Shale formations constitute 60% of the rocks that make up the Earth's crust being only a small group of them containers of hydrocarbons. The necessary conditions to ensure that these rocks have generated and stored oil or gas is that they have abundant organic matter deposited under anoxic conditions but in addition to this, to become a shale reservoirs they must meet a number of properties geophysical, geochemical and petrophysical.
While in the conventional fields for the evaluation and calculation of the hydrocarbons in place is required to know the values of porosity, water saturation, permeability, reservoir volume and the volumetric factor of the gas or oil; in a shale play is also necessary to know the Total Organic Carbon (TOC), thermal maturity, depositional environment, mineralogical composition and mechanical properties.
In this work we'll discuss briefly each of them and we'll determine between which values should be comprised such properties so that a shale formation is considered viable for the hydrocarbons production. Then we'll show how to make calculations of the hydrocarbons volume containing in the formation (Oil and gas in place ) and we'll estimate the hydrocarbon reserves through the volumetric method. Finally we will analyze the sweet spot of the main shale play in the United States from where we'll get some important conclusions.
Figure 1: Elements necessary to make productive a shale play (modified from Hill et. all 2008)
The fundamental and indispensable requirement so that a shale play may contain hydrocarbons is the presence of kerogen in the same, which, is a complex organic compound product of the diagenesis of the organic matter.
As its presence is directly linked to the hydrocarbons generation and the alteration of the mechanical and elastic properties of the formation is important determine the content of the same in weight and volume as well as its classification and degree of thermal maturity.
Figure 2: image of a Barnett Shale sample where we can see the kerogen and the mineral Pyrite which is a product of shale thermochemical maturation. (Graphic of Nicholas Drezek, Schlumberger-Doll Research Center and Natasha Erdman, Jeol USA, inc.)
This method is used to determine the amount, maturity and type of hydrocarbon generated after the transformation of organic matter to kerogen.
For the analysis is introduced a known amount (100mg) of crushed rock (75 mesh screen) with oxygen.
Free hydrocarbons (S1) are determined from an isotherm to 340° C and measured using a flame ionization detector. The temperature is then increased to 640° C where the hydrocarbons are released from kerogen (through thermal cracking) creating the S2 peak. The temperature at which S2 is reached is called Tmax and represents the temperature at which occurs the maximum rate of hydrocarbons generation. The CO2 generated from the hydrocarbons oxidation in the heating from 340 to 580°C is measured by the IR cells and it's referred to as the S3 peak.
To obtain the total carbon content in the formation there are different methods in the industry being the most frequently used: Rock-Evaluation Pyrosysis, Leco cr 412 and estimation using well logs. Although measurements made from cores are the most representative these require more time and budget by which generally cores are extracted in exploratory wells to determine their properties in the laboratory to calibrate with them the log tools.
Figure 3: Graphical expression of Rock Evaluation Pyrolysis output.
As results of the test are obtained the values of total organic carbon (TOC%), S1, S2, S3 and Tmax.
Total carbon content is determined in dried sediments and total organic carbon is determined in dried and acidified sediments using a LECO CR-412 Carbon Analyzer. Sediment is combusted in an oxygen atmosphere and any carbon present is converted to CO2. The sample gas flows into a non-dispersive infrared (NDIR) detection cell. The NDIR measures the mass of CO2 present. The mass is converted to percent carbon based on the dry sample weight. The total organic carbon content is subtracted from the total carbon content to determine the total inorganic carbon content of a given sample (Bernie B. Bernard, Texas).
Figure 4: Leco Cr-412 Carbon analyzer.
In addition the values of high resistivity have their origin in the low percentage of water that has the kerogen normally less than the irreducible water of the formation. Neutron porosity is also affected since the tool in addition to measuring the hydrogens of the fluids inside the pore space it also measures the H present in the kerogen, bitumen and clay-bound water. As a result the logs gamma ray, uranium, density and ΔLogR whose interpretations are derived empirically need to be calibrated with measurements of cores to ensure their accuracy.
The response of the kerogen to the well log is characterized by shows certain alterations in its measurement such as: high activity in the gamma ray log, high resistivity, low matrix density and high sonic and neutron porosity.
The great values obtained in the gamma ray log are due to the fact that the kerogen generates a reducing environment that favour the precipitation of uranium whose presence alters the response of the tool since this normally measures thorium and potassium (mainly).
Figure 5: Conventional log analyses, SpectroLith, and ELANPlus interpretation of conventional and underlying gas shale. Schlumberger.
The recommended method for determining the kerogen volume with well logs is to use integrated the tools NMR, density and geochemical; where simplistically, the low grain density of kerogen leads to the density log identifying a kerogen-rich zone as porous, yet the kerogen will appear as matrix to an NMR log. The difference in these two volumes can be equated to kerogen volume (Gonzales, Lewis, Hemingway. Et al 2013)
Figure 6: Petrophysical representation of kerogen volume estimate from integration of gamma-gamma density, geochemical, and NMR logs (Gonzales, Lewis, Hemingway. 2013 )
Once estimated the volume of kerogen it must be converted to total organic carbon using the following equation:
TOC= total organic carbón (lbf/lbf)
Φker= kerogen volume (vol/vol)
ρker= kerogen density (g/cm3)
ρb= bulk density (g/cm3)
Κ=kerogen conversion factor
Where k is a conversion factor that considers the type of kerogen, thermal maturity and elements present within the kerogen (S, O and N) which are not part of the organic content.
Table 1: kerogen conversion factor, Κ.
Obtained the value of total organic carbon present in the formation is proceed to classify it as poor if the percentage by weight of the TOC is between 0,50 to 1,00%, fair between 1.00 to 2.00%, good if this is between 2,00 to 5,00% and very good to excellent when it is greater than 5.00% (Kevin McCarthy 20 11).
Table 2: Classification of the source rock.
The values of hydrogen and oxygen obtained from the sample in the Pyrolysis test are used to calculate the hydrogen and oxygen index:
HI = 100 * S2/TOC%
OI = 100 * S3/TOC%
These values are plotted in a chart called diagram of Van Krevelen which allows classifying the organic matter in one of four different types of kerogen existing as shown below.
Figure 7: Four kerogen types (I, II III and IV) evolution paths with correlating values of Vitrinite reflectance (VR) and Thermal alteration index (TAI) (F. K. North 1985)
Table 3: Origin, type, source, and hydrocarbon potential of different kerogens.
The thermal maturity measures the degree of conversion of the organic carbon content in the formation to hydrocarbons, where their potential of generation depends on the thermal history of the rock that contains the kerogen and is linked to the temperature and pressure that this reached when it was being buried.
Its determination is important because it allows us to know the type of hydrocarbon that may contain the formation: if the rock is in an immature stage the kerogen has not reached the necessary conditions to produce oil or gas, when the kerogen is in a mature stage it's prone to hydrocarbon generation while if it has passed the stage of maturity (over mature) most of the oil has cracked to dry gas and we are front a shale gas play.
The methods used in the industry to determine the kerogen maturity are: The vitrinite reflectance (Ro), Tmax of the Pyrolysis test and the visual assessment of the colour of the organic matter.
The Vitrinite Reflectance (Ro) consists in analyzing the reflection of a beam of light in a particle of vitrinite through a photomultiplier where the values obtained are recorded as percentages. From these values the organic matter is classified as:
Oil window 0,7-1,00
Condensate/ Wet gas window 1,00-1,3
Dry gas window >1,3
The Tmax is the temperature obtained in the Pyrolysis test with which we can determine the degree of maturity achieved by the organic matter in the following way (Stage of Thermal Maturity for Oil)
Visual inspection classified the organic matter depending on its color since this suffering a gradual change from yellow to black as it is subjected to increments of pressure and temperature.
Figure 9: color change in the organic matter with the maturity degree, Dan Jarvie 2005.
These three methods are frequently used in assembly (to be available) to increase the accuracy in the determination of the thermal maturity of organic matter, being the Vitrinite Reflectance the method most used in the oil industry.
The depositional environment refers to the ecosystem in which were deposited the sediments and debris organic that constitute and have given origin to the shale formation. At this point it is important to differentiate between marine environments and non-marine (lacustrine, fluvial) as these tell us to some extent the type of kerogen that can contain the formation and the percentage of clay present in the same.
The facies characterization allows us a better understanding of the the changes in the mineralogical composition, organic content and mechanical properties of the formation, although the shale appears to be homogeneous formations of large extension with meters of thick, these are highly heterogeneous and if we move only a meter in the vertical direction its properties and content of organic matter can vary drastically. This is due to these fine-grain sediments are deposited very slowly and with subsequent compaction and lithification, a 1 meter thick interval of rock may represent thousands to millions of years of time (Passey, Bohacs, Esch, Klimentidis, and Sinha, 2010). That is why a correct lithologic model allow us to understand and select the best intervals to drill and stimulate.
Figure 10: Changes in percentage content of organic carbon (TOC) along an interval which is several tens centimetres thick. An example from the US basins (Passey et al., 2010)
The shale reservoirs show a variable and complex mineralogy including carbonates, quartz, clay minerals such as chlorite, illite, smectite and kaolinite and large detritus which may include pyrite and siderite.
Mineralogy is determined in laboratories through cores or in wells with logs: for its determination with cores and/or drilling cuttings is used petrophysical microscopes and/or Xray difraction and to determine the clay mineralogy is used X-ray difraction and/or SEM (scanning electronic microscope).
Figure 11: Ternary diagram shows shale classification.
For its determination through well logs can be used integrated the tools: nuclear, electrical and acoustic calibrated with geochemical measurements of cores in laboratories; or by geochemical log which obtained measurements of clay, carbonates, pyrite and Quartz-feldspar-mica without being affected by the presence of kerogen (C, H, O) since it measures Si, Ca, Fe, Ti, S and Gd plus other elements which improving its accuracy.
Figure 12: Interpreted Mineralogies using the RockViewTM expert system, Richard Arnold & Matt Bratovich, Baker Hughes
Once determined the percentages of clay, quartz and carbonate is proceed to calculate the Mineralogy Brittleness Index of the formation which will give us an idea of the response of the rock to the fracture treatment.
The greater is the BIM of the formation, it will tend to behave in a manner more fragile and less ductile making it conducive to the treatment of hydraulics fracturing since when this is subjected to pressure will result in a higher number of fissures and fractures.
Figure 13: comparison between ductile and brittle rock, CSUG 2008.
As a practical rule we can say that the content of silica and carbonate increases the brittleness of the formation and the clay content decreases it by what this should be less than 30% of the total to ensure a good response to the treatment.
Another way to calculate the brittleness is using the mechanical properties of the rock as will be explained below.
Mechanical Properties, Porosity, Permeability, Water Saturation, Adsorbed Gas, Formation volume, Estimating hydrocarbons in place, Risks, Sweet spot and a general conclusion.
DETERMINATION OF TOTAL CARBON, TOTAL ORGANIC CARBON AND INORGANIC CARBON IN SEDIMENTS, Bernie B. Bernard, Heather Bernard, and James M. Brooks TDI-Brooks International/B&B Laboratories Inc. College Station, Texas 77845
UNCONVENTIONAL TIGHT OIL RESERVOIRS: A CALL FOR NEW STANDARDIZED CORE ANALYSIS WORKFLOWS AND RESEARCH. Gary A. Simpson and Neil S. Fishman, Hess Corporation, 2015.
Geological characteristics and ‘‘sweet area’’ evaluation for tight Oil. Cai-Neng Zou, Song-Tao Wu, Zhi Yang, Sen-Hu Lin, Lian-Hua Hou, Qiu-Lin Guo, Ru-Kai Zhu, Jing-Wei Cui, Deng-Hua Li, She-Jiao Wang. 14 October 2015
AN INTEGRATED PETROPHYSICAL APPROACH FOR SHALE GAS RESERVOIR. Richard Arnold & Matt Bratovich, 2014, BAKER HUGHES, .
Evaluating Shale Gas Plays using the Barnett Shale Model. Dan Jarvie, Dallas SIPES Meeting Oct 18, 2005
Formation Evaluation in Shale Prospects Experience in Argentina Vaca Muerta Formation, Martin Paris, Posted March 30, 2015
Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States,Energy Information Administration (EIA), 2013.
New Evaluation Techniques for Gas Shale Reservoirs, Rick Lewis, David Ingraham, Marc Pearcy: Oklahoma City, Jeron Williamson, Walt Sawyer, Joe Frantz: Pittsburgh. 2004.
DETERMINATION OF FORMATION ORGANIC CARBON CONTENT USING A NEW NEUTRON-INDUCED GAMMA RAY SPECTROSCOPY SERVICE THAT DIRECTLY MEASURES CARBON, Jorge Gonzalez, Richard Lewis, James Hemingway, Jim Grau, Erik Rylander and Ryan Schmitt, Schlumberger 2013.
From Oil-Prone Source Rock to Gas-Producing Shale Reservoir–Geologic and Petrophysical Characterization of Unconventional Shale-Gas Reservoirs. Q. R. Passey, K. M. Bohacs, W. L. Esch, R. Klimentidis, and S. Sinha, ExxonMobil Upstream Research Co. 2010.