London South BankUniversity

PETROPHYSICS PRESENTATION

PETROPHYSICAL EVALUATION OF HAYNESVILLE SHALE GAS RESERVOIR

Prepared by:

Eneotu, Maclean Jacob - 2928554

Mohsin Hassan - 3222401

Ahmed Hussein - 2936451

Kingsley, Green Okpara - 2932743

Prepared for:

Dr. Pedro Diaz

08 January 2014

Summary

This report is intended to provide an overview of the petrophysical evaluation carried out in Haynesville shale gas reservoir in the United States of America. This is important because of the role that petrophysical evaluation of reservoirs plays in the oil and gas industry in terms of exploration and reserves estimate.

Various petrophysical properties were considered including mineralogy and lithology, total organic carbon (TOC), porosity, permeability, fluid saturation etc. The various methods used in evaluation in these properties in Haynesville shale gas play were considered together with comparison of different methods used for evaluation of a particular property. For example, in terms of porosity evaluation, porosity evaluation by NMR log and porosity evaluation by crush rock method was considered. For Haynesville reservoir, integrated petrophysical evaluation techniques which involved the use of some conventional logging tools and other unconventional methods were employed.

From the study, it was found that the various log analyses and core analyses for the petrophysical evaluation of Haynesville shale gas reservoir were in agreement, with only little discrepancies. In addition, unlike other shale gas reservoirs with ultra-low porosity, the Haynesville reservoir has a relatively good porosity (4.6%). Summary of average core analysis properties and relevant parameters for the Haynesville shale gas reservoir are shown in Appendix 1.

From the findings of this study, it was concluded that the Haynesville shale gas reserve has a good resource potential. This conclusion was based on the estimated total organic content (TOC); this was estimated to be 2.3 wt.-%.

1.0 Introduction

The main objective of this report was to study the petrophysical evaluation of Haynesville shale reservoir. The Haynesville shale is an unconventional gas reservoir extending from East Texas to Northwest Louisiana (see figure 2) .The Haynesville shale is black, organic-rich shale of Upper Jurassic age that is approximately 10,500 –13,500 feet deep.

Shale gas reservoirs usually have low porosity but the Haynesville shale’s porosity has been found to be usually higher than other shales, indicating its ability to contain more gas. Little wonder, the recent estimate of its recoverable reserve done in 2009 showed that Haynesville shale has a recoverable reserve of 75 trillion cubic feet of recoverable gas, second only to the Marcellus Formation in the US, while its proven reserve estimation carried out in 2011 showed that Haynesville shale has a proven reserve of 29.5 trillion cubic feet of gas (US Energy Information Administration, 2011).

Like every other unconventional hydrocarbon reservoir, petrophysical evaluation of reservoir properties in Haynesville shale proved to be quite challenging. Possible factors that contributed to this challenge include variable and complex mineralogy, difficulty in acquiring native state core samples etc. In addition, shale gas petrophysical interpretations could also be challenging since the gas-bearing shale deposits usually function as reservoir, source and seal at the same time. Thus, they would be characterized by all three elements.

Typical evaluation of shale gas reservoirs include determination of some petrophysical properties like total organic carbon (TOC), gas-filled porosity and total porosity, lithology and mineralogy, matrix permeability, fluid saturation (mostly gas and water), vitrinic reflectance or level of maturity etc.

“Generally, proper petrophysical evaluation or characterization of shale-gas reservoirs require an integrated analysis of an extensive logging suite to determine the highly variable mineralogical composition, organic carbon content, porosity, and fluid saturations, among other relevant petrophysical properties that assist well completion decisions” (Ramirez, et., al 2011).

For Haynesville shale, various evaluation methods were applied for determination of different petrophysical properties. For example, mineralogy and lithology determination was done by both gamma-ray spectrometry and X-ray diffraction, total organic carbon determination was done by both the deltaLogR method and from NMR log, and porosity determination was done by crush dry rock method and also from NMR log. For Haynesville petrophysical evaluation, the proposed workflow for Shale gas petrophysical evaluation as proposed by Quirein et al., (2010) was used as shown figure 3.

This report will look into the results obtained from these various methods, and compare the various measurements.

2.0 Geology of Haynesville Gas Play

The Haynesville Shale is black, organic-rich shale mainly mudstones of Upper Jurassic age that underlies much of the Gulf Coast area of the United States, extending from East Texas to Northwest Louisiana. The Haynesville Formation overlies the Smackover Formation and is overlain by rocks of the Cotton Valley Group (relatively solid limestone sometimes referred to as the Haynesville limestone). Haynesville stratigraphic column is shown in figure 1. Figure 2 shows an outline map of Haynesville shale reservoir showing the geographic areas covered by the gas play in East Texas and Northwest Louisiana.

Fig. 1 – Haynesville stratigraphic column (Ramirez, et al., 2011)

Fig. 2 – Outline map of Haynesville shale reservoir showing the geographic areas covered by the gas play in East Texas and Northwest Louisiana in dashed red.

Source: Energy Information Administration based on data from HPDI, TX Railroad Commission, LA Dept. of Natural Resources, Operators. Updated May 26, 2011. http://www.eia.gov/oil_gas/rpd/shaleusa4.pdf

3.0 Petrophysical Evaluation of Haynesville Shale

For the petrophysical evaluation of Haynesville shale gas reservoir, a proposed workflow for shale gas reservoir as given in the literature of Quirein et al., (2010) was used. This workflow is shown in figure 3. Also the petrophysical techniques for laboratory evaluation of shale gas petrophysical properties as proposed by the Gas Research Institute in 1996 was used (quoted in Sondergeld et. al 2010). See Appendix 2.

Fig. 3- Proposed workflow for Shale gas petrophysical evaluation as proposed by Quirein et. al., (2010).

3.2 Petrophysical evaluation methods used in Haynesville shale gas reservoir for the determination of various petrophysical properties.

3.2.0 Mineralogy and Lithology determination 3.2.1 Multi-Mineral Method with Geochemical and Standard Triple Combo Logs.

In an attempt to develop proper evaluation methods or techniques for shale gas formations like Haynesville gas play, a lot of effort has been in to place. Some of these efforts include the use of special logging techniques like spectral elemental analysis or spectroscopy logging, geochemical logging, triple combo logging etc.

For Haynesville shale gas play, the multi-mineral geochemical logging tool string (GLT) developed by Schlumberger was used. This tool consists of four separate logging tools; the aluminium activation clay tool (AACT), the natural gamma-ray spectrometry tool (NGT), the compensated neutron tool (CNT), and the gamma-ray spectrometry tool (GST). A schematic drawing of the GLT which was used in Haynesville is shown in figure 3.

These four tools used three separate modes of gamma-ray spectrometry for a comprehensive elemental analysis of the formation. The NGT is located at the top of the tool string so that it can measure the naturally occurring radio nuclides, thorium (Th), uranium (U), and potassium (K), before the radioactivity is induced by the nuclear sources contained in the lower tools.

The CNT, located below the NGT, carries a Californium (252Cf) neutron source to activate the Al atoms in the formation. The AACT, a modified NGT, is located below the 252Cf source, measuring the activated gamma-rays in the formation. Scott and Smith (1973) showed that by combining the AACT measurement with the previous NGT measurement, the background radiation can be subtracted out and a reading of the formation Al is obtained.

The gamma-ray spectrometry tool, at the base of the string, carries a pulsed neutron generator to induce prompt-capture gamma-ray reactions in the borehole and formations and a NaI(Tl) scintillation detector to measure the energy spectrum of gamma rays generated by the prompt neutron capture reactions.

The spectrum from the GST, in conjunction with elemental concentrations from the NGS tool and AACT, allows derivation of the concentration of elements in the formation rock, such as Si, Ca, Fe, S, Ti, K, and Gd. Data from the tools in the string are sent by telemetry to the surface by the telemetry communication cartridge or cable communication cartridge (cable communication electronics). Lithology and mineralogy are then determined using the elemental weight fractions from the geochemical measurements

3.2.2 Analysis of actual rock samples for lithology and mineralogy determination

The two main methods employed in this are the X-ray diffraction analyses (XRD) which measures the amount of specific minerals in a rock sample and X-ray fluorescence analyses which measure the amount of specific elements in a rock sample. For Haynesville, XRD was used. The result is shown in figure 5 which shows that the most abundant mineral in Haynesville shale gas play is illite. A comparison of the results from the gamma-ray spectrometry tool with log analysis is shown in table 1.

Fig. 4 - Schematic drawing of the Schlumberger geochemical logging tool string used in the Haynesville shale gas evaluation (Gonçalves and Ewert, 1998)

Fig. 5- Bratovich and Sommer (2009)

Keys for mineralogy and lithology determination

Table 1: Comparison of log determined mineralogy to core XRD (Parker et., al 2009)Mineral XRD

(wt-%)Mineral Spectroscopy(wt-%)

Chlorite 1.4 0Calcite 0.0 0.5Quartz 46.2 43.2Illite 4.5 5Pyrite 0.4 1.1Siderite 0.0 0.0Sodium feldspar 9.9 11.6Anhydrite 7.7 10.2Dolomite 15 17.5

3.3 Total organic carbon (TOC) determination.

TOC determination is very important in shale gas petrophysical evaluation. One reason for this is because it is generally used to predict the resource potential of a shale gas play as shown in table 2. Another reason for this is because of its relationship to porosity (see figure 6). Thus, how much TOC is present in a shale gas can tell how much adsorbed gas the reservoir has.

Generally, TOC is associated with the organic compound; kerogen. “The TOC of 10 wt% is associated with an approximate kerogen volume of 20 vol%” (Bust et al., 2013). Unfortunately, the neutron and density logs sense kerogen as an additional porosity. Consequently, with an actual kerogen volume of 20 vol%, and without accounting for kerogen in the interpretation, the traditional neutron-density cross plot porosity will be high by 20 vol%. For Haynesville shale gas reservoir, two methods were used for TOC determination. These are the 3.1.2 ∆ logR technique and NMR method.

Table 2- Relationship between total organic carbon and resource potential (Alexander, et. al 2011).

Total Organic Carbon (Weight %) Resource Potential< 0.5 Very poor0.5 to 1 Poor1 to 2 fair2 to 4 Good4 to 10 Very good> 10 Unknown

Fig. 5- Relationship between total porosity and TOC (wt-%) Passey et. al., 2010)

3.3.1 ∆ logR Technique for TOC determination of Haynesville Shale Gas Reservoir

In Haynesville shale play, the total organic carbon content (TOC) was estimated using the method developed by Passey et al., (1990). This method is called the ∆ logR techniques, and it uses common widely available well logs (porosity/resistivity) logs to identify organic-rich shale and calculate their TOC by the empirical formula given below:

TOC=[DLogR∗10(2.297−0.1688∗LOM )] (1)

Where:

TOC is the total organic carbon in wt%LOM is the level of maturity (unitless)DLogR is the curve separation measured in logarithmic resistivity cycles = Log (RESD / RESDbase) - 2.5 * (DENS – DENSbase)

Where:

RESD = deep resistivity in any zone (ohm-m)RESDbase =  deep resistivity baseline in non-source rock (ohm-m)DENS = density log reading in any zone (gm/cm3) DENSbase = density in non-source rock (gm/ cm3)

To simplify the above formula, Passey et al., also gave a graphical form of the equation as shown in figure 6.

Fig. 7 – Graphical representation for TOC estimation as postulated by Passey et al., (1990)

To use the graphical form of the equation, LOM and ∆ logR have to be known. To get LOM, vitrinite reflectance (Ro) values were converted to LOM with the graph below. For Haynesville; the vitrinite reflectance is 1.6% (see appendix 2). Thus, the level of maturity was estimated to be approximately 12 (that is high thermal maturity). Then from figure 7, the total organic carbon (TOC) was estimated to be approximately 2.3 wt-%.

Fig. 6 - Graph for finding Level of Organic Maturity from Vitrinite Reflectance

(Crain’s Petrophysical Handbook, http://spec2000.net/11-vshtoc.htm)

3.3.2 TOC determination by core analysis.

A second approach for TOC evaluation in Haynesville was done by core analyses. This was carried out using NMR, fluid density, bulk density and the reservoir mineralogical data. This relationship is given as:

V TOC=ρm−ρgrρm−ρTOC

(2a)

ρgr=ρb− ρfluid∅

(1−∅ ) (2b)

mTOC=

ρTOCρgr

∗ρm− ρgr

ρm−ρTOC

(2c)

Where:

ρb is the bulk density

ρgr is the total grain density including inorganic and organic matrix constituents

Ø is the NMR total porosity

ρfluid is the density of pore filling fluid, determined from NMR fluid typing

VTOC is the volume fraction of organic matrix components

mTOC is the mass fraction of organic matrix components

A comparison between the well log (∆ logR ) TOC evaluation method and the core method of TOC evaluation is shown in track 5 of figure 7. The comparison shows that both methods were reasonably in agreement.

Fig. 7 - Interpretation results for a representative Haynesville well (Quirein et al. 2012)

Track 1 presents the correlation logs, and Track 2 depicts the mineralogy, from left to right, kerogen, chlorite, illite, pyrite (red), sodium feldspar (orange), calcite, quartz, clay-bound water, free water, and gas-filled porosity. Track 3 presents the fluid volumes (gas, clay-bound water, and free water), but also includes the kerogen matrix volume. The yellow circles represent the core gas-filled porosity, and the green circles show the core porosity. The volume of gas is broken down into its matrix (red) and kerogen (dull red) gas-filled porosity. Track 4 compares the core and well logs TOC. Track 5 presents the grain density, and Track 6 presents pyrite.

3.4 Porosity determination

Porosity calculations from neutron and log measurements usually come with significant uncertainties due to the variable mineralogies and the variable amounts of low density organic material present in these reservoirs. Furthermore, conventional logs for porosity evaluation may sense the porous kerogen often seen in a typical shale gas as an additional porosity. A typical pore structure of a shale gas showing this additional kerogen is shown in figure 8.

Fig. 7 - Typical shale gas pore structure (Sondergeld, et al, 2010)

In the petrophysical evaluation of Haynesville shale gas reservoir, two methods were used for porosity determination. These methods are:

3.4.1 Nuclear Magnetic Resonance (NMR) Log

Due to the variable mineralogies in the Haynesville shale gas reservoir, conventional porosity logging measurements like the neutron and density logs were not used. Rather an NMR log was used. The reason for this is that NMR logging measurements does not depend on the mineralogy of the matrix, except in cases in which the formation contains significant amounts of ferromagnetic or paramagnetic materials. Comparison of this method of porosity determination of shale gas reservoir and the core analysis (crush dry rock) method are shown in table 4 and figure 9.

3.4.2 Porosity determination by crush dry rock method

This method of porosity determination of shale gas reservoir usually follows the process shown in figure 8.

Fig. 8 – Crush dry rock method of porosity determination.

∅=(V b−Vg)/Vb (4)

Where:

Vb=W d/ ρbdWhere:∅ is porosityV b is bulk volume

Vg is grain volume

W d is weight of dry, crushed core sample (g)ρbd is bulk density of dry whole core (g/cm3)

For the gas-filled porosity, same equation as (4) was used, except that the bulk volume will be given asVw=Ww / ρbw

Where:W w is weight of wet, crushed core sample (g)ρbw is bulk density of wet whole core (g/cm3)

For the set of 25 samples selected for Haynesville petrophysical evaluation, average total porosity was 2.47 % before crushing and 6.30 % after crushing. Table 3 shows the porosity results comparing the crushed samples to the whole core pieces. The gas-filled porosity estimated was 4.6%.

Table 3- Porosity comparison of whole core sample and crushed samples for Haynesville shale gas.

Whole Core Crushed Samples

Depth Porosity (%) Grain Density (g/cm3)

Porosity (%) Grain Density (g/cm3)

2346.6 1.9 2.59 8.7 2.722347.1 1.8 2.55 5.4 2.632348.3 3.7 2.45 12.6 2.682349.9 3.9 2.36 12.2 2.582350.5 3.9 2.4 12.1 2.62351.7 2.4 2.33 13.3 2.592352.8 1.6 2.42 6.3 2.6

The low apparent values of porosity and grain density measured on the whole core pieces were caused by incomplete penetration of the pore network by helium during the grain-volume measurement. For these measurements on the whole cores, up to about 30 minutes was allowed for apparent equilibrium, compared with 1 minute or less required for most reservoir rocks.

For the very low permeability in these shales, however, 30 minutes is insufficient. Crushing the core samples improves by a factor of 10,000 the ratio of surface area to volume divided by the characteristic length that the helium has to penetrate during grain-volume measurement. This combined ratio multiplied by then permeability of the rock sample controls the speed of the grain-volume measure.

All pore space in this low-porosity formation is regarded as interconnected, despite the small pore sizes and extremely low permeability. Other workers have shown that, in low-porosity sandstones, carbonates, or crystalline rocks, virtually all pores remaining after cementation, mineralization, and diagenesis retain some interconnectivity. Therefore, crushing the Haynesville shale should not create entry into any pores that previously were isolated.

Table 4- Comparison between NMR total porosity and Core rushing total porosity for Haynesville Shale gas reservoir (Ramirez, et al 2011).

Depth (ft) ID Total porosity (%) NMR

Total porosity (%) Core crushing

10556 X556.0 3.1 4.3110560 X560.0 3.6 5.2110565 X565.0 3.110570 X570.0 3.2 5.56

10574.5 X574.5 4.0610580 X580.0 3.1 5.28

10584.5 X584.5 2.7 3.910595 X595.0 2.210600 X600.0 3.01

Fig. 9- Comparison of crush rock method and the NMR log (log method).

The comparison between the two methods used in the determination of porosity of Haynesville shale gas play shown in track 1 in the figure above shows a good agreement between both methods.

3.5 Permeability

According to Passey et al (2010), porosity determination of Haynesville gas play was done using the pressure or pulse decay method on crushed rock samples. The Pulse Decay Permeameter (See figure 10) which is widely used for ultra-low permeability tight gas sands, cap rock and other very low permeability rock was used. This instrument uses a pulse decay measurement technique developed by Core Laboratories.

In this technique, a small pore pressure pulse is applied to one end of a jacketed sample and the pressure vs. time behaviour is observed as the pore fluid moves through the sample from one reservoir to another. Initially both valves are open and pressure is constant throughout the system. Next, valve 1 is closed and the pressure is changed slightly in the large Reservoir 1. Valve 1 remains closed for a few minutes to allow thermal effects to diminish (particularly important if the pore fluid is gas). Valve 2 is then closed and at time equal zero, valve 1 is opened. A small differential pressure between the reservoirs will be indicated by the ∆P transducer and will decrease with time.

Pressure in Reservoir 1 remains constant during the decay. Because a valve is required between the sample and the reservoir which applies the pressure pulse, it is desirable to apply the pressure pulse through the large reservoir so opening the valve will not

significantly change the reservoir volume. After the differential has decreased by approximately 20%, the decay is terminated by opening valve 2. This accelerates the equilibration of pressure so the next measurement can be made.

As the pressure transient propagates though the sample, the computerized data acquisition system records the delta pressure across the sample, the downstream pressure, and time. A log differential pressure times mean pressure versus time plot was displayed real time on screen. Permeability was then calculated from a linear regression performed on the pressure time data and the results stored to a data file.

Fig. 9- Schematic of a Pulse Decay Permeameter (Bourbie and Walls, 1982)

3.6 Evaluation of fluids saturation

3.6.1 Water Saturation

In conventional reservoirs, the use of Archie equation can be used to determine water saturation. This equation is based on porosity and resistivity logs.

SwT=n√ a∗Rw∅ T

m∗Rt

To apply the above equation, the following properties in addition to total porosity have to be known:

Resistivity of the rock (Rt) Rock electric parameters (a, m and n) Formation water resistivity

It is pertinent to note here that in conventional reservoirs, Archie attributed the increase of true formation resistivity relative to the resistivity of water to hydrocarbon occupying part of the pore space. The presence of conductive solids in the form of clay minerals was later treated as excess conductivity or a non-Archie component in the saturation equation, because it was seen to reduce formation resistivity.

However, in shale gas reservoirs petrophysics, a third component exists in the form of solid kerogen which has a reveres or opposite effect to clay minerals in that it increases formation resistivity. The NMR tool could have offered a potential solution for the evaluation of water saturation independent of resistivity measurement.

However, the measured data may not properly represent the co-existence of free and adsorbed gas. The gas adsorbed to the surface of the kerogen is problematic and may not respond in the same way as free gas because there are solid-like constituents associated with its composition (Ramirez et al. 2011).

In Haynesville shale gas play, a new approach was used called the “pseudo-Archie approach”. In this method, the Archie equation was used but the cementation and saturation exponents were different from their respective defaults, m = n = 2. In this case, it was m = n = 1.7.

To calculate water saturation from log analysis, it is important to establish formation-water salinity. Because formation water rarely is produced from the Haynesville shale, water salinity is essentially unknown. Through use of the cores from some air-drilled wells, the water salinity was measured directly on crushed core samples. A sample split of 20g of crushed rock was mixed and equilibrated with 100mL of ion-free distilled water. Chloride ion was then measured on a water sample with an ion chromatograph and, in some cases, by titration. This chloride content was then converted to sodium chloride and allocated back to the bulk volume of formation water measured in a companion crushed sample with the analysis procedures described previously. In the Haynesville shale gas play, the formation water salinity was measured to be 190,000 ppm (190 kppm).

3.6.2 Gas saturation (Sg):

The gas saturation was obtained when water saturation (Sw) in the samples were subtracted from 1 that is one minus Sw that is (1-Sw).

Conclusions

At the end of this study, the following conclusions can be drawn

• Evaluation of Haynesville shale gas petrophysical properties gas play like every other was quite challenging due to variable mineralogies and lithologies.

• An integrated approach is the best way for shale gas petrophysical evaluation.

• Pseudo-Archie water saturation evaluation method was used in Haynesville shale gas reservoir evaluation.

• Information gathered from the various evaluation methods was useful in optimizing the stimulation methods for the Haynesville shale.

• There was agreement between various methods used for the evaluation of a particular petrophysical property of the Haynesville shale.

• The Haynesville shale gas play has good porosity compared to other shale gas play.

• Most of Haynesville shale gas reservoir mineral compositions are illite.

Group ReflectionAs a group, our interpersonal skills were significantly developed. This was because the four people in the group were on different wavelengths; those with natural presentation skill, those with good grasp of the subject studied, etc. As a group, new things were learnt in the course of working on this project.

From the several meetings held, the group became a proper functioning unit through a blend of concession and coaction, thereby enhancing our interpersonal development.

On what could have been done differently to improve in the future, the group agreed that communication is very important in every team work, and as such the forum on Blackboard could have been used a lot better to share information and for general communication. Overall, all members of the group agreed that the exercise was a good one to undertake.

Personal Reflections

Maclean Jacob Eneotu - Functioning as the group leader in this project has helped enhanced my leadership and team- working skills. The project was quite challenging as we had to choose a difficult case study (shale gas). At the end, it was worthwhile.

Mohsin Hassan – This project has given me the opportunity to learn something new and also develop my inter-personal skills.

Ahmed Hussein – Working on this project was really interesting as it gave me the chance to really get interested in the world of unconventional petroleum resources.

Kingsley Green Okpara - A very exciting project to work on. I believe my team-working skill has improved significantly.

References

Bourbie, T., & Walls, J. (1982). Pulse decay permeability: Analytical solution and experimental test. Old SPE Journal, 22(5), 719-721. [Online] Available from: http://www.onepetro.org/mslib/app/Preview.do?paperNumber=00009744&societyCode=SPE [Accessed: 01 December 2013].

Bratovich, M., & Sommer, D. A. (2009). Application of an Integrated Petrophysical Evaluation Approach to North American Shale Gas Reservoirs. in: 2nd SPWLA Regional Symposium, Mumbai, India, November 2009. Society of Petrophysicists and Well Log Analysis, pp. 1-14. [Online] Available from: http://spwlaindia.org/download.php? folderName=past...aPPLICATION.pdf [Accessed: 29 November 2013].

Bust, V. K., Majid, A. A., Oletu, J. U., & Worthington, P. F. (2013). The Petrophysics of Shale Gas Reservoirs: Technical Challenges and Pragmatic Solutions, in: International Petroleum Technology Conference, Bangkok, Thailand, February 2012. International Petroleum Technology Conference (IPTC 14631), pp. 1-16. [Online] Available from: http://www.onepetro.org/mslib/app/Preview.do?paperNumber=IPTC-14631-MS&societyCode=IPTC [Accessed: 29 November 2013].

Parker, M., Buller, D., Petre, J., & Dreher, D. (2009). Haynesville Shale-Petrophysical Evaluation, in: SPE Rocky Mountain Petroleum Technology Conference, Denver, Colorado, USA, April 2009. Society of Petroleum Engineers (SPE 122937), pp. 1-11. [Online] Available from: http://www.onepetro.org/mslib/app/Preview.do?paperNumber=SPE-122937-MS&societyCode=SPE [Accessed: 30 November 2013].

Passey, Q., Bohacs, K., Esch, W., Klimentidis, R., & Sinha, S. (2010). From Oil-Prone Source Rock to Gas-Producing Shale Reservoir-Geologic and Petrophysical Characterization of Unconventional Shale-Gas reservoirs, in: International Oil and Gas Conference and Exhibition, China, June 2010. Society of Petroleum Engineers (SPE 131350), pp. 1-27. [Online] Available from: http://www.onepetro.org/mslib/app/Preview.do?paperNumber=SPE-131350-MS&societyCode=SPE [Accessed: 28 November 2013].

Ramirez, T., Klein, J., Bonnie, R., & Howard, J. (2011). Comparative Study of Formation Evaluation Methods for Unconventional Shale Gas Reservoirs: Application to the Haynesville Shale (Texas), in: North American Unconventional Gas Conference and Exhibition, Woodlands, Texas, USA, June 2011. Society of Petroleum Engineers (SPE 144062), pp. 1-31. [Online] Available from: http://www.onepetro.org/mslib/app/Preview.do?paperNumber=SPE-144062-MS&societyCode=SPE [Accessed: 29 November 2013].

Sondergeld, C., Newsham, K., Comisky, J., Rice, M., & Rai, C. (2010). Petrophysical Considerations in Evaluating and Producing Shale Gas Resources, in: SPE Unconventional Gas Conference, Pittsburgh, Pennsylvania, USA, February 2010. Society of Petroleum Engineers (131768-MS), pp. 1-34. [Online] Available from: http://www.onepetro.org/mslib/servlet/onepetropreview?id=SPE-131768-MS [Accessed: 01 December 2013].

APPENDIX 1

Table 4- Summary of average core analysis properties and relevant parameters for the Haynesville shale gas play (Ramirez, et. al., 2011).

Property / Parameter Value Units CommentMineralogy: Total Clay 31 wt-% XRD, dominantly illite, chloriteTOC 2.3 wt-% TOC content by Leco analyserGas-filled porosity 4.6 % GRI crushed sampleTotal porosity 6.3 % GRI crushed sampleAverage permeability 0.0056 mD low permeabilityVitrinite reflectance 1.6 % High thermal maturity

Haynesville thickness 95 ftThinner than other area penetrations

Fluid pressure gradient 0.75 psi/ft Estimated, DFIT analysisGeothermal gradient 2.055 °F/100ft Bresch and Carpenter,2009Formation water salinity 190 kppm Core crushing and leachingAverage water saturation

31.8

Average clay bound water

19.1

APPENDIX 2

Petrophysical Techniques for Evaluating Shale Reservoir as proposed by the Gas Research Institute in 1996 (Sondergeld et. al., 2010)

APPENDIX 3

SOME CORES USED FOR HAYNESVILLE SHALE GAS RESERVOIR EVALUATION