Pulse-decay Permeability Research Articles

Impact of Petrophysical Properties on Hydraulic Fracturing and Development in Tight Volcanic Gas Reservoirs

The volcanic reservoir is an important kind of unconventional reservoir. The aqueous phase trapping (APT) appears because of fracturing fluids filtration. However, APT can be autoremoved for some wells after certain shut-in time. But there is significant distinction for different reservoirs. Experiments were performed to study the petrophysical properties of a volcanic reservoir and the spontaneous imbibition is monitored by nuclear magnetic resonance (NMR) and pulse-decay permeability. Results showed that natural cracks appear in the samples as well as high irreducible water saturation. There is a quick decrease of rock permeability once the rock contacts water. The pores filled during spontaneous imbibition are mainly the nanopores from NMR spectra. Full understanding of the mineralogical effect and sample heterogeneity benefits the selection of segments to fracturing. The fast flow-back scheme is applicable in this reservoir to minimize the damage. Because lots of water imbibed into the nanopores, the main flow channels become larger, which are beneficial to the permeability recovery after flow-back of hydraulic fracturing. This is helpful in understanding the APT autoremoval after certain shut-in time. Also, Keeping the appropriate production differential pressure is very important in achieving the long term efficient development of volcanic gas reservoirs.

Effects of rock mineralogy and pore structure on stress-dependent permeability of shale samples.

We conducted pulse-decay permeability experiments on Utica and Permian shale samples to investigate the effect of rock mineralogy and pore structure on the transport mechanisms using a non-adsorbing gas (argon). The mineralogy of the shale samples varied from clay rich to calcite rich (i.e. clay poor). Our permeability measurements and scanning electron microscopy images revealed that the permeability of the shale samples whose pores resided in the kerogen positively correlated with organic content. Our results showed that the absolute value of permeability was not affected by the mineral composition of the shale samples. Additionally, our results indicated that clay content played a significant role in the stress-dependent permeability. For clay-rich samples, we observed higher pore throat compressibility, which led to higher permeability reduction at increasing effective stress than with calcite-rich samples. Our findings highlight the importance of considering permeability to be stress dependent to achieve more accurate reservoir simulations especially for clay-rich shale reservoirs.This article is part of the themed issue 'Energy and the subsurface'.

Dual-permeability microstratigraphy in the Barnett Shale

We observed multi-scale porosity and permeability at the cm-scale in a Barnett Shale core through a pulse-decay permeability test. The core is composed of alternating layers of silty-claystone and claystone. We interpret the silty-claystone has a permeability of 3.41×10−20 m2 (34.6 nD) and a porosity of 5.6% and that the claystone has a permeability of 1.80×10−23 m2 (0.0182 nD) and a porosity of 4.8%. The horizontal effective permeability is 2.05×10−20 m2 (20.8 nD) and we estimate the vertical effective permeability to be 4.58×10−23 m2 (0.0452 nD). The effective permeability anisotropy ratio is approximately 450. These results suggest that relatively high-permeability carrier beds drain organic rich lower permeability beds. The microstratigraphy of mudstones has a fundamental control on flow, and may provide an explanation for recent studies that have suggested either pervasive natural fracturing or extraordinary levels of induced fracturing are necessary to explain shale production behavior.

Investigation on the variation of shale permeability with spontaneous imbibition time: Sandstones and volcanic rocks as comparative study

The development of gas shale needs a large scale of hydraulic fracturing during the process of well completion. However, the rate of flow-back is always less than the half of the injected fluid. Thus, a large number of fracturing fluid becomes retention in the shale reservoir and aqueous phase trapping (APT) appears. APT appears after well drilling, completion, work over and stimulation operation, caused by fluid filtrating into formation and resulting in permeability reduction. However, after the well was shut in for a period of time in shale gas development, the APT can be auto-removed. In order to investigate the auto-removal mechanism of shale reservoirs, related experiments were performed. In this paper, we used pulse-decay permeability method to monitor the permeability change of shale rocks during the process of shale rocks spontaneous imbibition. At the same time, the sandstones and volcanic rocks did as control samples. From the experiments, the permeability of sandstones and volcanic rocks decreases with increasing imbibition time, and there are no cracks produced in the process of imbibition of these two kinds of samples. However, during the process of shale rocks imbibition, cracks appear on the surface of samples, which may be caused by clay swelling. Simultaneously, the permeability of shale rocks fluctuates apparently. Some shale samples even have the specific interval that the permeability increases with soaking liquid time. This specific phenomenon may be caused by the new produced cracks, which increases the pore volume. Because the matrix of shale has the characteristic of hydrophobicity, much of the new pores couldn't be occupied by the liquid under the effect of spontaneous imbibition. Thus, the gas flowing channels tremendously increase. However, the stress sensitivity can lead to shale permeability decrease, which impacts the variation of permeability under certain confining pressure. These findings contribute to better understanding the shale APT auto-removal after hydraulic fracturing.

Petrophysical and geomechanical characteristics of Canadian tight oil and liquid-rich gas reservoirs: I. Pore network and permeability characterization

Abstract The results from an ongoing laboratory study investigating petrophysical characteristics of the Montney and Bakken formations in Canada are presented. The primary objectives are to (1) characterize the pore network (porosity, pore size distribution) and fluid transport (permeability) properties of these formations in areas with limited datasets and (2) analyze the effects of different geological factors on porosity, pore size distribution and permeability. The techniques used for characterization include: Rock–Eval pyrolysis; bitumen reflectance (BRo); grain size measurement; helium pycnometry; low-pressure gas (N2) adsorption (surface area, pore size distribution); pressure-decay profile permeability, pulse-decay and crushed-rock gas (N2, He) permeability and fracture permeability tests. Rock–Eval analysis and microscopic observations indicate that most samples are organic-lean (average TOC content: 0.3 wt.%), ranging from fine-grained siltstone to very fine-grained sandstone (grain size range: 27–53.7 μm). The measured permeability values on core plugs increase with increasing porosity (2.1–14.1%), ranging between 3.3 ⋅ 10−6 and 7.3 ⋅ 10−2 mD. For the core plugs analyzed (“as-received”), profile (probe) permeability values (9.2 ⋅ 10−4–7.3·10−2 mD) are consistently higher than pulse-decay (1.6 ⋅ 10−5–3.9 ⋅ 10−2 mD) and crushed-rock (3.3 ⋅ 10−6–4.6 ⋅ 10−5 mD) permeability values. Corrected profile (probe) permeability values for “in-situ” effective stress (5.3 ⋅ 10−5–2.5 ⋅ 10−2 mD) are, however, comparable with the pulse-decay (1.6 ⋅ 10−5–3.9 ⋅ 10−2 mD) permeability values. Unpropped fracture permeability, determined using an innovative procedure in this work, can be significantly (up to eight orders of magnitude) higher than matrix permeability under similar effective stress conditions. The grain size data are correlated to permeability values. The dominant pore throat diameter controlling fluid flow is estimated for all samples using Winland-style correlations; these values agree with those obtained from low-pressure N2 adsorption analysis. Applying multiple analysis techniques on a large number of samples (26 m of slabbed core, 22 core plugs and their accompanying cuttings), this study provides a comprehensive petrophysical characterization of Montney and Bakken tight oil and liquid-rich gas reservoirs in Canada.

Impacts of nanopore structure and elastic properties on stress-dependent permeability of gas shales

This paper presented the stress-dependent porosity and permeability measurements of shale in lower Silurian Longmaxi Formation using a PoroPDP-200 Pulse decay permeameter. The pore structure was investigated by mercury injection and nitrogen adsorption measurements. Micron-sized fractures and nanopore structure of shale samples were identified through mercury saturation curves and adsorption–desorption isotherms. Uniaxial and triaxial tests were conducted so as to measure the elastic parameters of the shale samples. Three analytical models of pore compressibility were displayed to investigate the effects of pore geometry and rock elastic properties on pore compressibility. Pulse-decay permeability measurements revealed that an exponential function could describe the permeability deterioration upon applied effective stress. The stress-dependent permeability of shale was more sensitive than sandstone because of the high pore compressibility. It could be observed from analytical models that pore compressibility increased with a decreasing pore aspect ratio and Young's modulus. Microfractures were identified by the shape of mercury capillary pressure curves. The nanopores of the shale samples were dominated by a slit-shaped geometry (low aspect ratio), which was observed by hysteresis loop of nitrogen adsorption analysis (Type H3). Uniaxial and triaxial tests results showed that static Young's modulus of shale samples were sensitive to total organic carbon (TOC) and montmorillonite-illite mixed layer content. Pore compressibility was sensitive to the aspect ratio, yet insensitive to Young's modulus above 20 GPa. When the Young's modulus was less than 20 GPa, pore compressibility was both sensitive to aspect ratio and Young's modulus. The stress-dependent permeability data of samples with micron-sized fractures could also be fitted to the Walsh model, which showed that the permeability of microfractures in shale samples were more sensitive to effective stress than hydraulic fractures because of the fracture scale. These results showed that reservoir engineers could accurately predict the stress-dependent permeability in shale, and estimate the gas flow properties in macro-scale and micro-scale pores and fractures.

A comparison of shale permeability coefficients derived using multiple non-steady-state measurement techniques: Examples from the Duvernay Formation, Alberta (Canada)

Matrix permeability, while an important control on fluid flow in unconventional reservoirs, is difficult to measure in the laboratory. There are now multiple methods for laboratory determination of permeability for shales, but little consensus on the appropriate method for permeability measurement. Each technique is based on different physical principles and utilizes reservoir samples at different scales. The combination of sample size and preparation and measurement conditions can lead to a wide range in permeability estimates, creating confusion for recipients of the data. In this work, we compare different non-steady state methods for determination of gas permeability in low-permeability Canadian shales and provide insight into the causes of permeability variation. Further, we analyze and discuss the effects of different controlling factors including porosity, pore-fluid content, mineralogy and effective stress on permeability.Gas permeability measurements were conducted on low-permeability (shale) samples from the Duvernay Formation (Alberta, Canada) using three different methods: profile (probe), pulse-decay and crushed-rock permeability techniques. The analyzed samples differ in total organic carbon (TOC) content, pore network characteristics (porosity, pore size distribution), pore-fluid content (“as-received” and cleaned/dried) and mineralogy. Profile (probe) and crushed-rock permeability measurements were performed on samples in the “as-received” and cleaned/dried conditions. Pulse-decay measurements were conducted on samples in the cleaned/dried state. Helium pycnometry/expansion measurements were performed using “as-received” and cleaned/dried samples under unconfined and controlled “in situ” effective stress conditions.Permeability values derived for the Duvernay samples are strongly dependent on measurement technique, sample size and sample conditions. In the “as-received” state, profile (probe) permeability values, both uncorrected (3.7×10−4–2.7×10−2mD) and corrected (1.5×10−5–5.7×10−4mD) for “in-situ” stress, are consistently higher than crushed-rock (3.7×10−7–5.9×10−6mD) permeability values. Similarly, in the cleaned/dried state, profile (probe) permeability values, both uncorrected (1.9×10−2–1.2mD) and corrected (5.8×10−5–1.4×10−2mD) for “in-situ” stress, are consistently higher than pulse-decay (8.4×10−5–7.6×10−4mD) and crushed-rock (3.8×10−5–1.1×10−3mD) permeability values. In the cleaned/dried state, pulse-decay permeability values (8.4×10−5–7.6×10−4mD) are comparable with crushed-rock (3.8×10−5–1.1×10−3mD) permeability values. Profile (probe) and crushed-rock permeability values measured on cleaned/dried samples are approximately two orders of magnitude higher than those measured on “as-received” samples.The observed discrepancies between permeability values derived from the various non-steady-state techniques is rationalized in terms of sample size, treatment, stress-state and physical principals of measurement. The combined use of these methods is however recommended to provide insight into the controls of sample heterogeneity at sub-cm scales, which is particularly important for shale samples.

New Method Research of Tight Oil Reservoir Pulse Decay Permeability Measurement

The permeability of tight oil reservoir is very low and general perm-plug method always has a big difference. The results can’t reach the test accuracy requirements. This paper measured 26 block rocks of Changqing tight oil reservoir and several typical tight oil reservoirs in CNPC with pulse decay new method. The result shows that the pulse decay permeability measured in the new method and steady-state Klinkenberg-corrected permeability have a good relationship. We drew a figure about the porosity and steady-state Klinkenberg-corrected permeability of these tight oil reservoirs. This research offers a technical support to the tight oil reservoirs about basic data permeability measurement.

Characterization of pore systems in seal rocks using Nitrogen Gas Adsorption combined with Mercury Injection Capillary Pressure techniques

Porous microstructure parameters of seal rock samples originating from different depths within Brazilian geological formations were correlated to empirical models which predict the intrinsic permeability. Mercury Injection Capillary Pressure (MICP) and Nitrogen Gas Adsorption (N2GA) were applied in combination as complementary techniques; MICP to obtain the porosity values and the size distribution of meso- and macropores, and N2GA associated with the Brunauer, Emmett and Teller (BET) theory to determine the specific surface area (So). The Barret, Joyner and Hallenda (BJH) theory was applied to find the size distribution of the micro- and mesopores. The combination of the MICP and N2GA curves showed that the samples analyzed present a polymodal pore size distribution (PSD) and a total porosity ranging from 0.33 % to 10.44 %. The So values measured by N2GA were higher than those calculated by MICP, due to the majority of the samples having a mean pore size of 20–1000 Å. The intrinsic permeability could also be predicted applying the measured parameters, So, PSD curves and total porosity in the Carman–Kozeny and Series–Parallel models. The ranges of permeability values obtained were 4.09 × 10−24–4.96 × 10−21 m2 and 9.48 × 10−27–9.14 × 10−22 m2, respectively. These results were compared with values reported in the related literature and those obtained for four samples submitted to pressure pulse decay permeability (PDP) tests.

Geological evaluation of Halfway–Doig–Montney hybrid gas shale–tight gas reservoir, northeastern British Columbia

Evaluation of the reservoir quality of the Triassic Halfway–Montney–Doig hybrid gas shale/tight gas reservoir in the Groundbirch field in northeastern British Colombia requires an integration of unconventional and conventional methodologies. Reservoir evaluation includes reservoir thickness and structure, total porosity, TOC content, organic maturity, pore size distribution (micro- to macro-pore size fractions), surface area, mineralogy and pulse-decay permeability. Quartz (10–74%), carbonate (13–73%) and feldspar (0–42%) dominate the mineralogy of all formations with illite (0–32%) being locally important. The Tmax values range between 443 and 478 °C placing the reservoirs beyond the oil window. Pore size distribution by low-pressure gas adsorption analysis identifies a large variation between the contributions from the micro-, meso- and macro-pore size fractions. Matrix permeabilities range between 1.0E-3 and 6.5E-7 mD at an effective stress between 2400 and 3300 PSI (16.5–22.8 MPa).Changes in depositional environments and diagenetic processes manifest as differences in lithology and mineralogy within the Montney and Doig reservoirs which subsequently affect the fabric, texture and pore size distribution. Fabric, texture and pore size distribution contribute to the variation in the permeability and the proportions of free to sorbed gas within the reservoir. Quartz-rich, coarser-grained intervals (upper portions of Doig C, B and Halfway Formation) have lower surface area, greater porosities and a higher volume of macropores compared to the carbonate- and clay-rich finer-grained intervals (Doig A). Permeabilities do not vary according to lithology with higher permeabilities found within both fine-grained (Doig A) and coarser-grained (Halfway Formation) units. Permeability is controlled by pore size distribution. Higher permeability samples contain a balanced ratio between micro-, meso- and macro-porosity. The finer-grained intervals have higher sorbed gas capacity due to higher surface areas because of the higher volumes of finer mesopores and micropores than the coarser-grained units. However, porosity and permeability are low in some parts of the Doig A and fracture stimulation is necessary to achieve economic flow rates.

Innovative methods for flow-unit and pore-structure analyses in a tight siltstone and shale gas reservoir

Tight gas reservoirs are notoriously difficult to characterize; routine methods developed for conventional reservoirs are not appropriate for tight gas reservoirs. In this article, we investigate the use of nonroutine methods to characterize permeability heterogeneity and pore structure of a tight gas reservoir for use in flow-unit identification. Profile permeability is used to characterize fine-scale (1 in. [2.5 cm]) vertical heterogeneity in a tight gas core; more than 500 measurements were made. Profile permeability, although useful for characterizing heterogeneity, will not provide in-situ estimates of permeability; furthermore, the scale of measurement is much smaller than log scale. Pulse-decay permeability measurements collected on core plugs under confining pressure were used to correct the profile permeability measurements to in-situ stress conditions, and 13-point averages of profile permeability were used to relate to log-derived porosity measurements. Finally, N2 adsorption, a new method for tight gas was used to estimate the pore-size distribution of several tight gas samples. A unimodal or bimodal distribution was observed for the samples, with the larger peak corresponding to the dominant pore-throat size, as confirmed by independent methods. Furthermore, the adsorption-desorption hysteresis loop shape was used to interpret the dominant pore shape as slot-shaped pores, which is typical of many tight gas reservoirs. The N2 adsorption method provides rapid analysis and does not suffer from some of the same limitations of Hg injection. In the future, we hope that the N2 adsorption method may prove useful for flow-unit characterization (based on dominant pore size) of fine-grained (siltstone-shale) tight gas reservoirs.

Laboratory pressure pulse decay permeability measurement of Boda Claystone, Mecsek Mts., SW Hungary

The Boda Claystone Formation (BCF), explored as a possible geological disposal of HLW in Hungary, has peculiar physical and chemical characteristics. Due to the petrophysical behaviour many new methods and experimental development were applied, while the traditional methods, e.g. steady state flow test on the basis of Darcy’s law, are too time-consuming. The pressure pulse decay (PPD) technique destinated to estimating gas and water permeability is one of these new methods developed for the BCF study. The main advantage of the PPD permeability compared with traditional permeability measurements is that very fast (in case of k g ∼ 10 −19 m 2 15–25 min, k w ∼ 10 −21 m 2 6–7 h), only 0.1–0.5 MPa pressure difference applied in the two sides of the examined core, quasi in situ circumstances can be provided and their uncertainty estimated. For the correct interpretation of results of the three cores originated from different underground boreholes of the formerly URL’s Alpha-1 drift, geochemical, minerological and petrophysical analysis were carried out. The time-consumption of drying, the fact that the dry core absorbed humidity of the atmosphere very fast, as well as the unsuccess of saturation under vacuum drew attention to the importance of the necessity of careful preparation and handling as well as the necessity of geochemical and mineralogical analysis.

A Technique for Faster Pulse-Decay Permeability Measurements in Tight Rocks

Summary Laboratory pulse-decay measurements using a gas or liquid are effective for determining the permeability of rocks in the range from 0.1 md to 0.01 μd. The actual measurement time with this pressure-transient technique is fairly short, but pressure pre-equilibration sometimes requires hours. This paper shows how the total time can be reduced significantly, especially if the sample's pore volume (PV) is measured independently or estimated accurately. Permeability is calculated from "late-time" measurements. Strategies for minimizing errors and increasing sample throughput are presented.

Pulse decay permeability: Analytical solution and experimental test : Bourbie, T; Walls, J Soc Petr Engr J, V22, N5, Oct 1982, P719–721

Pulse decay permeability: Analytical solution and experimental test : Bourbie, T; Walls, J Soc Petr Engr J, V22, N5, Oct 1982, P719–721

Pulse Decay Permeability: Analytical Solution and Experimental Test

Abstract A new analytical solution is presented for the laboratory pulse decay permeability problem. With this solution, permeability of a core sample can be calculated from the decay rate of a pressure pulse applied to one end of the sample. This development permits rapid, accurate measurement of permeability in samples such as tight gas sands, limestones, and shales.