4.2 Some definitions

Petrophysics is a vast domain which can’t be summarized in a few paragraphs. Each rock requires specific petrophysical equations, or at least specific values for the parameters of these equations. Also, as for any other sciences, practitioners have developed multiple techniques to compute any given petrophysical log, different techniques requiring a different set of input logs or different techniques being based on a different conceptual understanding of the intrinsic characteristics of the rock. At last, the list of reservoir properties requested by engineers might be different from one study to the next (conventional vs unconventional, natural fractures to be modeled or not…). As it is impossible to cover everything in one paper, we have decided to focus on a simple set of petrophysical logs: VSH, porosity, SW and permeability. Discussion between your geomodeler and your petrophysicist will allow you to adapt what is proposed hereafter to your specific reservoir and your specific petrophysical analysis. In complement, we invite you to refer to one of the many excellent books available for more details about well logging (Ellis and Singer, 2007) and petrophysics (Doveton, 2014).

The purpose of well logging is to measure how the rocks and fluids in the vicinity of the wellbore react to different stimuli such as electricity (resistivity logs…), nuclear emission (density logs…) and acoustic waves (sonic…). Well logging provides an essential input to formation evaluation but also to completion evaluation. Among other things, once processed, cleaned and calibrated, well logs help to answer questions about the nature, location and quality of the hydrocarbons. Well logs are also used to quantify important rock and fluid properties such as VSH, porosity, permeability and SW, through the process of petrophysical analysis. These petrophysical logs are in turn needed as input to engineering studies, and so as input to geomodeling.

VSH quantifies the part of the rock that is “ineffective” in the sense that it will slow down or prevent the good flow of the hydrocarbons. GR is used as the base line for quantifying VSH as some clays such as illite contain radioactive minerals such as potassium which are detected by the GR log. Some clays such as kaolinite does not contain any of the radioactive minerals (potassium, uranium, and thorium), detected by the GR log, and are therefore not visible to this log. The presence and proportion of each type of clay, among which those not visible to GR, can be observed and measured in core samples and then used to correct the VSH logs as needed.

Two main types of porosity are defined: total porosity (PHIT) and effective porosity (PHIE). PHIE is the percentage of the rock volumes which represents the connected porosity. It is made of all the pores that are connected and form the pore network. Only fluids in the pore network can be moved through production (unless some recovery techniques are used to connect some of the non-connected pores to the pore network). The total porosity is the fraction of the rock made of all the pores, both connected and non-connected. PHIT includes PHIE and mathematically PHIT is always greater or equal to PHIE.
Total water saturation (SWT) and effective water saturation (SWE) are associated respectively to PHIT and PHIE. The water saturation represents the percentage of the pore volume (total or effective) filed with water.

Most engineers want to see PHIE and SWE modeled in 3D, as these are important input parameters to their own computations (flow simulation, volumes). That being said, some recovery techniques are influenced by the total pore volume, not just the connected pore volume. As such, geomodelers should always check with their engineers what type of porosity and SW are needed (if not both). It should also be noted that initial SW is needed for flow simulation and the current SW might be different to the initial SW. Initial means the state of SW in the reservoir before any production or enhanced recovery technique occurred. SW logs based on well logging done after EOR techniques, like waterflooding, were applied must be corrected or discarded. Waterflooding will increase SW in the vicinity of the water injectors and the SW logs will show higher values than were prevailing in the initial condition of the reservoir.
The discussion about which the type of porosity and SW needed (effective and/or total) must involve the petrophysicist as this request might change the way he/she will complete his/her petrophysical analysis.

For some reservoirs, measuring total properties on core is more easily done (or simply feasible) than measuring effective porosity. For some reservoirs, it is the reverse. The key to a good petrophysical analysis is the capacity to calibrate it back to some reliable core measurements. If core studies measured total properties, the petrophysicist will compute PHIT and SWT from the logs, calibrate them to the core measurements, and then, if needed, the petrophysicist will derive PHIE and SWE properties from PHIT and SWT. If core studies measured effective properties, the petrophysicist will do it the other way around. VSH is one of the parameters linking PHIE and PHIT. Any uncertainty on VSH (because of clays not seen by the GR for example) will add uncertainty in the porosity computation. SW is the most difficult log to quantify because the coring process doesn’t preserve SW well. SW core measurement can be very unreliable. In conventional reservoirs, capillary pressure is extremely useful to quantify SW, but such technique can’t always be applied in unconventional reservoirs. Also, SW being partly connected to the porosity, any porosity uncertainty (coming from VSH uncertainty among other things), will also create uncertainty in the estimation of SW.

Permeability values change depending on the direction considered. The vertical permeability quantifies how the fluids move in the vertical direction, while the horizontal permeability quantifies how the fluids move in the plane of deposition. For flat to near-flat reservoirs, “horizontal” does mean horizontal. In complex structural reservoirs (folds, faults, tilted blocks…), the plane of deposition might not be “horizontal” anymore. The same can be said for the “vertical” permeability. For reservoirs with natural and/or induced fractures, a more complex horizontal permeability field must be considered as fluids will move with more ease in the direction parallel to the fractures (if they are open) than perpendicular to them. Geomodels usually contain two permeabilities (vertical, horizontal). Some studies consider three permeabilities when two orthogonal horizontal permeabilities are needed. In this paper, we consider just one permeability as the message is about the general workflow, not about the specifics of any given type of reservoir. A discussion in your team will clarify what is needed in your case.

For consolidated reservoirs, permeability can be measured on core with some level of confidence. Cross-plots between core porosity and core permeability are used to define a mathematical relationship between the two properties. Once porosity logs are available (and calibrated to the core porosity measurements), the mathematical relationship porosity-permeability is used to compute permeability logs from the porosity logs. Permeability is very hard to measure, especially in non-consolidated rocks. As such, the porosity-permeability relationship contains a lot of uncertainty.

Table of contents

Introduction

Chapter 1 - Overview of the Geomodeling Workflow

Chapter 2 - Geostatistics

Chapter 3 - Geologists and Geomodeling

Chapter 4 - Petrophysicists and Geomodeling

Chapter 5 - Geophysicists and Geomodeling

Chapter 6 - Reservoir Engineers and Geomodeling

Chapter 7 - Reserve Engineers and Geomodeling

Chapter 8 - to be published in the summer 2019

To be published mid-March 2018

Chapter 9 - to be published in the summer 2019

To be published mid-March 2018

References

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