be extremely cautious in assigning reserves to undrilled tracts that offset tracts at a mature stage of production.
  • Although transient pressure analysis provides useful data, applying modern interpretation techniques mandates using highly accurate quartz pressure transducers.
  • The accuracy of type curve matching depends on the accuracy of the mathematical model used for the type curves. An invalid model cannot yield a valid interpretation. Even if the model is valid, analysis of results might not provide unique answers.
  • In pressure-depletion reservoirs, the rate/time performance of wells typically is hyperbolic. The behavior of an average well might be used to estimate reserves, but one should expect wide variation in performance between wells.
  • In reservoirs producing by pressure depletion, the early performance of wells typically is characterized by relatively rapid decline in the production rate, which usually is caused by transient pressure behavior. Reserves cannot be estimated with any degree of confidence using decline trend analysis until wells have passed through the transient pressure period and settled into semisteady-state conditions.

Aguilera[3] provides guidelines for estimating RE in fractured reservoirs, classifying fractured reservoirs by pore type and “storage ratio”—the relative amount of storage in matrix vs. fractures. Table 1 is adapted from Aguilera’s Tables 2 and 3.

Aguilera does not state so, but “oil” presumably means light oil—stock-tank gravities greater than approximately 25°American Petroleum Institute (API). Also, Aguilera does not mention the influence of well spacing on RE, which could be a major factor, depending on the nature of the fracture system.

References

  1. Reiss, L.H. 1980. The Reservoir Engineering Aspects of Fractured Formations. Paris, France: Editions Technip.
  2. P’an, C.H. 1982. Petroleum in Basement Rocks. AAPG Bull. 66 (10): 1597-1643. http://aapgbull.geoscienceworld.org/content/66/10/1597.abstract.
  3. Aguilera, R. 1999. Recovery Factors And Reserves In Naturally Fractured Reservoirs. J Can Pet Technol 38 (7). PETSOC-99-07-DA. http://dx.doi.org/10.2118/99-07-DA.

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See also

PEH:Estimation_of_Primary_Reserves_of_Crude_Oil,_Natural_Gas,_and_Condensate

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