www.ikonscience.com GEO2016 (Bahrain) 7th-10th March, 2016

PREDICTING PORE PRESSURE IN CARBONATES: A REVIEWSam Green*, Stephen O’Connor*+ and Alexander Edwards*** Ikon Science, Durham UK ** Ikon Science, Teddington, UK (+ Presenting Author)

AbstractCarbonate reservoirs are the targets of many drilling programs in the Middle East. One of the challenges in developing these types of reservoir is to mitigate the risk caused by unexpected pore pressure - these pressures can vary dramatically from relatively benign (e.g. Arab C and D Formations) to highly overpressured (e.g. Gotnia Formation, Oman/Kuwait).

A problem arises however, that existing pore pressure prediction techniques (that were developed for shales) are being applied to these targets with little consistency. There is a tendency in the industry to use seismic velocity data and porosity-based, shale-centric techniques to predict pore pressure directly in carbonates. This approach, at best, will only ever give a local, empirical fit as internally carbonates are too variable.

An approach looking at the basin history is advised, as the paleo-history of a carbonate will dictate its current pressure regime, coupled with sensible pressure modelling in any associated shales, and understanding of elastic (Poisson’s Ratio, Young’s Modulus, Vp, Vs and Rho) and mechanical (UCS, coefficient of friction) properties of the carbonates.

1 - The ProblemTraditional pore pressure prediction fails in carbonates because porosity variation is controlled by a wide variety of physical (stress, temperature) and chemical (pore water composition) parameters and not just effective stress as in shales.

Variable depositional, Dissolution and, Early and Late diagenetic fabrics, e.g. Ahr, 2008.

These factors mean that porosity can vary on a scale of only 10-100’s of meters and cannot be directly used to determine pressure consistently.

Reliance on simple porosity changes as is routinely performed for shales will lead in inaccurate pressure prediction i.e. typically under-prediction (Figure 1).

3 - A Coupled Geological-Pressure ModelA clue on how to predict carbonate pore pressure can be determined by analysis of the North Sea Chalk, where overpressures up to many 1000’s of psi are observed.

Overpressure increases from the edge of the Central Graben towards the basin centre which directly cor-relates to increased Tertiary sedimentation (greater load = higher pore pressure).

The magnitude of overpressure in the underlying Jurassic/Triassic reservoirs is observed to match the high overpressures at the base of the Chalk.

These observations imply that the Chalk overpressures are linked to those of the overlying Tertiary and the underlying Jurassic/Triassic, such that the Chalk acts as a pressure transition zone (Figure 2). The shape of this transition zone may be controlled by chalk thickness and permeability variations.

Simply put, carbonate pressures are influenced by the pressures in their surrounding clastics. Shale pres-sure prediction techniques can then be applied in these encasing (and inter-bedded, non-cemented) shales to give a sense of carbonate pressures.

2 - Understanding the Compaction of CarbonatesCarbonates rarely undergo mechanical compaction and porosity reduction as shales do as there is a further complication; a diagenetic overprint that can lead to both an enhancement or a reduction in porosity. Thus carbonates are stress-invariant, e.g. Chuhan et al., (2002) and Lubandazio et al, 2001.

The diagenetic complexity associated with carbonate porosity variability leads to velocity/porosity-depth relationships that are inherently unpredictable even locally on a field-scale, rendering traditional porosity-based shale pore pressure prediction methods invalid.

Carbonates are primarily made of calcium carbonate and are significantly faster than shales at the same depth. Consequently any shale-based pressure model will be applied to higher velocities than those expected for a shale at a given depth (Figure 1).

4 - Integration of Elastic Rock Properties for Pressure PredictionNew facies-based inversion should be able to model intra-carbonate shales accurately, allowing shale pressure estimates which can infer the associated carbonate pressures. These inversions can also help with understanding connectivity and lateral extent, and vertical relief of carbonate bodies that can be used to model pressure more effectively.

New approaches based on elastic and dry rock moduli and effective stress have been attempted by multiple authors in both carbonates and shales (which could easily be applied to carbonates).

Variation in the dry rock moduli can be expressed by Q, the Quality Factor (the inverse of attenuation), and used to predict pore pressure as successfully achieved in clastic sequences, e.g. Salehi & Mannon (2013) but has yet to be demonstrated to be effective in carbonates.

Effective stress calculation within carbonates using the compressibility of rocks as pore pressure has been shown to be potentially positive as it is dependent on the changes in pore space, which is a function of rock and pore compressibility, e.g. Atashbari & Tingay (2012)

These methods are based on calibrating to values of bulk rock moduli and pore compressibility which are obtained from special core analysis and is limited to the areas in which the cores are available. The key will be to use these cores as calibration an then back-out Young’s modulus and Poisson’s Ratio from seismic data intra-well.

Figure 2

Figure 1

• Ahr, W.M. 2008. Geology of carbonate reservoir; the identification, description and characterization of hydrocarbon reservoirs in carbonate rocks. Wiley Publishing, New Jersey, USA.

• Atashbari, V. and Tingay, M., 2012, Pore Pressure Prediction in a Carbonate Reservoir, SPE Oil and Gas India Conference and Exhibiition, (SPE 150836) pp. 28–30.

• Chuhan, F. A., Bjørlykke, K. and Lowrey, C., 2001, Closed-system burial diagenesis in reservoir sandstones: Examples from the Garn Formation at Haltenbanken area, offshore mid- Norway, Journal of Sedimentary Research, 71 (1), pp. 15–26.

• Lubandazio, M., Goulty, N.R. and Swarbrick, R.E. 2002. Variations of velocity with effective stress in chalk: null result from North Sea well data. Marine and Petroleum Geology, 19, pp. 921-927.

• Salehi, S., and Mannon, T., 2013, Application of seismic frequency based pore pressure prediction in well design: Review of an integrated well design approach in deep water gulf of Mexico, J Geology & Geosciences, 2 (3), pp. 125-134.

• Lucia, F. J., 1995, Rock-fabric/petrophysical classification of carbonate pore space for reservoir characterization, American Association of Petroleum Geologists Bulletin, 79 (9), pp. 1275–1300.

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