Movable Fluid Research Articles

Pore-fracture network alteration during forced and spontaneous imbibition processes in shale formation

Imbibition controls mass transfer in the complex pore-fracture network in shale, which may change the pore-fracture network and lead to a low efficient flowback of fracturing fluid. Thus, it is necessary to accurately characterize the pore-fracture network alteration during the imbibition process. In this study, forced and spontaneous imbibition tests were conducted under the confining pressure on selected shale core samples with induced fractures, collected from Longmaxi Formation, Sichuan Basin, China. The low-field nuclear magnetic resonance (NMR) spectrometer was employed to monitor the variation of pores and micro-fractures in the shale core samples during the dynamic imbibition process. In addition, optimal surface relaxivities, ranging from 0.019 to 0.033 μm/ms, were determined by comparing the NMR T2 distributions with the pore size distributions (PSDs) measured via high-pressure mercury intrusion (HPMI) tests. Then, the measured dynamic T2 spectra with three distinct peaks were converted into the corresponding PSDs to quantitatively analyze the number, size, and connectivity changes of small pores, large pores, and micro-fractures in shale. Results show that the total porosities of the four shale core samples are increased by 3.5%, 10.2%, 32.9%, and 36.3% after the imbibition tests. The forced imbibition leads to more remarkable improvements in the pore volume of large pores with radius between 0.2 and 3.6 μm. In contrast, the spontaneous imbibition results in more significant increases in the number and size of small pores with radius between 0.0004 and 0.36 μm. It is also found that the total porosity increment is primarily an outcome of small pore alteration during the imbibition. Moreover, the enlarged pores and micro-fractures are mainly categorized as the capillary bounded fluid pores and movable fluid pores, which significantly affect the efficiency of oil and gas transfer in shale. The findings of our study demonstrate the comprehensive effects of capillary force, clay hydration, osmotic potential, confining and pore pressures, and creep deformation and failure on the pore-fracture network alteration in shale and advance the understanding of the mechanisms behind the forced and spontaneous imbibition processes.

Comparison of Pore Size Distribution, Heterogeneity and Occurrence Characteristics of Movable Fluids of Tight Oil Reservoirs Formed in Different Sedimentary Environments: A Case Study of the Chang 7 Member of Ordos Basin, China

Comparison of Pore Size Distribution, Heterogeneity and Occurrence Characteristics of Movable Fluids of Tight Oil Reservoirs Formed in Different Sedimentary Environments: A Case Study of the Chang 7 Member of Ordos Basin, China

Influencing mechanics and correction method of nuclear magnetic resonance measurement in igneous rocks reservoir

Nuclear magnetic resonance (NMR) measurement provides lithology-independent porosity and pore structure for sedimentary reservoirs. Recently, oil and gas were discovered in igneous rock formations, however, NMR logging porosity is substantially lower than the true porosity, and the T2 distributions does not characterize the pore-size distributions. These observations limit the use of NMR logging in igneous rock formations and new research is needed to be developed. To address this gap in the literature, using numerical simulation of NMR behavior, we conduct a theoretical study to examine the impact of magnetic susceptibility, echo spacing, and fluid type on the T2 distributions in igneous rock. The simulation results and laboratory experiment show that, the paramagnetic minerals affect the magnetization of fluids in pores and rate of the echo decay, and NMR porosity is thus significantly reduced. To effectively correct the NMR measurement, a new approach is proposed to improve the underestimation of NMR porosity and T2 distribution shifting to shorter times. For a pore model, the corrected porosity and T2 distribution are both in good agreement with the model. In a case study from Chepaizi area of Junggar Basin, China, the corrected NMR porosity matches well with core measurement, and the corrected T2 distribution shifts to longer times more than before. Moreover, bound fluid volume and movable fluid volume are both corrected, and the NMR permeability also agrees well with core laboratory measurement, which proves that the correction method effective. Therefore, this technology enables NMR log for evaluating the igneous rock reservoir quality.

Study on the pore structure, fluid mobility, and oiliness of the lacustrine organic-rich shale affected by volcanic ash from the Permian Lucaogou Formation in the Santanghu Basin, Northwest China

Lacustrine organic-rich shale with extremely heterogeneous pore structure is widespread in the second member of the Permian Lucaogou Formation (P2l2) of the Santanghu Basin. However, information on the pore structure, fluid mobility, and oiliness characteristics is still lacking, as well as the interaction between them in the organic-rich shales remains controversial. To address these problems, this study analyzed the influencing factors of pore structure, oiliness, and fluid mobility of the P2l2 shale and constrained the lower limit of movable fluid pore throat radius based on thin sections, routine core analysis, whole rock X-ray diffraction (XRD), scanning electron microscopy (SEM), high-pressure mercury injection (HPMI), nuclear magnetic resonance (NMR), constant-rate mercury injection (CMI), and nano-CT scanning data. The P2l2 shale was characterized by fine-grained minerals of felsic (tuffaceous material) and carbonate (dolomite), with poor reservoir physical properties and strong oil-bearing heterogeneity. Micro- and nano-scale pores are the main type of storage space. Among them, most of the microfractures emit green to yellow hydrocarbon fluorescence regardless of whether they are filled or not, as do the edges of dolomite grains. While the edges of the felsic minerals are characterized by stronger orange yellow fluorescence of organic matter. According to the morphology and parameters of HPMI and NMR curves, the pore structure can be divided into four types. From type 1 to type 4 pore structure, the maximum mercury saturation decreases from 95 to 47 % (avg. 70 %), indicating poor pore connectivity, and the pore throat radius that mainly contributes to permeability is > 0.04 μm. Meantime, the NMR T2 spectrum gradually transitions from right unimodal to left unimodal behavior, with a gradual decrease in the saturation of movable fluid and a transition of the mineral type from carbonate to felsic. Fluid mobility is not only influenced by macropores, but also related to the content of small pores (T2 < 1 ms) and the mineral type. On this basis, the lower limit of the movable fluid pore throat radius in the P2l2 organic-rich shale is finally determined to be 40 nm.

Impacts of pore-throat spaces on movable fluid: Implications for understanding the tight oil exploitation process

In this study, a series of experiments were carried out on tight sandstone samples from the Yangchang Formation in the Ordos Basin, China to investigate their pore-throat spaces and fluid flow capacity, including nuclear magnetic resonance (NMR) test, constant-rate mercury injection (CRMI), pore-casted thin section analysis, scanning electron microscopy (SEM), and X-ray diffraction (XRD). The pore-throat space was divided into two main types based on CRMI and NMR results: the throat-dominant space and the intergranular pore-dominant space, and the volume proportions was calculated. Proportions of different pore-throat spaces do not affect the total reservoir space, and the proportion of the throat-dominant space plays an important role in controlling the complexity of the pore-throat structure. The intergranular pore-dominant space contributes the main permeability, which affects the fluid flow capacity of tight sandstone through the large throats connecting intergranular pores. Fluid flow capacity in the intergranular pore-dominant space is related to the configuration of pores and throats, a higher proportion of the short conduit throats exist means a more homogeneous pore-throat structure, bound water is redistributed on the pore-throat surface to form a thin water film after centrifugation, leading to a higher proportion of movable fluid. The change of throat volume proportion to the total pore-throat volume with pore-throat radius was studied based on CRMI. With the increase of the pore-throat radius, the proportion of the throat volume first decreases in a fluctuating manner and then starts to increase rapidly at a certain radius (rt-p). The rt-p value is believed to determine the fluid flow capacity of the tight sandstone. This study has certain reference significance for understanding the fluid flow during the exploitation process of tight sandstone.

Revisiting movable fluid space in tight fine-grained reservoirs: A case study from Shahejie shale in the Bohai Bay Basin, NE China

Assessment of movable fluid is a key topic in production of tight formations. Evaluation of the movable fluid was usually conducted on tight sandstone formations while rarely on black organic-rich shales. To analyze the movable fluid properties in tight black shales, we document the basic geochemical and petrological features of Paleogene Shahejie shale and carry out quantitative analyses of the movable fluid properties. A modified method is proposed to estimate the pore size distribution. Results indicate that Shahejie shale is characterized by a low porosity and under-saturated of movable fluid. Further, porosity and saturation of movable fluid in shales are mainly determined by the heterogeneity of pore structure. Besides, micropores and mesopores with pore radius smaller than 6.69–18.25 nm (the lower limits are calculated for the collected samples based on the low-field Nuclear Magnetic Resonance (LF-NMR) transverse relaxation time ( T 2 ) spectra, i.e., the lower limit is different for each sample) provide substantial movable space for the fluid. Previously, relaxation rate that related to conversion from T 2 spectra of porous media to pore size distributions is often regarded as constant as well as thickness of film fluid that produces pore surface relaxation. However, our work indicates that both the relaxation rate and thickness of film fluid are variables as a function of the pore radius. This study enriches the application of movable fluid properties in tight reservoirs formations, especially shales, and lays a foundation for tight porous media research using LF-NMR in future. • Movable fluid saturation indicates the exploitable rate of reservoir. • Movable fluid porosity is used to calculate the exploitable degree of reservoir. • The newly proposed method first employs nonconstant ρ 2 and h. • ρ 2 and h increase predictably as pore radius increases.

Effects of pore structure on the moveable oil saturation in water-driven tight oil sandstone reservoirs

Tight oil sandstones have large oil reserves but low waterflooding efficiency and oil recovery. The movable oil saturation (MOS) is a critical parameter for evaluating oil recovery in water-driven tight oil sandstone reservoirs. However, its controlling factors in tight oil sandstones are still not well understood. In this study, the tight/low-permeability sandstones in the Chang 8 and Chang 9 Members of the Honghe Oil Field in the Ordos Basin (China) provide an opportunity to determine the effects of pore structure on the MOS. Porosity, permeability, thin sections, scanning electron microscopy (SEM), large field-of-view SEM imaging method (MAPS technique), high-pressure mercury intrusion (MICP), and micro-CT scanning were systemically conducted to analyze the pore structure analysis. MOS values were obtained from the relative permeability tests. The results show that porosity, pore-throat size, and the sorting coefficient have no evident relationship with the MOS. Many of the higher-permeability samples even show lower MOS values. Moreover, analysis of micro-CT images before and after waterflooding indicates that the lower-permeability samples tend to swept larger areas than the higher-permeability samples, resulting in greater oil-displacement efficiencies and MOS values. Instead, the cumulative mercury saturation at the apex of the mercury injection hyperbola curve (Sapex), the ratio of the maximum pore-throat radius and the medium pore-throat radius (Rmax/R50), and movable fluid saturation (MFS) show a good linear relationship with the MOS. The displaced oil is primarily from intergranular pores and partly from intragranular pores. The micropores that are widely distributed at the grain-grain contact display low original oil saturation and low oil displacement efficiency. It is proposed that the volume of the well-connected pores that contribute to permeability is the key factor controlling the MOS regardless of the type of rock.

Fracture Characteristics and Heat Accumulation of Jixianian Carbonate Reservoirs in the Rongcheng Geothermal Field, Xiong'an New Area

AbstractGeothermal energy plays an important role in urban construction of the Xiong'an New Area. Geothermal reservoir fracture distribution of the Mesoproterozoic Jixianian Wumishan Formation (Fm.) carbonate reservoir in the Rongcheng geothermal field are evaluated based on FMI log from Wells D19 and D21. The results show carbonate reservoir fracture density of Well D19 is 15.2/100 m, greater than that of Well D21 with a value of 9.2/100 m. Reservoir porosity and permeability of Well D19 are better than that of Well D21, and the water saturation is bimodally distributed. The movable fluid volume ratio (BVM) of Well D19 is 2% to 8% with some zones exceeding 20%, while the value of Well D21 is less than 4%. Therefore, reservoir fractures in Well D19 are more conducive to fluid flow. Reservoir fractures have a similar occurrence to normal faults, indicating that the tensile stress field controlled the formation of such fractures. Developed reservoir fractures provide a good channel for groundwater convection. The circulation of regional groundwater and the heat exchange between water and rock and the multiple heat accumulation patterns form a stable and high potential heat reservoir in the Rongcheng geothermal field.

Effect of pore-throat structure on gas-water seepage behaviour in a tight sandstone gas reservoir

In this study, effect of pore-throat structure on gas–water seepage behaviour in a tight gas sandstone formation has been experimentally examined. More specifically, pressure-controlled mercury injection tests were performed to measure capillary pressure and identify the characteristics of a pore-throat structure such as its connectivity and size distributions. According to the pore-throat structure together with its median throat radius, pore-throat skewness, relative sorting coefficient, and cutoff throat volume ratio, the pore-throat structure was then classified into three types, while gas permeabilities under different conditions are corrected with consideration of the slippage effect and different pore-throat structures. Subsequently, seepage characteristics, including distribution of movable fluid saturation, relative permeability, and water locking degree, were quantified using displacement experiments integrated with the nuclear magnetic resonance (NMR) technique for the three classified types of pore-throat structure, respectively. With the deteriorated pore-throat structure, the throat size distribution curves are found to shift to the left, porosity gradually decreases, and the irreducible water saturation gradually increases. Both water saturation at the isotonic point and irreducible water saturation increase, and gas phase relative permeability at the irreducible water saturation together with water relative permeability within the saturation range of simultaneous gas–water flow decreases consecutively, indicating the seepage capacity of gas and water is weakened. With the deteriorated pore-throat structure, the water locking becomes more serious and its corresponding water saturation together with the damage coefficient of gas permeability is larger, and the influence of water on gas phase flow is more significant. The pore-throat structure, especially its connectivity, is found to be the main factor dominating the movable fluid saturation and two-phase seepage characteristics in a tight sandstone gas reservoir. This study allows us to better understand how the pore-throat structure affects the gas–water seepage behaviour in a tight gas reservoir, provided that its characterization has been quantitatively conducted and the seepage patterns are identified and classified within a consistent and unified framework. These findings further provides solid fundamentals for efficient and effective exploitation of tight gas reservoirs.

Effects of pore-throat structures on the fluid mobility in chang 7 tight sandstone reservoirs of longdong area, Ordos Basin

Pore structure and fluid mobility are important factors affecting reservoir quality evaluation and effective hydrocarbon resource assessment in tight sandstone reservoirs. In this research, 14 tight sandstone samples from the Chang 7 member of the Upper Triassic Yanchang Formation in the Longdong area of the Ordos Basin were analyzed through high-pressure mercury injection (HPMI), low-temperature nitrogen adsorption (LTNA) and nuclear magnetic resonance (NMR) experiments to clarify the pore-throat structure characteristics of tight sandstone reservoirs and their influence on the occurrence characteristics and mobility of reservoir fluids. The results suggest that the different distributions and combinations of pore and throat types and sizes resulted in three pore-throat structures and four pore-throat spaces in the study area, corresponding to different occurrence characteristics of movable fluid. Among them, the type I pore-throat structure is characterized by large pore throats, high pore-throat connectivity and weak heterogeneity, with the highest corresponding average movable fluid saturation (MFS) and movable fluid porosity (MFP). The pore-throat size distribution (PSD) of type II pore-throat structure has bimodal characteristics with a low pore-throat sorting degree but a good pores and throats configuration relationship with the higher average MFS and MFP. The type III pore-throat structure has developed intercrystalline pores with a smaller average pore-throat radius, the highest fractal dimension and the lowest fluid mobility. Micropores and mesopores, as the main pore-throat spaces in the three types of pore-throat structures, are the main contributors to the petrophysical properties and the main occurrence place for movable fluids. Nanopores with strong heterogeneity and macropores with high permeability both occupy small pore-throat spaces and have little influence on reservoir fluid mobility. It is thus cleat that the pore-throat structure of tight sandstone reservoirs is the main factor affecting reservoir fluid mobility. More specifically, a pore-throat structure with a large pore-throat radius, good pore-throat connectivity and weak heterogeneity is favorable to the occurrence and seepage of movable fluids. Moreover, reservoir fluid mobility is comprehensively influenced by reservoir petrophysical properties and various clay minerals. Lower clay mineral contents and higher reservoir quality are conducive to the high flowability of tight sandstone reservoir fluids.

Experimental evaluation of tight sandstones reservoir flow characteristics under CO2–Brine–Rock multiphase interactions: A case study in the Chang 6 layer, Ordos Basin, China

By the end of 2020, tight oil production accounted for 65% of total U.S. crude oil production (EIA, 2020). Carbon dioxide flooding is widely recognized as an efficient way of developing tight oil reservoirs. The flow characteristics of host rocks may be changed by CO2-Brine-Rock interactions during CO2 injection. It is necessary to reveal the impact of CO2-Brine-Rock interactions on tight oil recovery, which is critical in understanding the fundamental mechanisms of CO2 flooding for enhanced tight oil recovery. However, the flow characteristics alteration behavior and mechanism during CO2 flooding are still unclear. In this study, outcrop sandstone samples from the Chang 6 layer of Triassic Yanchang formation in Ordos Basin were used. First, CO2 solubility in formation water was measured. Then, the corrosion rate due to carbonic acid on rock minerals was evaluated under reservoir conditions. The porosity, pore throat diameter for the movable fluid, liquid permeability, mineral composition and cast thin sections in tight sandstones were compared before and after corrosion. The corrosion was found to have enhanced both porosity and liquid permeability, with liquid permeability exhibiting the highest increment. Pore and throat diameter for movable fluids in tight sandstones decreased after the reaction, implying reduced irreducible water saturation. XRD results showed that calcite, dolomite and feldspar were main corrosion minerals. The corrosion pores significantly increased after corrosion. These findings indicate improved formation petrophysical properties associated with CO2 flooding in tight sandstones. This study provides a theoretical basis for the efficient development of tight oil reservoirs during CO2 flooding.

Pore Structure and Movable Fluid Characteristics of Typical Sedimentary Lithofacies in a Tight Conglomerate Reservoir, Mahu Depression, Northwest China

The pore structure and movable fluid characteristics of tight conglomerate reservoirs are complex, which are greatly different from conventional reservoirs. The depositional mechanism is the fundamental factor controlling the physical properties of conglomerate reservoirs. However, there is a lack of systematic research on the pore structure and movable fluid characteristics of conglomerate reservoirs with typical sedimentary facies. This paper investigates the pore structure and movable fluid characteristics of conglomerate of different sedimentary facies based on various experiments. Casting thin sections, X-ray diffraction, scanning electron microscopy, high-pressure mercury injection, and nuclear magnetic resonance experiments were conducted on 32 conglomerates samples from the Mahu Sag, Junggar Basin, China. The quality classification method of tight conglomerate reservoirs is established. The results show that the conglomerate can be divided into three sedimentary facies; traction flow conglomerate (TFC) and pebbled sandstone (PSS) mainly develop intergranular pores and dissolved pores; and the pore diameter curves are mainly a double peak, single peak, and flat peak. Gravity flow conglomerate (GFC) mainly develops dissolved pores and interstitial micropores, and the pore diameter curve is mainly a single peak. PSS includes pebbled gritty sandstone (P(G)SS) and pebbled fine sandstone (P(F)SS). TFC and P(G)SS are favorable class I reservoirs, while GFC and P(F)SS are nonfavorable class II reservoirs. A new parameter, the ratio of the major axis to the minor axis of the pore outer ellipse (axial ratio), is proposed to quantitatively describe the compaction effect. The average axial ratios of the three lithofacies are 3.04, 3.98, and 8.78, respectively, indicating that the compaction is intensified and the pore structure becomes worse. By analyzing the correlation between pore structure parameters and permeability, it is found that the main controlling factors of permeability of GFC and TFC are sorting and connectivity, respectively, and the main flow radius is the most suitable parameter to describe permeability. A linear spectral decomposition method was used to establish a new quantitative calculation method of movable fluid saturation for different types of pores, and the results show that the movable fluid saturation of intergranular pores is the highest (average: 65.43%), and the movable fluid saturation of TFC and P(G)SS with more intergranular pores is the highest. Movable fluid saturation is inversely proportional to the content of I/S and the compaction rate and positively proportional to the content of quartz and feldspar and the cementation rate. The fluid mobility of water-wet samples is weaker. The research results provide theoretical support for the identification of favorable reservoirs and the cognition of a development mechanism.

Difference of Microfeatures among Diagenetic Facies in Tight Sandstone Reservoirs of the Triassic Yanchang Formation in the Midwestern Region, Ordos Basin

Based on the background of sedimentary characteristics, a large amount of core and thin section analysis, taking Chang 6 reservoir of Yanchang Formation in the central and western Ordos Basin as an example, through the application of scanning electron microscopy, high-pressure mercury injection, nuclear magnetic resonance and microscopic water drive oil model, and other experimental test methods, the diagenetic facies types and microscopic pore structure characteristics of tight sandstone reservoirs are discussed and analyzed in depth. The results show that the average porosity loss rate caused by early diagenesis compaction in the study area is 50.62%, which is the main reason for reservoir compactness. The cementation further causes porosity loss, and the later dissolution increases the reservoir space in the study area to a certain extent. Different diagenetic facies reservoirs not only have obvious differences in porosity evolution characteristics but also have significant differences in pore throat radius distribution characteristics, movable fluid occurrence characteristics, and water drive oil characteristics. The pore throat distribution with radius greater than R50∼R60 determines the permeability. The difference in movable fluid saturation mainly depends on the connectivity of the relative large pore space corresponding to the relaxation time greater than the cut-off value of T2. The size of pore throat radius has a good control effect on water flooding efficiency.

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.

Analysis of Microscopic Main Controlling Factors for Occurrence of Movable Fluid in Tight Sandstone Gas Reservoirs Based on Improved Grey Correlation Theory

Tight sandstone reservoirs have the characteristics of poor physical properties, fine pore throats, and strong microheterogeneity compared with conventional reservoirs, which results in complicated movable fluid occurrence laws and difficult mining. Taking the tight sandstone gas reservoir of He 8 formation in Sulige gas field as an example, based on physical property test analysis, constant velocity mercury injection, and nuclear magnetic resonance experiments, an optimized gray correlation calculation model is established by improved gray correlation theory, which quantitatively characterizes the influence of microscopic pore structure parameters of different types of tight sandstone gas reservoirs on the occurrence of movable fluids, and the main controlling microgeological factors for the occurrence of movable fluid in tight sandstone gas reservoirs with close/similar physical properties are selected. The results show that the occurrence of movable fluid in Type I reservoirs is mainly affected by the effective pore-throat radius ratio, the saturation of mercury in the total throat, and the effective pore radius, and the occurrence of movable fluid in Type II reservoirs is mainly affected by the effective throat radius per unit volume and total throat mercury saturation and mainstream throat radius. Moreover, the occurrence state of movable fluids in Type II reservoirs is controlled by the throat radius stronger than that of Type I reservoirs. It has important guiding significance for the efficient development of tight sandstone gas reservoirs.

Characteristics of movable fluids in tight sandstone reservoir and its influencing factors: a case study of Chang 7 reservoir in the Southwestern of Ordos Basin

Aiming at the problem of complicated occurrence and flow state of the fluid in tight sandstone reservoir, this paper takes Chang 7 reservoirs in Southwestern of Ordos Basin as an example to analyze the occurrence characteristics of movable fluids by nuclear magnetic resonance experiment, while takes a series of microscopic experiments to analyze the influencing factors of difference of movable fluids. The results show that the T2 spectrum curves of fluid-saturated samples from Chang 7 reservoirs in the study area are dominated by the unimodal shape and the left-high-peak-right-low-peak bimodal shape. After centrifugation, the T2 spectrum curves are dominated by the left-high-peak-right-low-peak bimodal shape. The average movable fluid saturation is 33.27%, and the average T2 cutoff value is 13.61 ms. The movable fluids are mainly distributed in medium and large pores, and a small amount is distributed in small pores. The occurrence characteristics of movable fluids in tight reservoirs are complex and not controlled by a single factor. The size of throats and the connectivity of pore-throat have obvious effects on the saturation of movable fluids. The small size of throats and poor connectivity of pore-throat in tight reservoirs not only restrict the fluids in micropores, but also make the fluids in macropores difficult to flow under the control of small throats. The development of clay minerals will make the pore throats smaller, more complex and have poorer connectivity, and increase the fluid seepage resistance. On the other hand, it will make the specific surface area larger, which will cause a large number of fluids adsorbed on the clay surface and difficult to flow, resulting in the reduction of movable fluid saturation.

Classification and control factors of pore-throat systems in hybrid sedimentary rocks of Jimusar Sag, Junggar Basin, NW China

Aiming at the complicated problem of the genesis of high-quality hybrid sedimentary rocks, the pore-throat systems, controlling factors and fluid mobility of hybrid sedimentary rocks in the Permian Lucaogou Formation in Jimusar Sag were examined. The results show that the hybrid sedimentary rocks contain 5 types of pore-throat system, intergranular (Type A), mixed intergranular-dissolved-intercrystalline (Type B), dissolved (Type C), mixed dissolved-intercrystalline (Type D) and intercrystalline (Type E) ones. The pore-throat systems are controlled by 3 major factors, the component content and arrangement (CCA) of hybrid sedimentary rocks, sedimentary environment and diagenesis. CCA controls the matrix support mode of hybrid sedimentary rocks, and therefore controls the types and changes of pore-throat system. The sedimentary environment mainly controls the macroscopic distribution of pore-throat system, i.e., hybrid sedimentary rocks deposited in the near source and high-energy environment are characterized by high content of coarse-grained component, granular/interbedded-support mode, and development of Type A and Type B pore-throat systems. Hybrid sedimentary rocks deposited in the medium-energy environment far from source are characterized by dolomitic/mud support mode and Type C and Type D pore-throat systems. Hybrid sedimentary rocks deposited in low-energy environment far from source have mainly Type E and Type D pore-throat systems. Diagenetic processes such as compaction and calcite cementation make the proportions of Type A and Type C pore-throat systems decrease further. In the hybrid sedimentary process of sandy-mud, pore-throat system types show a change of “A→B→C→D”, in that of dolomite-sand, pore-throat system types show a change of “A→C→D→E” or “B→D→E”, and in that of dolomite-mud, pore-throat system types show a change of “D→E”, which are affected in details by the contents of coarse-grain component, feldspar and dolomite. The reservoir with Type A pore-throats has the best physical properties and fluid mobility, and the reservoirs with Type D and Type E pore-throats have the poorest. The movable fluid distribution is related to the matrix support mode, and the larger pores in hybrid sedimentary rocks of dolomite/mud support mode have no obvious advantage in fluid mobility. The findings of this study provide a geological basis for evaluating and building reasonable interpretation model of hybrid sedimentary rocks sweet spot.

NMR Fluid Substitution–A New Method of Reconstructing T2 Distributions Under Primary Drainage and Imbibition Conditions

Most nuclear magnetic resonance (NMR)-based petrophysics models, such as pore structure characterization and permeability prediction, were developed using T2 distributions measured at fully water-saturated conditions (i.e., Sw = 1). The downhole implementation of those models across the hydrocarbon zones is disputable due to partial saturation (Sw &lt; 1) conditions; hence, a correction to such effects on T2 distributions is required. This paper provides a critical review of the fluid substitution methods currently available in the industry and presents an improved method for enhanced formation evaluation. In the new method presented, an effective irreducible water saturation model is used to account for the pore structure and capillary pressure effects, which were barely considered by the currently available NMR fluid substitution methods. For water-wet reservoir rocks, the typical NMR T2 distribution at the partial saturation condition displays a clear separation between the wetting and nonwetting phases. The water phase can be classified as irreducible and movable fluid volumes. Then, using a T2 mapping relationship and a total porosity constraint, the T2 distribution of movable water at Sw &lt; 1 is shifted and amplified to determine the T2 distribution of movable water at Sw = 1. To validate the new method, NMR measurements were conducted on sandstone samples at Sw = 1 as well as Sw &lt; 1. The reconstructed T2 distribution at Sw = 1 was compared with the measured T2 distribution at Sw = 1. Results showed that the reconstructed T2 distribution matched very well with the T2 distribution measured at Sw = 1, confirming the robustness of the new technique. Parameters used in the reconstruction methodology are observed to be a good indicator of pore connectivity. During desaturation, the water T2 in large pores shifts to a shorter T2 because of the enhanced surface relaxation as the water volume decreases while the surface area remains constant. Therefore, the amplitude at the short T2 increases. The increased amplitude was remapped to large pores in reconstructing T2 spectra of full saturation.

Pore structure and fractal characteristics of ultralow-permeability sandstone reservoirs in the Upper Triassic Yanchang Formation, Ordos Basin

The complex pore structure and high heterogeneity of ultralow-permeability sandstone reservoirs have a significant effect on reservoir quality evaluation and hydrocarbon resource assessment. We collected 10 reservoir samples from the Upper Triassic Yanchang Formation Chang 8 in the Zhenbei area of the Ordos Basin. We measured the pore size distribution (PSD) and fluid occurrence characteristics of the reservoir by pressure-controlled porosimetry, rate-controlled porosimetry, and nuclear magnetic resonance, and then we analyzed the results via the fractal theory to determine the pore space fractal characteristics. Our analysis indicates that the three major pore types of these reservoirs are residual intergranular pores, dissolution pores, and intercrystalline pores. The pore structure of the ultralow-permeability sandstone reservoirs is highly heterogeneous with pore throats of various scales, and the corresponding fractal characteristics are notably different, exhibiting multifractal features. Compared with macropores and mesopores, micropores are more uniform and regular in terms of their PSD and thus only slightly influence the reservoir quality. The complexity of the throat distribution and whole pore space is attributed to the development of dissolution pores and the content of feldspar minerals. Fractal features depend on the movable fluid pore space and effective pores, whose fractal dimensions reflect the complexity of interconnected pores and correlate well with the porosity and permeability. The development of different types and sizes of pore throats in these ultralow-permeability sandstone reservoirs resulted in the observed pore structure heterogeneity. The difference in mineral composition and content of these reservoirs aggravates the pore structure complexity and affects the reservoir quality evaluation and further oilfield development.

NMR characterization of fluid mobility in tight sand: Analysis on the pore capillaries with the nine-grid model

Pore fluids are generally classified into movable fluid and irreducible fluid by one or two NMR T2 cut-offs (T2C). Fluid movability in tight sands may not be accurately characterized by pore size-based classification methods solely because of the complex pore structure and heterogeneity in pore size. In this study, we propose a nine-grid model to characterize fluid movability and calculate the percentages of free fluid (FF), capillary-bound fluid (CAF), and clay-bound fluid (CBF). The pore size distributions and capillarity boundaries are converted from T2 and mercury injection capillary pressure (MICP). Three T2 spectra (TFF, TCAF, and TCBF) under water saturation, centrifugation, and heat-treatments are measured to classify pore fluids as FF, CAF, and CBF according to the pore capillary force needed to displace them. T2C1 and T2C2 are calculated to classify pores into three size categories. Finally, the nine-grid model that is composed of the three T2 distributions and two T2C is applied to explain results of a N2 displacement test and evaluate fluid movability in two samples. The results suggest that the conventional classification method based on fixed T2C results in the underestimation of CAF and overestimation of CBF. The macro-pores (T2 > T2C1) range in size larger than 85.20 nm and 113.64 nm and have pore capillary pressures lower than 6.46 MPa and 8.62 MPa. Micro-pores (T2 < T2C2) are smaller, ranging in size lower than 13.96 nm and 31.84 nm, and have high capillary pressures. Compared with conventional methods, the introduced model interprets the pore capacity-related displacement process well, especially for the remarkable displacement ratio of medium pores. The co-effect of fluid types and pore sizes in gas-displacing-water tests indicates that the process is primarily governed by fluid-matrix interaction and the connections among pores, rather than a simple sequential displacement of larger-to-smaller pores.