Mercury injection capillary pressure (MICP) evaluation of reservoir lithologies, cap seals, intra-formational seals and fault seals is conducted at the National Centre for Petroleum Geology and Geophysics (NCPGG). MICP measurements may be integrated with seismic to microstructural data to provide a robust basis for interpretation of the reservoir potential, sealing capacity and stability/strength of individual strata. A range of MICP-based services is offered by NCPGG including non-wetting phase directional injection and withdrawal, pore network characterisation, free water level determination, calculation of reservoir efficiency, empirical cuttings to core data correction, calculation of hydrocarbon column heights and integration with scanning electron microscope sample analysis.
 
 

An understanding of capillary pressure behavior is vital to optimise reservoir characterisation and to accurately determine cap, intra-formational and fault sealing capacity (Figure 1). Investigation of the sealing capacity and pore-throat aperture size distribution for seals and reservoir lithology is conducted via mercury porosimetry using the latest Micromeritics Autopore-III porosimeter (Figure 2). This state-of-the-art equipment is capable of injecting non-wetting phase (mercury) in user-defined, step-like pressure increments up to 60,000 psi (~413MPa) into an evacuated and cleaned/dried core plug or cut sample. Innovative laboratory processes control injection direction. The volume of mercury injected at each pressure increment is automatically recorded until the maximum analytical pressure, or 100% pore-volume Hg saturation is achieved. Pressure is subsequently plotted against incremental Hg saturation readings to generate the drainage curve. Processes may be reversed to generate non-wetting phase imbibition curve. Injection analysis can be carried out at reservoir conditions if pressure data is available, however, low reservoir pressures may inhibit total non-wetting phase saturation.
 
 

Mercury porosimetry is based on the capillary law governing liquid penetration into small pores. Capillary forces in the reservoir and seal are functions of surface and interfacial liquid tensions, pore-throat size and shape, and the wetting properties of the rock. This law, in the case of a non-wetting liquid like mercury and assuming cylindrical pores is expressed by the Washburn (1921) equation:

where Pc = capillary pressure (dynes/cm2), g= surface tension of Hg, Q = contact angle of mercury in air, rc = radius of pore-throat aperture (m m) for a cylindrical pore.

The surface tension of mercury varies with purity. The interfacial tension for air-mercury is 485 dynes/cm2. The contact angle (Q ) between clean mercury and sample pores varies with specimen composition, however, 140° is generally accepted by industry.

Rearranging the Washburn equation in terms of rc:

This equation is employed to calculate the critical pore-throat aperture (CTS). CTS is the pore-throat size at which maximum intrusion of the non-wetting phase occurs for a relatively minor pressure increase (Figure 3). CTS values are vital in reservoir characterisation and threshold pressure and permeability identification/prediction.

Entry pressure, displacement pressure, and threshold pressure are terms referring to the critical points on the mercury injection curve (see Figure 3). The entry pressure on the mercury injection curve is the point on the curve at which mercury initially enters the sample. This point is often indicative of the largest pore aperture size (Robinson, 1966). However, this parameter can be difficult to accurately determine as sample size and surface irregularities, relative to total pore size distribution, create a boundary condition that affects the low-pressure portion of the curve. Surface irregularities also effect the low mercury saturation portion of the MICP curve. These irregularities do not follow the Washburn equation relationship and result in a conformance MICP injection error. This factor must be recognised when characterising a reservoir/seal as conformance can lead to significant errors in calculating both entry and threshold pressures.

The most important factor when evaluating seal potential is determining the pressure required to form a connected filament of non-wetting fluid through the pore space of the sample. As mercury is a non-wetting fluid, pressure must be built up before it displaces the wetting phase. At a sample specific pressure, which is dependent on the pore-throat size, the percentage of mercury intruded increases rapidly. This is the threshold/displacement pressure and graphically corresponds to an upward convex inflection point on the mercury injection curve (Figure 3).

Pittman (1992) and Winland (Amoco Production Company) have attempted to identify a mercury saturation percentile at which the reservoir threshold pressure can be predicted to occur. Three, five and ten percent of the total mercury saturation are commonly used to predict this threshold pressure. Ten percent mercury saturation is theoretically defined as the displacement pressure (Schowalter, 1979). Pittman (1992) also suggested that the apex of a peak obtained by plotting capillary pressure divided by the percentage of mercury intruded, against the percentage of mercury intrusion serves as an estimate of the threshold pressure. This suggestion is based on analysis of undeformed sandstones. This method is employed by NCPGG to vindicate the chosen threshold pressure apex when no clear threshold pressure indicator is present. Often a sample with a large pore-throat distribution displays many minor MICP apexes. These additional apexes relate to distinct pore-throat aperture sizes within the sample created by the grain-size heterogeneity, authigenic cements, poor sorting etc.
 
 

Ideally, separate samples from undeformed reservoir and fault should be analysed to accurately determine the height of hydrocarbon column the fault may support relative to the undeformed strata. For specimens where the fault zone is too narrow to cut, an additional sample can be cut with the fault zone cutting horizontally across the centre of the plug with regions of hanging and footwall flanking either side. In order to constrain the pore size of these thin fault rocks, the sample is sealed on all sides except the footwall base by coating in an epoxy resin. This procedure ensures directional injection across the fault and also minimises closure effects during mercury injection analysis on samples with large external surface areas to volume ratios.

The mercury injection curves of sealed samples containing faults will display two threshold pressure indicators. The first inflection point threshold is characteristically low and represents the initially intruded host lithology. The second threshold is dominantly at a greater injection pressure and represents the pressure at which the fault-seal zone is breached. It is this pressure value that is employed to calculate the sealing capacity and height of the hydrocarbon column the faults may support. Also available at NCPGG is integration of fault seal MICP data with core-scale (Figure 4) and scanning electron micro-structural analysis (Figure 5) of fault rock type to validate fault gouge prediction data (Figure 6).
 
 

Quantitative application of mercury capillary data to sub-surface conditions requires the conversion of mercury capillary pressure values to sub-surface hydrocarbon-water and/or gas-water capillary pressure values. The Hg/air-brine/hydrocarbon conversion factor can be expressed as:

where (Pc)hw = capillary pressure for hydrocarbon-water system, ghw = interfacial tension of hydrocarbon and water in dynes/cm, Qhw = contact angle of hydrocarbon and water, gma = interfacial tension of mercury plus air, and Qma = contact angle of mercury and air against the solid. The interfacial tension of mercury and air is ~480 dynes/cm at laboratory conditions. The contact angle between mercury and solid is 40° C (Schowalter, 1979). Sub-surface values for hydrocarbon-water capillary pressures can be calculated by entering the sub-surface hydrocarbon-water interfacial tension value into the above conversion factor equation (Purcell, 1949). The laboratory derived air-mercury threshold pressure values can be multiplied by this conversion factor to produce sub-surface hydrocarbon-water capillary pressure values. Sub-surface hydrocarbon-water interfacial tension values for all projects are calculated using specific reservoir temperature and pressure conditions. Note: gas-water interfacial tensions are generally greater than oil-water interfacial tensions for both surface and sub-surface conditions. Gas-water threshold pressures are therefore greater than oil-water displacement pressures for the same rock.
 
 

Decisions concerning how hydrocarbon recovery from a reservoir can be maximised are based on an understanding of the entire reservoir as a transmission system for multiphase fluids. This understanding requires knowledge of the chemical and physical interactions of fluids within the rock-pore system as well as qualitative information concerning the nature of fluid-flow pathways. Pore geometry of the reservoir lithology plays a major role in reservoir quality (e.g. Bliefnick and Kaldi, 1996; Melas and Friedman, 1992: Varva et al., 1992). Pore geometry refers to the shape, size and inter-pore connectivity of the poresand pore-throats. Because of wettability differences between air/mercury and brine/hydrocarbon systems, mercury injection does not reproduce reservoir specific conditions. However, MICP accurately provides an analogue when calibrated to measured/calculated values of reservoir fluid properties (Varva et al., 1992).

Petrophysical characteristics such as porosity, recovery efficiency, irreducible water saturation, pore-throat size, pore-throat size distribution and threshold pressure are determined using mercury porosimetry. These characteristics determine the shape, slopes and plateau of the capillary-pressure curve. Analysis of the MICP curve is, therefore, important for various phases of reservoir production, especially secondary and tertiary recovery. These data may be evaluated in conjunction with additional SCAL and routine core petrophysical data in order to provide an accurate assessment of reservoir and/or seal potential.

For additional information on NCPGG MICP services please contact:
Ric Daniel (rdaniel@ncpgg.adelaide.edu.au) or
Dr John Kaldi (jkaldi@ncpgg.adelaide.edu.au)
 

  REFERENCES

  Bliefnick, D. M. and Kaldi, J. G. 1996. Pore geometry; control on reservoir
  properties, Walker Creek Field, Columbia and Lafayette counties, Arkansas.
  American Association of Petroleum Geologists Bulletin, 80,  7, 1027-1044

  Jones, R. M., Boult, P., Hillis, R. R., Mildren, S. D. and Kaldi, J. 2000.
  Integrated hydrocarbon seal evaluation in the Penola Trough, Otway Basin.
  APPEA Journal 2000.

  Melas, F. F. 1992.  Petrophysical characteristics of the Jurassic Smackover
  Formation, Jay Field. American Association of Petroleum Geologists
  Bulletin, 76; 1, 81-100.

  Pittman, E. D. 1992. Relationship of porosity and permeability to various
  parameters derived from mercury injection - capillary pressure curves for
  sandstones. American Association of Petroleum Geologists Bulletin, 51,
  191-198.

  Purcell, W. R. 1949. Capillary pressure - their measurements using mercury
  and the calculation of permeability therefrom: AIME Petroleum Trans., 186,
  39-48

  Schowalter, T. T. 1979. Mechanics of Secondary Hydrocarbon Migration and
  Entrapment. American Association of Petroleum Geologists Bulletin, 63, 5,
  723-760.

  Vavra, C. L., Kaldi, J. G. and Sneider, R. M. 1992. Geological Applications
  of Capillary Pressure: A Review. American Association of Petroleum
  Geologists Bulletin, 76, 840-850.