Quantitative Mineralogy of Reservoir Rocks Using Fourier Transform Infrared
Spectroscopy

Ballard, Bryce

doi:10.2523/113023-stu

Cited by 8 publications

(5 citation statements)

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“…The FTIR mineralogy (see Sondergeld and Rai, 1993;Ballard, 2007) of the two Wolfcamp shale samples (XX86, XX88) is shown in Fig.2. Illite is found to be the dominant clay mineral.…”

Section: Flow Regime Testmentioning

confidence: 99%

Comparison of Steady-State and Transient Methods for Measuring Shale Permeability

Mathur

Sondergeld

Rai

2016

SPE Low Perm Symposium

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Shale matrix permeability is important in evaluating the economic viability of unconventional reservoirs. Inconsistent permeability measurements reported from pressure decay analysis on crushed rock samples is forcing a re-examination of core plugs measurements. Various methods have been developed to measure permeability on core plugs which include steady state and transient methods. Because of the use of different techniques to measure permeability by different laboratories it becomes necessary to compare the resulting values. An experimental apparatus has been developed which has the capability to measure permeability using steady state and several transient methods.To compare some permeability values, appropriate gas corrections have to be applied. Gas corrections depend on the flow regime prevalent during the measurement. The transient flow regime dominates at low pressures when the pore sizes are small. In the transition flow regime, gas permeability measurements cannot be corrected with a simple Klinkenberg correction but require second order permeability correction such as the double slip correction. An experimental investigation to understand the flow regime at different pore pressures was carried out on two Wolfcamp shale samples. Steady state permeability of these samples was measured using helium and nitrogen at a constant effective pressure of 3000 psi over different pore pressure ranges from 100 psi to 3000 psi; the permeabilities were corrected using the Klinkenberg and the double slip correction. It was assumed that whichever correction resulted in similar permeabilities for both gases over the pore pressure range, would be the appropriate correction for that range. It was found that for pore pressures less than 250 psi permeabilities required second order corrections, indicating a transition flow regime at these pore pressures in shales. However at pore pressures greater than 2000 psi permeabilities required negligible corrections. It is therefore recommended to use pore pressures greater than 2000 psi for gas permeability measurements in shale.Permeability of five horizontal Wolfcamp shale samples were measured using steady state and transient methods at an effective pressure of 3000 psi using nitrogen gas. Three measurements were applied for each method at pore pressures less than 250 psi and a double slip correction was applied. The three methods yielded similar permeabilities with differences being less than 30%. Therefore transient methods provide comparable results to steady state gas permeability measurements when the proper corrections are applied.

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“…The FTIR mineralogy (see Sondergeld and Rai, 1993;Ballard, 2007) of the two Wolfcamp shale samples (XX86, XX88) is shown in Fig.2. Illite is found to be the dominant clay mineral.…”

Section: Flow Regime Testmentioning

confidence: 99%

Comparison of Steady-State and Transient Methods for Measuring Shale Permeability

Mathur

Sondergeld

Rai

2016

SPE Low Perm Symposium

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“…Mineralogy was determined through transmission infrared spectroscopy the details of this technique are given in Sondergeld and Rai (1993) and Ballard (2007). Noteworthy in the mineralogy is the lack of any secondray minerals, such as clays, in particular (see Fig.…”

Section: Figure 3-compilation Of Porosity and Permeability Data Repormentioning

confidence: 99%

Petrophysical Study of UAE Carbonate Outcrop at Jabal Hafit

Sondergeld

Wampler

Abdelghany

et al. 2016

SPE Annual Technical Conference and Exhibition

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Jabal Hafit consists of Tertiary outcrops that give insight into stratigraphic sequences and regional reservoirs in the Middle East. This study examines outcrops from various strata in the Rus, Dammam, and Asmari Formations varying from Early Oligocene to Eocene in age. These Formations exist throughout the UAE and Middle East and contain some large regional hydrocarbon reservoirs.This study examines porosity, permeability, mineralogy, NMR, MICP (mercury injection capillary pressure), and SEM images for 72 core samples. FTIR (Fourier Transform Infrared) mineralogy shows that these samples are calcite dominated carbonates with two strata being dolomite dominated. Sample porosities decrease linearly with increasing pressure and range from 0.47 to 27.26%. Klinkenberg permeabilities decrease linearly with increasing pressure for most samples, with some samples showing nonlinear pressure dependence indicating the presence of cracks. Permeabilities range from 0.0002 to 54.85 md. A porositypermeability correlation has been developed based on measured core data. The Reservoir Quality Index is used to identify similar reservoir flow characteristics and two flow zones have been identified across the three Formations. The second flow zone demonstrates some permeability pressure dependence. NMR shows bimodal pore distributions in some samples as well as extreme variability from layer to layer. A comparison of NMR, ϕ NMR , and Boyle's Law, ϕ He , porosities shows good agreement at porosity values lower than 10% with the ϕ NMR < ϕ He at larger porosities. The Free Fluid Model and Mean T 2 Model are used to estimate permeability from NMR data. Corrected T 2 cutoffs are determined from S wir via centrifuge method to define the correct Bound Volume Irreducible (BVI) and Free Fluid Index (FFI) for each sample. Measured T 2 cutoff times range from 2.38 to 598 ms. Calibrated and uncalibrated Free Fluid Model and Mean T 2 Model permeabilities are compared with measured core permeability values. For these samples, the Mean T 2 Model gives a better permeability estimate. SEM images reveal the bulk of the pores are equant in shape and document the existence of microporosity. Some MICP and NMR measurement capture the bimodal pore distributions.

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“…Total porosity was determined with the method proposed by Karasthatis (2007). Mineralogy was determined with transmission Fourier Transform Infrared spectroscopy (FTIR) (Sondergeld and Rai, 1993;Ballard, 2007), and TOC was measured with the Leco method. Prior the NMR study the shale samples were stored in glass vial for approximately 2 years.…”

Section: Nmr Study Of Brine and Oil Saturated Shalesmentioning

confidence: 99%

“…( 1) In equation 1, the subscript bulk indicates bulk relaxation time, ρ2 is the surface relaxivity. S/V denotes the pore surface to volume ratio.…”

Section: Introductionmentioning

confidence: 99%

NMR Response of Brine, Oil, and Methane in Organic Rich Shales

Tinni

Odusina

Sulucarnain

et al. 2014

SPE Unconventional Resources Conference

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The application of NMR methods to evaluate the fluid content in hydrocarbon reservoirs requires the understanding of the NMR response of the fluids present in the rock. The presence of multiple fluids which can be in liquid, gaseous or adsorbed phase in nanometer size pores (associated with various minerals and organic matter) add another degree of complexity to the interpretation of NMR data in shales. This report presents the findings of a laboratory study on the NMR responses of brine, oil and methane in shales. The acquisition of the NMR data was made at 2MHz. NMR T2 distributions were acquired at TE = 0.2ms on companion core plugs from the Haynesville shale and at TE = 0.3ms for Barnett and Woodford shale samples. The NMR T 2 distributions acquisitions were conducted on samples saturated with brine (2.5% KCl) and oil (dodecane). The NMR T 2 data acquired on the native state samples (as received) showed a bimodal distribution with the dominant peak at T 2 less or equal to 1ms. After saturation in parallel with oil and brine with increasing saturation pressures we observed in the case of brine an increase in amplitude of the NMR peak located at T 2 less or equal to 1ms. At higher saturation pressures we observed a shift in the T 2 time of this peak toward longer T 2 times. When the samples were saturated with oil and the saturation pressure increased we observed the development of second NMR T 2 peaks around 6-20 ms with no substantial increase of the peaks at T 2 less than 1ms; the observed distributions are bimodal. The measurements with methane were conducted at TE = 0.3ms on 2 Haynesville core plugs at a methane pressure of 4000 psi and a confining pressure of 5000psi. The NMR T 2 distributions that were essentially unimodal in the as received state with a peak at 0.35-0.4ms, evolved into a bimodal distribution in response to the injection of methane. The first peak was observed at the same T 2 time as in the as received state with no substantial change in amplitude and second peak was located at 10-20ms ms. This results show that the NMR response of methane and oil is similar. Monitoring the saturations increase with NMR show that brine can enter the entire pores spectrum while oil and methane have access only to a fraction of the pore space.

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Quantitative Mineralogy of Reservoir Rocks Using Fourier Transform Infrared Spectroscopy

Cited by 8 publications

References 0 publications

Comparison of Steady-State and Transient Methods for Measuring Shale Permeability

Comparison of Steady-State and Transient Methods for Measuring Shale Permeability

Petrophysical Study of UAE Carbonate Outcrop at Jabal Hafit

NMR Response of Brine, Oil, and Methane in Organic Rich Shales

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