Characterization of Tight and Shale Unconventional Reservoirs from Logs

Transcription

1 SPE MS Characterization of Tight and Shale Unconventional Reservoirs from Logs E. R. (Ross) Crain,.Pet,rophysical Consultant, Calgary Alberta Canada Hassan Aharipour GI Technologies (Beijing) Co., Ltd; Mohsen Zeinali, Iranian Central Oil Fields Company (ICOFC) Copyright 2016, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Argentina Exploration and Production of Unconventional Resources Symposium held in Buenos Aires, Argentina, 1 3 June This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Essentially there is decline in the world conventional oil reservoirs production. The shale oil and shale gas reservoirs are extensive hydrocarbon resources however they require additional technology to enable them to be produced. In the world, unconventional reservoirs are large volume but hard to develop. Conventional resources which correspond to light crude oil and sweet natural gas trapped into porous and permeable reservoirs. These resources can be produced at a relatively low cost because hydrocarbon flow out of the reservoir by natural depletion and no expensive upgrading processing is required. As the source rock mature, a portion of the solid organic matter is transformed into the liquid hydrocarbon move into the pore space displacing the formation water. Immature shales contain solid organic carbon (kerogen) with no liquid oil. The oil is obtained by heating the rock in-situ or at the surface to mature the kerogen. When the reservoir or the fluid properties, or both deteriorate, it becomes necessary to apply specific technologies to extract and upgrade these resources. The application of these technologies comes at an increasing financial and environmental risk, which makes unconventional resources more challenging for development. Organic carbon is usually associated with silt shale. If a source rock has not been exposed to temperatures above 120 C, it is termed a potential source rock but organic carbon (kerogen) still did not transformed into the liquid oil and gas to move in the pores. Total organic carbon (TOC) measured in the laboratory and widely is used to help for evaluation of shale gas and shale oil reservoirs. Introduction The shale gas and shale oil reservoirs show remarkable variation in lithology from claystone to marlstone and mudstone to sandstone and carbonate, therefore an extended suit of logs, formation micro imager (FMI), elemental capture spectroscopy (ECS), neuclear magnetic resonance (NMR) and dipole sonic imager (DSI) are recommended. The in-situ pore volume to take account both free gas volume and adsorbed gas volume and are used for total gas reserve estimation. A multi disciplinary integration team, geologist, petrophysicist, reservoir engineer, drilling engineer, completion and stimulation engineers are needed to focuse on increasing production rates and ultimate reservoirs economically and responsabiliy from tight oil to tight gas reservoirs. Log analysis of unconventional reservoirs call core support for evaluation of organic contents. Industry standards of crushing shale gas and shale oil core samples for analysis may cause some underestimation of permeability because it cannot take account of micro fractures or any interconnectivity of the rock organic component. The rock mecanics data have essential role for quantifying shale brittleness estimations.

2 2 SPE MS The two elastic moduli commonly used by the industry to quantify shale brittleness are Poisson s ratio and Young s Modulus. Basically the purpose of drilling horizontal wells increased the contact between the reservoir and the wellbore. Due to the extremely low permeability of shale (micro to nano Darcy) gas molecules move very slowly into the shale matrix. A conventional vertical well can only produce very limited gas at low production rate. The objective of horizontal multistage hydraulic fracturing is to increase as much as possible the contact surface between wellbore and shale matrix. Sahle plays are source rocks characterized with complex pore system. Petrophysicist is dealing more with quartzic/calcareous shale, rather than a shaly sand/limestone within complex pore network and pore throat makes problem for penetration by mercury injection. The pore system includes both matrix porosity and kerogen porosity within ultra low permeabilities less than 0.1 md. The petrophysisicst has central role in unconventional field development studies, which feeds integrated team with more data than the other disciplins, made petrophysicist role vital for successing an oil company unconventional long term projects. Unconventional reservoirs mostly were developed and produced in the Northern America and worldwide no anough production history in other parts of the world and actually unconventional petrophysics did not well unknown. The lack of unconventional petrophysical experience is cuasing wrong log analysis which is producing invalid and silly results, so be sure to understand that type of the reservoir, petrophysicist is dealing with. In this paper a systematic and practical petrophysical methodologies were introduced for better understanding unconventional petrophysical models for valid reserves estimations. Methods, Procedures, Process Total Organic Carbon Characterization (TOC) Organic carbon is in the form of kerogen ancient life preserved in sedimentary source rock after degradation by bacterial and chemical processes and further modified by temperature, pressure, and time. The latter step, called thermal maturation, is a function of burial history (depth) and proximity to heat sources. Maturation provides the chemical reactions needed to give gas, oil, bitumen, pyrobitumen, and graphite (pure carbon). The organic carbon is usually associated with silt shale. If a source rock has not been exposed to temperatures above 120 C, it is termed a potential source rock but organic carbon (kerogen) still did not transformed into the liquid oil or gas to move into the pores. Total organic carbon is measured in the laboratory and widely is used to help for evaluation of shale gas and shale oil reservoirs. Total organic carbon is measured in laboratory is used to assess the quality of the source rock and widely is using to help evaluate unconventional reservoirs. Analyzing TOC in the Laboratory The total organic carbon content of rocks is obtained by heating the rock in a furnace and combusting the organic matter to carbon dioxide. The amount of carbon dioxide liberated is proportional to the amount of carbon liberated in the furnace, which in turn is related to the carbon content of the rock. The carbon dioxide liberated can be measured several different ways. The most common methods use a thermal conductivity detector or infrared spectroscopy. About 80% of a typical kerogen (by weight) is carbon, so the weight fraction of TOC is 80% of the kerogen weight. The factor is lower for less matured and higher for more matured kerogen: Wtoc = Wker * Ktoc Wker = Wtoc / Ktoc Wtoc = weight fraction of organic carbon (%) Wker = weight fraction of kerogen (%) Ktoc = kerogen correction factor - range = 0.68 to 0.90, default 0.80 Another lab procedure is called RockEval, burns both hydrogen and carbon, so the data need to be calibrated to the standard method by performing a chemical analysis on the kerogen. Rock- Eval Pyrolysis Analysis Rock-Eval combusts crushed sample of the rock at 600ºC. The rock-eval is not recommended for use with coals

3 SPE-Number-MS 3 or source rocks with significant amounts of kerogen Type III and IV. A rock sample is crushed finely enough so that 85% falls through a 75 mesh screen. Approximately 100 mg of the sample is loaded into a stainless steel crucible capped with a micro mesh filter. The analyzer consists of a flame ionization detector and two IR detector cells. The free hydrocarbons S1 determined from an isothermal heating of the sample at 340 degrees Celsius. These hydrocarbons are measured by the flame ionization detector. The temperature is then increased from 340 to 640 degrees Celsius. Hydrocarbons are then released from the kerogen and measured by the flame ionization detector creating S2 peak. The temperature at which S2 reaches its maximum rate of hydrocarbon generation is referred to Tmax. The CO2 generated from the oxidation step in the 340 to 580 degrees Celsius is measured by the IR cells and is referred to the S3 peak. Measured results from a typical Rock Eval study contain: TOC: Weight percentage of organic carbon S1: amount of free hydrocarbons in sample (mg/g) S2: amount of hydrocarbons generated through thermal cracking (mg/g) provides the quantity of hydrocarbons that the rock has the potential to produce through diagenesis. S3: amount of CO2 (mg of CO2/g of rock) - reflects amount of oxygen in the oxidation step. Ro: vitrinite reflectance (%) Tmax: temperature at maximum rate generation of hydrocarbons occurs. Calculated results included: Hydrogen index HI = 100 * S2 / TOC% Oxygen index OI = 100 * S3 / TOC% Production index PI = S1 / (S1 + S2) Figure 01 The source rock potencial is defined base on TOC weight percent (Figure 02). Figure 02 Kerogen Maturity Vitrinite reflectance (Ro) is used as an indicator of the level of organic maturity (LOM). Ro values between 0.60 and 0.78 usually represent oil prone intervals and Ro > 0.78 indicates gas prone. High values can suggest "sweet spots" for completing gas shale wells. Vitrinite Fluorescence mode observations are made on all samples and provide supplementary evidence concerning organic matter type and exinite abundance and maturity. For fluorescence mode a 3 mm BG-3 excitation filter is used with a TK400 dichroic mirror and a K490 barrier filter. The Tmax is a useful indicator of maturity, higher values being more mature. Graphs of HI vs Ro and HI vs Tmax are used to help refine kerogen type and to assess maturity with respect to the oil and gas "windows".

4 4 SPE MS Depth plots of Ro and Tmax are helpful in spotting the top of the oil or gas window in specific wells and locating sweet spots for possible production using horizontal wells (Figure 03). Figure 03 Adsorbed Gas Content (Gs) Adsorption isotherms indicate the maximum volume of methane that a gas shale can store under equilibrium conditions at a given pressure and temperature. The direct method of determining adsorption isotherm involves cutting core that is immediately placed in canisters, followed by measurements of the gas volume evolved from the shale over time. When the sample no longer evolves gas, it is crushed and the residual gas is measured (scf/ton). The Figure 04 illustrated adsorbed gas content vs TOC. Figure 04 Visual Analysis of TOC from Logs Visual analysis for organic content is based on the porosity - resistivity overlay technique, widely used to locate possible hydrocarbon shows in conventional log analysis. By extending the method to radioactive zones instead of relatively clean zones, organic rich shales (potential source rocks, gas shales and oil shales) can be identified. Usually the sonic and density logs are used as the porosity log. The key point is to align the sonic or density on top of the logarithmic scale resistivity log so that the sonic and density curves lie on top of the resistivity curve in the low resistivity shales. Low resistivity shales are considered to be non-source rocks and are unlikely to be gas shales. Shales or silts with source rock potential will show considerable crossover between the porosity log and resistivity curve. The absolute value of the sonic and resistivity in the low resistivity shale is called base-lines, and these base-lines will vary with depth of burial and geologic age. The Figure 05 demonstrated North Western Venezuela Maracaibo Lake La Luna source rock which is overlayed density and resistivity logs (yelow color) and demonstrating presence of organic carbon (Kerogen) at the top of La Luna Formation. The Passey s method underlaying deep resistivity with density was confirmed TOC rich intervals at the top of La Luna Formation.

5 SPE-Number-MS 5 Figure 05, Track no. 7 In this paper a systematic methodologies and procedures are explained to develop comprehensive petrophysical models. The integration of logs with core data is the key point to produce reliable resalts for unconventional gas shales and oil shales. TOC from Density, Sonic and GR Logs Correlation of core TOC values to log data leads to useful relationships for specific reservoirs. A strong correlation exists in some shale with uranium content from the spectral gamma ray log. In other cases, the relationship is made with density, resistivity, sonic and gamma ray logs. Variations in matrix mineralogy strongly affected this type of correlation and it is possible that mineralogy will mask any trend with TOC. The crossplot shown below is a sample plot for a particular well in the Barnett shale (Figure 06). Figure 06 Kerogen Volume Log analysis models need volume fractions of kerogen, not the weight fractions. This is found from: Wtoc = toc% / 100 Wker = Wtoc / Ktoc

6 6 SPE MS Vker = Wker / RHOker Vmat = (1 - Wker) / RHOmat Vrock = Vker + Vmat Vker = Vker / Vrock Wtoc: TOC weight Wker: kerogen weight Ktoc: kerogen factor Vker: kerogen volume RHOker: kerogen density Vmat: matrix volume Vrock: rock volume RHOmat: matrix density Kerogen Density The below plot shows TOC specific gravity (DENStoc) and rock grain density (DENSma) cross plot using inverse grain density on Y-Axis (Figure 07). DENSma = 1 / INTCPT = 1 / 0.37 = g/cc DENStoc = 1 / (SLOPE + INTCPT) = 1 / ( ) = 1.28 g/cc DENSker = DENStoc / Ktoc = 1.28 / 0.80 = 1.42 g/cc Ktoc is kerogen correction factor and range = 0.68 to 0.90, default value= 0.80 Typical values for DENSker are in the range 0.95 for immature to 1.45 for very mature, with a default of 1.26 g/cc. Figure 07 TOC Determination from Logs Passey s Method (DlogR): The most common and popular method is based on sonic vs resistivity or density vs resistivity as described in "A Practical Model for Organic Richness from Porosity and Resistivity Logs" by Q. R. Passey, S. Creaney, J. B. Kulla, F. J. Moretti and J. D. Stroud, AAPG Bulletin, V. 74, P , It is also known as "DlogR". The "D" originally is the Greek letter Delta (ΔlogR).

7 SPE-Number-MS 7 DlogR(SON)= log(rd/rsh) (DT-DTsh) DlogR(DENS)= log(rd/rsh) (RHOB-RHOsh) TOC=DlogR*10^( *LOM) DT: sonic log DTsh: shale sonic value RD: deep resistivity log RDsh: shale resistivity value DENS=density log RHOB=bulk density LOM: kerogen level of maturity TOC: total organic carbon Correlation of TOC and DlogR: Figure 08 Schmoker and Hester s Equation for TOC Weight Determination: TOC (Wt%)=( / RHOB) TOC: total organic carbon weight% RHOB: formation bulk density measured by density tool TOC Determination from Elemental Capture Spectroscopy (ECS) The ECS log measures the weight contribution of various elements in the formation for example calcium, oxygen, iron, silicon, and so forth. By using a least squares statistical approach, the elements can be composed into the minerals that might be present in the rock. For an unconverntional rock one of the minerals can be kerogen. The

8 8 SPE MS results are in weight fraction so kerogen can be compared directly to geochemical data from the lab. The TOC and XRD or XRF lab data can be used to constrain the inversions, giving results that will naturally match kerogen and mineralogy data quite well. TOC Correlation with FMI In water-base mud, the colors in micro-resistivey image of an area with high kerogen content tend to be yellow color whereas in adjacent shaly beds of low kerogen content the color is dark brown (Figure 09). Figure 09 Trend of Logs in Organic Rich Rocks High resistivity (Figure 10) Low bulk density and low PEF (Figure 11) High uranium and GR (Figure 12) Figure 10 Figure 11 Figure 12 Oil Shale and Gas Shale Clay Volume Determination

9 SPE-Number-MS 9 The shale gas and shale oil source rocks basically are not pure shale and are radioactive silt shale due to high uranium associated with the organic content. Thorium curve recommended use for shale volume determination if it is available from spectral GR. When the thorium curve is missing the total gamma ray (GR) still can be used by moving the clean and shale base lines compared to the conventional shaly sands. Be sure to adjust parameters by calibrating to XRD. Unconconvention Shales Clay, Porosity and Water Saturation Models Clay Volume from Thorium: Vcl = (TH_log - TH_clean) / (TH_sh TH_clean) Vcl: Clay volume from thorium TH_log: Thorium log TH_clean: Clean zone thorium log value TH_sh: Shale zone thorium log value Clay Volume from GR: Vcl = (GR_log - GR_clean) / (GR_sh GR_clean) Vcl: Clay volume from GR GR_log: GR tool readings GR_clean: Clean zone GR value GR_sh: Shale zone GR value Oil Shale and Gas Shale Porosity Models The unconventional shale source rocks contain both free porosity and Kerogen (Figure 13) or only kerogen (Figure 14). Figure 13 Figure 14 Figure 15 shows porosity model for organic rich shale source rock. Figure 15

10 10 SPE MS Effective Porosity Determination Effective porosity is calculated shale and kerogen corrected density neutron, A good core control is necessary. PHIdc = PHID (Vsh * RHOsh) (Vker * RHOker) PHInc = NPHI (Vsh * NPHIsh) (Vker * NPHIker) Phie = (PHInc + PHIdc)/2 PHIdc: corrected density porosity (fractional) PHInc: corrected neutron porosity (fractional) PHID: calculated density porosity (fractional) NPHI: neutron porosity (fractional) Vsh: calculated sale volume (fractional) RHOsh: Shale density (g/cc) Vker: estimated kerogen volume (fractional) RHOker: estimated kerogen density (g/cc) NPHIker: kerogen neutron porosity (fractional) NPHIsh: shale neutron porosity (fractional) Phie: calculated effective porosity (fractional) NPHIker is in the range of 0.45 to 0.75, similar to poor quality coal. Default = 0.65 Effective porosity from a nuclear magnetic resonance (NMR) did not include kerogen porosity because of kerogen low T2 relaxation decay time. So neutron density porosity (PHInd) and NMR porosity cross plot is used for calibration of neutron density porosity values in the wells without NMR data (Figure 16). Figure 16 Kerogen porosity= Neutron Density porosity - NMR porosity (Figure 17)

11 SPE-Number-MS 11 Figure 17 Water Saturation Model Water saturation is best done with Simandoux equation. C = (1 - Vsh) * a * (Rw@FT) / (Phie ^ m) D = C * Vsh / (2 * RSh) E = C / RD Sw = ((D ^ 2 + E) ^ D) ^ (2 / n) Sw: water saturation from Simandox equation (fractional) Vsh: shale volume (fractional) Rsh: shale resistivity (ohm.m) RD: deep resistivity log (ohm.m) m: cementation exponent n: water saturation exponent Rw: formation water resistivity (ohm.m) Phie: effective porosity (fractional) a: tortosity factor Capillary pressure data needed to calibrate water saturation in the free porosity. Due to low porosity, special laboratory procedures are needed. Conversion of Volumetric Results to Mass Fractions Generally volumetric results from logs convert to the mass fractions. Wtshl = Vsh * 2.35 Wtqtz = Vqtz * 2.65 Wtlim = Vlim * 2.71 Wtdol = Vdol * 2.87 Wtker = Vker * 0.95 Wtrock = = Wtsh + Wtqtz + Wtlim + Wtdol + Wtker Wtker=TOC / Wtrock Vxxx = volume fractions of the components WTxxx = weight of the components Wxxx = mass fractions of the components WT%xxx = weight percent of the components Lithology and Porosity from Multi-mineral Model Simultaneous equations solution is widely used in multi mineral evaluation from logs. A typical equation set for a gas shale and oil shale would be:

12 12 SPE MS DENS = 2.35 * Vsh * Vqtz * Vlim * Vdol * Vker * PHIe DTC = 120 * Vsh + 55 * Vqtz + 47 * Vlim + 43 * Vdol * Vker * PHIe PHIN = 0.30 * Vsh * Vqtz * Vlim * Vdol * Vker * PHIe PE = 3.45 * Vsh * Vqtz * Vlim * Vdol * Vker * PHIe 1.00 = Vsh + Vqtz + Vlim + Vdol + Vker + PHIe PHIe and Vker could come from relationships between core data and one or more log data. The above mineral properties are in English units and will need some adjustment to suit local conditions to prevent negative answers. Vsh, Vqtz, Vlim, Vdol, Vker: Volumes of shale, quartz, limestone, dolomite and kerogen Cutoff Parameters Porosity defines gas storage potential permeability hydrocarbon flow capability and TOC take place of hydrocarbon saturation as a net pay indicator. The key requirements for definition of cut-off parameters are: Sand volume Porosity Permeability TOC Gas Shale and Oil Shale Permeability Uncertainty Since permeability is an exponential function of porosity, small porosity variations make a big difference for productivity estimates. Log permeability is often pessimistic, even though the average porosity is correct (Figure 18). Figure 18 Gas Shale Total Gas In-place Total gas presents fine grained shale gas come from contribution of: Adsorbed gas which is adsorbed at the surface of the kerogen. Gas adsorption capacity is decreased with increasing temperature and maturity. Free gas found in the kerogen pores. Free Gas In-place Estimation Gf = ( * A * h * Phie * Sge / Bg)

13 SPE-Number-MS 13 Gf: free gas volume (scf) A: area of interest (acres) H: productive thickness (ft) Phie: effective porosity (fractional) Sge: effective gas saturation (fractional) Bg: free gas formation volume factor Free Gas formation Volume Factor Psc: pressure in standard conditions (psia) T: temperature (F) Z: true gas deviation factor Adsorbed Gas In-place Estimation Gs = 1,359.7 * AhρGsc Gs: sorbed gas-in-place volume (scf) A: area of interest (acres) h: productive thickness (ft) ρ : average density (g/cc) Gsc: adsorbed gas storage capacity, scf/ton, from longmuir isotherm experiment on core Free Gas and Adsorbed Gas Recovery Factor ffg: fractional free gas recovery Zi: initial z factor (dimensionless) Z: Z factor at average pressure (dimensionless) P: average pressure (psia) Pi: initial pressure (psia)

14 14 SPE MS fsg: fractional sorbed gas recovery GsL: Langmuir storage capacity (scf/ton) Gci: initial gas content or storage capacity (scf/ton) P: average pressure (psia) PL: Langmuir pressure (psia) Log Characteristics of Oil Shale Organic matter has strong radioactivity, hence the oil shale has a high gamma ray. Organic matter is a non-conducting material, thus the oil shale has a high resistivity. Organic matter has low density and its density is much lower than rock matrix density, so the oil shale has a low bulk density. Organic matters have low pef. Oil Shale Yeild (Grade) Determination The grade of oil shale can be determined by measuring the yield of an oil shale sample in a laboratory retort. The method commonly used in Canada and United States is called the modified Fischer Assay, first developed in Germany and then adapted by the U.S. Bureau of Mines. The technique was subsequently standardized as the ASTM Method. Some laboratories have further modified the Fischer Assay method to better evaluate different types of oil shales and different methods of oil shales processing. Oil Shale Yeild Determination from Fisher Assay Method Heating a 100 g sample crushed to 2.38 mm mesh, retort to 500ºC. The distilled vapors of oil, gas, and water are passed through a condenser cooled with ice water into a graduate centrifuge tube. The oil and water are separated by centrifuge. Oil yield is usually converted from mass fraction into US or Imperial gallons per tone of rock. In Canada, oil yield is quoted in liter per metric tone of rock. Emprical Equations for Estimating Oil Yield from Density and Sonic Logs A literature search quoted by R. M. Habiger and R. H. Robinson in 1985 gives the following equations for estimating oil yield: Smith (1956) Garfield County, Colorado: OY = 31.6 * DENS^2-206 * DENS OY = 22.9 * DENS^2-167 * DENS Bardsley and Algermissen (1963) Unita Basin, Utah: OY = * DENS OY = 41.01x10^-4 *DTC^ Tixier and Alger (1967) Piceance Basin, Colorado: OY = * DENS Cleveland-Cliffs (1975) Unita Basin, Utah OY = 496 * DENS^ OY = 157 * 10^-4 * DTC^

15 SPE-Number-MS 15 Oil Shale In-situ Retorting The process involves heating underground oil shale, using electric heaters placed in deep vertical holes drilled through a section of oil shale. The volume of oil shale is heated over a period from two to three years untill pyrolysis temperature until reaches F, at which point oil is released from the shale. The released product is gathered in collection wells positioned within the heated zone. Development of Oil Shale and Gas Shale Reservoirs Horizontal Wells The purpose of drilling a horizontal well is to increase the contact between the reservoir and the wellbore. Wells are drilled vertically to a determined depth above the tight reservoir. The well is then kicked off at an increase angle until it runs parallel within the reservoir. Once horizontal well is drilled to a selected length which can extend to 3-4 km. This portion of the well is called horizontal leg (Figure 19). Figure 19 Multi Stage Hydraulic Fracturing Due to extremely low permeability of shale (micro to nano Darcy), gas molecules move very slowly in shale matrix and a conventional vertical well can produce very limited gas at low rate. The objective of horizontal multistage hydraulic fracturing is to increase as much as possible contact surface between wellbore and shale matrix (Figure 20). The two elastic moduli commonly are used in the industry to quantify shale brittleness are; Poisson s ratio and Young s Modulus. Poisson s ratio is the ratio of transverse strain over axial strain. The lower Poisson s ratio,more rock brittleness. The sandstone has lower Poisson s ratio and thus is more brittle than shale. Figure 20

16 16 SPE MS Nomenclature RD: Deep resistivity TOC: Total organic carbone n: water saturation exponent m: cementation exponent Phie: effective porosity Rw: formation water resistivity Sw= water saturation from logs Rsh: shale resistivity XRD: X ray diffraction ECS: elemental capture sonde a: tortosity factor OY: oil yield Gs: adsorbed gas volume Gf: free gas volume FMI: formation micro imager ECS: Elemental Capture Spectroscopy References E.R. (Ross) Crain, Crain s Petrophysical Handbook online at Petrophysics (second addition), Djebbar Tiab & Erle C. Donaldson, Elsevier Inc, copyright 2004 Shale Gas: An Unconventional Reservoir, Sunjay, CSPG, CSEG, CWLS Convention 2011 Recent Advances in the Analytical Methods Used for Shale Gas Reservoir Gas-in-Place Assessment* By Robert C. Hartman1, Pat Lasswell2, and Nimesh Bhatta1 Search and Discovery Article #40317 (2008), Posted October 30, 2008 Evaluation of Shale Gas Reservoirs, Maqsood Ahmad, University of Adelaide 2014 Characterization of Shale Gas Reservoirs By Logging and Minerralogical Studies, Robei Sara, University of Kasdi Merbah Ouargla, Algeria 2013

17 SPE-Number-MS 17 Petrophysics and Shale Gas Development in the Middle East, Robert S. Kuchinski, Kuwait SPWLA Chapter 2012 Direct Method for Determining Organic Shale Potential from Porosity and Resistivity Logs to Id tif P ibl R Pl Identify Possible Resource Plays, T. Bowman, AAPG Symposium New Orleans 2010 Petrophysical Characterization of the Marcellus & Other Gas Shales, Daniel J. Soeder, NETL, Morgantown, WV, AAPG Eastern Section Meeting, Arlington, Virginia 2011