Phase behavior of gas condensate in porous media using real-time computed tomography scanning

The phase behavior of gas condensate in reservoir formations differs from that in pressure-volume-temperature(PVT)cells because it is influenced by porous media in the reservoir formations.Sandstone was used as a sample to investigate the influence of porous media on the phase behavior of the gas condensate.The pore structure was first analyzed using computed tomography(CT)scanning,digital core technology,and a pore network model.The sandstone core sample was then saturated with gas condensate for the pressure depletion experiment.After each pressure-depletion state was stable,realtime CT scanning was performed on the sample.The scanning results of the sample were reconstructed into three-dimensional grayscale images,and the gas condensate and condensate liquid were segmented based on gray value discrepancy to dynamically characterize the phase behavior of the gas condensate in porous media.Pore network models of the condensate liquid ganglia under different pressures were built to calculate the characteristic parameters,including the average radius,coordination number,and tortuosity,and to analyze the changing mechanism caused by the phase behavior change of the gas condensate.Four types of condensate liquid(clustered,branched,membranous,and droplet ganglia)were then classified by shape factor and Euler number to investigate their morphological changes dynamically and elaborately.The results show that the dew point pressure of the gas condensate in porous media is 12.7 MPa,which is 0.7 MPa higher than 12.0 MPa in PVT cells.The average radius,volume,and coordination number of the condensate liquid ganglia increased when the system pressure was between the dew point pressure(12.7 MPa)and the pressure for the maximum liquid dropout,Pmax(10.0 MPa),and decreased when it was below Pmax.The volume proportion of clustered ganglia was the highest,followed by branched,membranous,and droplet ganglia.This study provides crucial experimental evidence for the phase behavior changing process of gas condensate in porous media during the depletion production of gas condensate reservoirs.

Experimental Investigation on Condensate Revaporization During Gas Injection Development in Fractured Gas Condensate Reservoirs

The gas field in the Bohai Bay Basin is a fractured metamorphic buried-hill reservoir with dual-media characteristics. The retrograde vaporization mechanism observed in this type of gas condensate reservoir differs significantly from that observed in sand gas condensate reservoirs. However, studies on improving the recovery of fractured gas condensate reservoirs are limited;thus, the impact of retrograde vaporization on condensate within fractured metamorphic buried-hill reservoirs remains unclear. To address this gap, a series of gas injection experiments are conducted in pressure-volume-temperature(PVT) cells and long-cores to investigate the retrograde vaporization effect of condensate using different gas injection media in fractured gas condensate reservoirs. We analyze the variation in condensate volume, gas-to-oil ratio, and condensate recovery during gas injection and examine the influence of various gas injection media(CO_(2), N_(2), and dry gas) under different reservoir properties and varying gas injection times. The results demonstrate that the exchange of components between injected gas and condensate significantly influences condensate retrograde vaporization in the formation. Compared with dry gas injection and N_(2) injection,CO_(2) injection exhibits a superior retrograde vaporization effect. At a CO_(2) injection volume of 1 PV, the percentage shrinkage volume of condensate is 13.82%. Additionally, at the maximum retrograde condensation pressure, CO_(2) injection can increase the recovery of condensate by 22.4%. However, the condensate recovery is notably lower in fractured gas condensate reservoirs than in homogeneous reservoirs, owing to the creation of dominant gas channeling by fractures, which leads to decreased condensate recovery. Regarding gas injection timing, the effect of gas injection at reservoir pressure on improving condensate recovery is superior to that of gas injection at the maximum retrograde condensation pressure. This research provides valuable guidance for designing gas injection development plans and dynamic tracking adjustments for fractured gas condensate reservoirs.

A new model simulating the development of gas condensate reservoirs

A new simulation model for the development of gas condensate reservoirs is introduced based on the influence that phase change,non-Darcy flow,and capillary pressure have on the production of gas condensates.The model predicts well performance,including bottom-hole pressure,oil/gas production rate,oil/gas recovery,gaseoil ratio,and the change in produced fluid composition.It also calculates dynamic characters,such as the change of pressure field and oil/gas saturation field during the development of gas condensate reservoirs.The model is applicable to different boundary conditions(both constant-pressure and sealed boundary)and different production modes(both constant-pressure and constant-volume production modes).Model validation attempted using numerical simulation results for sealed boundary conditions with constant-pressure production mode has shown a relatively good match,proving its validity.For constant-pressure boundary conditions with constant-volume production mode,four stages are defined according to the dynamic behavior of production performance in the development of gas condensate reservoirs.

A transient production prediction method for tight condensate gas wells with multiphase flow

Considering the phase behaviors in condensate gas reservoirs and the oil-gas two-phase linear flow and boundary-dominated flow in the reservoir,a method for predicting the relationship between oil saturation and pressure in the full-path of tight condensate gas well is proposed,and a model for predicting the transient production from tight condensate gas wells with multiphase flow is established.The research indicates that the relationship curve between condensate oil saturation and pressure is crucial for calculating the pseudo-pressure.In the early stage of production or in areas far from the wellbore with high reservoir pressure,the condensate oil saturation can be calculated using early-stage production dynamic data through material balance models.In the late stage of production or in areas close to the wellbore with low reservoir pressure,the condensate oil saturation can be calculated using the data of constant composition expansion test.In the middle stages of production or when reservoir pressure is at an intermediate level,the data obtained from the previous two stages can be interpolated to form a complete full-path relationship curve between oil saturation and pressure.Through simulation and field application,the new method is verified to be reliable and practical.It can be applied for prediction of middle-stage and late-stage production of tight condensate gas wells and assessment of single-well recoverable reserves.

Phase Transitions and Seepage Characteristics during the Depletion Development of Deep Condensate Gas Reservoirs

Deep condensate gas reservoirs exhibit highly complex and variable phase behaviors,making it crucial to understand the relationship between fluid phase states and flow patterns.This study conducts a comprehensive analysis of the actual production process of the deep condensate gas well A1 in a certain oilfield in China.Combining phase behavior analysis and CMG software simulations,the study systematically investigates phase transitions,viscosity,and density changes in the gas and liquid phases under different pressure conditions,with a reservoir temperature of 165°C.The research covers three crucial depletion stages of the reservoir:single-phase flow,two-phase transition,and two-phase flow.The findings indicate that retrograde condensation occurs when the pressure falls below the dew point pressure,reachingmaximum condensate liquid production at around 25MPa.As pressure decreases,gas phase density and viscosity gradually decrease,while liquid phase density and viscosity show an increasing trend.In the initial single-phase flow stage,maintaining a consistent gas-oil ratio is observed when both bottom-hole and reservoir pressures are higher than the dew point pressure.However,a sudden drop in bottom-hole pressure below the dew point triggers the production of condensate oil,significantly reducing subsequent gas and oil production.In the transitional two-phase flow stage,as the bottom-hole pressure further decreases,the reservoir exhibits a complex flow regime with coexisting areas of gas and liquid.In the subsequent two-phase flow stage,when both bottom-hole and reservoir pressures are below the dew point pressure,a significant increase in the gas-oil ratio is observed.The reservoir manifests a two-phase flow regime,devoid of single-phase gas flow areas.For lowpressure conditions in deep condensate gas reservoirs,considerations include gas injection,gas lift,and cyclic gas injection and production in surrounding wells.Additionally,techniques such as hot nitrogen or CO_(2) injection can be employed to mitigate retrograde condensation damage.The implications of this study are crucial for developing targeted development strategies and enhancing the overall development of deep condensate gas reservoirs.

Effect of chloralkanes on the phenyltrichlorosilane synthesis by gas phase condensation

To enhance the process of phenyltrichlorosilane synthesis using gas phase condensation, a series of chloralkanes were introduced. The influence of temperature and chloralkane amount on the synthesis was studied based on the product distribution from a tubular reactor. The promoting effect of chloralkane addition was mainly caused by the chloralkane radicals generated by the dissociation of C–Cl bond. The promoting effect of the chloromethane with more chlorine atoms was better than those with less chlorine atoms. Intermediates detected from the reactions with isoprene and bromobenzene demonstrated that both trichlorosilyl radical and dichlorosilylene existed in the reaction system in the presence of chloralkanes. A detailed reaction scheme was proposed.

Detailed kinetics of methylphenyldichlorosilane synthesis from methyldichlorosilane and chlorobenzene by gas phase condensation

Methylphenyldichlorosilane(MPDS, CH3C6H5 SiC l2) is an important silicone monomer for the synthesis of highperformance polymethylphenylsiloxane polymers. In this work, the mechanism of the synthesis of MPDS from methyldichlorosilane and chlorobenzene by gas phase condensation was studied, and a kinetic model with 35 species and 58 elementary reactions was established. Experiments were carried out in a tubular reactor under a wide range of reaction conditions. The calculated mole fractions of the reactants and products were in a good agreement with the experimental results. A mechanism of the insertion of chloromethylsilylene into the C\Cl bond of chlorobenzene was proposed, which was proved to be the main pathway of MPDS production. The established kinetic model can be used in design and optimization of the industrial reactor for MPDS synthesis.

Numerical Simulation of Oil and Gas Two-Phase Flow in Deep Condensate Gas Reservoirs in Bohai Buried Hills

The BZ19-6 gas field is characterized by high temperature and high pressure (HTHP), high condensate content, little difference between the formation pressure and dew point pressure, and large amount of reverse condensate liquid. During the early stage of depletion development, the production gas-oil ratio (GOR) and production capacity remain relatively stable, which is inconsistent with the conventional reverse condensate seepage law. In view of the static and dynamic conflict in development and production, indoor high-temperature and high-pressure PVT experiment was carried out to reveal the mist-like condensation phenomenon of fluids in the BZ19-6 formation. And the seepage characteristics of condensate gas reservoirs with various degrees of depletion under the condition of HTHP were analyzed based on production performance. The change rule of fluid phase state was analyzed in response to the characterization difficulties of the seepage mechanism. The fluid state was described using the miscible mechanism. And the interphase permeability interpolation coefficient was introduced based on interfacial tension. By doing so, the accurate characterization of the “single-phase flow of condensate gas-near-miscible mist-like quasi single-phase flow-oil-gas two-phase flow” during the development process was achieved. Then the accurate fitting of key indicators for oilfield development was completed, and the distribution law of formation pressure and the law of condensate oil precipitation under different reservoir conditions are obtained. Based on research results, the regulation strategy of variable flow rate production was developed. Currently, the work system has been optimized for 11 wells, achieving a “zero increase” in the GOS of the gas field and an annual oil increase of 22,000 cubic meters.

Origin of gas condensate reservoir in Fuman Oilfield, Tarim Basin, NW China

To understand the reservoir property and hydrocarbon accumulation conditions of the Middle and Upper Ordovician intraplatform shoal between ultra-deep main strike-slip faults in Fuman Oilfield of the Tarim Basin, China, the main strike-slip faults in and around well FD1 in the basin were analyzed in terms of sedimentary facies, sequence stratigraphy, intraplatform shoal reservoir property, and oil and gas origins, based on drilling data. The Yingshan Formation intraplatform shoal between the main strike-slip faults is superimposed with low-order faults to form a new type of hydrocarbon play. Firstly, hydrocarbons generated from the Lower Cambrian Yuertusi Formation source rocks vertically migrated into the second member of Yingshan Formation through the main strike-slip faults, and then migrated laterally until they were accumulated. A small amount of oil from Well FD1 came from the Yuertusi Formation source rocks in the mature stage, and a large amount of gas originated from oil cracking in the ultra-deep reservoirs. Therefore, the secondary gas condensate reservoir in Well FD1 is characterized by high gas to oil ratio, dry gas (dryness coefficient being 0.970) and hybrid origin. This new type of hydrocarbon play characterized by intraplatform shoal and low-order fault suggests a prospect of continuous hydrocarbon-bearing area in Fuman Oilfield, which will expand the ultrap-deep oil and gas exploration in the oilfield.

Test of the Relative Permeability Curve of a Gas and Oil Condensate System and its Effect on the Recovery of Oil and Gas

The relative permeability curve has been measured with simulation oil (refined oil) and gas (nitrogen or air) at room temperature and a lowpressure, both of which are very important parameters for depicting the flow of fluid through porous media in a hydrocarbon reservoir. This basic measurement is often applied in exploitation evaluation, but the underground conditions with high temperature and pressure, and the phase equilibrium of oil and gas, are not taken into consideration when the relative permeability curve is tested. There is an important theoretical and practical sense in testing the diphase relative permeability curve of the equilibrium of oil and gas under the conditions of high temperature and pressure. The test method for the relative permeability curve is proposed in this paper. The relative permeability of the equilibrium of oil and gas and the standard one are tested in two fluids, and the differences between these two methods are stated. The research results can be applied to the simulation and prediction of CVD in long cores and then the phenomenon can better explain that the recovery of condensate gas rich in condensate oil is higher than that of CVD test in PVT. Meanwhile, the research shows that the relative permeability curve of equilibrium oil and gas is sensitive to the rate of exploitation, and the viewpoint proves that an improved gas recovery rate can properly increase the recovery of condensate oil.

Gas Condensate Two Phase Flow Performance in Porous Media Considering Capillary Number and Non-Darcy Effects

Retrograde condensation frequently occurs during the development of gas condensate reservoirs. The loss of productivity is often observed due to the reduced relative permeability to gas as condensate accumulates near the well bore region. How to describe the condensate blockage effect exactly has been a continuous research topic. However, up to now, the present methods usually over-estimate or underestimate the productivity reduction due to an incorrect understanding of the mechanism of flow in porous medium, which inevitably results in an inaccurate prediction of production performance. It has been found in recent numerous theoretical and experimental studies that capillary number and non-Darcy flow have significant influence on relative permeability in regions near the well bore. The two effects impose opposite impacts on production performance, thus leading to gas condensate flow showing characteristics different from general understanding. It is significant for prediction of performance in gas condensate wells to understand the two effects exactly. The aim of the paper is to describe and analyze the flow dynamics in porous media accurately during the production of gas condensate reservoirs. Based on the description of three-zone flow mechanism, capillary number and non-Darcy effect are incorporated in the analysis of relative permeability, making it possible to describe the effect of condensate blockage. The effect of capillary number and inertial flow on gas and condensate relative permeability is analyzed in detail. Novel Inflow Performance Relation (IPR) models considering high velocity effects are formulated and the contrast analysis of different IPR models is conducted. The result shows that the proposed method can help predict the production performance and productivity more accurately than conventional methods.

Enhancing recovery and sensitivity studies in an unconventional tight gas condensate reservoir

The recovery factor from tight gas reservoirs is typically less than 15%, even with multistage hydrauhc tractunng stimulation. Such low recovery is exacerbated in tight gas condensate reservoirs, where the depletion of gas leaves the valuable condensate behind. In this paper, three enhanced gas recovery （EGR） methods including produced gas injection, CO2 injection and water injection are investigated to increase the well productivity for a tight gas condensate reservoir in the Montney Formation, Canada. The production performance of the three EGR methods is compared and their economic feasibility is evaluated. Sensitivity analysis of the key factors such as primary production duration, bottom-hole pressures, and fracture conductivity is conducted and their effects on the well production performance are analyzed. Results show that, compared with the simple depletion method, both the cumulative gas and condensate production increase with fluids injected. Produced gas injection leads to both a higher gas and condensate production compared with those of the CO2 injection, while waterflooding suffers from injection difficulty and the corresponding low sweep efficiency. Meanwhile, the injection cost is lower for the produced gas injection due to the on-site available gas source and minimal transport costs, gaining more economic benefits than the other EGR methods.

Re-Examination of the Oil and Gas Origins in the Kekeya Gas Condensate Field,Northwest China——A Case Study of Hydrocarbon-Source Correlation Using Sophisticated Geochemical Methods

This work discussed the origins, alteration and accumulation processes of the oil and gas in the Kekeya gas condensate field based on molecular compositions, stable carbon isotopes, light hydrocarbons, diamondoid hydrocarbons and biomarker fingerprints. A comparison study is also made between the geochemical characteristics of the Kekeya hydrocarbons and typical marine and terrigenous hydrocarbons of the Tarim Basin. Natural gas from the Kekeya gas condensate field is derived from Middle–Lower Jurassic coal measures while the condensates are derived from Carboniferous–Permian marine source rocks with a higher maturity. In the study area, both natural gas and condensates have experienced severe water washing. A large amount of methane was dissolved into the water, resulting in a decrease in the dryness coefficient. Water washing also makes the carbon isotopic compositions of the natural gas more negative and partially reverse. Considering that the gas maturities are higher than once expected, gas generation intensity in the study area should be much stronger and the gas related to the Jurassic coal measures could promise a greater prospecting potential. As a result of evaporative fractionation, the Kekeya condensates are enriched in saturates and lack aromatics. Evaporative fractionation disguises the original terrigenous characteristics of the light hydrocarbons associated with the natural gas, making it appear marinesourced. Thus, alteration processes should be fully taken into consideration when gas–source correlations are carried out based on light hydrocarbons. With the condensates discovered in the study area all being ＂migration phase＂, the pre-salt Cretaceous and Jurassic reservoirs may promise great exploration potential for the ＂residual phase＂ hydrocarbons. This research not only is of significance for oil and gas exploration in the southwest Tarim Basin, but also sheds light on the oil/gas-source correlations in general.

Daily Variation of Natural Emission of Methane to the Atmosphere and Source Identification in the Luntai Fault Region of the Yakela Condensed Oil/Gas Field in the Tarim Basin,Xinjiang,China

The static flux chamber method was applied to study natural emissions of methane to the atmosphere in the Luntai fault region of Yakela Condensed Oil/Gas Field in the Tarim Basin, Xinjiang Municipality, northwestern China. Using an online method, which couples together a gas chromatography/high-temperature conversion/isotope ratio mass spectrometry （GC/C/MS）, 13^C/12^C ratios of methane in flux chambers were measured and showed that methane gases are liable to migrate from deep oil/gas reservoirs to the surface through fault regions and that a part of the migrated methane, which remains unoxidized can be emitted into the atmosphere. Methane emission rates were found to be highest in the mornings, lowest in the afternoons and then increase gradually in the evenings. Methane emission rates varied dramatically in different locations in the fault region. The highest methane emission rate was 10.96 mg/m^2·d, the lowest 4.38 mg/m^2, and the average 7.55 mg/ m^2·d. The 13^C/12^C ratios of the methane in the flux chambers became heavier as the enclosed methane concentrations increased gradually, which reveals that methane released from the fault region might come from thermogenic methane of the deep condensed oil/gas reservoir.

Geological emission of methane from the Yakela condensed oil/gas field in Talimu Basin, Xinjiang, China

A static flux chamber method was applied to study natural emissions of methane into the atmosphere in the Yakela condensed oil/gas field in Talimu Basin, Xinjiang, China. Using an online method, which couples a gas chromatography/high-temperature conversion/isotope ratio mass spectrometry (GC/C/MS) together, the 13C/12C ratios of methane in the flux chambers were measured. The results demonstrated that methane gases were liable to migrate from deep oil/gas reservoir to the surface through microseepage and p...

Deliverability of wells in carbonate gas condensate reservoirs and the capillary number effect

With the development of the Tazhong No. 1 carbonate gas condensate reservoir in China, it has become more and more important to study the characteristics of gas condensate well deliverability. A single-well radial simulator for dual-permeability reservoirs was established to study the influences of fluid properties, permeability, and pressure drawdown on well deliverability with and without the capillary number effect. The simulation shows that well deliverability basically maintains its initial value and is not affected by the capillary number when the formation pressure is higher than dew-point pressure. However, well deliverability drops rapidly when the formation pressure is lower than dew-point pressure. Even if the condensate dropout is very low, well deliverability without the capillary number effect reduces to 50 percent of its initial value when reservoir pressure declines to 95 percent of dew-point pressure, but well deliverability is significantly improved if the capillary number effect exists. The capillary number effect is most significant when reservoir pressure is just lower than dew point pressure, then the effect decreases; the reduction of well deliverability is mainly caused by the reduction of gas relative permeability of the matrix system near the wellbore.

Change of phase state during multi-cycle injection and production process of condensate gas reservoir based underground gas storage

Based on the differences in production mode and operation process between gas storage and gas reservoir,we established a phase balance test procedure and a theoretical simulation model of phase balance during multi-cycles of injection and production of underground gas storage(UGS)rebuilt from condensate gas reservoir to study the phase characteristics of produced and remaining fluids during multi-cycles of injection and production.Take condensate reservoir gas storage as example,the composition of produced fluid and remaining fluid,phase state of remaining fluid,retrograde condensate saturation and condensate recovery degree in the process of multi-cycles of injection-production were studied through multi-cycle injection-production experiment and phase equilibrium theory simulation.The injected gas could greatly improve the recovery of condensate oil in the gas reservoir,and the condensate oil recovery increased by 42% after 5 cycles of injection and production;the injected gas had significant evaporative and extraction effects on the condensate,especially during the first two cycles;the condensate oil saturation of the formation decreased with the increase of injection-production cycles,and the condensate oil saturation after multi-cycles of injection-production was almost 0;the storage capacity increased by about 7.5% after multi-cycles of injection and production,and the cumulative gas injection volume in the 5 th cycle increased by about 25%compared with that in the 1 st cycle.

The Possibility of Wax Formation in Gas Fields:a Case Study

Natural gas production from a gas reservoir （Reservoir A） located in the south of Iran, presents solids deposition during processing because the condensate contains suspended and dissolved solids. Solids deposition occurs not only in the transportation lines from the wells to the separators but also in the various operating units of gas streams and condensate stream. In this study, the multisolid-phase model has been used to predict the wax precipitation from gas and gas condensate fluids. The properties of gas and liquid phases are described using the Soave-Redlich-Kwong （SRK） equation of state. The model is then used to predict the possibility of the wax formation in Reservoir A gas facilities, located at the south of Iran. Solid deposition which occurred in the various streams of that facility confirmed the calculated results. Finally, the wax appearance temperature （WAT）, the weight percent of wax formation and the effects of pressure and temperature on the wax formation were also predicted.

Gas condensate reservoirs: Characterization and calculation of dew-point pressure

A large data bank of more than 700 gas-condensate samples collected from literature and experiments was established.On this basis,empirical correlations and equations of state commonly used to calculate dew-point pressure(DPP)were evaluated.A new model for estimating DPP was proposed.All the empirical correlations and the Peng-Robinson state equation were compared,and sensitivity of parameters was analyzed.The current standards used to identify gas condensate were evaluated and found to be not accurate enough.The Peng-Robinson state equation has no unique solution and is affected by multiple factors such as the characterization of C7+components and the splitting scheme.The Nemeth-Kennedy correlation has the highest accuracy when applied to the data bank established in this study,followed by Elsharkawy correlation and Godwin correlation.While Shokir correlation cannot be used for samples without C7+components,it is therefore the lowest in accuracy.The newly proposed model has an average absolute error,root mean square error and coefficient of determination of 7.5%,588,and 0.87,respectively,and is better than the above four correlations statistically.The proposed model proved to be more accurate and valid when compared to experimental results and simulation with the Peng-Robinson state equation.

Application of Statistical Methods to Biomarkers for Geochemical Evaluation and Genetic Type Determination of Gas Condensates in the Persian Gulf and Coastal Fars,Southern Iran

In a comprehensive geochemical study,the genetic relationships among 14 samples of gas condensates from the Persian Gulf were investigated for the purpose of evaluating the respective source rocks in terms of both age and sedimentary paleoenvironment.Chemometric analysis was used for categorization and determination of a certitude range to determine the genetic type of the condensate families in the studied basin.The samples were collected from Late Permian-Triassic reservoirs(Dalan and Kangan formations)located in 6 gasfields(gas condensate)hosting some of Iran’s most important gas/gas condensate reserves.Obtained by gas chromatography-mass spectrometry(GC-MS),a total of 16 biomarker parameters(10 maturity-related parameters and 6 sedimentary environment-related parameters)were used to evaluate the samples in terms of thermal maturity(and hence their positions in the maturity chart),the sedimentary environment of the source rock and the lithology.Application of Hierarchical Clustering Analysis(HCA)and Principal Component Analysis(PCA)to the collected data led to the categorization of the samples into three main genetic groups,Ⅰ-Ⅲ.GroupsⅠandⅢwere found to be located in the east and the west of the Persian Gulf,respectively,while GroupⅡwas developed between the two other groups.