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Tight sandstone water-bearing gas reservoirs typically exhibit low porosity and low permeability, with reservoir rocks characterized by complex pore structures, often featuring micron-scale or smaller pore throats. This intricate reservoir structure significantly restricts fluid flow within the reservoir, necessitating a certain threshold pressure gradient (TPG) to be overcome before flow can commence. This study focuses on the Ordos Basin and explores the influence of high water content tight sandstone gas reservoirs on TPG under different water saturation and formation pressure conditions through experiments. A mathematical model of TPG is established using multiple linear regression method. The results show that TPG is primarily affected by water saturation, followed by formation pressure. As the water saturation increases, the TPG of the core decreases, and the change becomes more pronounced when the water saturation exceeds 50%. As formation pressure increases, the weakening of the slippage effect in gas molecules leads to TPG stabilization, especially when local pressure exceeds 25.0 MPa. The research also shows that low-permeability cores exhibit greater TPG variation with pressure changes, while high-permeability cores remain more stable. A mathematical model was developed and validated to predict TPG based on permeability, water saturation, and formation pressure. These findings highlight the need to monitor formation water content during tight sandstone gas reservoir development to optimize production strategies, providing valuable insights for improving reservoir management and guiding future research. [ABSTRACT FROM AUTHOR]

The resistivity difference between oil and gas layers and the water layers in low contrast tight sandstone reservoirs is subtle. Fluid identification and saturation calculation based on conventional logging methods are facing challenges in such reservoirs. In this paper, a new method is proposed for fluid identification and saturation calculation in low contrast tight sandstone reservoirs. First, a model for calculating apparent formation water resistivity is constructed, which takes into account the influence of shale on the resistivity calculation and avoids apparent formation water resistivity abnormal values. Based on the distribution of the apparent formation water resistivity obtained by the new model, the water spectrum is determined for fluid identification in low contrast tight sandstone reservoirs. Following this, according to the average, standard deviation, and endpoints of the water spectrum, a new four-parameter model for calculating reservoir oil and gas saturation is built. The methods proposed in this paper are applied to the low contrast tight sandstone reservoirs in the Q4 formation of the X53 block and X70 block in the south of Songliao Basin, China. The results show that the water spectrum method can effectively distinguish oil-water layers and water layers in the study area. The standard deviation of the water spectrum in the oil-water layer is generally greater than that in the water layer. The new fourparameter model yields more accurate oil and gas saturation. These findings verify the effectiveness of the proposed methods. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Oilfield Development in Daqing is the property of Editorial Department of Petroleum Geology & Oilfield Development in Daqing and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

In-depth understanding of the gas–water seepage law caused by different degrees of gas layer perforation and varying gas production rates is key to determining a reasonable development technology policy for vertical heterogeneous edge-water gas reservoirs. Based on core physical data from the entire section of the X2 well, a large-scale high-pressure positive-rhythm profile model that takes into account the influence of "discontinuous interlayer" was innovatively established. The water intrusion process of the gas layer profile under different gas production rates and degrees of gas layer perforation was simulated using an electrical resistivity scanning device. The experimental model has an area of 3000 cm2, with a maximum pressure of 70 MPa and a maximum temperature resistance of 150 °C. It includes 456 evenly distributed fluid saturation test points to accurately monitor the gas–water distribution, addressing the issues of small bearing pressure and insufficient saturation monitoring points found in other large-scale models. The experimental results show that, in heterogeneous reservoirs, the high-permeability zone controls the invasion path of edge water, which is the main reason for the uneven invasion of edge water. For the positive-rhythm profile of the F layer, a higher gas production rate (1000 mL/min) shortens the water-free gas recovery period of the gas well and reduces the recovery rate. Perforating the upper two-thirds of the layer can inhibit edge-water breakthrough, prolong the water-free gas recovery period of the gas well, enable the gas–water interface to advance more uniformly, and enhance the recovery degree. The results of this study greatly enhance our understanding of the water invasion characteristics of positive-rhythm reservoirs under the influence of different gas production rates and varying degrees of gas layer perforation. [ABSTRACT FROM AUTHOR]

In order to clarify the water invasion law and residual gas distribution characteristics in edge and bottom water gas reservoirs with multi-well development, a large-scale three-dimensional physical simulation model was developed and a physical simulation experiment method for the water invasion law of multi-well development in sandstone gas reservoirs with strong water drives was established. Water invasion physical simulation experiments of multi-well development under the conditions of different water body multiples and production systems were conducted. The results show the following: (1) Gas wells near fractures and high-permeability zones experience the earliest water breakthrough. The larger the water body multiple, the faster the rate of water invasion, the earlier the water breakthrough time of gas wells, the more severe the degree of water invasion in gas reservoirs, and the lower the ultimate recovery rate. (2) Shutting in low-position gas wells immediately after water breakthrough reduces the overall water production of the gas reservoir and extends the overall water-free gas production period. However, the ultimate recovery rate is lower than when the wells are not shut in. (3) The residual gas in the fracture model is mainly distributed around the fracture and the edge of the gas reservoir, with the ultimate recovery rate ranging from 38.5% to 58.2%. The residual gas in the fracture–high-permeability zone model is mainly distributed around the fracture–high-permeability zone and the edge of the gas reservoir, with the ultimate recovery rate ranging from 28.32% to 41.8%. The experimental results have important guiding significance for the economical and efficient development of similar gas reservoirs. [ABSTRACT FROM AUTHOR]

The efficient use of depleted gas reservoirs for hydrogen storage is a promising solution for transitioning to carbon-neutral energy sources. This study proposes an analytical framework for estimating hydrogen storage capacity using a comprehensive material balance approach in depleted gas reservoirs. The methodology integrates basic reservoir engineering principles with thermodynamic considerations to accurately estimate hydrogen storage capacity in both volumetric drive and water drive gas reservoirs through an iterative approach based on mass conservation and the real gas law. This framework is implemented in a Python program, using the CoolProp library for phase behavior modeling with the Soave–Redlich–Kwong (SRK) equation of state. The methodology is validated with numerical simulations of a tank model representing the two reservoir drive mechanisms discussed. Also, a case study of a synthetic complex reservoir demonstrates the applicability of the proposed approach to real-world scenarios. The findings suggest that precise modeling of fluid behavior is crucial for reliable capacity estimations. The proposed analytical framework achieves an impressive accuracy, with deviations of less than 1% compared to estimates obtained through numerical simulations. Insights derived from this study can significantly contribute to the assessment of strategic decisions for utilizing depleted gas reservoirs for hydrogen storage. [ABSTRACT FROM AUTHOR]

The evaluation of gas content plays a key role in determining the efficient development of shale reservoirs. To better understand the gas–water miscible competitive adsorption mechanism in the pore-fracture system of water-bearing shale, the water vapor adsorption experiment of dry shale and the methane gas adsorption experiment of water-bearing shale were carried out to compare and analyze the competitive adsorption laws of formation water and methane gas on the shale surface under different temperatures, pressures, and water saturation conditions. Moreover, based on the molecular layer adsorption theory, the gas–liquid–solid interface competitive adsorption model considering the coupling of temperature, pressure, and water saturation was established to predict the actual gas content of water-bearing shale reservoirs. The results show that the main controlling factors affecting the adsorbed gas content of water-bearing shale are specific surface area, temperature, and water content in turn according to weight coefficients; Compared with the gas–solid adsorption model, the gas–liquid–solid competitive adsorption model has higher accuracy in calculation results, which are much closer to the desorption data of shale cores in Jiaoshiba area, Fuling, China. Hence, the competitive adsorption model provides a theoretical foundation for reasonably evaluating the exploitation potential of shale gas reservoirs. [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas Geoscience is the property of Natural Gas Geoscience and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The tight sandstone reservoirs in the Sulige Gas Field have complex pore structures and gas-water distribution, and the water production law in the complex gas-water distribution areas has not been clarified. The water production of gas wells in different regions varies greatly, and the water production of gas wells seriously affects the efficient development of natural gas. In order to improve the benefit of gas field development, this study takes stress-sensitive effects, gas-water immiscibility, and constant production conditions of gas wells under a certain gas-water ratio Rgw as constraints, and considers the fluid seepage as an isothermal seepage process, an evaluation model of the productivity of a theoretical water-producing gas well and a relative permeability model of the gas phase are constructed. Moreover, the influence of water production on the degree of pressure drop, gas well productivity, and gas well recovery was systematically analyzed. This study shows that when the water-gas ratio of gas wells is less than 1, 1-2, 2-3, 3-4, 4-5, and greater than 5, its influence on productivity is less than 40%, 52%, 50%, 58%, 61%, 65% and greater than 65%, respectively. The average water-gas ratio of the water-producing gas wells in the Sulige Gas Field is 1.27 m3/10 4 m3. The effect of water production on recovery is compared with the case of no water production: for water-producing gas wells, the recovery rate of Type I wells is reduced by 8.45%, that of Type II wells is reduced by 9.58%, and that of Type III wells is reduced by 11.54%. [ABSTRACT FROM AUTHOR]

Warning and controlling the water invasion in water-driving reservoirs is significant because water invasion will seriously hamper well productivity and gas recovery. Unfortunately, there are few comprehensive methods to control water invasion. First, we establish and verify a water invasion model of reservoir scale. Then, a new workflow for warning and controlling the water invasion is proposed using the numerical simulation method. The workflow first judges the water invasion characteristics, determines the water invasion index based on the production data, and then controls the water invasion by finding and closing the perforation layer of serious water production. Finally, the optimal water control scheme is obtained by comparing water and gas production. The results show that the accuracy of the geological reserves of the established water invasion model is 99% and has a good pressure fitting result. The early warning chart for the gas reservoir in the west of Amu Darya B area is drawn, including the early warning pressure and the level 1, level 2, and level 3 early warning water–gas ratio, which is convenient for field application. For the water-driving wells west of area B, the early warning value of the water–gas ratio increases with the increase of gas production rate during fixed production and decreases with the increase of bottom hole pressure during constant pressure production. Closing the harmful perforation from the water-finding study will significantly reduce the water while retaining the gas production. After water control technology, water production decreased by 90.9%, while gas production decreased by only 9.7%. [ABSTRACT FROM AUTHOR]

It has been widely accepted that China is one of the biggest natural gas consumers. Related to the imports of LNG, China stands in a very uncomfortable situation. Most domestic gas reservoirs fall within deep water drive gas reservoirs inordinately, which has entered the production depletion stage. Accurate estimation of SEC recoverable reserves of deep water drive gas reservoirs is of great significance for gas consumption planning and peak shaving. The existing calculation methods of recoverable reserves mainly consist of static methods and dynamic methods. In the early stage of exploration and development, the volumetric method has often been utilized to calculate the recoverable reserves. With the continuous development of gas reservoirs, the main methods for evaluation are dynamic methods, including the successive subtraction of production method, water drive curve method, prediction model method, attenuation curve method, improved virtual curve method, and material balance method for deep gas reservoirs. [ABSTRACT FROM AUTHOR]

In recent years, with the rapid development of salt cavern gas storage reservoir construction in China, the characteristics of salt rock reservoirs with strong non-homogeneity and many interlayers have brought challenges to the dynamic prediction of water solution cavity construction. Aiming to solve this problem, this paper constructs a three-dimensional non-homogeneous salt cavern reservoir water-soluble cavity building prediction model, which takes into full consideration the non-homogeneity of salt rock reservoirs, interlayers, reservoir temperatures, and water injection process parameters, among other factors. By comparing the calculation results of the software compiled by the model with those of other numerical simulation software, we show that the model can accurately reflect the influence of geological parameters on the cavity morphology under the condition of non-uniform geological parameters, with higher simulation accuracy, and ultimately analyze individual examples. It can provide important theoretical support and practical guidance for the construction of a salt cavern gas storage reservoir. [ABSTRACT FROM AUTHOR]

Tight gas reservoirs possess unique pore structures and fluid flow mechanisms. Delving into the flow and imbibition mechanisms of water in fractured tight gas reservoirs is crucial for understanding and enhancing the development efficiency of such reservoirs. The flow of water in fractured tight gas reservoirs encompasses the flow within fractures and the imbibition flow within the matrix. However, conventional methods typically separate these two types of flow for study, failing to accurately reflect the true flow characteristics of water. In this study, micro-CT imaging techniques were utilized to evaluate the impact of matrix absorption and to examine water movement in fractured tight gas deposits. Water flooding experiments were conducted on tight sandstone cores with different fracture morphologies. Micro-CT scanning was performed on the cores after water injection and subsequent static conditions, simulating the process of water displacement gas in fractures and the displacement of gas in matrix pores by water through imbibition under reservoir conditions. Changes in gas–water distribution within fractures were observed, and the impact of fracture morphology on water displacement recovery was analyzed. Additionally, the recovery rates of fractures and matrix imbibition at different displacement stages were studied, along with the depth of water infiltration into the matrix along fracture walls. The insights gained from this investigation enhance our comprehension of the dynamics of fluid movement within tight gas deposits, laying a scientific foundation for crafting targeted development plans and boosting operational efficiency in such environments. [ABSTRACT FROM AUTHOR]

WAG flooding is a dynamic process of continuous reservoir flow field reconstruction. The unique advantages of WAG flooding cannot be utilized, due to the fixed water–gas ratio. Therefore, we must investigate the dynamic adjustment of the water–gas ratio for WAG flooding. Using nine cases of long-core displacement experiments in low-permeability reservoirs, the development effects of three different displacement methods, namely, continuous gas flooding, WAG flooding with a fixed water–gas ratio, and WAG flooding with a dynamic water–gas ratio, were investigated after elastic development, water flooding, and gas flooding. This study shows that for early elastic development in low-permeability reservoirs, WAG flooding can significantly improve oil recovery, but WAG flooding with a dynamic water–gas ratio is not conducive to the control of the water cut rise and gas channeling. As a result, it is more suitable to adopt WAG flooding with a fixed water–gas ratio. For early water flooding in low-permeability reservoirs, WAG flooding more clearly improves oil recovery and suppresses gas channeling, but WAG flooding with a dynamic water–gas ratio exhibits a higher oil recovery and thus is recommended. For early gas flooding in low-permeability reservoirs, whether the development effect of WAG flooding can improve oil recovery and inhibit gas channeling strongly depends on whether the water–gas ratio is adjusted. The development effect of WAG flooding with a dynamic water–gas ratio is significantly better than that with a fixed water–gas ratio. Therefore, WAG flooding with a dynamic water–gas ratio is recommended to achieve the best displacement effect. This research has important practical significance for further improving the development effect of WAG flooding in low-permeability reservoirs. [ABSTRACT FROM AUTHOR]

The late-stage development of gas reservoirs often encounters the paradox of significant remaining formation pressure coupled with low wellhead pressure, which indicates small drainage volume, low gas production rate, and low recovery efficiency, reducing gas supply and economic benefit. Owing to the lack of experimental research, the reasons behind this contradiction between gas production and producing pressure differential are unclear. The key factors affecting the development outcomes are reservoir permeability and initial water saturation, while the evaluation parameters include gas and water production rates, reservoir pressure, and recovery efficiency. Based on the characteristic properties of typical gas fields, physical simulation experiments of constant-rate gas production are conducted on spliced long cores with average permeabilities of 2.300, 0.486, and 0.046 millidarcy (mD). Furthermore, leveraging the multi-point embedded pressure measurement technique, the pressure drawdown propagations and the macroscopic and microscopic characteristics of connate water production at the initial water saturations of 0%, 20%, 40%, and 55% are investigated. By connate water, we mean water that occurs naturally within the pores of rock. Pre- and post-experiment core weighing and nuclear magnetic resonance testing are performed. In addition to the mercury injection tests, the results indicate that during gas reservoir depletion, connate water primarily stems from macropores and mesopores, with micropores and nanopores capturing water through capillary imbibition. Moreover, lower permeability and higher initial water saturation lead to greater pressure gradients, increased connate water production, and reduced recovery efficiency. Reservoirs with permeabilities below 0.1 mD are significantly affected by connate water, exhibiting steep pressure profiles. Owing to connate water, the near-wellbore pressure quickly decreases, while distant reservoir pressure barely decreases, implying a limited drainage area. To enhance the recovery efficiency, measures like infill drilling and reservoir stimulation are recommended for low-permeability gas reservoirs. [ABSTRACT FROM AUTHOR]

The performance of carbon geo-sequestration is influenced by several parameters, such as the heterogeneity of the reservoir, the characteristics of the caprock, the wettability of the rock, and the salinity of the aquifer brine. Although many characteristics, like the formation geology, are fixed and cannot be altered, it is feasible to choose and manipulate other parameters in order to design an optimized storage programme such as the implementation of CO2 injection techniques, including continuous injection or water alternating CO2, which can significantly increase storage capacity and guarantee secure containment. Although WAG (water-alternating-gas) technology has been widely applied in several industrial sectors such as enhanced oil recovery (EOR) and CO2 geo-sequestration, the impact of the CO2-to-water ratio on the performance of CO2 geo-sequestration in heterogeneous formations has not been investigated. In this study, we have constructed a 3D heterogeneous reservoir model to simulate the injection of water alternating gas in deep reservoirs. We have tested several CO2-water ratios, specifically the 2:1, 1:1, and 1:2 ratios. Additionally, we have estimated the capacity of CO2 trapping, as well as the mobility and migration of CO2. Our findings indicate that injecting a low ratio of CO2 to water (specifically 1:2) resulted in a much better performance compared to situations with no water injection and high CO2-water ratios. The residual and solubility trappings were notably increased by 11% and 19%, respectively, but the presence of free mobile CO2 was reduced by 27%. Therefore, in the reservoir under investigation, the lower CO2-water ratio is recommended due to its improvement in CO2 storage capacity and containment security. [ABSTRACT FROM AUTHOR]

It is necessary to improve oil production from reservoirs. Various methods have been proposed to increase oil extraction from reservoir. Each method has specific challenges. In this research, the effect of water and gas injection in to Azadegan reservoir has been analyzed. Azadegan oil field is located south of Iran. In this study, water, immiscible gas and water alternating gas injected to reservoir and its effect on enhanced oil recovery have been investigated. Finally, a comparison between results of methods is provided. Results show that effective method for enhanced oil recovery is immiscible gas injection with 46% oil production efficiency and water alternating gas injection with 36% oil production efficiency. This study shows that oil production efficiency can be increased if duration of gas injection is increased. This study shows, increasing viscosity of water in water alternating gas scenario did not improve the production of Azadegan reservoir. [ABSTRACT FROM AUTHOR]

As one of the severe accident countermeasures, a method of injecting gas into pool water in a suppression chamber to capture and decontaminate aerosol particles contained in the gas is proposed. For severe accident countermeasures, a physical model for single bubbles representing hydrodynamic phenomena is included. The aim of this study is to elucidate the effect of aerosol particles on the shape and upward behavior of single large diameter bubbles. For this purpose, several aerosol particles with different solubility in tap water were used as parameters to investigate the effect of bubble diameter and Eötvös number on large single bubbles. As a result, the aspect ratio of single bubbles with aerosol particles is smaller than that of droplets without aerosol particles. Furthermore, the aspect ratio was smaller when containing soluble aerosol particles than insoluble aerosol particles. The terminal velocity and drag coefficient were less affected by aerosol particles in the region where bubble diameter is large. Comparison of the numerical and experimental results for aspect ratio showed a similar trend in the increase of aspect ratio with the increase of Eötvös number, but for the quantitative values, the experimental results were much lower than the numerical results. [ABSTRACT FROM AUTHOR]

Although improving the recovery of water-invaded gas reservoirs has been extensively studied in the natural gas industry, the nature of the efficiency of water-invaded gas recovery remains uncertain. Low-field nuclear magnetic resonance (NMR) can be used to clearly identify changes in water saturation in the core during high-pressure water-invasion gas. Here, we provide four types of water-invasion gas experiments (spontaneous imbibition, atmospheric pressure, high-pressure approximate equilibrium, and depletion development water-invasion gas) to reveal the impact of the water-invasion gas efficiency on the recovery of water-invasion gas reservoirs. NMR suggested that imbibition mainly occurs in medium to large pores and that residual gas remains mainly in large pores. The amount of gas driven out from the large pores by imbibition was much greater than that driven out from the small pores. Our findings indicate that the initial gas saturation, contact surface, and permeability are the main factors controlling the residual gas saturation, suggesting that a reasonable initial water saturation should be established before the water-invasion gas experiments. Additionally, the water-invasion gas efficiency at high pressures can be more reliably obtained than that at normal pressures. After the high-pressure approximate equilibrium water invasion for gas displacement, a large amount of residual gas remains in the relatively larger pores of the core, with a residual gas saturation of 42%. In contrast to conventional experiments, the residual gas saturation and water displacement efficiency of the high-pressure approximate equilibrium water invasion for gas displacement did not exhibit a favorable linear relationship with the permeability. The residual gas saturation ranged from 34 to 43% (avg. 38%), while the water displacement efficiency ranged from 32 to 45% (avg. 40%) in the high-pressure approximate equilibrium water invasion for gas displacement. The residual gas saturation in the depletion development water-invasion gas experiment was 26–40% (average: 33%), with an efficiency ranging from 45 to 50% (average: 48%), indicating that the depletion development experiment is closer to the actual development process of gas reservoirs. Our findings provide novel insights into water-invasion gas efficiency, providing robust estimates of the recovery of water-invasion gas reservoirs. [ABSTRACT FROM AUTHOR]

The Dongsheng gas field is a water-bearing tight gas reservoir characterized by high connate water saturation. During gas production, the transformation of connate water into movable water introduces a unique water production mode, significantly impacting gas reservoir recovery. Current experimental and theoretical methods for assessing formation water mobility are static and do not address the transformation mechanism from connate into movable water. In this study, we considered dynamic changes in formation stress and proposed the mechanism for the transformation of connate water into movable water during depressurization, involving the expansion of connate water films and the reduction of pore volume. We developed a novel methodology to calculate the dynamic changes in movable and connate water saturation in tight reservoirs due to reservoir pressure reduction. Furthermore, we quantitatively evaluated the transformation of connate water into movable water in the Dongsheng gas field through laboratory experiments (including formation water expansion tests, connate water tests, and porosity stress sensitivity tests) and theoretical calculations. Results show that under original stress, the initial connate water saturation in the Dongsheng gas field ranges from 50.09% to 58.5%. As reservoir pressure decreases, the maximum increase in movable water saturation ranges from 6.1% to 8.4% due to the transformation of connate water into movable water. This explains why formation water is produced in large quantities during gas production. Therefore, considering the transition of connate water to movable water is crucial when evaluating water production risk. These findings offer valuable guidance for selecting optimal well locations and development layers to reduce reservoir water production risks. [ABSTRACT FROM AUTHOR]

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Water alternating gas (WAG) is a cyclical process that involves alternating water and gas injections with the primary goal to improve sweep efficiency by maintaining initial high pressure, slowing water and gas breakthrough, and lowering oil viscosity. The objective of this work is to apply and optimize a WAG strategy on a carbonate field with light oil, compare it to the initially planned water-flooding strategy, and investigate the capability of WAG to improve field production. In this research, a compositional reservoir simulator was used to model a WAG process by injecting produced gas into the reservoir, using the same well structure as an optimized water-flooding strategy. Subsequently, a WAG strategy was created, optimizing the number and locations of wells, to facilitate a comparative analysis of the two recovery methods. The WAG optimization involved a detailed assessment of variables such as bottom hole pressure (BHP), WAG cycle duration, maximum gas oil ratio (GOR), and well positioning, to achieve a high net present value (NPV). The study focuses on the application of WAG optimization modeling in unconventional reservoirs, specifically pre-salt carbonate reservoirs, and investigates its implications on production strategy and forecast, emphasizing its potential for maximizing NPV and oil recovery in a recently producing field. The results showed that WAG improved reservoir performance when compared to water injection and produced a greater amount of oil. This solution showed potential to be tested under uncertainties (reservoir heterogeneity, faults, fractures, karsts, vugs, etc.) as future steps. [ABSTRACT FROM AUTHOR]

Natural gas, as one of the main energy sources of the modern clean energy system, is also an important raw material for the chemical industry, and the stable extraction of natural gas reservoirs is often affected by bottom water. It is difficult to control water in natural gas reservoirs, while fractured gas reservoirs are even more demanding. This is due to the complexity of the seepage laws of gas and water in fractures, resulting in the poor applicability of conventional processes for water control. Continuous research is needed to propose a process with effective control capabilities for bottom-water fractured gas reservoirs. Aiming at the above difficulties, this paper is based on a large-scale three-dimensional physical simulation device to carry out physical model design and simulation results testing and analysis. The water control ability of the combination of density-segmented sieve tubes and continuous packers in fractured gas reservoirs is explored. The physical simulation results show that the fracture distribution characteristics control the upward transportation path of bottom water. According to the segmentation characteristics of the fractures at the horizontal section location, optimizing the number of horizontal well screen tube segments and the density of boreholes reduces the cone-in velocity of bottom water before connecting the fractures to a certain extent. And the combined process has different degrees of water control ability for the three stages of bottom water transportation from the fractured gas reservoir to the production well. As the degree of water in the production well increases, the water control ability of the process gradually decreases. After the implementation of the water control process, the water-free gas production period was extended by about 6.84%, and the total production time was extended by about 6.46%. After the shutdown of the horizontal wells, the reduction in daily water production can still reach 21% compared to the natural extraction. The results of this research can provide process suggestions for water control in offshore fractured reservoirs and further ensure stable production in offshore fractured gas reservoirs. [ABSTRACT FROM AUTHOR]

Unconventional gas is a momentous energy source due to its considerable reserves and eco-friendly properties, where relative permeability is a key evaluative parameter of unconventional gas extraction. However, the geo-complexity, multiscale and multieffect of the unconventional gas reservoir challenge the relative permeability evaluation and production enhancement. Here, we establish a gas–water flow model by integrating multifractal theory, covering from nanoscale to macroscale and regarding the effects of slip, gas desorption–diffusion and water film separation, to reliably evaluate the relative permeability evolution during unconventional gas development. Based on our model, we describe the permeability of the unconventional reservoir with an 88% less evaluation error compared to the single fractal Darcy with the literature benchmark. Moreover, we characterize the gas–water relative permeability with a no more than 10% evaluation error based on the experimental data. The slip effect plays the most crucial role in the evaluation precision of relative permeability. We reveal that the permeability of the unconventional gas reservoir is decreased by the increase of generalized fractal dimension which enhances the heterogeneity and tortuosity of pores. We uncover that the slip effect facilitates the relative permeability of gas and water. Besides, the gas desorption–diffusion boosts gas relative permeability while limiting water relative permeability, whereas water film separation enhances water relative permeability but hinders gas relative permeability. This work brings insights into the precise description of multiscale and multieffect gas–water porous flow in unconventional gas development. [ABSTRACT FROM AUTHOR]

Water-based enhanced oil recovery methods have been developed to improve the oil production rate from ultra-tight reservoirs. By coupling the effect of surfactant as wettability alteration and water alternating gas injection method, we aimed to determine the most efficient enhanced oil recovery technique. We performed seven injectivity scenarios to measure the oil recovery factor by introducing the alkylbenzene sulfonic acid (LABSA) as a surfactant agent during the active carbonated water alternating gas (ACWAG) injection. To consider the effect of slug size during water alternating gas injection, we used two different slug sizes (0.3, and 0.6). After the water breakthrough, a little oil volume was produced, and the maximum oil recovery factor at 1.5 Pore Volume (PV) was 26%. This issue corresponded to the water channeling after the breakthrough point. For smaller slug sizes (0.3), the maximum oil recovery factor (78%) was reached in smaller pore volumes. One of the exciting results wass the considerable influence of slug ratio during the water alternating gas (WAG) injection, in which it provided more oil recovery factor (83%) when the gas volume is higher than the water volume. Finally, by introducing the coupling effect of active carbonated water (made by LABSA surfactant) and WAG injection, the maximum oil recovery factor was 85%, corresponding to the better efficiency of active carbonated water in interfacial tension reduction. The results of this comprehensive investigation can be extended in ultra-tight sandstone reservoirs and can be applied as a further guideline in numerical simulations. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The driving forces behind gas flow and migration, as well as the associated gas–water distribution patterns in tight gas reservoirs, are not only closely related to the formation mechanisms of "sweet spots", but also serve as crucial geological foundations for the development of efficient modes and optimal well placement. In this work, three methods, namely, critical gas column height driven by buoyancy, critical pore throat radius driven by buoyancy, and gas–water distribution attitude, were used to quantitatively evaluate the critical conditions for buoyancy and overpressure to get gas flowing in the tight sandstone gas field. In light of the geological background, the driving forces of gas flow/migration and gas–water distribution patterns were comprehensively analyzed. On this basis of the origins of overpressure driving gas flow/migration were identified by using multiple empirical methods, the evolution of overpressure and characteristics of gas–water distribution driven by overpressure were studied by using PetroMod_2014 simulation software. The results show that the four main gas-bearing layers in the NX tight sandstone gas reservoir differ widely in gas flow/migration dynamics and gas–water distribution patterns. Gas accumulation in the H3b layer is influenced by both buoyancy and overpressure. Subsequently, buoyancy leads to the differentiation of gas from water based on density and the formation of edge water. Furthermore, the distribution area of the gas reservoir is determined by the presence of an anticline trap. In contrast, in H3a, H4b and H5a gas layers, buoyancy is not sufficient to overcome the capillary force to make the gas migrate during and after accumulation, and the driving force of gas flow is the overpressure formed by fluid volume expansion during hydrocarbon generation of Pinghu Formation source rocks. Because buoyancy is not the driving force of natural gas flow, H3a, H4b and H5a layers have gas and water in the same layer and produced together, and no boundary and bottom water, where the anticlinal trap does not control the distribution of gas and water, and gas source faults control the boundary of the gas reservoir. These understandings not only significantly expand the gas-bearing target of H3a, H4b and H5a gas layers delineated in the buoyancy driving pattern but also provide an important geological basis for the formulation of an efficient development plan by class and grade for the NX tight sandstone gas field. [ABSTRACT FROM AUTHOR]

Objective During the exploitation process of high-sulfur gas reservoirs, natural gas hydrates are easily formed in the wellbore and pipeline, causing ice blockage and affecting normal production. Methods Under the conditions of constant temperature and volume, the effects of the mineralization ions on the growth rate of high-sulfur gas hydrates are experimentally studied in an Hastelloy reactor. The effects of pressure, mineral ions of gas field water and solution morphology on the growth process morphology, growth characteristics and extension pattern of high-sulfur gas hydrate at the gas-liquid interface were also studied by direct top-view observation. Results It is shown that the salts can decrease the growth rate of hydrates and change the morphology of the hydrate crystal. At the gas-liquid interface, the hydrate grows from the nucleation point in a two-dimensional expansion pattern. When elevating the pressure, it has little effects on the morphology of hydrate crystal, but it can increase the growth rate of hydrate. Conclusions The analysis shows that ionization effects of the salts decrease the activities of water and affect the growth process of hydrate. The experimental results of this work have great significance for hydrate prevention and the normal exploitation of high-sulfur gas reservoir. [ABSTRACT FROM AUTHOR]

Applications of the traditional static material-balance method in gas reservoirs become a challenge with production maturity due to variability in aquifer influx, infill drilling, and production-operational changes in offset wells, among others. Besides, some existing modeling approaches involve a trial-and-error method, making the solution outcomes nontrivial. This study proposes a new methodology for analyzing production data involving water-drive gas reservoirs. The main findings of this study include the following: (1) A straight-line plot that yields gas and water in-place volumes, (2) A modified-(pav/z)* plot exhibits a straight-line with an x-intercept of gas initially-in-place, similar to that in a conventional-(pav/z) plot, (3) A new definition of degree of aquifer support that is quantifiable using production data. Synthetic data verified the proposed modeling approach, whereas a field dataset provided validation. [ABSTRACT FROM AUTHOR]

The western Sulige gas field is a new and key reserve area for the rolling development of the Sulige gas field in China. However, due to the complex gas–water relationship and the difficulty in identifying gas and water formation, the scale and benefit deployment of the gas field are seriously restricted. In particular, almost all of the wells in the area produce water, and no water measurements have been carried out for any single well, which leads to an unclear understanding of the dynamic characteristics of the production wells, thus affecting the productivity calculations of the gas wells and the overall regional productivity evaluation. Based on the testing data for a gas well, the impacts of the reservoir property parameters on the gas and water production were analyzed by combining the production performance and static geological characteristics. It was determined that the physical parameters K, Kh, and φSg had good positive correlations with gas production but not with water production; thus, effective prediction cannot be obtained for water production in gas well testing. After the analysis of the liquid-loading law, the gas wells were classified into three types: continuous liquid-carrying production, slight liquid-loading, and liquid-loading wells. In general, up to 96% of the gas wells were liquid-loaded. According to the different production performances exhibited in the different stages of the gas wells, five types of methods for diagnosing water production wells were proposed (gas testing, pilot production, gas–liquid two-phase measurement testing, liquid level detection, and production performance analysis), as well as the diagnostic criteria and corresponding solutions. To obtain real-time water production data for each well and investigate the change in the water–gas ratio (WGR) during the whole production process, a water production splitting method for gas wells based on three-dimensional geological modeling and numerical simulation combined with the constraints of the total water production of gas gathering stations was explored and established. The splitting results can be used to evaluate the water and gas productivity of gas wells and determine the best deliquification period. The gas well productivity when water production was considered was about 10% lower than that when water production was not considered. The best deliquification period was determined to be 125 days for wells with small water production, 20 days for wells with moderate water production, and 3 days for wells with serious water production. The results of this study could provide technical support for the scientific evaluation of gas well production indicators, reduction in development costs, and improvement in oil recovery. [ABSTRACT FROM AUTHOR]

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Copyright of China Sciencepaper is the property of China Sciencepaper and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

In the two test productions that have been conducted in the hydrate reservoir test development zone in the South China Sea, the gas production capacity of single wells is low and the exploitation difficulty with the cost is too high for commercial demand economically. The low permeability of the hydrate-bearing layer (HBL) acts as the major barrier for pressure propagation during depressurization. Hydraulic fracturing by the combined depressurization is considered a promising hydrate production enhancement technology that can effectively improve the seepage state in the reservoir. In this study, to evaluate the effectiveness of the development methods association with fracturing, we established an idealized Class II hydrate reservoir and studied it using a multi-stage fractured horizontal well to assist in depressurization extraction. In order to evaluate the production enhancement effect of this method, we compared the gas production results of four methods, including single vertical well, vertical fractured well, horizontal well, and multistage fractured horizontal well through numerical simulation. In order to investigate the influence of key fracture parameters on the production enhancement effect, a sensitivity analysis of the production effect of Class II hydrate reservoirs with different fracture spacing, number of fractures, fracture conductivity, and fracture length was conducted, and the results were analyzed in terms of gas production and water production behavior curves as well as physical field evolution over time. The simulation results show that the multi-stage fractured horizontal wells have the best production increase in the comparison of well types. In the analysis of fracture parameters, it can be found that the selection of proper fracture spacing and dimensionless fracture conductivity can lead to a significant increase in gas production. [ABSTRACT FROM AUTHOR]

Well TMG-02 with the depth interval of 5058.77 to 9389.43ft of Opolo field located in the Niger delta was assessed for hydrocarbon using suite of geophysical well logs. Suite includes gamma ray (GR), formation density (RHOB), neutron porosity (NPHI), and resistivity logs. The analysis was carried out to estimate the field‟s hydrocarbon prospect by identifying hydrocarbon bearing reservoirs and their properties. The quantitative and qualitative results, identified thicker units of sand than shale lithology, three reservoirs A, B, C within the depth ranges from 5058.77ft to 9389.43ft, capable of accumulating hydrocarbon based on the petrophysical parameters calculated were delineated. The effective porosity for each of the reservoir are: 27%, 24% and 19% respectively. It was observed that reservoir A, B had excellent permeability while reservoir C was low as a result of thicker shale sequence within the reservoir. The result obtained shows presence of hydrocarbon bearing gas water contact in Reservoir A at depth of 5119.70ft, gas oil contact and oil water contact at depths 7310.00ft and 7438.69ft in Reservoir B and Gas water contact at depth 9032.00ft at Reservoir C. [ABSTRACT FROM AUTHOR]

This study provides insights into the experience gained from investigating the thermodynamic behavior of well and reservoir fluids during acid gas injection (AGI) in a hydrocarbon field to enhance oil recovery (EOR) and to reduce greenhouse gas emissions. Unlike conventional water and natural gas injection, AGI involves complicated phase changes and physical property variations of the acid gas and reservoir fluids at various pressure-temperature (P-T) conditions and compositions, and both constitute crucial parts of the EOR chain. A workflow is developed to deal with the reservoir fluid and acid gas thermodynamics, which is a key requirement for a successful design and operation. The workflow focuses firstly on the development of the thermodynamic models (EoS) to simulate the behavior of the reservoir fluids and of the injected acid gas and their integration in the field and in well dynamic models. Subsequently, the workflow proposes the thermodynamic simulation of the fluids' interaction to determine the Minimum Miscibility Pressure (MMP), yielding the dynamic evolution of the fluids' miscibility that may appear within the reservoir. Flow assurance in the acid gas transportation lines and in the wellbore is also considered by estimating the hydrate formation conditions. [ABSTRACT FROM AUTHOR]

Fluid backflow behavior and reservoir damage during methane commingled drainage from multiple coal seams were investigated via physical experiments and reservoir modeling. First, the initial water saturation of coal reservoir was determined by an experimental method, and then based on low-field nuclear magnetic resonance technology, coal imbibition and centrifugation tests were conducted to obtain gas permeability under different water saturation. Finally, a reservoir model was used to calculate the shut-in pressure and interlayer interference performance of the commingled drainage well. The following conclusions were derived from a case study of GP-2 well in the western Guizhou Basin. At the initial stage of commingled drainage, the wellbore serves as a medium for coordinating the energy of each production layer, allowing the fluids from the high-pressure production layer to flow back into low-pressure layers, thus creating a new stable system. Using inflow performance relationship curves, the initial shut-in pressure of GP-2 was determined to be 6753 kPa. Simulations demonstrate that pressure anomalies are a prerequisite for the presence of reverse fluids, the water imbibition and gas lock phenomenon would result in the loss of the irrecoverable permeability to reservoirs. The ideal average gas production rate of the commingled well is 3846 m3 d−1 for 3000 days of drainage, when ignoring reservoir damage only 6% interlayer interference was detected in the commingled drainage well, which may be disregarded in operation. In comparison, the ultimate interference coefficient of the commingled drainage well might be as low as -50% when water imbibition is factored in, and as much as 90% of CBM resource could not be produced with both water imbibition and gas lock in the reservoir. This research bridges the gap between reservoir dynamics and interference analysis and provides a basis for the favorable layer selection and drainage system establishment in commingled drainage wells. [ABSTRACT FROM AUTHOR]

Changqing tight gas field has been on fashion among China in recent years. Figuring out gas and water seepage behaviors matters a lot for maximizing gas reservoir recovery. One tool for that is to conduct two-phase seepage experiment and reveal seepage features. Experiments show that gas or water's flowing capacity has a directly positive relationship with its saturation. The larger saturation, the higher permeability. Thus, one method of determining whether a gas well produces water or not is to compare the initial water saturation with its starting-flowing saturation. If the initial gas or water saturation is larger than its critical saturation, it starts to flow. Meanwhile, this critical saturation ranges hugely. For reservoirs with high porosity, permeability, and pore structure like type I, the starting-flowing saturation is 15.6% for gas and 36.6% for water, meaning that it is easily for gas or water to reach the critical saturation and make the seepage happen. The critical saturation in reservoir of type III which has low porosity, permeability, and pore structure is as high as 28.8% for gas and 58.1% for water, indicating that high fluid saturation is needed to have it flow. Finally, four horizontal wells in Sudongnan block are analyzed to verify the method. The prediction that two of them will produce water in the beginning and the other two will not is highly in line with their production data. This method has been proved effective in the prediction of gas wells. [ABSTRACT FROM AUTHOR]

During the rebuilding of a gas reservoir, repeated "strong injection and mining" processes change the seepage capacities of gas and water. Hence, accurately determining the seepage laws of gas and water in a gas storage reservoir is crucial. In this study, a standard relative permeability test was conducted with a one-dimensional core. Additionally, a gas reservoir injection and mining simulation experiment was conducted with a two-dimensional plate. The results show that the relative permeability curve obtained by the one-dimensional core test did not accurately reflect the operation characteristics of the gas storage and the change in the seepage law during the gas reservoir construction. Furthermore, in the two-dimensional plate experiment, the operation mode was restored using the plane radial flow formula, the mutual relationship between the gas and water's effective permeability under different injection stages was established, and the multi-cycle injection operation was accurately described. This method lays the foundation for the construction of gas reservoirs and the establishment of the multi-phase seepage law for gas reservoirs. [ABSTRACT FROM AUTHOR]

For gas reservoirs that contain water, investigating characteristics of water–gas seepage is crucial to the formulation of gas field development plans and predicting the production capacity and water breakthrough of gas wells. For the purposes of such an investigation, the process of water invasion into a water-containing gas reservoir was studied based on four sandstone samples whose physical properties differed quite vastly (permeability: 0.112–192.251 mD; porosity: 8.33–20.60%). Gas–water relative permeability experiments were conducted on the gas-driven water in the reservoir conditions (temperature: 135 °C; pressure: 75 MPa). Starting with the sandstone samples' microstructural characteristics, particular attention was paid to the impacts of throat radius and clay content on the water–gas seepage characteristics. It was found that the basic physical properties, microscopic characteristics, and mineral composition of the sandstone samples all affected the water–gas seepage characteristics. The larger the pore-throat radius, the stronger the ability of sandstone samples to allow fluid through under the same water saturation and the greater the relative permeability of gas and water phases. Furthermore, the wider the throat radius and the lower the clay content, the greater the gas–water relative permeability. Isotonic water saturation and irreducible water saturation were found to be negatively to throat radius and positively with clay content. Furthermore, When sandstone samples have similar clay content, the average throat radius is four times larger, its irreducible water saturation is decreased by 1.63%, its residual gas saturation is decreased by 1.00%, and the gas permeability under irreducible water saturation increases by more than 400 times. Water intrusion showed a more significant impact on the gas–water flow characteristics of the low-permeability sandstone samples, and it severely restricted the flow capacity of the gas phase. [ABSTRACT FROM AUTHOR]

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Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

In this study, a water- and heavy hydrocarbon-removal process of a natural gas refinery currently in operation using the temperature swing adsorption method is modeled and investigated. The aim of this process is to decrease the hydrocarbon dew point to −10 °C and diminish the water content of the gas to about 0.1 ppm. This unit consists of four beds with two layers in which two beds are in the adsorption state, while the others are kept in the regeneration state. The gas composition and the bed specification are obtained from the available data from the refinery. The Ergun equation is considered for the pressure drop calculation. The results show that the developed model can predict the outputs with good accuracy. Sensitivity analysis of operating condition parameters such as temperature, pressure, and regeneration gas flowrate are carried out. Analysis of the regeneration temperature proved that temperature reduction from 268 °C to 210 °C can improve recovery of the heavy components. In addition, the regeneration gas flow rate can be reduced to about 0.4 kmole·s−1 as an optimum value. Moreover, 303 to 310 °C is the optimum range for the feed temperature. Due to the presence of the air cooler in the upstream process, and according to the ambient air temperature, feed temperature can be decreased to obtain better results. [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas Geoscience is the property of Natural Gas Geoscience and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Understanding the immiscible displacement mechanism in porous media is vital to enhancing the hydrocarbon resources in the oil and gas reservoir. Improving resource recovery requires quantitatively characterizing the effect of wettability heterogeneity on the immiscible displacement behaviors at the pore scale, which can be used to predict the displacement distribution of multiphase fluids and evaluate the optimal wettability strategy in porous media. The heterogeneity of fluid wettability in a natural rock makes it extremely hard to directly observe the fluid displacement behaviors in the reservoir rocks and quantify the sensitivity of preferential displacement path and displacement efficiency to wettability distribution. In this study, the phase-field model coupling wettability heterogeneity was established. The gas-water two-phase displacement process was simulated under various wettability distributions and injecting flux rates in a complex pore structure. The effect of wettability heterogeneity on immiscible displacement behavior was analyzed. The results indicated that wettability heterogeneity significantly affects the fluid displacement path and invasion patterns, while the injecting flux rate negatively influences the capillary–viscous crossover flow regime. The continuous wetting patches enhanced the preferential flow and hindered displacement, whereas the dalmatian wetting patches promoted a higher displacement efficiency. The results of the fractal dimensions and specific surface area also quantitatively show the effects of wettability distribution and heterogeneity on the complexity of the two-phase fluid distribution. The research provides the theoretical foundation and analysis approach for designing an optimal wettability strategy for injecting fluid into unconventional oil and gas reservoirs. [ABSTRACT FROM AUTHOR]

In the development of natural gas reservoirs, the water produced in wells will cause a decline in gas well productivity. In this study, a selective frozen gel plugging agent system suitable for water plugging in gas reservoirs under conditions of high temperature and high salinity. The plugging capacity of the gel system was evaluated. The experimental results showed that: (1) the optimal experimental scheme of the frozen gelling system was as follows: 107 °C with 1.0% AM-AMPS +0.6% p-benzenediol +0.6% hexamethylenetetramine +0.2% thiourea. (2) The optimal injection volume of the system for water phase plugging was 0.5 PV, and the system has an excellent plugging effect at a permeability of 356–3118 mD. (3) The system could also effectively improve the degree of heterogeneity, and the smaller the degree of heterogeneity, the better the improvement effect. (4) The gel system had a good effect on different plugging methods, and the gas medium did not affect the plugging performance. This study provides a sufficient theoretical basis for the exploitation of high-temperature and high-salinity water-bearing gas reservoirs through experimental research, which is of great significance for improving production capacity. [ABSTRACT FROM AUTHOR]

The currently reported bottom water sealing materials and fracturing technologies can hardly simultaneously achieve the high production and low water cut of gas reservoirs due to the complexity of various formation conditions. Therefore, without controlling the fracturing scale and injection volume, a kind of polylactide polymer water plugging material with a density of 1.15–2.0 g/cm3 is developed, which can be used to seal the bottom water of a gas–water differential layer by contact solidification with water and automatic degradation with natural gas. This technology can not only fully release the production capacity of the gas reservoir but also effectively control water production and realize the efficient fracturing development of the target gas reservoir. Laboratory test results show that the smart plugging agent has a bottom water plugging rate of 100%, and the low-density plugging agent has a dissolution rate of 96.7% in methane gas at 90 °C for 4 h and a dissolution rate of 97.6% in methane gas at 60 °C for 6 h, showing remarkable gas degradation performance. In addition, settlement experiments show that the presence of a proppant can increase the settlement rate of a plugging agent up to many times (up to 21 times) in both water and guanidine gum solution. According to the actual conditions of well J66-8-3, a single-well water plugging fracturing scheme was prepared by optimizing the length of fracture, plugging agent dosage, and plugging agent sinking time, and a post-evaluation method was proposed. It has guiding significance to the development of similar gas reservoirs. [ABSTRACT FROM AUTHOR]

The environmental problem posed by shale gas wastewater has received considerable research attention. Researchers mostly focus on the technical aspect of terminal centralized treatment with little concern on the topic of early collection and on-site pretreatment of PW near gas gathering stations. In this study, the short-term fluctuations of the DOM molecular composition and the concurrent transformation of the microbial community and functions were carefully examined when the PW was temporarily stored in a simulated reservoir near gas wells. Ultra-high resolution mass spectrometry was used to determine the molecular structure of the DOM samples. The data showed that during the short-term storage of PW, strongly polarized and nonvolatile organic compounds developed a complex molecular structure, resulting in molecules that were more unsaturated and lower bioavailability. Microbial activity was responsible for the changes in organic matter composition that occurred in the later stages of the storage process, during which the amount of nitrogenous organic molecules increased. Network analysis offered vital information on microbial functions related to organic matter composition and the patterns of interaction between them. Organic molecule consumption and accumulation were intimately connected to the interactions between various bacteria the same as the consumption and accumulation of DOM molecules. [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)