How to evaluate a shale play?

Part B

Emanuel Martin

In the first part of “HOW TO EVALUATE A SHALE PLAY?" we've developed: Shale play features, Main properties to evaluate, Kerogen, Total Organic Content (TOC), Organic Matter Classification, Thermal Maturity Determination, Depositional environment, facies characterization and Mineralogical composition. Now we're going to develop:



Mechanical properties



Unconventional fields only produce hydrocarbons cost-effectively through stimulation treatments to large-scale, due to this, the determination of the mechanical properties of the formation and its variation along the same recover a greater importance in these "reservoirs" since these allow us to determine the degree of fracturability of the formation, select the optimal orientation of the wells and designing the fracture treatment.


Between the main properties to evaluate are found in situ stress, Young's modulus, Poisson's ratio, Brittleness and the degree of natural fracturing of the formation.


Mechanical properties are determined through laboratories testing in cores of the formation together with well logs sonic or sonic dipole which allows us to calculate the shear stress or rigidity module of the formation from which we can estimate the pore pressure and the net stress.

Figure 1: main stresses to which are subjected the rock.

In-situ stresses are constituted by overburden stress, the maximum horizontal stress and minimum horizontal stress which determine the direction in which will spread the fracture in the formation and together with the pore pressure and Poisson’s ratio allow to calculate the pressure required to initiate the fracture treatment.


The Brittleness index is obtained from the Young’s modulus and Poisson’s ratio using the next equation:



Eindex is the Young's modulus

νindex is the Poisson's ratio

The Brittleness index must be greater than 0.33 to ensure the success of the treatment and also high value of Young’s modulus and low Poisson’s ratio indicate brittle rock behavior.

Figure 2: Cross plot of Young's modulus and Poisson's ratio showing the brittleness index (Rickman et al. 2008)

To determine the orientation and density of the natural fractures is analyzed the information acquired through seismic, image logs, well cores and surface outcrops.


Once these have been determined are used to relate the tectonic events, in situ stress, anisotropy and mechanical properties of the rock with which is built the geomechanical model of the formation. This model allows to obtain an overall understanding of the mechanical behavior of the reservoir from which are determined the reservoir performance, the location and orientation of the wells and is designed the fracture treatment.

Figure 3: Multi-disciplinary fracture system characterization (

Porosity evaluation



The porosity and permeability determination are the tasks more difficult to perform in the shale characterization since these are formed by sediments of small grain sizes, resulting in a pore network extremely complex. To facilitate its understanding the porosity in the shale fields can be divided into three parts: porosity within the natural fractures and microfractures, intergranular porosity within the inorganic matrix and porosity inside the organic matter.


Its determination can be made in the laboratory using the dual FIB/SEM system, traditional methods and well logs.


The dual FIB/SEM (focused ion beam milling and scanning electron microscopy) is the most accurate method to determine the pore volume. To obtain it, is analyzed high resolution pictures taken from samples of cores from which are identified the pores and is calculated its volume. Then from images obtained from samples taken at different planes of the core is built a dimensional model 3D which allows to visualize, analyze and understand the connectivity between the pores.

Figure 4: pore determination in a shale with FIB/SEM (Slat & Brien et. Al 2013).

Among the traditional methods are found helium porosimetry, Mercury injection capillary pressure (MICP) and pycnometer. While these methods are faster and cheaper than the previous they are usually affected by   pore access problems  for the molecules of gases and liquids (due to the ultra low  reservoir permeability), adsorption effects, volume changes in the natural fissures and microfractures (due to variations in pore pressure and confinement pressure  during the test) so is recommended adjust their measurements with those obtained from the SEM.




The density log presents alterations in the porosity measurement due to the frequent changes in the shale mineralogy are translated into a significant variation of the rock density together with the presence of dense minerals such as iron carbonates and pyrite. In addition to determine the kerogen density is another challenge for the tool as it changes with the maturity of the same.


Neutronic log to infer the formation porosity through the hydrogens present in the formation it measure a greater porosity than the real because this is affected by the presence of the HO- in the crystalline structure of the clays kaolinita, chlorite, illite and  smectite as well as the hydrogens that constitute the kerogen and bitumen being necessary its calibration with laboratory measurements.


The use of the resistivity log is strongly questioned in the shale, despite being used normally, due to the water salinity of the formation varies widely in small distances, in addition the presence of kerogen increases the formation resistivity and the presence of conductive solids  in the form of clay minerals decrease it.

Figure 5: Schematic of a matrix where is shown the total and effective porosity. (Modified from Arnold & Bratovich, Baker Hughes 2014)

The NMR log is the tool more accurate to determine the total porosity in a shale because that is the least influenced by the presence of the organic matter and the peculiarities of this. Normally the porosity values obtained by NMR are close to the values obtained in the laboratory using crushed rock methods.



Permeability evaluation



The permeability in the shale reservoirs is constituted by the matrix permeability and the system permeability. Matrix permeability is the permeability of the rock and due to the heterogeneity present in the shale this often varies in several orders of magnitude, being within the range of 10-4 to 10-8 mD.


For its determination in laboratories are made measurements with Crushed Rock Injection or Mercury/gas Injection Method (Pulse Decay Permeability method) in cores of the formation, it can be also estimated through NMR log.

Figure 6: Pulse decay equipment for permeability determination (Core Laboratories).

On the other hand the permeability of the system is constituted by the permeability of the matrix and the permeability of the open fractures. Its determination cannot be made using logs because these are unable to estimate the permeability of the fractures, so for its evaluation is used the pressure transient testing. In addition with this test we can assess the reservoir pressure, its conductivity and the effectiveness of the stimulation treatment.


Below is shown a pressure buildup test in a shale gas field where we can see that the effective permeability of the system is relatively high compared with the average values of the matrix.

Figure 7: Pressure derivative plot from pressure builup test performed on gas shale (Lewis, Ingraham, Pearcy et. Al 2004 Shclumberger)

It is important to highlight then that the permeability of the system as opposed to the conventional fields is a variable of the time, since this decreases to decrease the volume of hydrocarbons present in the reservoir. To better understand this phenomenon, we must analyze the shale production rates where the first stage of the curve is characterized by a strong and abrupt declination of the flow followed by a slight declination in the long term.

Figure 8: typical production curve of a shale.

This is due to the fact that during the first stage the hydrocarbons produced come from the drainage of the fracture network where the dominant permeability is the system permeability (obtained with the pressure buildup test) but as time passes and the production is stabilized in low rates the hydrocarbons produced come mainly from the zone not stimulated of the reservoir, the matrix, where the permeability is the obtained from the cores in the laboratory (matrix permeability). This is why that should be implemented a weighting factor between one and zero in function of the time to use the system permeability to simulate a shale reservoir and analyze their productivity.



Water Saturation



The water saturation in the shale is normally equal to the percentage of water irreducible of the formation because in them were generated the hydrocarbons, which were subsequently expelled from the same by moving a large part of the mobile water toward the adjoining formations.


Its determination by the resistivity log as in the porosity determination is highly disputed since as mentioned above this tool is affected by the clay minerals (conductive solids), solid kerogen and the variation in the water salinity; which have been reported have large variations over short vertical distances with no apparent relationship to organic content or any other petrophysical parameter (Sondergeld et al. 2010b). In other words we are in front of a reservoir that does not behave as a reservoir of Archie and although some authors have achieved an acceptable match between measurements of cores and the values obtained with the tool using an equation of Pseudo-Archie with exponents of cementation and saturation of 1.7. (Luffel et al. 1992) this tool should be used only under calibrations made from well cores.


A more accurate solution is to determine the water saturation with the NMR log since this doesn't need to measure the formation resistivity to obtain saturation values. In addition this tool can differentiate the percentage of free water and clay bound water thanks to the different times of relaxation (T2) that these have.

Figure 9: NMR log, interpretation of the different times of relaxation T2 (Taken from Crain

Adsorbed gas evaluation (for shale gas play)



To calculate the gas volume present in a shale is necessary determine the volume of free gas in the pores and microfractures of the formation together with the gas adsorbed in the pores's walls inside the kerogen, which,  in some shale has come to be the 85% of the gas stored in the reservoir (e.g. Faraj et to the. 2004). This explains because the ultimate recovery in reservoirs with significant amount of gas adsorbed (shale) has been reported be up to ten times greater than for other reservoirs with similar permeability and porosity (tight). (Economides & Wang 2010).


The volume of gas adsorbed is calculated by the Langmuir isotherm which is obtained from tests made in laboratories with cores of the formation. Although its use may not be the most accurate given that recent studies have shown that the gas adsorption in the pores's walls of the kerogen is multilayer its employment has become a standard in the industry.

Figure 10: Langmuir isotherm where we can see Langmuir volume and pressure (Modified from Boyer et al, Schlumberger Oilfield review 2007).

From the isotherm are obtained the Langmuir volume (volume of gas adsorbed at a infinite pressure), the Langmuir pressure (pressure to which is gets the half of the Langmuir volume) and the reservoir pressure; they are entered into the following equation to calculate the volume of gas adsorbed



Gs= gas storage capacity (scf/ton)

p=reservoir pressure (psia)

VL= Langmuir volume (scf/ton)

PL= Langmuir pressure (psia)


To achieve a continuous estimation of the volume of gas adsorbed is used to establish relations between the curves of standard logs and the gas volume; being common the relationship between the volume of gas adsorbed and the variation in the concentration of organic matter in the formation.

Figure 11: Gas Storage Capacity vs. TOC weight fractions  (Jarvie, 2007 AAPG SW Section meeting)

Once obtained the volume of gas adsorbed (AGIP) and the free gas in situ (free gas in-place (GIP)) these are combined to calculate the total volume of gas in the reservoir. In the next graphic are show the contribution of the free gas and the gas adsorbed to the total gas volume present in the formation in function of the reservoir pressure.

Figure 12: Combining Free and Adsorbed gas for Total Gas In-Place (EIA 2013)

Determination of the formation's volume



The volume of a shale is calculated in the same way as in the conventional reservoirs where is resorted to cross-sections and thickness maps obtained through seismic and to stratigraphic correlations made from logs in exploratory wells. All the information obtained are entered in the simulator where is built the geological model of the formation and is obtained its volume.

Figure 15: shale formation modeling in a simulation through information acquired with seismic and well logs.

Cut-off selection



As in the conventional field is used cut-off values to determine the net thickness of the reservoir. Given that the shale plays only produce hydrocarbons  through the use of hydraulic fracturing  the concept of cut-off in these reservoirs is a little different  to that of the conventional fields, being linked to the properties that allow to assure the presence of hydrocarbons in the same and the feasibility of the  fracture treatment. In function of them we can divide the cut-off in two groups:


Properties that ensure the hydrocarbon content and its storage:


  • organic matter content
  • thermal maturity
  • porosity


Properties that ensure the fracture treatment:


  • brittleness
  • clay volume
  • thickness
  • fracture gradient


In the following table is shown the cut-off values commonly used in the industry:

Table 1: cut-off values commonly used in the industry for shale plays.

From which we can evaluate and determine qualitatively the risk in the development of a shale as is shown synthetically in the following flowchart made by M. Ahmad for a shale gas.

Figure 16: Shale gas reservoir selection criteria base on geological, geochemical and mineralogical characteristics (Maqsood Ahmad 2014).

Sweet spots



The Sweet Spots are the parts of reservoir where is concentrated the best properties of the formation and they indicate to us the places by where we must start the development of the same to minimize investment risks and to recoup the capital invested in a minor lapse of time.


The sweet spots in a shale is characterized by:


  • large thickness
  • high content of organic matter and adequate thermal maturity.
  • high porosity
  • high brittleness
  • high number of natural fractures
  • low clay content
  • low fracture initiation pressure
  • low water saturation

Estimating Shale Oil In-Place



Once determined and analyzed the properties of the reservoir and obtained the net volume of the formation is proceed to calculate the oil in-place (OIP) and the ultimate recovery (UR) using the volumetric method:



N=OIP= initial oil in place (stb, stock-tank barrels)

A= area, in acres (with the conversion factors of 7,758 barrels per acre foot).

h= net shale thickness, in feet.

Φ= porosity (dimensionless fraction).

So= the fraction of the porosity filled by oil or also can be used (1-Sw) instead So.

Boi= initial oil formation volume factor (reservoir bbl/stb). Oil and dissolved gas volume at reservoir conditions divided by oil volume at standard conditions.


Ultimate Recovery


To estimate the reserve is multiplied the initial oil in place obtained by the recovery factor. The EIA assigns a recovery efficiency factor in function of the mineralogy, reservoir properties and geological complexity as is shown below.


Favorable Oil Recovery. A 6% recovery efficiency factor of the oil in-place is used for shale oil basins and formations that have low clay content, low to moderate geologic complexity and favorable reservoir properties such as an over-pressured shale formation and high oil-filled porosity.


Average Oil Recovery.  A 4% to 5% recovery efficiency factor of the oil in-place is used for shale gas basins and formations that have a medium clay content, moderate geologic complexity and average reservoir pressure and other properties.


Less Favorable Gas Recovery. A 3% recovery efficiency factor of the oil in-place is used for shale gas basins and formations that have medium to high clay content, moderate to high geologic complexity and below average reservoir pressure and other properties.


Once the recovery factor was determined is used the next equation:








UR = Ultimate Recovery, STB

OIP = Original oil in place, STB

RF = Recovery factor or Recovery Efficiency, %.

Estimating Total Gas In-Place



To determine the Total Gas In-Place should be added the Free Gas In-Place with the Gas Adsorbed In-Place.


Free gas in-place:



GIP= initial gas in place (scf)

A= area, in acres (with the conversion factors of 43,560 square feet per acre

and 640 acres per square mile).

h= net shale thickness, in feet.

Φ= porosity

Sg= the fraction of the porosity filled by gas or also can be used (1-Sw) instead Sg.

Bg= initial gas formation volume factor (ft3/scf)

P= reservoir pressure, in psi.

T= temperature, in degrees Rankin (the factor 460oF is added to the reservoir temperature in the equation).


Adsorbed Gas In-Place:



AGIP= adsorbed gas in place (scf)

Gs= gas-storage capacity (scf/ton)

p=reservoir pressure (psia)

VL= Langmuir volume (scf/ton)

PL= Langmuir pressure (psia)

ρ= shale density (ton/cft)


Total Gas In-Place:






TGIP is the total gas in place

GIP: free gas in place

AGIP: adsorbed gas in place



Ultimate Recovery



To estimate the reserve is multiplied the initial gas in place obtained by the recovery factor. The EIA assigns a recovery efficiency factor in function of the mineralogy, reservoir properties and geological complexity as is shown below:


Favorable Gas Recovery. A 25% recovery efficiency factor of the gas in-place is used for shale gas basins and formations that have low clay content, low to moderate geologic complexity and favorable reservoir properties such as an overpressured shale formation and high gas-filled porosity.


Average Gas Recovery. A 20% recovery efficiency factor of the gas in-place is used for shale gas basins and formations that have a medium clay content, moderate geologic complexity and average reservoir pressure and properties.


Less Favorable Gas Recovery. A 15% recovery efficiency factor of the gas in-place is used for shale gas basins and formations that have medium to high clay content, moderate to high geologic complexity and below average reservoir properties.


Once the recovery factor was determined is used the next equation:








UR = Ultimate Recovery, SCF

TGIP = Total Gas In-Place, SCF

RF = Recovery factor or Recovery Efficiency, %.




To determine the volume of hydrocarbons in situ are used conventional procedures with some modifications in its valuation and measurement to adjust them to the characteristics of these new reservoirs. In addition the great heterogeneity of the shale along with the difficulty in the measurements of some of its properties forces the reservoir engineers to work with a higher level of uncertainty than the accustomed.


Also have appeared new factors to evaluate such as the percentage of organic matter and its thermal maturity together with the change of importance in some of the classic properties as the mineralogy and mechanical properties of the formation transforming them in decisive factors to determine the viability in the shale development.


The conventional logs must be used under calibrations made from well cores of the formation because the variable mineralogy in the shale along with the presence of radioactive metals, conductive solids, dense minerals and kerogen in the same produce distortions in their measures. The NMR and geochemical logs have been transformed into two indispensable tools at the time of characterize a shale since these are the less affected by their particularities and they allow to evaluate the porosity, formation mineralogy, water saturation and kerogen volume.


In addition becomes evident the need to standardize the laboratory procedures for the measurement of the reservoir properties since several of the practices used in conventional fields are not adjusted to  the new features of the shale. In this way will decrease the gap found between the values reported by different laboratories in the determination of the same properties in the same formation.


On the other hand special attention should be given to not add in the total porosity the volume occupied by the "water" of clays (structural hydroxyl, OH-) because do this is not technically correct since these are not empty spaces water-filled if not they are part of the molecular structure of the matrix components.


We have also found the need to add a weighting coefficient in function of time for when we use the system permeability in the determination of the reservoir productivity and carry out its simulation.


Finally we can say that the cut-off values in the shale plays follow new patterns that are in accordance with the change of production philosophy of the same and as well as the technique of hydraulic fracturing continue to evolve and its costs decreasing the evaluation of the reservoir properties are going to reduce simply to that the rock contains hydrocarbons and it can be fractured.

Author: Emanuel Omar Martin, Petroleum Engineer




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