Critical Condensate Saturation Research Articles

A Double-Scale method for near-well flow in reservoir simulation

Simulation of near-well flow around a single well in reservoirs is normally studied using radial logarithmic grids. A promising method for more complicated, multi-well cases is a combined approach of using a Cartesian and a radial grid. In this paper, a new method of overlapping grids is introduced in which a radial grid is overlapped on a coarse Cartesian grid in the area around a well. Connectivity between the two grids is established using an appropriate boundary condition. Five different algorithms of grids connectivity with internal boundary conditions are presented in which the data are transferred between the grids by interpolation pressure and saturations in each grid. This method is implemented in the open-source Matlab Reservoir Simulation Toolbox (MRST) using the modified black-oil model. The proposed approach is validated by simulation of a reference fine radial grid model on a gas-condensate reservoir. Comparing the results with the reference model indicates that the proposed Double-Scale method using a 21 × 21 coarse Cartesian grid is as accurate as a 1001 × 1001 simple Cartesian fine grid model. Then, a double-layer numerical problem with two production wells was simulated and sensitivity analysis was conducted to investigate the effect of critical condensate saturation and vertical permeability. Finally, the second SPE comparative solution project was simulated to compare the performance of the proposed method with the use of the perpendicular bisector (PEBI) grids around the well. Results showed that the accuracy of the PEBI grid and Double-Scale method are comparable. However, the proposed Double-Scale method is almost 2 times faster in this specific problem. • The new Double-Scale method is implemented in MRST toolbox. • The accuracy of results highly increases by using the Double-Scale method. • This method reduces the CPU time of simulation significantly. • The gravity drainage can be seen by monitoring vertical permeability variation. • The second SPE comparative solution project was simulated by the Double-Scale method.

On the liquid condensate vertical migration near the production wells of gas-condensate reservoirs

Accumulation of liquids in gas-condensate reservoirs may lead to a vertical flow of liquid caused by density difference in the presence of gravity. In this paper, the effect of this vertical flow on the prediction of production data has been investigated. To achieve this goal, a single-layer synthetic cylindrical reservoir is considered and, the flows are simulated with and without vertical direction grid blocks with two lean and rich fluids. The governing equations of the so-called Modified Black-Oil (MBO) model are solved in a cylinder sector using the open-source Matlab Reservoir Simulation Toolbox (MRST). When the vertical flow is taken into consideration, the results show that gravity may lead to migration of liquid condensates to lower regions and the production rates decrease as a consequence of wellbore partially blockage especially for the rich fluid. In addition, gravity may cause a non-linear effect on the flow behavior and increase in the condensates production rates. All results are also obtained for three values of critical liquid condensate saturation to show the effect of this parameter on the production. It has been shown that neglecting the vertical flow may cause significant errors in the result of production, i.e. up to 25% when the fluid is rich and the critical condensate saturation is 0.15. To generalize the effect of the reservoir thickness, dimensional analysis is carried out which yields a similarity parameter. The findings of this study can help for a better understanding of near well flow in gas-condensate reservoirs. Based on this study, in applications in which the reservoir gas is rich in condensate and the thickness of the reservoir layer or the vertical permeability is high enough, it is recommended that the gravity effect is taken into account by enough grid points in the vertical direction in each layer.

Wettability alteration of reservoir rocks to gas wetting condition: A comparative study

AbstractProductivity of gas condensate reservoirs reduces significantly due to the near wellbore condensate/water blockage phenomenon. A novel, permanent solution to alleviate this problem is near wellbore wettability alteration of reservoir rocks to preferentially gas wetting conditions; industrial chemical materials are good candidates for this purpose, because of their eco‐friendly characteristics, economical price, and mass production. In this paper, a comparative study is conducted on two industrial fluorinated chemicals, MariSeal 800 and SurfaPore M. Static and dynamic contact angle measurements, spontaneous imbibition, and core flooding tests were conducted to investigate the effect of utilized chemical agents on surface wetting behaviour and fluid flow characteristics of rock samples. Contact angle measurements demonstrate that the liquid phase is changed to a non‐wetting phase after chemical treatment and MariSeal 800 has a greater potential to decrease the surface free energy of the calcite surface. Although both chemicals reveal great potential in static contact angle measurements, further experiments were conducted to distinguish between their abilities. Spontaneous air liquid imbibition tests and endpoint relative permeability measurements approved the potential of utilized chemicals to improve liquid phase mobility and decrease critical condensate saturation, which improve production parameters and reservoir productivity. Liquid phase endpoint relative permeabilities of sandstone core samples were improved by factors of 1.74 and 2.62; furthermore, irreducible liquid phase saturations were decreased by factors of 0.68 and 0.5 using MariSeal 800 and SurfaPore M chemicals. The results of this research help efficient selection of chemical agents for further field applications.

Numerical Determinationof Critical Condensate Saturation in Gas Condensate Reservoirs

Critical condensate saturation, Scc, is a key parameter for the evaluation of well deliverability in gas condensate reservoirs. We propose a new method to determine Scc by performing three-phase flow simulations with three-dimensional (3D) pore network model. First, we establish a network model with random fractal methodology. Second, based on the condensation model in the literature of Li and Firoozabadi, we develop a modified condensation model to describe the condensation phenomenon of gas with connate water in the porous medium. The numerical model is verified by experimental measurements in the literature. Then, we investigate the influence of different factors on the critical condensate saturation, including micro pore structure (pore radius and fractal dimension), condensate gas/oil interfacial tension (IFT), and flow rate at different irreducible water saturation, Swi. The simulation results show that Scc decreases with increasing of average pore radius, but increases with increasing of fractal dimension. In the case of the same gas/oil interfacial tension, the higher the connate water saturation, the higher the critical condensate saturation. There is a critical gas/oil interfacial tension, below the critical value, the critical condensate saturation increases drastically with increasing of interfacial tension while it keeps almost unchanged when the interfacial tension is above the critical value. The critical condensate saturation decreases with increasing in the gas flow rate. High capillary number results in low critical condensate saturation. Reasonable increase in producing pressure drop can effectively improve the flow capacity of condensate oil.

Sensitivity analysis and economic optimization studies of inverted five-spot gas cycling in gas condensate reservoir

Abstract Gas condensate reservoirs usually exhibit complex flow behaviors because of propagation response of pressure drop from the wellbore into the reservoir. When reservoir pressure drops below the dew point in two phase flow of gas and condensate, the accumulation of large condensate amount occurs in the gas condensate reservoirs. Usually, the saturation of condensate accumulation in volumetric gas condensate reservoirs is lower than the critical condensate saturation that causes trapping of large amount of condensate in reservoir pores. Trapped condensate often is lost due to condensate accumulation-condensate blockage courtesy of high molecular weight, heavy condensate residue. Recovering lost condensate most economically and optimally has always been a challenging goal. Thus, gas cycling is applied to alleviate such a drastic loss in resources. In gas injection, the flooding pattern, injection timing and injection duration are key parameters to study an efficient EOR scenario in order to recover lost condensate. This work contains sensitivity analysis on different parameters to generate an accurate investigation about the effects on performance of different injection scenarios in homogeneous gas condensate system. In this paper, starting time of gas cycling and injection period are the parameters used to influence condensate recovery of a five-spot well pattern which has an injection pressure constraint of 3000 psi and production wells are constraint at 500 psi min. BHP. Starting injection times of 1 month, 4 months and 9 months after natural depletion areapplied in the first study. The second study is conducted by varying injection duration. Three durations are selected: 100 days, 400 days and 900 days. In miscible gas injection, miscibility and vaporization of condensate by injected gas is more efficient mechanism for condensate recovery. From this study, it is proven that the application of gas cycling on five-spot well pattern greatly enhances condensate recovery preventing financial, economic and resource loss that previously occurred.

Study of production enhancement through wettability alteration in a super-giant gas-condensate reservoir

Near wellbore condensate blockage phenomena commonly reduce gas production significantly. One efficient method for overcoming such problem is wettability alteration. Such issues as wettability state, treatment radius and time to reach the maximum level of production need be optimized prior to field application. In this paper, impact of these parameters are studied on gas and condensate production enhancement through wettability alteration. To do this, behavior of a well located in supergiant offshore Iranian gas condensate field is simulated and analyzed using a compositional model, single well and radial grid. The real fluid and reservoir properties of the studied well are utilized to construct the model. Different wettability states were defined using various relative permeability curves at various distances from the wellbore along with different treatment times are tested to find the best condition. Results indicate that near-wellbore wettability alteration leads to lower critical condensate saturation which has a significant impact on improving production parameters and reservoir recovery factors. Also, the highest recovery factor is achieved at optimal conditions where wettability is altered from strong liquid-wet to intermediate-wet at the small radius around the production well in early times. Furthermore, the inflow performance relationship curve (IPR) moves upward considerably which represents the magnificent production improvement.

Experimental Research of Critical Condensate Saturation and Flow Characteristics of Gas Condensate Reservoir

The critical condensate saturation is a key parameter to reflect condensate flow capacity. The authors propose an experimental method to determine the critical condensate saturation and analyze the flow characteristics of gas condensate by coreflooding and chromatography. Using this method, they perform two sets of experiments with real-core of a gas condensate reservoir and a binary mixture fluid of methane and n-pentane under 84°C. Experimental results show that the critical condensate saturation is 3.04% and 4.66% when irreducible water saturation is 40% and 27%, respectively. The results also indicate porous media will raise the dew point pressure. The irreducible water and capillary number effect is conducive to the flow of condensate. Based on experimental researches, the authors theoretically analyze the distribution and mobilization characteristics of condensate. Although critical condensate saturation is low, it doesn't mean the condensate will be able to flow freely when it achieves the value, and condensate saturation will continue to increase. Compositional simulation is performed to demonstrate that the critical condensate saturation is low, which is important for the high effective development of a gas condensate reservoir.

Two-Phase Flow in Volatile Oil Reservoir Using Two-Phase Pseudo-Pressure Well Test Method

Abstract When the bottomhole pressure (BHP) of volatile oil reservoirs falls below the bubblepoint pressure, two phases are created in the region around the wellbore, and a single phase (oil) appears in regions away from the well. The oil relative permeability reduces towards the near-wellbore region due to increasing gas saturation. This behaviour is quite similar to a gas-condensate reservoir below the dew-point, where the gas relative permeability is reduced due to the existence of a liquid bank around the wellbore. There are numerous publications in the literature concerning the behaviour diagnostic and well deliverability calculation in the case of gas-condensate reservoirs. However, the behaviour of volatile oil reservoirs is not well understood. This paper aims at understanding the behaviour of volatile oil reservoirs. We used reservoir compositional simulations to predict the fluid behaviour below the bubblepoint, and then exported the flowing bottomhole pressure to a well test package to diagnose the existence of different mobility regions. In this study, the applicability of the two-phase pseudo-pressure method on volatile and highly volatile oil reservoirs was investigated, and it was found that this method is a very powerful tool for the prediction of true permeability and mechanical skin. Also, this method is capable of distinguishing between mechanical skin and condensate bank skin, which can be very helpful for designing after-drilling well treatment and IOR process designs. Introduction In gas-condensate reservoirs, retrograde condensation occurs when the flowing bottomhole pressure declines below the dew-point pressure, creating four regions in the reservoir with different liquid saturations. Away from the well, an outer region has the initial liquid and gas saturation. Next, nearer the well, there is a rapid increase in liquid saturation and a decrease in the gas mobility where the liquid still is immobile. Closer to the well, an inner region is formed where liquid saturation is higher than the critical condensate saturation and both oil and gas phases are mobile. Finally, in the immediate vicinity of the well, there is a region with a lower liquid saturation due to capillary number (the ratio of viscous to capillary forces) effects. Such a region has been inferred from a number of experimental core studies at low interfacial tension and high flow rates. The existence of the fourth region is important because it counters the reduction in productivity caused by liquid drop-out. The various mobility zones described above can be identified by well test analysis, using a variety of analytical and numerical models(1–3). Well test analysis is now commonly used to identify and quantify near-wellbore effects, reservoir behaviour (i.e. zones of different mobilities and storativities) and reservoir boundaries. Finding all of this information from well tests in gas-condensate reservoirs, however, is challenging. This is due to changes in the composition of the original reservoir fluid and the impact of wellbore dynamics. Nonetheless, gas-condensate flow behaviour is now reasonably well understood.

Gas Condensate Reservoir Performance

Abstract Gas condensate reservoirs exhibit complex coupling between phase behaviour, interfacial tension, velocity and pore size distribution. Appropriate characterization of the in situ fluids and relevant flow testing can provide valuable insight into gas condensate reservoir forecasting. The following insights were obtained during the course of this testing:The importance of path dependence was shown to be significant when creating equilibrium phases below saturation pressure for use in quantifying phase interference. Differences, due to compositional path, in API gravity of liquids in solution were quantified to be as much as 10 degrees, with molecular weight differences over 110 daltons.End-point saturations, such as trapped gas and residual condensate saturation, are sensitive to the level of interfacial tension (IFT). Critical condensate saturation was less sensitive to IFT (pressure).The two-phase injection approach and the protocol whereby explicit measurement of relative permeability is performed provide a very thorough gas-condensate reservoir data set, which are amenable for use in simulation and reservoir production forecasting. Background This paper discusses performance of gas condensate reservoirs. These reservoirs have a reservoir temperature located between the critical point and the cricondentherm on the reservoir fluid's pressure-temperature diagram. This is the only unique and accurate means of identifying gas condensate reservoirs; any other definition [condensate-gas ratio, C7+ molecular weight (MW) or C7+ API gravity] is specious and ersatz. In these reservoirs, as the pressure drops, vapour and liquid phases result. Capillary pressure causes phase interference which usually reduces gas productivity. A cross-section of interesting topics that show the complexities of gas-condensate reservoir production have been reported in the literature(1–7). All of the relevant parameters, if well understood, will lead to more accurate evaluation of the amount of hydrocarbon in place, the rate at which the resource can be produced and the optimization strategies as the reservoir matures. Introduction In this paper, retrograde condensate characterization and properties measurement, explicit relative permeability and two-phase dynamic steady-state measurements are discussed. Not withstanding the very specific nature of this paper in quantifying phase behaviour-fluid flow coupling in the laboratory, it was considered important to provide a short commentary on sampling of gas condensate fluids that form the foundation on which experimental gas condensate testing is built. Extensive treatment of this theme was beyond the scope of the current paper. Retrograde Condensate Sampling The bottomhole flowing pressure (PBHF) must be lower than reservoir pressure to induce flow. If the PBHF is less than dew point pressure then liquids drop out in the porous media around the production well. The gas is much more mobile than the condensate and, therefore, the gas-condensate ratios (GCR) exhibited at surface are commonly higher than that of the reservoir fluid. A further complication of this problem is that the composition of the surface liquid also changes. When the PBHF is above dew point, the MW of the surface liquid is the highest. Figure 1 shows the change in composition incident to decreasing bottomhole pressure.

Long-Term Performance of Hydraulically Fractured Layered Rich Gas Condensate Reservoir

Compositional simulator has been used to investigate the effect of hydraulic fracture on the performance of a layered rich gas condensate reservoir in Saudi Arabia. The reservoir consists of five layers having permeabilities ranging from 0.08 to 115 md with about 68% of the gas reserve located in the lowest permeability layer. The fracture is assumed to penetrate all layers. The results of this investigation showed that hydraulic fracturing of such a reservoir is effective in improving the productivity of the gas condensate wells. The productivity index (PI) of the cases investigated was found to increase by as much as 3.6 folds. Hydraulic fractures were also found to delay the onset of the dew point pressure and consequently extend the production plateau above the dew point pressure. The production plateau above the dew point pressure was found to increase with increasing the dimensionless fracture conductivity. The results of this study also showed that once the dew point pressure is reached, the flowing bottom hole pressure was found to drop sharply to the specified minimum flowing bottom hole pressure in the fractured and nonfractured cases. However, the drop is less severe in the fractured case. This sharp drop in the flowing bottom hole pressure results in dropping the productivity of the gas condensate wells. Condensate build up along the fracture faces was found to be more significant in the high permeability layers. At early times after reaching the dew point pressure, the highest condensate saturation was found to be in the highest permeability layer. However, at late times (after reaching pseudo steady state) it decreased to a certain level above the critical condensate saturation. Finally, formation cross-flow is found to improve the productivity of the fractured and the nonfractured gas condensate wells. However, the improvement is more pronounced in the fractured cases.

Phenomenological Modeling of Critical Condensate Saturation and Relative Permeabilities in Gas/ Condensate Systems

Summary The effects of gravity, viscous forces, interfacial tension, and wettability on the critical condensate saturation and relative permeability of gas condensate systems are studied using a phenomenological simple network model. The results from the simple model show that wettability significantly affects both critical condensate saturation and relative permeability. Relative permeability at some saturations may increase significantly as the contact angle is altered from 0° (strongly liquid-wet) to 85° (intermediately gas-wet). The results suggest that gas well deliverability in condensate reservoirs can be enhanced by wettability alteration near the wellbore.

Determination of Relative Permeability and Recovery for North Sea Gas-Condensate Reservoirs

Summary Coreflood experiments on gas condensate flow behavior were conducted for two North Sea gas condensate reservoirs. The objectives were to investigate the effects of rock and fluid characteristics on critical condensate saturation (CCS), gas and condensate relative permeabilities, hydrocarbon recovery and trapping by water injection, and incremental recovery by subsequent blowdown. Both CCS and relative permeability were sensitive to flow rate and interfacial tension. The results on gas relative permeability rate sensitivity suggest that gas productivity curtailed by condensate dropout can be somewhat restored by increasing production rate. High interfacial tension ultimately caused condensate relative permeability to decrease with increasing condensate saturation. Condensate immobile under gas injection could be recovered by water injection, but more immediate and efficient condensate recovery was observed when the condensate saturation prior to water injection exceeded the CCS. Subsequent blowdown recovered additional gas, but incremental condensate recovery was insignificant.

Compositional Numerical Modelling In Naturally Fractured Reservoirs

Abstract Recent improvements in the. speed. of numerical compositional simulators has made it possible to use a large number of grid blocks to model condensate reservoirs, volatile reservoirs, and gas injection projects. This paper discusses techniques for choosing pseudo components so as to use four to five pseudo components for the simulations. It also discusses the condensate dropout in the reservoir and its effect on the productivity of individual producing wells. The methods for characterizing fracture networks in a naturally fractured reservoir are presented and other parameters which affect hydrocarbon recovery are discussed as part of a parametric study. Introduction In recent years wells have been drilled to greater depths, resulting in the discovery of gas condensate reservoirs and volatile oil reservoirs at relatively high temperatures. A large amount of research has been conducted to investigate productivity from these oil reservoirs. This research has investigated how to tune an equation of state so as to match the actual phase behaviour which is occurring within a reservoir. Studies have reported on the effects of interfacial tension and velocity on gas-oil relative permeability curves. These studies indicate that bench type gas-oil and water-oil relative permeabilities are not applicable to predicting the performance of individual wells in gas condensate reservoirs. Well test data and recent advances in well logging procedures using well-bore imaging techniques have provided tools to better characterize the fracture system which exists in naturally fractured reservoirs. These data have been used in conjunction with stochastic models to describe the fracture network inside of these reservoirs. A parametric study using a number of variables was conducted for this paper. The results from this parametric study are useful in history matching to determine those parameters which, when adjusted, will have the greatest effect on the performance of the reservoir. This study will also suggest modifications which need to be made to numerical simulators so as to better simulate the actual mechanism which are occurring in gas condensate reservoirs. Mechanism of Flow in Naturally Fractured Reservoirs Fluid flow in naturally fractured reservoirs differs significantly from that in a single porosity system. The numerical simulator breaks the reservoir into two different systems: one, a system of matrix blocks which mayor may not have capillary contact and the other, a network of fractures. The simulation assumes that most of the flow to the wells will occur through the fracture network which contains a relatively small fluid volume, but high permeability, and that the bulk of the hydrocarbon fluids are contained within the matrix blocks. As reservoir pressure is depleted, the fluids are expelled from the blocks into the fracture system, which conveys them to the producing wells. Gas condensate reservoirs initially are at pressures at or above the dewpoint. Once the pressure has been depleted below the dewpoint, liquid will condense and two phases will be present. When these two phases are present the liquid will not flow in either the matrix or the fracture system until a critical condensate saturation is obtained.

Critical Condensate Saturation in Porous Media

The understanding of gas and condensate flow in porous media is critical to the optimum exploitation of gas–condensate reservoirs. Critical condensate saturation and relative permeabilities are the key parameters for the evaluation of possible recovery strategies. This work is aimed at developing a mechanistic network model for the critical condensate saturation in which phase trapping and connectivity in the pore corners are critically examined. Porous media are modeled by networks of pore bodies interconnected by pore throats. Bodies and throats are characterized by their connectivity, shapes, and radii distributions. Pore-level laws are identified from micromodel experiments with near-critical fluids. A nonzero critical condensate saturation can be obtained in the absence of contact angle hysteresis due to the converging–diverging nature of the throats. The critical saturation at which the condensate flows is found to be a function of pore geometry, water saturation, and interfacial tension (or the Bond number). The modified sphere-pack model underpredicts the critical condensate saturation of typical sandstones. The cubic model adequately predicts the critical saturation and its experimentally observed trends.

Experimental Investigation of Critical Condensate Saturation and Its Dependence on Interstitial Water Saturation in Water-Wet Rocks

SummaryAn experimental investigation of retrograde condensation in water-wet pores was conducted in micromodels and long cores to determine the critical condensate saturation and to evaluate the significance of interstitial water on condensate mobility. Although the interstitial water lowered the critical condensate saturation, it also could reduce the initial recovery rate by restricting condensate drainage.

Determination of Gas-Condensate Relative Permeability on Whole Cores Under Reservoir Conditions

SummaryRock samples from a Middle East carbonate retrograde condensate gas field were studied to determine their relative permeability to gas and condensate curves. We have emphasized the determination of condensate minimum flowing saturation—or critical condensate saturation—and the reduction of permeability to gas in the presence of immobile condensate saturation.A ternary pseudoreservoir fluid of methane/pentane/nonane made it possible to work in simulated reservoir conditions with a greater flexibility for experimental procedures. The initial water saturation equaling that in the reservoir was restored. The results of the gas-condensate system indicate that the critical condensate saturations are high (the average value is 36% PV) and that the reduction of permeability to gas is higher than for a standard gas/oil system. Also presented are the details of the experimental procedures, the fluid characteristics, the results, and a discussion.