Development Of Gas-condensate Reservoirs Research Articles

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.

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.

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, gas–oil 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.

Evaluation of the gas recycling duration on the hydrocarbon recovery from gas condensate fields

Optimization of formation pressure maintenance technologies in the development of gas condensate fields with a high initial content of condensate in the reservoir gas using numerical modelling. A study on the efficiency of dry gas injection for pressure maintenance in gas condensate fields was performed with the help of numerical 3D models. Key technological indicators of the reservoir development were calculated for the dry gas injection period of 12, 24, 36, 48, and 60 months. The results are presented as plots for the parameters in a study. Based on the results of the studies, it was found that the introduction of dry gas injection technology ensures that reservoir pressure is maintained at the highest level compared to the development of gas condensate reservoirs on primary depletion. Due to this, further condensate drop-out in the reservoir is slowed down, and the production of partly already condensed hydrocarbons is ensured by their evaporation into the dry gas injected from the surface. The simulation results indicate that increase in the injection duration period leads to an increase of the cumulative condensate production and hence the final hydrocarbon recovery factor. The heterogeneity of oil and gas deposits, both in terms of area and thickness, significantly affects the efficiency of the developed hydrocarbon enhancement technologies. In order to minimize the negative impact of heterogeneity, it is necessary to conduct additional studies on the conditions of specific reservoirs or fields. The reservoir pressure maintenance technology implementation according to various technological schemes, as well as using various types of injection agents, will significantly intensify the development of depleted gas condensate fields with a high condensate yield. Statistical analysis of the simulation results identified the optimum value of the dry gas injection period into the gas condensate reservoir, which is 34.3 months for the conditions of a given reservoir in the study.

Gas Condensate Wells: Challenges of Sampling, Testing and Production Optimization

The main problem of fluid sampling during well testing of reservoirs with near-critical fluids (gas condensate and volatile oil) is due to the fact that even a small pressure drawdown usually leads to the formation of a two-phase mixture in the bottom hole area, and it is almost impossible to take representative samples with downhole samplers or a formation tester. Sampling via test-separator and the current non-separation methods are also imperfect. An alternative method—MIKS (Multiphase IsoKinetic Sampling)—of gas condensate well testing was proposed, which is based on emulsifying a multiphase flow to particles of about 1–10 μm. Thereby MIKS would eliminate the problem of particle slippage in a homogeneous flow and enables high-quality sampling directly from the flowmeter line. The initial formation fluid is characterized by the maximum value of the condensate-gas ratio (CGR). Therefore, first, the well effluent would be adjusted to the mode with the maximum CGR using a choke manifold and a multiphase flow meter. Then the flow mixture is transferred to a by-pass line with an emulsifier to achieve an isokinetic flow. Thereafter, pressure samples can be taken into pressurized sampling bottles, in which thermodynamic conditions are preset according to the flow line. The efficiency of sampling and recombining procedures allows for conducting a study of reservoir samples in the field laboratory directly on the rig and obtaining a complete PVT report even before the completion of drilling and abandonment of the well. An additional economic effect is achieved by reducing the costs of transporting and samples storage. Well test equipment setup becomes much more compact and less weight; the costs of drilling time are reduced, which is viably important for well testing on the Arctic conditions. Another major problem in the development of gas condensate reservoirs is avoiding the condensate banking around producing wells. Optimization of condensate production can be achieved by maintaining the well operation mode at maximum CGR level by means of multiphase flowmeters. The formed condensate bank can be destroyed by a combination of methods—hydraulic fracturing, followed by cycling process—purging the formation with dried gas and/or injection of methanol into the formation. Methanol can be obtained from synthesis gas as a by-product in the utilization of associated gas also at the field. The specified set of measures will allow to revive the GC wells that are losing productivity, as well as to extend the period of high productivity of new wells.

Dew point pressure of gas condensates, modeling and a comprehensive review on literature data

The accurate and in-time prediction of gas condensates dew point pressure (PDew) is of great importance regarding the technical and economic points of view for fluid characterization, reservoir performance calculations, planning the development of gas condensate reservoirs, and design and optimization of production systems. Although the laboratory tests provide the most accurate and reliable results, it is an expensive and time-consuming process sometimes associated with some errors. Artificial intelligence-based methods have emerged as promising tools in different aspects of engineering. In this study, after a thorough analysis of the gas condensate data samples, the application of different intelligent modeling is investigated. A databank of 721 data samples is gathered, and different intelligent methods approaches are used for modeling. The results of three different data mining methods are combined using Committee Machine Intelligent Systems (CMIS) in an attempt to receive more accurate results. Three different methods of arithmetic, geometric, and harmonic approaches are utilized to develop the CMIS model. It was concluded that the harmonic CMIS yields the best predictions by average absolute relative deviation (AARD) and R2 values of 3.456% and 0.9702, respectively. This novel CMIS model could successfully outperform all the developed initial models. Additionally, a literature review showed that the proposed model could outperform the previously published models including artificial intelligence, equation of state, and correlation-based method considering both prediction accuracy and data coverage.

АНАЛИЗ ЭФФЕКТИВНОСТИ ПРИМЕНЕНИЯ САЙКЛИНГ-ТЕХНОЛОГИИ ПРИ РАЗРАБОТКЕ ЗАЛЕЖЕЙ ГАЗОВОГО КОНДЕНСАТА

Актуальность исследования обусловлена тем, что при разработке газоконденсатных залежей на месторождениях нефти и газа наблюдаются процессы ретроградной конденсации, вследствие которых в пласте безвозвратно теряются значительные объемы высококипящих компонентов углеводородной группы С5+, добыча которых являлась бы дополнительным доходным источником для нефтегазовых компаний. Общие запасы газового конденсата в России составляют около 2 млрд т, поэтому для решения проблемы наиболее полного извлечения компонентов газоконденсатной пластовой смеси необходимо внедрение новых эффективных методов добычи. Целью исследования является обоснование эффективности применения сайклинг-технологии для разработки газоконденсатной залежи. Объект: месторождение N, расположенное на территории Восточной Сибири. Методы: композиционное, геологическое и гидродинамическое моделирование газоконденсатной залежи. Результаты. Проведено композиционное моделирование газоконденсатной пластовой смеси в соответствии с компонентным составом проб газа и газового конденсата, а также результатами газоконденсатных исследований. Построена упрощенная геологическая модель исследуемой залежи, на основе которой проведено гидродинамическое моделирование ее состояния на различных режимах разработки. Сравнительный анализ показателей разработки газоконденсатной залежи, таких как коэффициент извлечения конденсата, коэфициент извлечения компонентов С2-С4 и конденсато-газовый фактор, на различных режимах работы доказал, что применение сайклинг-технологии приводит к увеличению извлечения компонентов углеводородной группы С5+ и позволяет решать ряд экономических и экологических задач. Возможна адаптация представленной модели под необходимые горно-геологические условия с целью применения данной технологии на территории Западно-Сибирской и других нефтегазоносных провинций.

Effect of retrograde condensation on the production performance of organic hydrogen compounds energy

The gas-condensate reservoirs are typical organic fossil reservoirs of hydrogen compounds energy. With the development of gas-condensate reservoirs, a part of condensate liquid of hydrogen compounds will appear under the influence of retrograde condensation mechanism. However, the effects of retrograde condensation on the production performance of organic hydrogen compound energy with different well types are still not clear. In this study, a series of numerical simulation models were established to investigate the law of retrograde condensation with different well types and reservoir permeabilities. Furthermore, the effects of retrograde condensation on gas well productivity were analyzed by the comparison between the compositional modeling and black oil modeling results. Results show that the condensate oil for the fractured wells is mainly distributed around the fracture tips instead of the perforation intervals for the unfractured wells. The maximum oil saturation and condensate area of two fractures at ends are much larger than those of middle fractures. The retrograde condensation exhibits a negligible impact on the production of multiple fractured horizontal wells with a cumulative gas production reduction 0.87%–1.57%. Hydraulic fracturing, multiple fractures and high reservoir permeability are conducive to lower the impact of retrograde condensation on the production of organic hydrogen compounds energy.

A proposed capillary number dependent model for prediction of relative permeability in gas condensate reservoirs: a robust non-linear regression analysis

Well deliverability reduction as a result of liquid (condensate) build up in near well regions is an important deal in the development of gas condensate reservoirs. The relative permeability is an imperative factor for characterization of the aforementioned problem. The dependence of relative permeability on the coupled effects of Interfacial Tension (IFT) and flow velocity (capillary number) together with phase saturation is well established in the literature. In gas condensate reservoirs, however, the influence of IFT and velocity on this parameter becomes more evident. The current paper aims to establish a new model for predicting the relative permeability of gas condensate reservoirs by employing the direct interpolation technique. To this end, the regression analysis was carried out using seven sets of literature published experimental data. The validity analysis was executed by utilizing statistical parameters integrated with graphical descriptions. Furthermore, a comparison was carried out between the proposed model and some literature published empirical models. The results of the examination demonstrated that the new model outperformed other correlations from the standpoints of accuracy and reliability.

Gas-condensate flow modelling for shale reservoirs

Condensate banking is the most challenging engineering problem in the development of gas-condensate reservoirs where the condensate accumulation can dramatically reduce the gas permeability resulting in impairment of wells productivity. An accurate assessment of condensate banking effect is important to predict well productivity and to diagnose well performance.Traditionally, Darcy law, combined with relative permeability models, has been used for modelling condensate banking effect in conventional reservoirs. This approach is also widely adopted in reservoir engineering commercial tools. However, for shale gas-condensate reservoirs, the gas flow deviates from Darcy flow to Knudsen flow due to the very small pore size in shale matrix (3–300 nm), compared to conventional reservoirs (10–200 μm). This gas flow is highly dependent on pore size distribution and reservoir pressure.In this paper, the effect of condensate saturation on Knudsen flow in shale matrix kerogen is investigated using a 3D pore network with a random pore size distribution. The Knudsen flow is incorporated at the pore level and gas permeability is evaluated for the whole network. In addition, the pore distribution effect in terms of log-normal mean and standard deviation is investigated. The concept of relative permeability in Darcy flow is extended to Knudsen flow by defining a new parameter called relative correction factor ξrel to evaluate the effect of condensate banking on Knudsen flow. This parameter can be employed directly in reservoir engineering tools.Simulation results showed that the relative correction factor is not only dependent on condensate saturation but also on pressure. This is due to the impact of pressure on the contribution of pore size ranges into the gas flow. In addition, results showed the effect of the pore size distribution where the standard deviation controls mainly the behaviour of Knudsen flow under condensate saturation. Disregarding this effect can lead to an overestimation of Knudsen flow contribution in well production under condensate banking effect.

The solubility of gas components and its importance in gas-condensate reservoir development

ABSTRACTThe authors investigated the solubility of the gas components in the natural gas-condensate systems and its importance in gas-condensate reservoir development. Also, they discuss some fundamental aspects of preferable methods for recovering trapped retrograde condensate in the formation that is left after primary production. Based on the obtained results from the constant composition expansion test of seven different gas-condensate systems provided a greater understanding of the occurrences and interchanges between liquid and gas phases in the recombined reservoir fluids. The correlation between amount of the dissolved gas in the liquid phase, the volume of vaporized condensate in the gas phase and retrograde condensation pressure was investigated. Analysis of this data identified that increasing dissolved gas in the liquid phase, increases vaporized condensate even in the same thermobaric condition and decreases the retrograde condensation pressure of the gas-condensate systems. It was determined that the solubility of gas components in the fluid should be considered when projecting the gas-condensate reservoirs development. As, improving the solubility of gas components in the condensate decreases the system fog up and retrograde condensation pressures and improves stability of aerosol condition of gas-condensate fluid, it influences on the reservoir condensate bearing to be increased. Therefore, injected gas for gas cycling or revaporization of accumulated condensate from the core can be controlled for the purpose of increasing its solubility and condensate bearing capability.

Experimental and modeling study of CO2 - Improved gas recovery in gas condensate reservoir

Abstract This paper presents the effectiveness of the CO 2 injection process at different periods during gas-condensate reservoir development. Taking a real gas-condensate reservoir located in China's east region as an example, first, we conducted experiments of constant composition expansion (CCE), constant volume depletion (CVD), saturation pressure determination, and single flash. Next, a series of water/CO 2 flooding experiments were been investigated, including water flooding at present pressure 15 MPa, CO 2 flooding at 25.53 MPa, 15 MPa, which repents initial pressure and present pressure respectively. Finally, the core flooding numerical model was constructed using a generalized equation-of-state model reservoir simulator (GEM) to reveal miscible flooding mechanism and the seepage flow characteristics in the condensate gas reservoir with CO 2 injection. A desirable agreement achieved in experimental results and predicted pressure volume temperature (PVT) properties by the modified equation of state (EOS) in the CVD and CCE tests indicated that the proposed recombination method can successfully produce a fluid with the same phase behavior of initial reservoir fluid with an acceptable accuracy. The modeling results confirm the experimental results, and both methods indicate that significant productivity loss can occur in retrograde gas condensate reservoirs when the flowing bottom-hole pressure falls below dew point pressure. Moreover, the results show that CO 2 treatment can improve gas productivity by a factor of about 1.39 compared with the water flooding mode. These results may help reservoir engineers and specialists to restore the lost productivity of gas condensate.

Experimental study into the effectiveness of the partial gas cycling process in the gas-condensate reservoir development

ABSTRACTIn this study a laboratory study was carried out with the purposes of estimating the effectiveness of the gas cycling process during gas-condensate reservoir development. Specific laboratory equipment was constructed to carry out an experimental investigation by modelling the gas injection and reservoir depletion process. Volumetric properties, fog up, liquid drop-out condition, and retrograde dew point pressures of gas-condensate fluids were investigated. The reservoir fluid was recombined based on samples from Azerbaijan natural gas-condensate reservoir. Results are describing gas injection effect on condensate/gas ratio and condensate recovery in each pressure step. These have provided an understanding on the influence of the retrograde dew point pressure on optimum gas injection stage. The analyses also assure that as condensate/gas ratio decreases continually during the gas injection process, which causes the reservoir fluid PVT characteristics to be changed accordingly furthermore the reservoir pressure can be depleted in order to vaporize the liquid phase and to maintain the reservoir fluid to be in a single phase state during the reservoir exploitation. It was seen to be closely related with retrograde dew point pressure and fog up pressures. Therefore, in terms of incorporating colloidal systems into the subject focusing more on the region between fogging up and retrograde condensation gave interesting results.

The effect of gas-condensate reservoir depletion stages on gas injection and the importance of the aerosol state of fluids in this process

As one of the primary techniques for enhanced oil recovery, the gas injection method has been investigated widely. However, introducing “dry gas” into a gas-condensate reservoir is more than miscible flooding that maintains reservoir pressure and improves oil displacement. This method is associated with complex thermodynamic processes or phase transitions, such as the re-vaporization of heavy hydrocarbon ends and connate water, the reduction of the condensate/gas ratio and retrograde dew point (RDP) pressure, etc. In this paper, a laboratory study was conducted to estimate the effectiveness of the gas injection process during gas-condensate reservoir development. Specific laboratory equipment was constructed to conduct an experimental investigation by modelling the gas injection and reservoir depletion process.Detailed analysis of experimental investigations suggests the gas injection process might be more effective when the “reservoir” pressure is below the initial RDP pressure of the fluid. Thermodynamically, this pressure stage could be conducive for gas injection, by decreasing the condensate/gas ratio, re-vaporizing the liquid phase that dropped out and maintaining the system in a single gas phase.To further examine the process of the liquid or fog formation phase in the gas-condensate mixture, the fluid was investigated as a colloidal structure. Theoretical findings confirm that the fog condition is a well-matched feature of gas-condensate fluids with the properties of aerosol-colloidal systems. The correlation between fog up (FU), RDP pressures and temperature was investigated experimentally. The rationale for increasing the difference between the FU and RDP pressures with the increase of temperature and other physical and thermodynamic properties of gas-condensate systems is explained according to the fundamentals of colloidal systems.Based on these obtained results, conclusions were reached about the physical nature of the condensation under reservoir conditions. The results show that condensation in the reservoir condition can occur when the pressure in the interval creates the formation of liquid phase micro-embryos or aerosols. Thus, the fluid condenses due to surface forces between the sub-micron-sized condensate particles and the rock granules. This phenomenon can cause condensate blockage or condensate banking in the early stage of reservoir development when even the reservoir pressure is greater than the RDP pressure identified in the PVT cell. These results were used to explain the dynamic processes occurring within and influencing the operating characteristics of the gas-condensate wells. Because these colloidal features of fluid can play a significant role in reservoir development, we recommended considering these aspects when planning gas injection methods.

Application of Artificial Neural Network–Particle Swarm Optimization Algorithm for Prediction of Gas Condensate Dew Point Pressure and Comparison With Gaussian Processes Regression–Particle Swarm Optimization Algorithm

For gas condensate reservoirs, as the reservoir pressure drops below the dew point pressure (DPP), a large amount of valuable condensate drops out and remains in the reservoir. Thus, prediction of accurate values for DPP is important and leads to successful development of gas condensate reservoirs. There are some experimental methods such as constant composition expansion (CCE) and constant volume depletion (CVD) for DPP measurement but difficulties in experimental measurement especially for lean retrograde gas condensate causes to develop of different empirical correlations and equations of state for DPP calculation. Equations of state and empirical correlations are developed for special and limited data sets and for unseen data sets they are not generalizable. To mitigate this problem, in this paper we developed new artificial neural network optimized by particle swarm optimization (ANN-PSO) for DPP prediction. Reservoir fluid composition, temperature and characteristics of the C7+ considered as input parameters to neural network and DPP as target parameter. Comparing results of the developed model in this research with Gaussian processes regression by particle swarm optimization (GPR-PSO), previous models and correlations shows that the predictive model is accurate and is generalizable to new unseen data sets.

Application of expert systems for accurate determination of dew-point pressure of gas condensate reservoirs

Dew-point pressure is a parameter that has a key role in development of gas condensate reservoirs. Dropping of reservoir pressure below the dew-point pressure results in a decrease in production because of near wellbore blockage. In addition, due to separation of liquids, the produced gas has fewer valuable components. This study tries to develop a dependable method based on machine learning to adequately predict this important parameter. The intelligent system used in this work is Radial Basis Function (RBF) network that is a very flexible tool for pattern recognition. This model was developed and tested using a total set of 562 experimental data point acquired from different retrograde gas condensate fluids covering a wide range of variables. To optimize the tuning parameters of the proposed model, genetic algorithm was incorporated. This study also presents a detailed comparison between the results predicted by the proposed RBF model and those of other universal empirical correlations and intelligent systems for estimation dew-point pressure. The results showed that the presented model is superior to the pervious classic correlations and also intelligent systems.

A New Method to Predict Water Breakthrough Time in an Edge Water Condensate Gas Reservoir Considering Retrograde Condensation

During the development of gas condensate reservoirs, condensate oil is separated as reservoir pressure drops to the dew point pressure. The prediction for water breakthrough time, the impact of precipitation of condensate oil, is usually ignored, which results in significant difference between prediction and realistic results. In order to better develop edge water condensate gas reservoirs and accurately predict the water breakthrough time, impact from condensate oil should be considered. Therefore, a new prediction formula of water breakthrough time is derived based on fluid flow in porous media considering impact of anti-condensate. A case study demonstrates that it is necessary to consider impact of condensate oil when predicting water breakthrough time. The new predicting formula provides theoretical basis for further research on edge water displacement mechanism as well as significant guidance for management of edge water gas condensate reservoirs.