Low-permeability Sandstone Reservoirs Research Articles

Applying NMR T2 Spectral Parameters in Pore Structure Evaluation—An Example from an Eocene Low-Permeability Sandstone Reservoir

The Eocene low-permeability sandstone reservoirs in the Dongying Depression, Bohai Bay Basin, China host a significant amount of oil reserves. The development of the reservoirs has been hampered by our inability to understand the complex and heterogeneous pore structures of the reservoirs. In this study, the pore systems, pore sizes, pore connectivity, and movable fluid distribution of the Eocene Shahejie Formation (Es4) sandstone reservoirs were investigated using an integrated analysis of optical and scanning electron microscopy (SEM), mercury injection capillary pressure (MICP), and nuclear magnetic resonance (NMR). The full-range pore structures of the Es4 sandstone reservoirs were evaluated by using NMR experiments. Various NMR T2 spectral parameters suitable for describing the pore structures and movable fluid distribution were extracted through morphological and statistical analysis of NMR T2 spectra. In combination with corresponding MICP data and petrophysical properties, we have demonstrated the reliability and robustness of the T2 spectral parameters for pore structure characterization. Four types of pore structures (I, II, III, and IV) were distinguished from the NMR T2 spectral parameters in association with other petrophysical properties and macroscopic behaviors. We have demonstrated the effectiveness of using the NMR T2 spectral parameters to characterize and classify micropore structures, which may be applied to effectively evaluate and predict low-permeability reservoir quality.

Pilot Test of Surfactant/Polymer Flood with Mixtures of Anionic/Cationic Surfactants for High-Temperature Low-Permeability Sandstone Reservoir

Summary The first pilot test of a surfactant/polymer (SP) flood in the world with mixtures of anionic/cationic surfactants (Sa/c) was performed in a high-temperature and low-permeability sandstone reservoir with a high content of clay to demonstrate the potential of this novel technique to improve oil recovery. Low critical micelle concentration of 2.78×10−6 mol/L, ultralow interfacial tension (IFT) of 10−3 to 10−4 mN/m when surfactant concentrations were greater than 0.025 wt%, and lower phase microemulsion with solubilization ratio of 22, as well as oil-washing rate of 61%, were obtained by using Sa/c. Carboxymethylcellulose sodium was adopted as an adsorption inhibitor (AI) to reduce the adsorption because of the high clay contained in the natural core. With the addition of AI, dynamic adsorption of Sa/c was approximately 0.30 mg/g sand, and the IFT remained nearly unchanged before and after adsorption. The viscosities of polyacrylamide with molecular weight (MW) of 6.16×106 daltons and SP were 3.0 and 4.1 mPa·s, respectively. Coreflooding results showed that more than 16% of original-oil-in-place (OOIP) crude oil was recovered by SP over waterflood. The pilot test of SP containing Sa/c was performed in a Sinopec reservoir with temperature of 83°C, salinity of 1.69%, permeability of 41.5 md, and clay content of 10 to 16%. A total of 0.40-pore volume (PV) chemicals, including 0.1-PV polymer preslug, 0.25-PV SP main slug, and 0.05-PV post-polymer drive, were injected from August 2012 to December 2017 with an injection rate of 0.08 PV/yr. Then, waterdrive was conducted. Maximal water cut decreased from 82.2 to 62.1%, and the peak daily oil production increased from 12.2 to 32.3 t. The oil recovery was increased by 8.0% of OOIP within 4 years.

Effects of the mechanical response of low-permeability sandstone reservoirs on CO2 geological storage based on laboratory experiments and numerical simulations

Carbon dioxide (CO2) geological storage (CGS) is an effective way for reducing greenhouse emissions. The injection of CO2 into the deep formation changes the pore pressure and effective stresses in the reservoir, thus leading to changes in stress-dependent porosity and permeability. These changes give feedback to the injection rate, migration, storage amount of CO2 in the target reservoir. In this study, we focus on the Liujiagou reservoir, one of the first demonstration CGS project in saline aquifers in the Ordos Basin, China. The mathematical model that defines the relationship between the permeability and the injection pressure (or effective stress) was obtained by laboratory experiments. On this basis, the permeability-stress law was successfully integrated into the thermo-hydro-mechanical (THM) coupled simulator TOUGH2Biot to simulate the feedback between the flow and mechanical response. The improved simulator was used to analyze the effects of reservoir mechanical response on CO2 geological storage efficiency. The modeling results indicated that the mechanical response of the reservoir had little effect on reservoir pore pressure and porosity, but it had a significant effect on reservoir permeability and the migration distance, injection rate, and total storage amount of CO2. The maximum increases in the lateral migration distance of CO2 caused by the reservoir mechanical response reached 13.1% using 5 MPa injection pressure. In addition, the total CO2 storage amount increased by 11.6% after 5 years of continuous CO2 injection. Furthermore, when the injection pressure was greater, the reservoir mechanical response had stronger enhancement effects on CGS. Overall, the results suggested that the reservoir mechanical response during CO2 injection was beneficial for increasing CGS efficiency and emphasized the importance of considering the mechanical response in CGS.

Experimental Investigation of the CO2 Huff and Puff Effect in Low-Permeability Sandstones with NMR.

For low-permeability sandstone reservoirs, CO2 huff and puff is an effective method for increasing oil recovery. Commonly, sandstone formations with low permeability have diverse pore and throat sizes and a complex pore-throat structure, which essentially affects the flow characteristics of CO2 and oil in the formation and further the CO2 huff and puff performance. It is necessary to understand the recovery degree of various microscale pore sizes under different operational parameters during CO2 huff and puff in tight sandstones. In this work, several experiments of cyclic CO2 injection are conducted with sandstone core samples with low permeability. Before and after the injection, the T2 spectra of the sandstone cores are compared using the NMR technique. We then discuss the micro residual oil distribution and recovery degree in different pores, such as micropores (<1 ms), small pores (1–10 ms), medium pores (10–100 ms), and macropores (>100 ms). It is found that the recovery degree in the different pores increases as the pore size increases. Oil can be recovered more easily from macropores and medium pores during the cyclic CO2 injection. The oil contained in micropores is relatively difficult to extract considering a high capillary force under immiscible conditions. It is found that the total recovery degree increases with the increase in soaking time. However, such a recovery degree increment in small pores is not as large as that achieved in medium and large pores. With the CO2 injection volume increase, the total recovery degree increases. When the CO2 injection volume is less than 1.5 PV, it is challenging to extract the oil from micropores and small pores. As the cycle number increases, the cyclic oil recovery decreases, and most of the oil is produced in the first cycle. This suggests that under the experimental conditions of this study, the cycle number of CO2 huff and puff shall not be more than 3. This work is important to further understand the CO2 huff and puff process for improving oil recovery in sandstone reservoirs with low permeability.

Study on percolation mechanism of low permeability reservoir

The development practice of low permeability reservoir shows that there is start-up pressure gradient in low permeability reservoir, and the lower the permeability is, the higher the start-up pressure gradient is. Therefore, there are different types of sandstones in low-permeability sandstone reservoirs, with different permeability and different starting pressure gradient, resulting in different seepage space. This paper attempts to establish mathematical model and numerical simulation model to simulate the movement law of oil and water in low permeability reservoir by considering different seepage space and its starting pressure, so as to study the distribution and variation law of invalid water injection in space, and provide basis for formulating reasonable injection production ratio and other injection production policies.

Modeling of gas saturation based on acoustic wave and pore structure classification and application in the low-porosity and low-permeability reservoir

Gas saturation is an essential parameter in natural gas reservoir evaluation. As complex pore structure reduces the resistivity contrast between gas and water layers, gas saturation is difficult to calculate accurately by rock resistivity in low-porosity and low-permeability reservoir. The gas saturation is positively correlated with the relative value of compressional wave (P wave) slowness’ square based on the rock acoustic wave theory. In this study, rock samples are divided into four types of pore structures according to nuclear magnetic resonance (NMR) data. Relation models between the gas saturation and the relative value of P wave slowness’ square are established for each type. New models are further applied in field logging data in low-porosity and low-permeability gas-bearing sandstone reservoirs. The result shows that the new models calculated gas saturation is in good agreement with the gas-producing test. This paper provides a new way of qualitative evaluation of gas saturation. It enriches effective evaluation methods in low-porosity and low-permeability gas-bearing reservoirs with non-electrical logging data.

Impact of Diagenesis on the Low Permeability Sandstone Reservoir: Case Study of the Lower Jurassic Reservoir in the Niudong Area, Northern Margin of Qaidam Basin

The Lower Jurassic reservoir in the Niudong area of the northern margin of Qaidam Basin is a typical low permeability sandstone reservoir and an important target for oil and gas exploration in the northern margin of the Qaidam Basin. In this paper, casting thin section analysis, scanning electron microscopy, X-ray diffraction, and stable isotope analysis among other methods were used to identify the diagenetic characteristics and evolution as well as the main factors influencing reservoir quality in the study area. The predominant types of sandstone in the study area are mainly feldspathic lithic sandstone and lithic arkose, followed by feldspathic sandstone and lithic sandstone. Reservoir porosity ranges from 0.01% to 19.5% (average of 9.9%), and permeability ranges from 0.01 to 32.4 mD (average of 3.8 mD). The reservoir exhibits robust heterogeneity and its quality is mainly influenced by diagenesis. The Lower Jurassic reservoir in the study area has undergone complex diagenesis and reached the middle diagenesis stage (A–B). The quantitative analysis of pore evolution showed that the porosity loss rate caused by compaction and cementation was 69.0% and 25.7% on average, and the porosity increase via dissolution was 4.8% on average. Compaction was the main cause of the reduction in the physical property of the reservoir in the study area, while cementation and dissolution were the main causes of reservoir heterogeneity. Cementation can reduce reservoir space by filling primary intergranular pores and secondary dissolved pores via cementation such as a calcite and illite/smectite mixed layer, whereas high cement content increased the compaction resistance of particles to preserve certain primary pores. δ13C and δ18O isotopes showed that the carbonate cement in the study area was the product of hydrocarbon generation by organic matter. The study area has conditions that are conductive to strong dissolution and mainly occur in feldspar dissolution, which produces a large number of secondary pores. It is important to improve the physical properties of the reservoir. Structurally, the Niudong area is a large nose uplift structure with developed fractures, which can be used as an effective oil and gas reservoir space and migration channel. In addition, the existence of fractures provides favorable conditions for the uninterrupted entry of acid fluid into the reservoir, promoting the occurrence of dissolution, and ultimately improves the physical properties of reservoirs, which is mainly manifested in improving the reservoir permeability.

Pore Structure Characterization of Eocene Low-Permeability Sandstones via Fractal Analysis and Machine Learning: An Example from the Dongying Depression, Bohai Bay Basin, China.

Poroperm analysis, mercury injection capillary pressure (MICP), and nuclear magnetic resonance (NMR) measurements were performed to delineate the pore structures and fractal behaviors of the Eocene low-permeability sandstones in the Dongying Depression, Bohai Bay Basin, China. Three types of pore structures (I, II, and III) have been classified by applying the self-organizing map (SOM) clustering model. Comparative analysis of three different fractal models indicates that the MICP tubular model and NMR model are quite effective for pore structure characterization. The results show that the reservoirs generally exhibit high fractal dimensions, indicative of complex pore structures. The presence of small pore throats is primarily responsible for the heterogeneities and complexities in the Eocene low-permeability sandstones. A modified Winland model was established for the permeability estimation using MICP data. Different from high-permeability reservoirs or unconventional (e.g., shale and tight formation) reservoirs, r10 is the best parameter for permeability estimation, indicating that the permeability of the Eocene low-permeability sandstones is largely controlled by the large pore systems. Additionally, a porosity model derived from movable fluids using NMR data has been established and provided better prediction effect compared with the classic Coates and Schlumberger Doll Research (SDR) models. Fractal analysis and permeability estimation are shown to be quite effective for investigating microscopic behaviors and in predicting the reservoir quality of low-permeability sandstone reservoirs.

Numerical simulation of formation damage by drilling fluid in low permeability sandstone reservoirs

Understanding the formation damage surrounding the well during the drilling operation is the key to predict damage degree and protect the formation in oil/gas reserviors. Based on the core drainage results, we obtained an empirical relationship between the invasion volume of drilling fluid and permeability reduction of formation. Furthermore, the equation is incorporated into a commercial reservior numerical simulation simulator to characterize the behaviors of drilling fluid invasion process. The results show that, although the invasion depth in low permeability reservoirs is short with the range of 1.7–2.5 m, the effect on recovery factor is significant due to the narrow seepage area in the near fracture region. When considering the formation damage, the pressure in the near-fracture damage region drops sharply, leading to a three-stage shape in pressure distribution curve. In addition, we found that high viscosity and low density oil-based slurry and shorter soaking period are conducive to decrease the formation damage during drilling operation. This work reveals the fundamental mechanisms of formation damage in low permeability reservoirs, which is a theoretical basis in formulation drilling fluids and optimization operation parameters.

Effect of Injection Pressure on CO2 Huff-n-Puff in Low-Permeability Sandstone Cores Using Nuclear Magnetic Resonance

In order to figure out the micro-scale recovery degree of different pore sizes, the T2 spectrum of low-permeability sandstone cores before and after CO2 huff-n-puff is obtained using NMR technique. The results show that the micro-scale recovery degree increases with increase of pore sizes. Oil in macropores and medium pores is more easily produced, and Oil in micropores is difficult to recover at 7-12MPa. The total recovery degree of three cores increases with the increase of injection pressure. This study is expected to be significant for understanding the mechanisms of CO2 huff-n-puff for enhancing oil recovery in low-permeability sandstone reservoirs.

Geochemical advances in Arctic Alaska oil typing – North Slope oil correlation and charge history

The Arctic Alaska petroleum province is geologically and geochemically complex. Mixed hydrocarbon charge from multiple source rocks and/or levels of thermal maturity is common within an individual oil pool. Biomarker and chemometric statistical analyses were used to correlate twenty-nine oils to five oil families derived from: (1) Triassic Shublik Formation (calcareous organofacies), (2) Triassic Shublik Formation (shaly organofacies), (3) Jurassic Kingak Shale, (4) Cretaceous shale (pebble shale unit and Hue Shale), and (5) Paleogene shale (Canning Formation). Age-diagnostic and source-related oil biomarker parameters establish clear genetic relationships between the normal oil-window components and their putative source designations. However, application of diamondoid analyses reveals mixed-oil accumulations with postmature charge contributions (diamondoid-rich and biomarker-poor) in many oils.Most sampled reservoirs contain a predominant charge derived from a single oil-window source plus a minor contribution from one or more higher maturity source(s). Variations in source organofacies also are recognized in the Shublik, Kingak, and Cretaceous oil families. In some cases, oils from multiple pools within a single field display relatively homogeneous geochemical profiles, suggesting a common source and migration pathway. For example, oil from the significant Pikka discovery is inferred to originate mainly from the calcareous Shublik Formation. In other cases, variability among oils from multiple pools within a single field (e.g., Milne Point, Colville River, and Northstar) likely indicates a more complex source, migration, and charge history. Results may be useful for anticipating the composition of oil charge in stratigraphic traps with low-permeability sandstone reservoirs, where oil gravity and other chemical parameters may influence economic viability.

Experimental Investigation of Permeability Evolution on Sandstone in Triaxial and Long-Term Dissolution Experiment

The temporal permeability and damage evolutions of low-permeability sandstone cores during triaxial and long-term dissolution experiments were measured using a triaxial-flow system. Three triaxial experiments were performed on sandstone cores having initial permeability ranging from 78 × 10 − 18 m 2 to 120 × 10 − 18 m 2 . Two sets of long-term dissolution experiments were conducted on cracked sandstone cores. All dissolution experiments were performed at room temperature and using a 10 g/L H2SO4 and 0.2 g/L H2O2 input solution. Permeability evolution was determined using Darcy’s law. The cores experienced an average increase of 25% in permeability in the dissolution experiment and 900%~1500% increase at the end of the experiment. The dissolution was fairly homogeneous during the long-term experiments whether on the 1 mm scale or the 10 μm scale. The relationship between damage and permeability was speculated and its correlation coefficient has been proved to be close to 1. These results suggest that hydraulic fracturing works well in permeability increase in low-permeability sandstone reservoir.

New Method for Quantitative Prediction of Liquid Flowback Based on the Capillary Bundle Model.

Liquid invasion damage plays a main role in the formation damage of low-permeability sandstone reservoirs. The long-term retention of working fluid in the formation will cause serious water blocking damage. In order to research the quantitative prediction of liquid flowback in low-permeability sandstone reservoirs, a new method for quantitative prediction of liquid flowback based on the capillary bundle model was proposed, which took into account the boundary layer effect. Besides, taking the low-permeability sandstone samples of Penglaizhen formation in the Sichuan basin as an example, the quantitative prediction of liquid flowback was carried out. Finally, a series of experiments including gas displacement experiment and nuclear magnetic resonance experiment were conducted to examine the validation of the new method for quantitative prediction of liquid flowback. The study indicates that the results of quantitative prediction were in good agreement with the experimental results. Liquid flowback is closely related to pore structure, boundary layer effect, and displacement pressure in low-permeability sandstone reservoirs. For the sandstone sample with a permeability of 5.5 mD, most of the liquid could be displaced out at 1 MPa, and liquid saturation in the sandstone sample tends to be stable at 32%; for the sandstone sample with a permeability of 0.0349 mD, liquid flowback process is more durable, thereby the cumulative mass of liquid flowback and liquid saturation change gradually, and liquid saturation tends to be stable at 55%. This study not only provides an insight into the microscope mechanisms of liquid flowback but also predicts the cumulative mass of liquid flowback and liquid saturation accurately.

Pore structure and fluid saturation of near-oil source low-permeability turbidite sandstone of the Dongying Sag in the Bohai Bay Basin, east China

Pore structure and oil saturation are important parameters in petroleum exploration and development, and the relationship between them is closer in near-oil source reservoirs (with a short-distance migration of oil and gas) than in other reservoirs. Using epoxy-impregnated thin sections, scanning electron microscopy (SEM), conventional core analyses of porosity and permeability, mercury intrusion porosimetry, and well logging, the characteristics of the petrology, physical properties, and pore structure we studied, as well as the relationship between pore structure and fluid saturation (maximum mercury intrusion saturation Smax and oil saturation So) of the near-oil source low-permeability turbidite sandstone reservoirs in the Es3 member of the Dongying Sag, Bohai Bay Basin, eastern China. The results indicate that the turbidite sandstone reservoirs are mainly composed of fine sandstone and siltstone, with porosities and permeabilities ranging from 5 to 25% and 0.1 to 40 mD, respectively, and can be classified as medium to low porosity and extra-low to ultra-low permeability reservoirs. The pore types of high-quality reservoirs are mainly dominated by intergranular pores, both primary and dissolved, probably due to the influence of the acidic fluids generated from the cracking of organic matter. The pore structure is complex with respect to the pore-throat size distribution, and the overall pore-throat radius is small. Several pore structure parameters together affect the fluid saturation distribution, among which the medium pore-throat radius (R50) and medium saturation pressure (P50) are especially correlated with oil saturation. Different pore structure types have different characteristics of fluid saturation distribution, and the oil-bearing grade and oil saturation of the reservoirs above the oil-water contact are typically positively correlated with pore structure. This study will help to classify the pore structure in the wellbore profile and improve the accuracy of the oil saturation calculation by well logging.

Delineation of sandstone reservoirs of Pletmos Basin offshore South Africa into Flow Units using Core Data

AbstractThe present study is focused on the comparison of petrophysical rock typing and zonation methods of the Valanginian age sandstone in the Pletmos Basin offshore South Africa, to produce a zonation scheme for the low-permeability shaly sandstone reservoirs from core porosity and permeability data. The Valanginian age sediments of the Lower Cretaceous consist predominantly of a shallow marine sequence with interbeds of siltstone, claystone, generally fine-grained sandstone, and glauconitic, with varying amounts of an argillaceous matrix. A core description report was used in conjunction with a gamma-ray log to group rock types into different facies based on texture and grain size. Three different facies were identified as facies 1, a moderately sorted fine to medium-grained glauconitic sandstone; facies 2, a fine to very fine-grained glauconitic sandstone, moderately sorted; facies 3, a very fine sandstone to siltstone, laminated, argillaceous and bioturbated. Three independent reservoir zonation methods (Winland r35 pore throat, Hydraulic Flow Unit, and Stratigraphic Modified Lorenz Plot) were applied to three wells (SW1, SW2, and SW3) for which wireline logs, core porosity, and permeability data are available. Results were analyzed and compared with facies used as a context for the identification of rock types and zones. The results revealed eleven zones, grouped as moderate, very-low, and tight zones. The moderate flow zone is the best reservoir quality rock composed of macroporous rock type, ranked, as good rock type associated with facies 1. Three very-low flow zones were identified, which are of a microporous rock type, ranked as poor quality rock, associated with facies 2. Eight tight zones were revealed, which are of nanoporous rock type ranked as an impervious rock. The tight flow zone is the most reduced rock quality associated with facies 3. This study has developed a zonation scheme that will be used to locate other flow zones as well as to investigate whether the units/zones identified extend to other parts of the field.

Numerical model on predicting hydraulic fracture propagation in low-permeability sandstone

Hydraulic fracture propagation is hard to predict due to natural joints and crustal stress. This process may lead to uncontrollable changes in hydrogeological conditions. Therefore, prediction and control of fracture propagation are paramount to permeability increase in ore-bearing reservoir. The coupled fluid-solid model was utilized to predict the hydraulic fracture propagation in low-permeability sandstone of a uranium mine. For this study, the model was modified to allow fractures to propagate randomly by using the cohesive zone method. The simulation was developed on a three-step process. First, geological data required to run the model, including crustal stress, strength and permeability, were assembled. Next, fracture propagation under different conditions of stress and injection volume were simulated. In the final step, experimental data required to validate the model were obtained. The simulation results indicate that the principal stress, distribution and orientation of natural fracture have vital influence on fracture propagation and induced complex fracture network. This work provides a theoretical basis for the application of hydraulic fracture in low-permeability sandstone reservoir and ensures the possibility to predict the generation of complex fracture network.

A new permeability predictive model based on NMR data for sandstone reservoirs

Predicting permeability from nuclear magnetic resonance (NMR) logging data using SDR model and Coates model provides a quick and relatively reasonable value for reservoir permeability estimate. Critical to these two models is to find contributions of different level of pore structure to permeability, but pore structure in them is only divided into two levels. In this study, T2 distribution is divided into several segments corresponding to different level of pore structure, and every segment has its weighted characteristic value. By this way, we have considered contributions of more different level of pore structure to permeability and established a new permeability model. It has been tested in dozens of core samples. Compared with results of Coates model and SDR model, the new NMR model result is more consistent with the air permeability. So, we provide an improved permeability estimate for low permeability and tight sandstone reservoir.

Flow Model Considering the Influence of Low Velocity Non-Darcy Flow and Reservoir Connectivity and its Application

During the development of low and ultra-low permeability sandstone reservoir, due to the starting pressure gradient of poor reservoir physical properties, it is difficult to establish effective displacement between oil and water wells, and high voidage replacement ratio and low formation pressure are common phenomena. So it is necessary to analyze the influential factor of high voidage replacement ratio of low and ultra-low permeability reservoir. A one source and one sink flow model considering low velocity non-Darcy flow and unconnected reservoirs was established by using the flow theory of unidirectional flow and radial flow, and the model was solved by numerical method. The results show that the unconnected layers of water well will lead to the increase of invalid water injection; the larger the starting pressure gradient is and the larger the volume proportion of unconnected layer is, the smaller the maximum annual liquid production rate is and the higher the cumulative voidage replacement ratio corresponding to maintaining the maximum liquid production rate is. It is theoretically proved that the existence of unconnected layers and starting pressure gradient are the factors leading to the existence of high voidage replacement ratio in low and ultra-low permeability reservoirs. The study provides a theoretical basis for the adjustment of high-efficiency water injection in reservoirs.

Pore structure evaluation of low permeability clastic reservoirs based on sedimentation diagenesis: A case study of the Chang 8 reservoirs in the Zhenbei region, Ordos Basin

Sedimentary diagenesis is one of the most significant factors in the development of low permeability sandstone reservoirs due to its important influence on the formation of pore structure. This study takes Group 8 of the Yanchang Formation in the Zhenbei region of the Ordos Basin as the research object. Methods including casting thin-sections, mercury injection, and scanning electron microscopy were used to analyse core and casting thin-sections to examine the sedimentary diagenetic processes, authigenic mineral composition, pore structure, and physical properties of the reservoirs in the study area. The influence of sedimentary diagenesis on the physical properties of the reservoirs was analysed, and the pore structures in the study area were divided into four types. By determining the development mechanism and distribution characteristics of each type of pore structure, the favourable reservoir areas were also predicted. The results showed that type I (large mesopores with medium throats) and type II (mesopores with fine throats) were the favourable pore structures in the research area. These were mainly formed by the rim cementation of chlorite, the dissolution of feldspar and other soluble components, and a weak to mid compaction. Areas with type I and type II pore structures are considered to have a high reservoir quality, with a porosity of between 10% and 25% and a permeability of between 1 mD and 50 mD. These areas are suggested as regions for optimised exploration and development.

A NOVEL FRACTAL MODEL FOR ESTIMATING PERMEABILITY IN LOW-PERMEABLE SANDSTONE RESERVOIRS

Permeability is one of the most important parameters for accurately predicting water flow in reservoirs and quantifying underground water inrush into coal mines. This study developed a predictive permeability model by considering the microstructural parameters and tortuosity effects of low-permeability sandstone. The model incorporates the fractal geometry theory, Darcy’s law, and Poiseuille equation into a multistep inversion framework for systematic interpretation of sandstone scanning electron microscopy (SEM) images. A threshold segmentation algorithm is applied to transform SEM images into binary images. Then, we used an improved statistical algorithm with binary image data to estimate the geometric parameters of each pore, such as the perimeter and area. The fractal parameters of pore microstructure were determined by fitting the data of pore perimeters and areas. Finally, the effects of tortuosity on microscopic percolation were considered, and a conventional model was modified for quantifying the relationship between microscopic pore structures parameters and macroscopic permeability. Eight groups of sandstone samples from the Xingdong coal mine in North China were collected for estimating permeability by the developed inversion framework. A direct permeability measurement was also conducted on each sample with an AP-608 automatic measuring instrument. The measured permeability values were compared with results from theoretical models, and we found that the accuracy of the newly developed predictive model is better than that of a conventional permeability model. The predictive model developed in this study provides a useful tool for estimating permeability in low-permeable sandstone reservoirs.