Controversial Petrophysical Quotes

Total Porosity or Effective Porosity? The Petrophysicist’s Old Chestnut

“The detail of this porosity evaluation and the equality of numerous core to log comparisons suggest a high degree of certainty in the evaluated total porosity (por). This porosity is calibrated to core oven dried helium porosities and is therefore “total porosity” despite core companies frequent use of the term “effective porosity” to mean these same oven dried helium interconnected pores. The confusion regarding total vs. effective porosity is due to the longstanding inconsistency between core companies frequent use of the term “effective porosity” to mean interconnected pores penetrated by He atoms in the laboratory vs. mainstream petrophysicists (Archie, W&S, Shell, NMR literature) use of this same term to mean (total porosity – clay bound water) following Hill, Shirley and Klein’s link between Qv and CBW. Hence the same meauserement value is called “total” by mainstream petrophysicists and “effective” by many core companies.  How can a crowd of such logical, scientifially minded folk get so confused? The term effective porosity is also used loosely in many other intuitive ways, as shown below.  It should be noted that non-NMR conventional logs lack the basic data from which to determine a storage capacity “effective” porosity from rocks containing non-clay micro-pores such as carbonates or quartz silts, and that non-NMR log based determinations of “effective” porosity in such micro-porous rocks are largely meaningless – what tool is providing the information for storage capacity? This is the primary reason why carbonates (reservoirs where compaction and clays do not control storage capacity and permeability) are difficult to evaluate with logs. This author uses “total porosity” to equate to the basic volumetric reference of conventional, hot oven dried core to constant weight (c.100degC) porosities, as with these plugs dried to 115degC. Under extremely rare circumstances (pers. comm Dave Bowen) conventional core oven helium dried porosities fail to report all the pore space, where pores are actually closed off as in intra crystalline pores. The essential point here is that correct use of the core reported grain density in the fixed point fluid density procedure above will still allow logs to duplicate the core measured porosities. It does not matter what that porosity is called – the important issue is whether logs are calibrated to a parameter which is directly measured and accurate. This subject has been discussed with rare common sense by Istvan Juhasz: “Porosity systems and petrophysical models used in formation evaluation” SPWLA London Chapter Porosity Seminar, 26th April 1988, which should be read by all aspiring petrophysicists to clarify this vexed issue”

Note: This is a total porosity evaluation in which shale porosity is evaluated as non zero and has an Ro-porosity (m) relationship. One of the many reasons for adopting total porosity is that the relationship between shale volume and Ro is revealed to the log analyst. In effective porosity evaluations the analyst is denied this information because the porosity parameter disappears as shales are approached, denying the petrophysicist powerful, cheap information for shaly sand evaluations. If the petrophysicist wants to understand tool responses – which respond to the whole formation not bits of it – during the petrophysical investigations shale porosity should not be hidden and Sw should not be truncated at 1.00. If your users prefer the cosmetics of effective porosity display it after you have finished the evaluation.



Provide End-Users with Effective Porosity – the Practical Result

“ ’Total’ porosity is useful for the calculation of porosity and water saturation. Core porosity measurements usually give total porosity. E&P managers need to know something different. They need estimates of potential reservoir thickness, ’effective’ porosity, permeability and the volumes of producible hydrocarbon and water.

‘Total’ and ‘effective’ porosity are equal in non-shaly reservoirs, and may be nearly equal in shaly sandstones containing clays (other than smectites) with little clay-bound water in the clay structure. In shaly sandstones containing hydrated clays (smectites), ‘effective’ porosity may be much less than ‘total’. Immature smectite shales with ‘core’ and ‘total’ porosities of 23% are impermeable non-reservoir rock.

To obtain practical results, petrophysicists and log analysts certainly need to understand and evaluate ‘total’ porosity and the volumes of water bound in clays. However, for the end users of the petrophysical results it is more informative to be provided with ‘effective’ porosity. It reduces confusion and give a more practical evaluation of the reservoir. In depth plots of the results, ‘total’ porosity should be de-emphasised and ‘effective’ porosity emphasized.”

Dick Woodhouse, Consultant.

Capillary Pressure Mercury Injection Data (MCIP) for Saturation Height?

.. In addition mercury data generally cannot be used for Sw-Height in a clayey low permeability rocks unless Cation Exchange Capacity and Clay Bound Water corrections have been made. During a mercury experiment a water phase is not present to wet the clays and fine pores and the mercury bulldozer barges its way through delicate clay lined throats, so, unlike air-brine data, mercury saturations provide a poor analogue for reservoir saturations. Mercury data provides pore throat size information for rock typing. This lack of a water phase is especially important here where Clay + Capillary Bound Water is a significant fraction of total porosity, as implied here by the 100% + difference between the air-brine and mercury data sets for the same reservoir height. Hence, despite the need for a resistivity independent bulk volume hydrocarbon these data have limited ability to supply a usefully accurate dm-m scale whole rock storage capacity.


What is Net Pay?  Definition and Cutoffs

Any discussion of net, netpay or cutoffs should start with a definition to clarify and unify the approach of different disciplines – a common cause of cutoff confusion. In the opinion of this author:

Netpay definition: The objective of Netpay is to delineate intervals containing fluids which make a contribution to production during the life of the field. Fluids which move or experience a change in saturation or pressure during production will make a finite, if small, contribution to production.

Hence if cutoffs are used the root criteria should be fluid movement, that is permeability, and saturation to imply which phase will move, not porosity or vshale. In the opinion of this author cutoffs are not necessary if permeability has been evaluated to within about 1/2 log cycle and correctly averaged in the reservoir static and dynamic models, indeed they will usually add error. Large errors in simulation are frequently caused by cutoffs – to blank out large volumes of rock, typically more than 50% GRV, as zero storage, zero permeability is usually more wrong than to at least approximately quantify their bulk volume hydrocarbon and permeability. This is especially true in low permeability, dry gas reservoirs.


Elan, Multimin, Mineral Solver.  Probabilistic or Deterministic Petrophysics?

“It should be noted that whilst over-determined, error-minimization (probabilistic) log analyses appear attractive they must demonstrate that the discontinuous core data has in fact been correctly extrapolated beyond core, rather than simply matched over core. If they fail to demonstrate mechanism(s) by which the cored answers are locked into the log analysis model applied beyond core they have failed to exploit the expensive and more accurate core data, and revert back to ‘log analysis’ – defeating the petrophysical objective of coring. The rigid extension of core data into uncored intervals is more difficult to demonstrate with probabilistic petrophysics than with deterministic petrophysics, and is a primary reason why simple deterministic methods persist in the face of what might appear as superior log analysis techniques. Again, it is the intention of this author that xx Field petrophysics is core based, not log based.”

“The interested petrophysicist may wish to consider that the use a multi-well, multiple linear regression of these same curves (portmlr) provided a better fit to core but a poorer overall porosity. This is because the fixed point zero porosity is lost in the MLR process and the scaling of pordn2sc (density-neutron shale corrected porosity) is forced to a non-feasible value (*0.374), because core porosity is of limited range. We know the pordn2sc factor needs to be ~ *1.00! It is worth noting that the deterministic fixed point technique (Juhasz 1988, Deakin 2002) overcomes the all too common limited range of core data by providing a zero porosity data point, and is the reason why the often ignored core grain density should be integrated into the log analysis. Also, the ‘interested petrophysicist’ may wish to ask him/herself how an Elan/Multimin approach integrates this hard data?”

Upscaling Geomodels – Permeability Averaging vs. Permeability Sum

Imagine your reservoir as a road cutting.  It contains a certain amount of hydrocarbons (EHC, m) and has a certain Flow Capacity (kh, mDm) regardless of what scale we choose to describe it at: 15cm (logs), 1m (static geo-model) or 5m (reservoir simulation geo-model).  All models must honor these facts.  If they do not they are wrong.  These facts cannot be dismissed as “an upscaling problem”, an attitude commonly expressed in meetings.  The permeability averaging method is not a fact about the reservoir. It’s flow capacity, kh, is.  The averaging method must equal our best estimate of kh and is simply the mathematical device which achieves this value for kh in the upscaled cell. The best estimate of kh is typically the petrophysical well test calibrated, effective kh.  The “averaged” permeability’s impact on the geo-cell Saturation-height calculation must be treated subsequently to honor the petrophysical EHC, but must not be allowed to violate the cell’s factual kh value.  A heterogeneity variance k factor, from the petrophysicist for each geo-cell interval in the log data, may be inserted into the saturation height formula to achieve equality in EHC and kh across all scales of reservoir description.  The k variance factor is a tuning parameter, a mathematical device which achieves our objective (as with m and n in Archie’s equation..). The final result must be equal EHC and kh at all scales.

Geomodel Checksums.  Export the geo-model’s grid upscaled, summed EHC and kh back into petrophysical software.  The total EHC and Flow Capacity of the rock must be equal at all scales.  Symptoms of problems are fudged Relative perms, kver/khor, or HCIIP to history match.