Low Gas Saturation Research Articles

Low oxygen saturation and discordant arterial blood gas measures have diagnosed a case of hemoglobinopathy

Pulse oximeter is a simple non-invasive equipment used to determine patient’s arterial blood oxygen saturation (SpO2). However, in some people, arterial blood gas measures (SaO2) are normal and low SpO2 values are related to hemoglobin variant rather than cardiac or pulmonary illnesses. Aim. We present a case of thalassemia that manifested with low SpO2 and discordant SaO2. Conclusion. When examining a patient with an unusually low SpO2, the differential diagnosis of a suspected hemoglobin variant should be investigated. Establishing an accurate diagnosis as soon as possible may help avoid unnecessary tests.

Numerical simulation for subsidence control in CO2 storage and methane hydrate extraction

Gas hydrates are increasingly viewed as a promising alternative to traditional fossil fuels. However, their extraction process poses risks to structural integrity, potentially causing significant subsidence. In this study, we developed a Thermo-Hydro-Mechanical-Chemical (THMC) model to analyze the impact of gas hydrate extraction on seabed subsidence. Our investigation focused on the influence of bottom hole flowing pressure, initial hydrate concentration, gas saturation, permeability, porosity, and rock thermal conductivity on subsidence during gas hydrate extraction via depressurization.The results show that seabed subsidence is affected by various factors such as bottom hole flowing pressure, initial hydrate concentration, gas saturation, permeability, porosity, and rock thermal conductivity. It was noted that significant subsidence is associated with low initial hydrate concentration, high permeability, porosity, low gas saturation, low rock thermal conductivity, and a notable pressure drop of 79.31%.To address this issue, we propose a seabed subsidence mitigation strategy involving CO2 injection. This approach not only safeguards offshore infrastructure and coastal communities but also helps reduce CO2 emissions, aligning with global climate change mitigation efforts. In our model, CO2 injection occurs in the subsurface reservoir at the interface between the free water zone and hydrate-bearing formations. The CO2 hydrates formation process releases heat, which dissociates methane hydrates, allowing the methane to be replaced by CO2 molecules and move towards the production well.Our analysis reveals that increasing injection temperature and rate significantly reduces subsidence. Additionally, the range of investigated injection pressures, which included pressures equal to and more than double the initial reservoir pressure, showed inconsequential impacts on seabed subsidence.The effectiveness of subsidence reduction is significantly enhanced by injecting a CO2/N2 mixture compared to pure CO2 injection. The most substantial reduction in subsidence occurred when a mixture of CO2 and N2 in a 50/50 vol/vol ratio was injected at a high rate.These findings offer crucial insights for optimizing the efficiency and control of gas hydrate extraction methods. They emphasize the importance of employing balanced injection strategies to minimize environmental risks and ensure sustainable energy extraction.

Production optimization in a fractured carbonate reservoir with high producing GOR

The Gas-Oil Ratio (GOR) is a crucial production parameter in oil reservoirs. An increase in GOR results in higher gas production and lower oil production, potentially leading to well shut-ins due to economic infeasibility. This study focuses on a real fractured oil field that requires urgent production operations to reduce the producing GOR. In this study, the static model for the field was developed using commercial software, involving steps such as data collection, fault modeling, meshing, and statistical analysis to prepare for dynamic simulation. The dynamic model incorporates geometry, gridding, and rock properties from the static model, utilizing a dual-porosity approach for the naturally fractured reservoir and the Peng-Robinson equation for fluid phase behavior. Initial reservoir conditions, production history, and rock-fluid interactions were defined, with relative permeability curves indicating a water-wet reservoir and low critical gas saturation affecting the GOR. To better understand the relationship between reservoir and production parameters, a detailed sensitivity analysis was performed using the Response Surface Methodology (RSM). Following the sensitivity analysis, a history matching process was conducted using the Designed Exploration and Controlled Evolution (DECE) optimizer to validate the model for future forecasts. Six operational scenarios were defined to decrease the production GOR and enhance final recovery from the field. The results indicate that the water injection scenario is effective in preventing the GOR increase by maintaining reservoir pressure, thereby sustaining production over a longer period. This scenario also improves oil recovery by approximately 6% compared to the base case. Finally, optimization was carried out using the DECE optimizer for each scenario to fine-tune the operational parameters. The goal was to maximize oil revenue for each scenario during the optimization process. This study stands out as one of the few that provides a comprehensive analysis of production behavior and development planning for a real fractured reservoir with high producing GOR.

PROSPECTS FOR THE DEVELOPMENT OF THE SHEBELYN GAS CONDENSATE FIELD

The paper provides a brief geological and industrial characterization of the Shebelinsky gas-condensate field, including the height of the gas-bearing layer, the area of gas occurrence, porosity, permeability of collectors, effective gas-saturated thickness of the coppery sandstones, and araucarite strata. The peculiarity of the deposits lies in the low permeability and gas saturation, deterioration of collector properties of productive reservoirs from the lower to the upper and from the central to the peripheral part of the deposit. A structural map of the cover of coppery sandstones and a map of water saturation of all productive horizons are presented. The dynamics of gas reserves and reservoir pressures of the field over the years are shown, along with the authors; forecasts for their future dynamics. Calculations of the volumes of water saturation of horizons and the total volume of reservoir water that has invaded the gas-bearing part of the field have been conducted. An analysis of water saturation and its future prospects has been carried out. Statistical calculations of the dependence of water saturation volumes on time and reservoir pressure have been performed, indicating a decrease in the rates of water saturation at the late stage of field development. A geological section of the Shebelinsky field is presented, indicating the possibility of gas migration through tectonic faults. All factors influencing the maintenance of reservoir pressure within the deposit have been analyzed, including: contour water flooding; surface subsidence; internal waterdrive regime; the elasticity of rock formations, gas, and It is shown that drilling 12 deep wells within the Shebelinsky field did not reveal new deposits or caps but confirmed the presence of gas saturation to a depth of 5.5 thousand meters. The analysis of field development indicates a balance between gas production and its migration from deep horizons as of the year 2023. Approved development indicators and author’s options are provided, supported by actual field development. The conclusion is drawn that, due to migration with a volume of production of 1700– 1900 million m3, the field will operate for another 100 years.

Impact of gas arising from gas hydrate decomposition on the effective permeability of bottom sediments of the Arctic shelf: a laboratory simulation

Relevance. The necessity to investigate the mechanism of gas (methane) flow occurring during decomposition of gas hydrate formations within the layers of bottom sediments. This process is evident through substantial releases of methane bubbles in extensive shallow regions of the Russian Arctic shelf and has the potential to alter the equilibrium of atmospheric methane, a critical greenhouse gas. Aim. To quantitatively investigate, within the context of gas transport in bottom sediments, the impact of free and bound gas within the pores on the nonlinearity of filtration flows. Methods. The model samples with filtration properties similar to those of the bottom rocks of the East Siberian Arctic shelf. During the experiments, a specific amount of gas was injected into the saturated model sample, followed by the measurement of its effective permeability during a slow decrease in pore pressure gradient. The obtained curve was interpreted within the framework of the threshold gradient model. Results. The experiments yielded curves showing the dependency of the threshold gradient magnitude on gas saturation for several samples. It was found that the threshold gradient linearly increases with the growth in gas fraction within the pore space. Already at a gas fraction of approximately 0.02, this value in the experiments reached 0.01 MPa/m, corresponding to the hydrostatic pressure gradient in water. This suggests that even areas with relatively low gas saturation may be impermeable to convective fluid flow. This possibility should be considered when creating models for bubble gas transporting through the rock layers of bottom sediments. Furthermore, the existence of gas-saturated zones with threshold gradients can significantly impact the vertical profile of pore pressure and lead to a reassessment of the depth of gas hydrate stability zones.

Coupling of source rock gas expulsion intensity and reservoir quality in time and space-a key to determine gas accumulation in Upper Paleozoic tight sandstones of the Mugua gas field, Ordos Basin, China

Research on gas accumulation mechanisms and variations in gas saturation is limited in the newly established Mugua gas field in the Ordos Basin. Understanding these aspects is vital for reduce drilling uncertainty and exploration risk. This study employed a variety of methods, including: (1) the use of organic geochemical examinations to determine the gas expulsion intensity of hydrocarbon source rocks; (2) fluid inclusion analyses to determine the time of gas accumulation; (3) a combination of optical microscopy, scanning electron microscopy observations, pore-simulation and permeability tests, mercury-intrusion capillary pressure experiments, and nuclear magnetic resonance studies to assess the properties of the reservoir quality and identify the tight sandstone rock type; (4) wireline logging and interpretive data analyses to research the gas saturations features; and (5) establish reservoir quality evolution model to systematically study this problem. Integrating fluid inclusion homogenization temperatures with burial and thermal histories indicates that gas accumulation in the Mugua gas fields occurred throughout the Early Jurassic to Late Cretaceous period. Five diagenetic facies have been identified: dissolution, quartz-cemented, clay mineral filling, tightly compacted, and carbonate-cemented facies. The reservoir quality evolution model reveals that the five diagenetic facies experienced densification before the period of gas accumulation. Therefore, for gas accumulation in tight sandstones, it is essential that mature and gas-generating source rocks, provide sufficient expulsion forces to drive gas into the rocks. The mechanism of gas accumulation in the Mugua gas field's tight gas sandstone reservoirs involves the process occurring in sandstones that are either near or interbedded with source rocks, under high pore-fluid pressure generated by gas production. Compared to other Upper Paleozoic gas fields in the Ordos Basin, the gas expulsion intensity in the Mugua gas field is lower, ranging from 6.12–8.39 × 108 m3/km2. Due to the low gas expulsion intensity, the Shihezi 8 Member's tight sandstone reservoirs, situated away from the source rock, typically show low gas saturation. Conversely, the dissolution and quartz-cemented facies within the Benxi, Taiyuan, and Shanxi Formations, intimately interbedded with hydrocarbon source rocks, exhibit good reservoir quality. They offer ideal conditions for gas accumulation, making them prime candidates for exploration and development.

Assessment of Depth of Mud-Filtrate Invasion and Water Saturation Using Formation-Tester Measurements: Application to Deeply Invaded Tight-Gas Sandstones

Formation pressure/fluid measurements are impacted by mud-filtrate invasion, which may require long fluid pumpout durations to acquire hydrocarbon samples with minimal mud-filtrate contamination. However, unlike other well-logging instruments, formation testers do not have a fixed depth of investigation that limits their ability to pump out mud filtrate until acquiring original formation fluids (i.e., sensing the uninvaded zone). We use an in-house petrophysical and fluid-flow simulator to perform numerical simulations of mud-filtrate invasion, well logs, and formation-tester measurements to estimate the radial distance of invasion and the corresponding radial profile of water saturation. Numerical simulations are initialized with the construction of a multilayer petrophysical model. Initial guesses of volumetric concentration of shale, porosity, water saturation, irreducible water saturation, and residual hydrocarbon saturation are obtained from conventional petrophysical interpretation. Fluid-flow-dependent petrophysical properties (permeability, capillary pressure, and relative permeability), mud properties, rock mineral composition, and in-situ fluid properties are obtained from laboratory measurements. The process of mud-filtrate invasion and the corresponding resistivity and nuclear logs are numerically simulated to iteratively match the available well logs and estimate layer-by-layer formation water saturation. Next, using our multiphase formation testing simulator, we numerically simulate actual fluid sampling operations performed with a dual-packer formation tester. Finally, we estimate irreducible water saturation by minimizing the difference between the hydrocarbon breakthrough time numerically simulated and measured with formation-tester measurements. The examined sandstone reservoir is characterized by low porosity (up to 0.14), low-to-medium permeability (up to 40 md), and high residual gas saturation (between 0.4 and 0.5). The deep mud-filtrate invasion resulted from extended overbalanced exposure to high-salinity water-based mud (17 days of invasion and 1,800 psi overbalance pressure) coupled with the low mud-filtrate storage capacity of tight sandstones. Therefore, the uninvaded formation is located far beyond the depth of investigation of resistivity tools, whereby deep-sensing resistivities are lower than those of uninvaded formation resistivity. Through the numerical simulation of mud-filtrate invasion, well logs, and formation-tester measurements, we estimated radial and vertical distributions of water saturation around the borehole. Likewise, we quantified the hydrocarbon breakthrough time, which matched field measurements of 6.5 hours. The estimated radius of invasion was approximately 2.5 m, while the difference between estimated water saturation in the uninvaded zone and water saturation estimated from the deep-sensing resistivity log was approximately 0.13, therefore improving the estimation of the original gas in place.

Supervised machine learning for discriminating fluid saturation and presence in subsurface reservoirs

This paper describes a workflow that combines machine learning and frequency-related multi-attribute analyses to predict the occurrence of water, oil, and high or low gas saturations in three Miocene Gulf of Mexico clastic reservoirs, the Ursa, King Kong and Lisa Anne fields. The models are trained on labeled data from the Ursa Field dataset and validation is conducted on the King Kong and Lisa Anne Field datasets, comprising four wells with oil and varying gas saturations. We also analyze the impact of fluid-type and saturation on a suite of frequency-related attributes, including independent frequency magnitudes and spectral shape attributes.We also assess feature significance using SHAP Analysis and our results indicate that that high gas saturation is characterized by high magnitudes of low frequencies, increased bandwidth, and lower skewness and kurtosis values. Conversely, low gas saturation is distinguished by high magnitudes of medium frequencies, reduced bandwidth, and higher skewness and kurtosis values.Our workflow demonstrates the power and utility of supervised machine learning for reservoir fluid identification and saturation prediction. Human interpreters relying solely on post-stack seismic data may find the task of reservoir fluid predictions challenging and the results may be compromised by subjectivity. This study underscores the potential of machine learning to improve hydrocarbon exploration and production, providing a more robust approach to prospect risk assessment using post-stack seismic data and frequency attributes.

Assessment of True Formation Resistivity and Water Saturation in Deeply Invaded Tight-Gas Sandstones Based on the Combined Numerical Simulation of Mud-Filtrate Invasion and Resistivity Logs

The process of mud-filtrate invasion involves immiscible fluid displacement and salt mixing between mud filtrate and formation fluids in porous and permeable rocks. Consequently, the post-invasion spatial distribution of fluids and electrolyte concentration around the borehole affects resistivity measurements with different depths of investigation (DOI). In the presence of deep mud-filtrate invasion, the assessment of water saturation in the uninvaded zone based on the deep resistivity log can be inaccurate. Deep and electrically conductive filtrate invasion coupled with shoulder-bed effects can artificially increase water saturation (Sw) estimations by 20 saturation units (s.u.) in the Barik reservoir, resulting in pessimistic estimates of hydrocarbon pore volume if no corrections are applied. The Barik sandstone reservoir, which is characterized by low porosity ( up to 14%), low-to-medium permeability (up to 40 md), and high residual gas saturation (40 to 50%), exhibits low storage capacity to admit the critical filtrate volume necessary for building an impermeable mudcake. Combined with multiple days of overbalanced exposure to saline water-based mud (WBM), mud-filtrate invasion results in deep and smooth radial transition zones where the uninvaded formation is far beyond the depth of investigation of laterolog tools. Deep resistivity values are, therefore, lower than the true formation resistivity. Additionally, numerical simulations of resistivity logs show that the resistivity reduction by conductive invasion is further aggravated by shoulder-bed effects when individual reservoir thickness falls below 2.5 m. This paper describes the implementation of a compositional fluid-flow simulator to numerically model WBM-filtrate invasion and mudcake buildup in vertical boreholes. The algorithm allows the simulation of physical dispersion and fluid displacement around the borehole in a multilayer model. Time-dependent radial profiles of Sw and salinity are combined with core-calibrated porosity and electrical properties to compute electrical resistivity via Archie’s formulation. Subsequently, numerically simulated logs are generated using vendor-specific forward model processing and compared against field measurements. This workflow was extensively tested in various reservoir intervals with a wide range of petrophysical rock types and drilling conditions. Results show that the deep laterolog exhibits low sensitivity to conductive filtrate invasion when reservoirs’ porosities are lower than 8%. Above that threshold value, invasion length is a nontrivial process involving multiple variables. Even though exposure time to openhole conditions is a key factor leading to deep invasion, certain reservoir characteristics can lead to deeper invasion at short exposure times and significantly increase uncorrected Sw estimates.

Technical advances in well type and drilling & completion for high-efficient development of coalbed methane in China

Compared with the United States, Australia, Canada, and other countries, China's coalbed methane reservoir is featured by low formation pressure, low permeability, low gas saturation, and strong heterogeneity, which not only increases the difficulty of reservoir stimulation but also restricts the single well production and the recovery efficiency of coalbed methane (CBM). In view of this, the research and application of horizontal drilling and completion technology of CBM at home and abroad are reviewed to provide references and theoretical supports for the advancement of the horizontal well engineering technology of CBM in China. This paper introduces a series of horizontal drilling and completion technologies (e.g., the well type design, well structure optimization, well trajectory control, wellbore stability, completion optimization, reservoir protection, etc.). The advanced technologies and their adaptability, including screen pipe completion and stimulation with dual-layer tubular strings, radial horizontal well screen pipe completion and magnetic steering drilling, are dialectically discussed in this paper. In addition, a novel integrated engineering mode for the efficient and green development of deep CBM and coal through the underground “well factory” is proposed. The conclusions are as follows: (1) In view of the geological conditions and surface environment of the coal seam in China, the horizontal drilling and completion technologies of high rank coalbed methane should be further refined, and an integrated development for the coal measure gas is required; (2) More efforts should be made to strengthen the innovative research on horizontal drilling & completion technology for low-medium rank coals and the broken coal, so as to identify the efficient development mode for the complex coalbed methane reservoir; (3) When encountering major technical challenges during the green and efficient development of unconventional coal mines such as deep coal mines, low grade coal mines and thin coal seams in China, it is necessary to explore the development mode via in-situ conversion process based on underground “well factory” to realize the integrated green and efficient development of deep CBM and coal; (4) The high quality transformation with low-carbon and green energy in China will not only ensure national energy security, but also achieve the goal of “carbon peaking and carbon neutrality”.

Seismic inversion for density using a transdimensional approach

Commercial and low-saturation gas (also called paleoresidual gas [PRG]) show similar strong amplitude signatures on P-wave seismic data. This poses an exploration risk in gas reservoir regions. However, density correlates inversely with gas saturation and can differentiate a zone of full gas saturation from PRG. This can improve the chances of success in terms of predrill prediction of gas saturation. Amplitude-variation-with-offset (AVO) inversion using prestack seismic data is the most commonly used technique that can estimate elastic parameters such as P-wave velocity, S-wave velocity, and density. Out of these three parameters, extracting density from seismic data is the most challenging due to its weak sensitivity to seismic reflection amplitude and the lack of good quality seismic data at far offsets. However, with recent improvements in seismic data acquisition and processing technology, which produces reliable AVO gathers, density estimates have improved. This requires that strong density sensitivity to AVO exists. Note that multiple density models may fit the data equally well. Therefore, quantifying uncertainty is crucial for interpretation and risk assessment. We apply a recently developed stochastic approach based on the Bayesian framework to solve the problem in a transdimensional framework, where the number of model parameters is treated as a variable and estimated along with the elastic properties. We use the reversible jump Hamiltonian Monte Carlo (RJHMC) algorithm to sample models from a variable dimensional model space and obtain a globally optimum model and uncertainty estimates. We use a synthetic and good quality real data set from Columbus Basin in Trinidad, which has a proven gas reservoir, to demonstrate the algorithm. The RJHMC results calibrate well with the logs and show the areal extents of the density anomalies within the 3D volume.

Discriminating seismic amplitude pitfall by low saturation gas using controlled-source electromagnetic technology

One of false positives in seismic amplitude associates with the presence of low saturation gas. The amplitude response is ambiguous prominently in shallow subsurface due to similar amplitude of fizz gas to highly saturated gas reservoir. This pitfall is demonstrated in Gassmann’s fluid substitution modelling which drastic velocity reduction is modeled by 5% of gas. The strong reduction induces anomalous bright spot in seismic similarly manifested by a highly gas reservoir. In pore fluid characterization, seismic amplitude of a brine reservoir is well distinguished from gas by change of response polarity from negative to positive amplitude due to higher brine modulus than gas. To a lesser extent, the negative amplitude of gas sand almost identical between commercial and non-commercial gas trap and difficult to distinguish in seismic. The similar negative amplitude of the gas cases caused by a very low gas modulus resulting to sudden drop of rock bulk modulus despite with the presence of low gas percentage. Thus, seismic velocity slows down when travels through a gas sand medium. Integration of controlled-source electromagnetic (CSEM) method in hydrocarbon prediction reduces exploration risk by only detecting commercial hydrocarbon. It exploits resistivity contrast between overburden and hydrocarbon reservoir which highly controlled by hydrocarbon saturation. CSEM normalized response exceeds the cut off response by a minimum saturation of 70% of gas. Less than 70% of gas, CSEM response is below the cut off response which considered as insignificant anomaly in CSEM measurement. It becomes a key strength as this method reduces amplitude uncertainty in seismic due to low saturation gas and potentially improves the chances of economic discovery in hydrocarbon exploration.

Reducing the risk of low saturation gas using controlled-source electromagnetic (CSEM) in K-Field, Central Luconia: a forward modeling case study

The application of controlled-source electromagnetic (CSEM) in hydrocarbon exploration significantly facilitates the detection of economic hydrocarbon. The method captures anomalies through the resistivity contrast between the overburdens and hydrocarbon-bearing lithologies. In most cases, the resistivity contrast is only prominent when there is sufficient hydrocarbon saturation. K-Field is situated on the continental shelf of Sarawak Basin, a sub-mature area for oil and gas in the Central Luconia province. Despite the low saturation of the gas in the Cycle VI sand, the seismic data shows a strong amplitude in the shallow section. Therefore, this study is conducted to assess the change of resistivity and CSEM response to the gas saturation and thickness variations of thin-gas sand in the K-Field. 3D resistivity models and three exploration wells are provided and two main methods are implemented in this study comprising the resistivity and CSEM forward modelings. The resistivity modeling is conducted using the Indonesia water saturation equation for different gas saturation scenarios and subsequently, the modeled resistivity is inputted in 1D and 2.5D CSEM forward modeling. The modeled CSEM response analysis is done by normalizing the modeled CSEM amplitude to the background or also known as normalized amplitude response (NAR). In gas saturation variation, the modeled resistivity showed an insignificant resistivity increase from 0.45Ωm to 0.55Ωm from wet case to 5% of gas and strongly increases to 35Ωm at 90% of gas saturation. The 1D CSEM NAR shows a very weak response of less than a 3% increase for 5% of gas and up to 230% increase for 90% of gas. In gas thickness variation, the CSEM NAR is weak and less than a 15% cutoff for all the tested thicknesses for 5% and 45% of in-situ gas. At 70% of gas, 25m is the minimum detected gas thickness with a 17.5% response increase, and at 90% of gas, the response is already strong at a minimum 5m thickness with a 35% increase. The modeled 2D CSEM responses also show that only 70% and 90% of gas sand layers in the K-field were delineated distinctively by the inline receivers with a 40% and 200% response increase respectively.

Unsupervised Machine Learning, Multi-Attribute Analysis for Identifying Low Saturation Gas Reservoirs within the Deepwater Gulf of Mexico, and Offshore Australia

An effective method of identifying and discriminating undersaturated gas accumulations remains unresolved, resulting in uncertainty in hydrocarbon exploration. To address this problem, an unsupervised machine learning multi-attribute analysis is performed on 3D post-stack seismic data over several blocks within the deepwater Gulf of Mexico and within the Carnarvon Basin, offshore Australia. Results reveal that low-saturation gas (LSG) reservoirs can be discriminated from high-saturation gas (HSG) reservoirs by using a combination of instantaneous attributes that are sensitive to small amplitude, frequency, and phase anomalies with self-organizing maps (SOMs). This methodology shows promise for de-risking prospects, even if it is not quantitative, particularly in frontier and exploration basins where wells may not exist or be very limited. However, this method only proved to be successful within the Gulf of Mexico and yielded limited results in the Carnarvon Basin. This difference is most likely due to the Carnarvon Basin having a different amplitude response resulting from a different burial history and fluid saturations when compared to the Gulf of Mexico. Therefore, this method is non-transferrable, and a different combination of attributes may be needed in other LSG-prone basins.

Mass transfer between fluids as a mechanism for seismic wave attenuation: experimental evidence from water–CO2 saturated sandstones

SUMMARY Seismic waves are typically assumed to propagate fast enough through a porous rock saturated with multiple fluid phases such that the interaction between the fluids can be considered adiabatic, or thermodynamically unrelaxed. However, at low gas saturations and when the gas is present in the form of microscopic bubbles the fluid mixture may in fact be thermodynamically relaxed at seismic frequencies. The effective fluid is then significantly more compressible. A transition from a thermodynamically relaxed to unrelaxed state of the fluids will be accompanied by frequency dependent attenuation of the wave in response to heat and/or mass transfer. We conducted experiments on two partially saturated sandstone samples to measure frequency dependent attenuation and modulus dispersion at seismic frequencies (<1000 Hz). For CO2 saturations of 0.1–0.2 per cent we observe significant attenuation and dispersion in the bulk and shear modulus, with an attenuation peak at ∼100 Hz. The bulk modulus was significantly lower than the prediction by Gassmann–Wood fluid substitution, which assumes that the fluids are thermodynamically unrelaxed. Numerical simulations in poroelastic media further indicate that a partially drained boundary condition does not adequately explain the observed attenuation and dispersion, particularly in the shear modulus. Numerical simulations at the microscopic scale support the notion that pore-scale heterogeneities could explain the observed shear attenuation and dispersion, since an external shear deformation can cause local compressions of the pore space. The observed attenuation and dispersion are interpreted to be predominantly due to a transition from a thermodynamically relaxed to unrelaxed state of the saturating fluids.

On the questions of supply of active gas raw materials in central Yakutia

The article deals with the problem of the reliability of the balance gas reserves of the Vilyui oil and gas region calculated by the volumetric method. Based on the analysis of the development of gas and gas condensate fields of the Predverkhoyansk and Vilyui oil and gas bearing regions, the low production capabilities of the depleted fields of the region are shown. It is concluded that the most reliable in the conditions of a complex geological structure of deposits is the assessment of gas reserves by the pressure drop method. The idea is formulated that for the fields of the Vilyui oil and gas bearing area, which have productive horizons with low initial gas saturation of reservoirs, the final gas recovery factors can be estimated at 0.55. The expediency of considering the issue of the special status of the Srednevilyui gas condensate field as a field with strategic gas reserves is noted.

Electrolyte layer gas triggers cathode potential instability in CO2 electrolyzers

Electrolytic carbon dioxide (CO2) reduction is becoming increasingly promising for managing anthropogenic CO2 emissions; however, issues related to unstable performance and ineffective gas management are still not fully accounted for in the field. Here, we identify two instability modes that are directly linked to the electrolyte layer gas saturation for an anion exchange membrane CO2 reduction flow cell circulating a neutral pH electrolyte (KHCO3). The cathode potential exhibits a semi-stable mode with low electrolyte layer gas saturations and a detrimental secondary mode with high gas saturations and a highly noisy, non-stationary potential. We illustrate that the gas saturation has a profound, direct impact on the mode of instability with a direct correlation between the coefficient of variation in cathode potential and the electrolyte layer gas saturation measured with real-time neutron radiography. This correlation is indicative of reaction site gas blockage that results in performance instability and reduced energy efficiency.

Displacement Efficiency in Tight Sandstone Based on Fractional Flow Curve Using Relative Permeability Data

In tight gas sandstone, relative permeability is an essential special core analysis dynamic test that can be used to estimate injectivity, secondary recovery, production rate, reservoir simulation, residual gas saturation, and effective water management. Having about 65% of hydraulic fracturing fluid not to flow back and stay in the reservoir results in having the tight sandstone gas reservoir to involve multi-phase flow, namely water and gas. During the hydraulic fracturing job both imbibition and forcibly imbibition processes take place while during fracturing fluid cleanup and gas production drainage flow becomes dominant.
 The steady state flooding process was used to measure the relative permeability curves for tight sandstone core sample collected from Travis Peak Formation at a depth of 8707 ft. The measurement process involved the performance of a series of steady state experiments with different gas-water injection ratio. The fractional flow curve has been plotted, based on the measured relative permeability, and used to calculate the displacement efficiency for the flow through such type of tight porous media. The measurement showed relatively high irreducible water saturation (31%) and low residual gas saturation (6%). The measured gas relative permeability decreased slowly at a constant rate with increased wetting fluid saturation. The obtained fractional flow curve does not follow the s-shape behavior observed in conventional reservoir. The obtained results showed that displacement efficiency can be enhanced by increasing water viscosity.

Morphological patterns and interface instability during withdrawal of liquid-particle mixtures

HypothesisThe stability of fluid–fluid interface is key to control the displacement efficiency in multiphase flow. The existence of particles can alter the interfacial dynamics and induce various morphological patterns. Moreover, the particle aggregations are expected to have a significant impact on the interface stability and patterns. ExperimentsMonodisperse polyethylene particles of different sizes are uniformly mixed in silicone oil to form the granular mixtures, which are injected into a transparent radial Hele-Shaw cell through different strategies to obtain the homogeneous and inhomogeneous (with particle aggregations) initial states. Subsequently, a systematic study of morphology and interface stability during the withdrawal of granular mixtures is performed. FindingsFor homogeneous mixtures, we observe earlier onset of fingering, more fingers and lower gas saturation at breakthrough than for pure fluid with equivalent viscosity. This effect can be attributed to the particle-induced perturbations. For inhomogeneous mixtures, particle clusters and bands significantly enhance the interface instability. Furthermore, we find that particle deposition due to liquid film entrainment occurs above a critical local flow velocity, and we elucidate the responsible mechanism through force balance analysis and the thin film theory. This work could be of practical significance in geoenergy and industrial applications.

A quantitative study of the scale and distribution of tight gas reservoirs in the Sulige gas field, Ordos Basin, northwest China

Gas and water distribution is discontinuous in tight gas reservoirs, and a quantitative understanding of the factors controlling the scale and distribution of effective reservoirs is important for natural gas exploration. We used geological and geophysical explanation results, dynamic and static well test data, interference well test and static pressure test to calculate the distribution and characteristics of tight gas reservoirs in the H8 Member of the Shihezi Formation, Sulige gas field, Ordos Basin, northwest China. Our evaluation system examines the scale, physical properties, gas-bearing properties, and other reservoir features, and results in classification of effective reservoirs into types I, II, and III that differ greatly in size, porosity, permeability, and saturation. The average thickness, length, and width of type I effective reservoirs are 2.89, 808, and 598 m, respectively, and the porosity is > 10.0%, permeability is > 10 × 10−3 µm2, and average gas saturation is > 60%. Compared with conventional gas reservoirs, tight gas effective reservoirs are small-scale and have low gas saturation. Our results show that the scale of the sedimentary system controls the size of the dominant microfacies in which tight gas effective reservoirs form. The presence of different types of interbeds hinders the connectivity of effective sand body reservoirs. The gas source conditions and pore characteristics of the reservoirs control sand body gas filling and reservoir formation. The physical properties and structural nature of the reservoirs control gas-water separation and the gas contents of effective reservoirs. The results are beneficial for the understanding of gas reservoir distribution in the whole Ordos Basin and other similar basins worldwide.