Gas Condensate Reservoirs Research Articles

Full-cycle enhancing condensate recovery-underground gas storage by integrating cyclic gas flooding and storage from gas condensate reservoirs

Underground gas storage (UGS) is efficient in large-scale natural gas storage and peak regulation. However, UGS operation based on gas-condensate reservoirs are challenging due to complicated phase behavior and multi-phase flow considering trapped condensate. This paper presents a method for full-cycle enhancing condensate oil recovery (EOR)-UGS by integrating cyclic gas flooding and storage from gas-condensate reservoirs. Full-cycle EOR-UGS is defined by four stages, including primary depletion, cyclic gas flooding, collaborative gas production and UGS operation. The EOR mechanisms of each stage are analyzed by experiments and simulation. Cyclic gas flooding can reduce drop out of condensate. The reasonable volume of cyclic gas flooding is 0.5 HCPV, enhancing condensate recovery factor by 42.8%. During the collaborative stage, gas injection can effectively evaporate and drive the condensate towards production wells. After five collaborative cycles, the condensate recovery factor is further enhanced by 21.8% and gas storage capacity can be increased more than 30%. Finally, optimal full-cycle EOR-UGS schemes can enhance condensate recovery factor by 69.92%. Compared with gas flooding to 1.5 HCPV followed by constructing UGS, the full-cycle EOR-UGS integration can improve condensate recovery factor by 7.37%. This work provides a new idea for UGS construction and operation based on gas-condensate reservoirs.

Mathematical modeling of well performance in shared gas condensate reservoirs

Shared reservoirs, in which typically contain internal and external regions, are under dominion of two or several operators (such as countries or companies). Therefore, some challenges (e.g., political issues for definition of border line) should be anticipated for the development of these fields. However, production data of external region is usually not available. Lack of knowledge regarding to external region production conditions has led to some challenges in forecasting of well deliverability and evaluation of gas migration. This is due to the assumption of constant drainage area in most of the well performance models which does not align with real cases. The aim of this study is to propose an analytical well performance and multi-phase flow methods for gas condensate reservoirs, accounting for the non-volumetric effect of the internal region wells in a shared pattern. In addition, the method can be used for estimation of gas migration and production rate of external region in such reservoirs. This could be achieved by the introducing a novel dynamic material balance and two phase pseudo-time function to calculate the average pressure through assessing the deliverability of internal wells. It is noted that the production information of the external region is not required here.Upon defining a shared pattern, we evaluated the proposed methodology through a commercial simulator using actual field data. The acquired results ensure the accuracy of its application in typical rock and fluid characteristics of gas condensare reservoirs. The proposed novel technique can be utilized for material balance calculation in shared reservoirs.

Effect of wax content on phase behavior of ultra-deep condensate gas reservoir: Experimental and thermodynamic model

The development of ultra-deep oil and gas reservoirs has become a trend in recent years. Comprehensive understanding of the complex phase behavior of waxy condensate gas is necessary for the exploitation of ultra-deep gas reservoir. The objective of this work is to study and predict the phase behavior of condensate gas under various wax contents. The condensate gas and wax samples were collected from ultra-deep condensate gas well in northwestern China. The phase behavior tests were performed to determine the dew point pressure, percentage of condensate liquid, and compressibility factor of condensate gas under different wax contents using an ultra-high-pressure Pressure-Volume-Temperature (PVT) setup. It can be found that the dew point increased with the increasing wax content. The percentage of condensate liquid and compressibility factor increased with the increasing wax contents. A thermodynamic model based on an equation of state (EOS) was proposed to describe the phase behavior under different wax content. The average absolute deviations (AAD%) between the calculated compression factor and the experimental values of 0 %, 6.79 %, 10.86 % and 14.18 % wax contained are 3.73 %, 2.43 %, 0.76 % and 0.25 %, respectively. The results show that the thermodynamic model developed in this work exhibits the highest prediction accuracy, which can provide the necessary guidance for the development of ultra-deep waxy condensate gas reservoir.

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.

Study on the distribution of oil ring components and volume changes during the depletion development process of high CO2 gas condensate reservoirs with oil ring

During the depletion development process, the fluid phase behavior of high CO2 gas condensate reservoirs with oil ring exhibits extremely complex due to the mass transfer processes between CO2 and oil. To study the phase behavior characteristics of high CO2 gas condensate reservoirs with oil ring, depletion development experiments were carried out at different depletion pressures and rates. The components of oil and gas produced in each depletion stage were analyzed by using chromatography to obtain the composition change of the remaining fluid. In addition, the reservoir phase behavior and the oil ring’s volume change during the depletion development process were calculated through equation of state. The experimental results show that for high CO2 gas condensate reservoirs with oil ring, the content of heavy components in the produced oil increased as the depletion pressure decreases. Due to the change of fluid composition and pressure during depletion, the volume change of the oil ring was divided into three stages. The volume of the oil ring increased slowly at first, then increased rapidly, and finally decreased. Increasing the depletion rate would increase the content of intermediate and heavy components in the produced oil and gas. A higher depletion rate was advantageous for enhancing recovery, whereas a lower depletion rate resulted in a larger volume of the oil ring. However, experiments show that there was a critical depletion pressure, which was 25.5 MPa for the Libra Central reservoir. The pressures below this threshold resulted in a reduction in the volume of the oil ring.

Wettability Alteration in Gas Condensate Reservoirs: A Critical Review of the Opportunities and Challenges

Wettability Alteration in Gas Condensate Reservoirs: A Critical Review of the Opportunities and Challenges

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

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

Investigation of the temperature field in gas condensate reservoirs taking into account thermodynamic effects

Based on modeling of non-isothermal filtration of a multiphase fluid, taking into account thermohydrodynamic effects and heat of condensation, the formation of a temperature field in a homogeneous porous medium at different pressures at the onset of condensation is studied. A numerical model of one-dimensional two-phase filtration taking into account the phase transition is obtained. Testing of the numerical solution was carried out on the basis of a well-known analytical solution for non-isothermal two-phase filtration in a reservoir taking into account mass transfer. The change in gas flow rate during condensate precipitation and the change in temperature over time on the well wall are considered. It is shown that, depending on the pressure of the onset of condensation (the radius of the onset of condensation in the formation), a different rate of formation of the temperature field in the formation is observed after the well is put into operation: the temperature anomaly can be positive, negative or inverse. The results of numerical experiments can be used when planning field studies in gas condensate wells.

A screening tool for carbon dioxide injection in gas reservoirs based on the material balance approach

Significant efforts are made to reduce the carbon dioxide concentrations in the atmosphere as part of a global scheme that aims to mitigate climate change. Carbon geological storage involves the storage of CO2 permanently in a subsurface reservoir, commonly a brine saturated aquifer, or a depleted reservoir. Carbon dioxide is also injected for enhanced oil or gas recovery (EOR/EGR). This work applies a material balance to CO2 for injection and storage in a single-phase dry and/or condensate gas reservoirs. The developed framework based on piston-like displacement can be either used for pressurising depleted gas reservoirs with CO2 or for EGR. Sensitivity studies of carbon dioxide injection in pressure depleted gas reservoirs and piston-like injection under water drive are presented for various production rates and initial reservoir pressures. Monte Carlo simulations are conducted for combinations of porosity and permeability of different formations such as sandstone, shale, and unconsolidated sand. The results show that CO2 piston-like injection in EGR is more efficient compared to first depleting the reservoir and then injecting CO2 as it controls the water influx. The recovery factors in CO2 EGR are almost insensitive to initial pressures and production rates for both single-phase and condensate gas. Higher permeability formations are much more effective, however, a formation with very high permeability may lead to stability problems.

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.

Phase behavior of gas condensate in fractured-vuggy porous media based on microfluidic technology and real-time computed tomography scanning

With the development of gas-condensate reservoirs, the phase behavior of gas condensate undergoes continuous changes. The phase behavior of gas condensate in PVT cylinders is different from that in fractured-vuggy gas-condensate reservoirs because multiscale pore structures can affect the phase behavior. By vuggy, we mean the formation of a reservoir contains cavity structures. To elucidate the influence of fractured-vuggy porous media on phase behavior of gas condensate, a microfluidic chip and a fractured-vuggy carbonate sample were prepared for pressure depletion experiments. The phase behavior of gas condensate in the chip during depressurization was observed via brightfield optical microscopy. The real-time computed tomography scanning was used to analyze pore structure of the sample and to obtain the phase behavior of gas condensate under different pressures. The results showed that the dew point pressure of the gas condensate was increased from 12.0 MPa in PVT cylinders to 14.8 MPa in nanochannels of the chip. The condensate liquid appeared in micropores at 14.4 MPa. The change of the average radius, coordination number, and tortuosity of condensate liquid ganglia were calculated and analyzed using pore network models. The shape factor and the Euler number were used to classify the condensate liquid into four types including clustered, branched, membranous, and droplets ganglia. The condensate liquid was generally distributed as clustered ganglia. This study provided evidence of the effect of fractured-vuggy porous media on phase behavior of gas condensate and clarified that the phase behavior of gas condensate varies in multi-scale pores.

Application of Deep Neural Network-Artificial Neural Network Model for Prediction Of Dew Point Pressure in Gas Condensate Reservoirs from Field-X in the Niger Delta Region Nigeria

Reservoirs of natural gas and gas condensate have been proposed as a potential for providing affordable and cleaner energy sources to the global population growth and industrialization expansion simultaneously. This work evaluates reservoir simulation for production optimization using Deep Neural network - artificial neural network (DNN-ANN) model to predict the dew point pressure in gas condensate reservoirs from Field-X in the Niger Delta Region of Nigeria. The dew-point pressure (DPP) of gas condensate reservoirs was estimated as a function of gas composition, reservoir temperature, molecular weight and specific gravity of heptane plus percentage. Results obtained show that the mean relative error (MRE) and R-squared (R2) are 0.99965 and 3.35%, respectively, indicating that the model is excellent in predicting DPP values. The Deep Neural Network - Artificial Neural Network (DNN-ANN) model is also evaluated in comparison to earlier models created by previous authors. It was recommended that the DNN - ANN model developed in this study could be applied to reservoir simulation and modeling well performance analysis, reservoir engineering problems and production optimization.

Machine learning modelling of dew point pressure in gas condensate reservoirs: application of decision tree-based models

Machine learning modelling of dew point pressure in gas condensate reservoirs: application of decision tree-based models

Experimental Study on the Control Mechanism of Non-Equilibrium Retrograde Condensation in Buried Hill Fractured Condensate Gas Reservoirs

During the depletion development of condensate gas reservoirs, when the formation pressure drops below the dew point pressure, the condensate oil and natural gas systems are in the non-equilibrium state of foggy retrograde condensation. The rational use of the non-equilibrium phase characteristics of the foggy retrograde condensation phenomenon during the development process will be beneficial to the recovery of condensate oil and natural gas. In order to clarify the retrograde condensation control mechanism during the non-equilibrium depletion development of condensate gas reservoirs, the phase characteristics of a condensate oil and gas system were studied by constant composition expansion and constant volume depletion experiments. Then, on the basis of a long core depletion experiment and chromatographic analysis experiment, the influence of different pressure drop speeds, fluid properties, and reservoir physical properties on the control effect of non-equilibrium retrograde condensation after the coupling of the fluid retrograde condensation and reservoir core is analyzed. The results show that during the pressure decline process, the condensate oil and gas system will produce a strong foggy retrograde condensation phenomenon, with the saturation of the retrograde condensate increasing and then decreasing. The cumulative recovery of the condensate oil and natural gas, as well as the mass fraction of the heavy components in the condensate oil, increase with the increase in the depletion rate. Different fluid properties and reservoir physical properties have a great influence on the cumulative recovery degree of the condensate oil, and have little influence on the recovery degree of the natural gas. This work has a certain guiding role for the stable production and enhanced recovery of fractured condensate gas reservoirs in subsurface structures of metamorphic rocks.

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, real-time 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.

Wettability Alteration of Berea Sandstone for Gas Condensate Applications.

Gas condensate reservoirs can suffer significant decreases in production due to the buildup of liquid in the vicinity of the wellbore, which occurs when the bottom-hole flowing pressure drops below the dew point pressure. Consequently, the generated liquid hydrocarbons can hinder the movement of the produced gas by adhering to the surfaces, thereby creating a condensate bank. One potential method for mitigating the issue of condensate banking involves the injection of chemical treatment and the alteration of wettability from a liquid-wet state to an intermediate gas-wet state. This study conducted an experimental investigation of the impact of fluorochemical treatment on altering the wettability from liquid-wetting to intermediate gas-wetting. The wettability of the Berea sandstone was analyzed before and after chemical treatment over a temperature range of 25-83 °C. The outcrop core samples of Berea sandstone used in this investigation exhibited an average porosity and permeability of 20% and 100 mD, respectively. The experimental results indicate that the application of chemical treatment has the potential to alter the wettability of Berea sandstone, transitioning it from a state of liquid-wetting to gas-wetting at standard temperatures. The chemical treatment alters the wettability from liquid-wet to intermediate gas-wet at higher temperatures. Furthermore, the alteration of wettability substantially improves the mobility of the oil phase and decreases the residual saturation of the oil, thereby aiding the reduction of liquid accumulation around the wellbore. According to this research, altering the wettability of the rock surrounding the wellbore in gas condensate reservoirs from a state of strong liquid-wet to gas-wet has the potential to enhance the deliverability of gas wells and improve injectivity in the field.

Effect of Pressure and Temperature Variation on Wax Precipitation in the Wellbore of Ultradeep Gas Condensate Reservoirs

Summary To investigate the wax precipitation mechanism of condensate in a wellbore during the ultradeep gas condensate reservoir development, condensate samples were prepared in this work. Changes in the temperature and pressure of fluid flow in the wellbore are simulated by a high-temperature and high-pressure pressure/volume/temperature (PVT) system. This simulation explores their influences on the wax precipitation of the condensate produced from the target reservoir. The results show that the temperature decrease weakens the wax molecular movement activity and promotes the precipitation of wax, resulting in the expansion of the pressure range in which wax precipitation occurs in the system. Meanwhile, decreasing the pressure promotes wax aggregation by increasing van der Waals forces between wax molecules, thereby increasing the wax precipitation rate. At different temperatures, the wax precipitate amount first increases and then decreases with decreasing pressure, which is determined by the wax solubility and remaining content in the system. Since the solubility of a low carbon number component is more sensitive to temperature and pressure changes than that of a high carbon number component, in the early stages of experimental temperature and pressure decreases, the precipitation of coarse crystalline wax with carbon numbers ranging from C16 to C30 is more active than that of microcrystalline wax with carbon numbers exceeding C30. The remaining amount of the former component in the system decreases rapidly, and its precipitation capacity weakens, thus increasing the amount of the latter component in the precipitated wax during the later stage of experiments; this trend corresponds to the shift of the curve peak of the wax carbon number distribution to an abscissa interval with the relatively high carbon numbers. This work can provide reference data for the prediction of the well depth at which the wax precipitation occurs and the wax composition, aiming to promote the implementation of wellbore wax blockage prevention programs.

Study on the characteristic of asphaltene-wax co-precipitation during gas injection of unconventional gas condensate reservoirs

The intensification of energy shortage has accelerated the development of unconventional oil and gas resources, during which complex problems of organic solid precipitation often occur. The precipitation behavior of organic solid such as asphaltene and wax play an important role in the optimization of reservoir production. However, there is still a lack of comprehensive understanding of the precipitation mechanism and interaction between asphaltene and wax, especially under high temperature and pressure. A self-designed precipitation apparatus based on backscattered light was utilized to achieve this objective. The effects of temperature range 30–120 ℃, pressure range 5–85 MPa, gas-oil ratio of 150，300 and 500 sm3/sm3 and injection gas of CH4, CO2 and N2 on organic solid precipitation in condensate oil-gas system were studied by physical simulation. The results revealed that asphaltene precipitated separately at high temperature, and asphaltene and wax co-precipitated at low temperature. Based on the observed precipitation behavior, a co-precipitation mechanism of asphaltene and wax under high-pressure conditions was proposed: Asphaltene particles precipitated first, providing nucleation sites for wax absorption, growth, and cross-linking as the pressure decreased. Moreover, the depressurization induced phase separation during oil and gas production resulted in the extraction of light components, reducing the solubility of wax and exacerbating reservoir damage caused by the precipitation of organic solid. Increasing the gas-oil ratio led to higher amounts of organic solid precipitation and shifted the pressure at which precipitation occurred. Furthermore, the miscibility of injection medium and condensate oil will also significantly affect organic matter precipitation, and the potential damage to the reservoir can be shown as follows: N2＞CO2＞CH4.

Study on characterization and distribution of four regions of tight sandstone condensate gas reservoirs in the depletion development process

The traditional three-region theory cannot explain why some condensate gas reservoirs have high production in field depletion development even if the formation pressure is below the dew point. To solve this problem, the re-designed depletion development experiments are conducted under various pressure drop velocities conditions. Besides, a new quantitive method of the pressure range of different regions is established. The results show that there is a fog-state region in the porous medium, which is in the adjacent area below the dew point, and the production of the fog-state region is as high as the pure gas region. Compared with the fog-state region, the instantaneous gas and condensate production in the movable gas and immovable condensate (MIMC) region decreased by 23% and 93.8% in this work, respectively. The depressurizing velocity has a great impact on the fog-state region range, the positive coupling effect caused by a suitable depressurizing velocity can enlarge the fog-state region and compress the MIMC region, but the inertia effect caused by over-high depressurizing velocity will generate plenty of condensate bridges and reduce the recovery of gas condensate reservoirs. To our knowledge, the existence and quantitive pressure range of the fog-state region of the gas condensate reservoir in the porous medium is experimentally determined for the first time, which improves the traditional three-zone theory of the gas condensate and gives important support to reservoir-scale field application.

Treatment of paraffin deposition behavior in gas-condensate wells with chemical inhibitors

As deep gas-condensate reservoirs are explored, the problem of paraffin deposition is becoming more prominent. Therefore, this paper collects condensate samples from representative paraffin deposition gas-condensate wells and analyzes basic physical properties. The cold plate deposition device is employed to study paraffin deposition behavior under well conditions and to divide the critical regions for paraffin deposition in gas-condensate wells. The experimental apparatus, such as the crude oil dynamic paraffin deposition rate tester, is utilized to investigate the preventive effect of paraffin dispersants and paraffin crystal modifier. The results show that there is significant phase change behavior in gas-condensate wells and gas phase is dominant form, but there is also phase evolution. It can be identified from the experiments that paraffin deposition is mainly located in the 1000 ~ 1500 m region, and a paraffin deposition identification chart has been established. The maximum deposition rate could reach 15.50 mm/year, which matched the temperature and pressure conditions of 45 ℃ and 70 MPa. The preventive effect of paraffin crystal modifiers greatly exceeds that of paraffin dispersants, with paraffin prevention rates of 85–95% at the optimal concentrations of 0.25–0.50 wt.%. The dissolving paraffin rate can reach 0.0169 g/min. It decreases the paraffin appearance temperature approximately 40% and significantly changes the paraffin crystal morphology. Increased deposition surface area of the cold plate structural design describes the paraffin deposition. This diagram facilitates the reliable identification of paraffin deposition areas and the deposition rates in the wellbore during production. The optimum amounts of BZ and PI paraffin inhibitors are quantified. This study provides a comprehensive understanding of the paraffin deposition behavior, and scientific basis and guidance for the selection of paraffin inhibitors in gas-condensate wells.