Gas Condensate Relative Permeability Research Articles

A new correlation for relative permeability in gas-condensate reservoirs

Gas-condensate flow around the wellbore is quite different from conventional gas oil flow. This is mainly due to complicated velocity effects on relative permeability in these very low interfacial tension systems. In the current study, it has been proposed that the desirable velocity effect on gas-condensate relative permeability is the result of inertial force. Having said that, inertial number, which is the ratio of inertial force over capillary force, could be a better candidate compared to capillary number when somebody deals with the modeling of gas-condensate relative permeability. A generalized correlation was obtained for gas-condensate relative permeability with applying this new approach. The results are promising. This approach is not only needs less core data, but also it is much simpler and even more accurate compared to previously developed equations using capillary number.

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ABSTRACT In this paper the optimal gas flow rate in a retrograde gas condensate reservoir has been calculated in order to minimize retrograde condensation, maximizing the slip velocity, due to the positive coupling effect; and minimizing the pressure drawdown, due to the Forchheimer effect (non-Darcy effect, inertial effect). Non-Darcy behavior has been thoroughly described because of its importance for describing additional pressure drawdown (more than expected by Darcy equation) in fluid flow in porous media, in situations where high velocity occurs. The coupling effect explains the increment of the gas-condensate relative permeability with increasing velocity and decreasing the interfacial tension. The Forchheimer equation has been used to calculate the bottom-hole flowing pressure for different gas flow rates. Because of the second term in the Forchheimer equation, which is function of the square of the superficial velocity of the fluid, this obtained value is less than the bottom-hole flowing pressure obtained from Darcy equation. This is important because a higher quantity of condensate liquids is obtained, which reduces the relative permeability, and as a result, the gas flow rate decreases due to this effect. For those different gas flow rates, the optimal gas flow rate, where the bottom-hole flowing pressure is acceptable, has been found. The novelty of the present work, is to present the optimal point where the gas flow rate is maximum, in which the non-Darcy effect is negligible. Keywords: Forchheimer effect, Coupling effect, Gas Condensate Reservoir

Identification and selection of a stable gel polymer to control or reduce water production in gas condensate fields

The existence of water in hydrocarbon reservoirs damages the wells. In many cases, it leads to shut off the wells and decreases the gas production efficiency. For example, one of the problems of fractured gas wells is unwanted water invasion to gas production areas through the existing fracture in the reservoirs. This would increase the water production and decrease the gas production efficiency. As well, increasing of water/gas production ratio will increase the total operational costs due to water separation from the gas flow, corrosion of inside and outside well facilities and hydrate formation. Hence, prevention of water production in gas wells can boost the gas production economy. Generally, some mechanical and chemical methods exist to control unwanted water. One of the most effective methods to control and prevent of water production in hydrocarbon reservoirs is gel polymer method. The gel polymer is a chemical method with high efficiency and low cost. This work is concerned with producing a stable and suitable gel polymer (HPAM–Cr (III) gel system) to control and remove water in the gas condensate fields. The important parameters in the gel construction such as the polymer and cross-linker concentrations, pH of solution and also the effect of different additives have been examined and optimized at four temperatures of 30, 60, 80 and 100 °C. The effect of gel polymer on the absolute and relative permeabilities of two different cores for water and gas condensate fluids has been investigated. The results show that prepared gel polymer results in decreasing the water relative permeability, while increases the gas condensate relative permeability.

A generalized correlation for predicting gas–condensate relative permeability at near wellbore conditions

It is a well established finding, both experimentally and theoretically that relative permeability ( k r) of gas–condensate systems at low interfacial tension (IFT) depends on velocity and IFT. There are a number of correlations available both in the literature and commercial reservoir simulators that account for the coupling (i.e., the increase of k r as velocity increases and/or IFT decreases) and inertial (i.e., the reduction of k r as velocity increases) effects at near wellbore conditions. These functional forms, which with the exception of Whitson et al. (Whitson, C.H., Fevang, O., Saevareid, A., Oct. 1999. Gas condensate relative permeability for well calculations, SPE 56476. Proc. of SPE Annual Technical Conference and Exhibition Texas) are based on saturation, estimate the two effects separately and include a number of parameters, which should be determined by cumbersome and expensive k r measurements at low IFT and high velocity conditions. We have previously reported the development of a fractional flow based correlation (Jamiolahmady, M., Danesh, A., Henderson, G.D. and Tehrani, D.H., Dec. 2006. Variations of gas–condensate relative permeability with production rate at near wellbore conditions: a general correlation, SPE Reserv. Eng. Evalu. J., 9 (6), pp. 688–697), which expressed the combined effect of coupling and inertia simultaneously, but its dependency on fluid viscosity limited its use to the range of IFT values studied. In this paper we present a generalized correlation based on relative-permeability-ratio, which is closely related to a fractional flow of gas and condensate. The parameters of the new correlation are either universal, applicable to all types of rocks, or can be determined from commonly measured petrophysical data. The performance of the correlation has been evaluated over a relatively wide range of IFT and velocity variations. This has been conducted by comparing its prediction with the gas–condensate relative permeability values measured on porous media with very different characteristics. These data had not been used in developing the correlation. The results are quite satisfactory confirming the generality of the correlation in providing reliable information on gas–condensate relative permeability values for near wellbore conditions.

Application of X-ray Scanner in Measurement of Gas Condensate Relative Permeability Using Steady-State Method

An experimental set-up has been built to measure gas condensate relative permeability using the steady-state method. The set-up is equipped with a recirculating closed system for circulating equilibrated gas and liquid condensate at the desired IFT level. The equilibrated gas and condensate liquid are generated in situ at the desired pressure. The experimental set-up is integrated with an x-ray scanner for measurement of liquid condensate saturation along the core sample at each fractional flow during the measurement of gas condensate relative permeability. This article presents a description of the experimental set-up and its features, the procedure developed, and the results demonstrating the usefulness of the x-ray scanner in measurements of gas condensate steady-state relative permeability. The measured gas condensate relative permeability test was repeated at the same condition and found to be having excellent repeatability.

Positive Effect of Flow Velocity on Gas-Condensate Relative Permeability: Network Modelling and Comparison with Experimental Results

Positive velocity dependency of relative permeability of gas–condensate systems, which has been observed in many different core experiments, is now well acknowledged. The above behaviour, which is due to two-phase flow coupling in condensing systems at low interfacial tension (IFT) conditions, was simulated using a 3D pore network model. The steady-dynamic bond network model developed for this purpose was also equipped with a novel anchoring technique, which was based on the equivalent hydraulic length concept adopted from fluid flow through pipes. The available rock data on the co-ordination number, capillary pressure, absolute permeability, porosity and one set of measured relative permeability curves were utilised to anchor the capillary, volumetric and flow characteristics of the constructed network model to those properties of the real core sample. Then the model was used to predict the effective permeability values at other IFT and velocity levels. There is a reasonable quantitative agreement between the predicted and measured relative permeability values affected by the coupling rate effect.

Gas Condensate Relative Permeability for Well Calculations

This paper addresses several issues related to the modeling and experimental design of relative permeabilities used for simulating gas condensate well deliverability. Based on the properties of compositional flow equations, we make use of the fact that relative permeability ratio krg/kro is a purely thermodynamic variable, replacing saturation, when flow is steady-state. The key relation defining steady-state flow in gas condensate wells is relative permeability krg as a function of krg/kro. Consequently, determination of saturation and kr as a function of saturation is not important for this specific calculation. Once the krg=f(krg/kro) relationship is experimentally established and correlated with capillary number (Nc), accurate modeling of condensate blockage is possible. A generalized model is developed for relative permeability as the function of krg/kro and capillary number. This model enables us to link the ‘immiscible’ or ‘rock’ curves with ‘miscible’ or 'straight-line’ curves by a transition function dependent on the capillary number. This model is also extended to the case of high-rate, inertial gas flow within the steady-state condensate blockage regionand locally at the wellbore. We have paid particular attention to the effect of hysteresis on the relation krg=f(krg/kro), based on our observation that many repeated cycles of partial/complete imbibition and drainage occur in the near-well region during the life of a gas condensate well. Finally, the composite effect of condensate blockage is handled using a ‘Muskat’ pseudopressure model, where relative permeabilities are corrected for the positive effect of capillary number dependence and the negative effect of inertial high velocity flow. Special steady-state experimental procedures have been developed to measure krg as a function of krg/kro and Nc. Saturations, though they can be measured, are not necessary. An approach for fitting steady-state gas condensate relative permeability data has been developed and used for modeling relative permeability curves.

Retrograde Condensate Dropout Phenomena in Rich Gas Reservoirs-Impact on Recoverable Reserves, Permeability, Diagnosis, and Stimulation Techniques

Abstract Gas condensate reservoirs exhibiting classic "dew point" or retrograde condensate dropout behaviour exist in many areas in the world. These reservoirs are unique in that, as the reservoir pressure is decreased, a certain volume of the heavy end fraction of the gas is precipitated in liquid form from solution in the gas. This condensate liquid may be temporarily or permanently trapped in the reservoir, causing severe reductions in gas production rates and the permanent loss of a large portion of the volatile and valuable condensate liquids (due to capillary pressure- induced trapping effects in the porous media). This paper reviews the basic theory of gas condensate dropout and describes, in detail, damage problems that may be associated with production of reservoirs of this type. Techniques for mitigating condensate dropout problems on a production basis, as well as stimulation techniques such as repressurization, lean and rich gas injection, surfactant and solvent injection, in situ combustion and water/gas injection, are reviewed, and the advantages and disadvantages of the techniques discussed. Introduction Rich gas or retrograde condensate gas reservoirs are common on a worldwide basis. Figure 1 provides a pressure-composition diagram for a typical hydrocarbon system at a fixed temperature level. The shaded portion of this figure represents an area of two-phase equilibrium at the specified composition and pressure condition. This is generally a region where an immiscible hydrocarbon liquid and gas phase co-exist in thermodynamic equilibrium. Outside this area is a single phase region, where only one continuous and homogeneous uniform phase exists. Potential Problems Associated with Rich Gas Condensate Systems There are two main categories of problems commonly associated with rich gas reservoir systems:Formation damage effects associated with the condensate dropout.Permanent loss of valuable light condensate liquids due to trapping effects in the reservoir. This paper addresses both of these issues and various techniques that can be used to reduce their impact on productivity and recovery. Formation Damage Issues in Gas Condensate Reservoirs The literature is replete with detailed discussions on formation damage(1–8). This paper does not address different types of damage which can occur during conventional drilling, completion and production operations, but concentrates solely on issues associated with condensate liquid dropout. The primary damage mechanism resulting in a reduction in gas production rate in a rich gas-condensate reservoir is generally associated with capillary pressure-motivated phase trapping effects. These effects result in permanent reduction in the effective permeability to gas in the region affected by the condensate dropout surrounding the wellbore. This phenomenon is illustrated pictorially in Figure 2 and using a set of gas-condensate relative permeability curves in Figure 3. As the condensate drops from solution in the gas while still in the porous media, capillary pressure effects are present [due to the generation of a second immiscible phase which has a finite interfacial tension (IFT) between it and the gas phase].

Effect of Positive Rate Sensitivity and Inertia on Gas Condensate Permeability at High Velocity

The authors have previously reported that gas condensate relative permeability will increase with increasing velocity when conducting steady-state measurements. The increase in relative permeability was referred to as ‘positive rate sensitivity’ or the ‘positive coupling effect’. A systematic series of core tests has since been conducted, generating data at IFT values ranging from 0.015 to 0.78 mN m −1 , using core types ranging in permeability from 11 to 350 mD. The results confirmed that the positive coupling effect existed in low permeability cores and different lithologies at low and high IFT. The maximum tested velocity was in the region of 75 m per day, which was estimated to be at the boundary above which inertia would be significant. To investigate the competition between inertia and the positive coupling effect, subsequent core tests have been conducted at velocities ranging from 7 to 700 m per day, with the higher velocity being in the region of fractions of a metre from the wellbore. The maximum test velocity was one order of magnitude above the velocity boundary with significant inertia. The test programme has generated previously unpublished data, showing that the positive coupling effect initially reduces the effect of inertia before becoming dominant in the core tests conducted using gas condensate fluids. Such unique data provide valuable information on the forces governing production at the wellbore to reservoir engineers.

Generating reliable gas condensate relative permeability data used to develop a correlation with capillary number

The authors have previously reported that steady-state relative permeability measurements conducted using condensing fluids will result in relative permeability increasing with increasing velocity. The techniques used, however, can be experimentally demanding, as individual steady-state points are measured and the initial condensate saturation in the core is established by condensation. If the data representative of the flow of condensing fluids could be generated using unsteady-state procedures and conventional gas–oil fluids, as has been suggested in literature, then the duration and cost of the tests would be greatly reduced. To investigate the applicability of conventional techniques to flow in gas condensate systems, a series of tests were conducted using conventional and condensing fluids. For each set of tests, the interfacial tension (IFT) and flow rate were the same, with the only variables being the measurement of steady-state relative permeability when using condensing fluids, and the measurement of unsteady-state relative permeability when using conventional fluids. The main areas of interest were hysteresis in the relative permeability curves between imbibition and drainage, and the degree of relative permeability rate sensitivity. It was demonstrated in this study that conventional methods could produce erroneous results when applied to condensing fluids. The steady-state gas condensate rate sensitive relative permeability data has been used to formulate a new correlation that relates gas and condensate relative permeability to capillary number (the ratio of viscous to capillary forces). The correlation incorporates two major parts, with exponents and coefficients that appear in the correlation being determined by regression of the steady state relative permeability data. Comparisons between the measured and predicted relative permeability curves show a good agreement. The study highlights the need to use condensing fluids when measuring gas condensate relative permeability.

Measurement and Correlation of Gas Condensate Relative Permeability by the Steady-State Method

SummaryHigh-pressure core flood experiments using gas condensate fluids in long sandstone cores have been conducted. Steady-state relative permeability points were measured over a wide range of condensate-to-gas ratios (CGR; volume of condensate per unit volume of gas, both at test pressure and temperature), and the velocity and interfacial tension (IFT) were varied between tests to observe the effect on relative permeability. The experimental procedures ensured that the fluid distribution in the cores was representative of gas condensate reservoirs. Hysteresis between drainage and imbibition during the steady-state measurements also was investigated, as was the repeatability of the data.A relative permeability rate effect for both gas and condensate phases was observed, with the relative permeability of both phases increasing with an increase in flow rate. The relative-permeability-rate effect was still evident as the IFT increased by an order of magnitude. The influence of end effects was shown to be negligible under the IFT conditions used in the tests, with the Reynolds number indicating that flow was well within the so-called laminar regime under all test conditions. The observed rate effect was contrary to that of conventional non-Darcy flow, where the effective permeability should decrease with increasing flow rate. A generalized correlation between relative permeability, velocity, and IFT has been proposed.The results highlight the need for appropriate experimental methods and relative permeability relations where the distribution of the phases are representative of those in gas condensate reservoirs.

Measurement and Correlation of Gas Condensate Relative Permeability by the Steady-State Method

Abstract High pressure core flood experiments using gas condensate fluids in long sandstone cores have been conducted. Steady-state relative permeability points were measured over a wide range of condensate to gas ratio's (CGR), with the velocity and interfacial tension (IFT) being varied between tests in order to observe the effect on relative permeability. The experimental procedures ensured that the fluid distribution in the cores was representative of gas condensate reservoirs. Hysteresis between drainage and imbibition during the steady-state measurements was also investigated, as was the repeatability of the data. A relative permeability rate effect for both gas and condensate phases was observed, with the relative permeability of both phases increasing with an increase in flow rate. The relative permeability rate effect was still evident as the IFT increased by an order of magnitude, with the relative permeability of the gas phase reducing more than the condensate phase. The influence of end effects was shown to be negligible at the IFT conditions used in the tests, with the Reynolds number indicating that flow was well within the so called laminar regime at all test conditions. The observed rate effect was contrary to that of the conventional non-Darcy flow where the effective permeability should decrease with increasing flow rate. A generalised correlation between relative permeability, velocity and IFT has been proposed, which should be more appropriate for condensing fluids than the conventional correlation. The results highlight the need for appropriate experimental methods and relative permeability relations where the distribution of the phases are representative of those in gas condensate reservoirs. This study will be particularly applicable to the vicinity of producing wells, where the rate effect on gas relative permeability can significantly affect well productivity. The findings provide previously unreported data on relative permeability and recovery of gas condensate fluids at realistic conditions.

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.