D.H. Tehrani

Measurement and correlation of gas condensate relative permeability by the steady-state method

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 ratios (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.

The effect of velocity and interfacial tension on relative permeability of gas condensate fluids in the wellbore region

Abstract High-pressure core flood experiments using gas condensate fluids in long sandstone cores were conducted to determine the effect of flow rate and interfacial tension on relative permeability. The data are applicable to near wellbore flow in gas condensate reservoirs, because viscous forces increased over capillary forces during the tests. A relative permeability rate effect for both gas and condensate phases was observed when using steady-state and unsteady-state testing methods. The tests were repeated at increasing flow rates which showed that the relative permeability of both phases increased with the increase in flow rate. Increasing the value of interfacial tension between the phases reduced the relative permeability of the gas phase more than the condensate phase; but the relative permeability of both phases continued to increase at higher flow rates. The influence of core end-effects was shown to be negligible at the low IFT conditions used in the tests. The Reynolds number indicated that flow was within the laminar regime at all test conditions. The observed rate effect was contrary to that of the conventional non-Darcy flow where the effective permeability decreases with increasing flow rates. Relative permeability tests conducted with conventional gas oil fluids at similar test conditions did not exhibit any significant rate effects. This study is applicable to the vicinity of producing wells, where the rate effect on gas relative permeability can significantly affect well productivity.

Visualisation of Oil Recovery by Water Alternating Gas (WAG) Injection Using High Pressure Micromodels - Water-Wet System

The use of WAG (water alternating gas) injection can potentially lead to improved oil recovery compared to injection of either gas or water alone, however the physical process is not well understood. Using high pressure glass micromodels, a series of WAG tests have been conducted using equilibrated fluids, with high quality images of the oil recovery processes operating during alternate WAG cycles being recorded. The tests were conducted using both water-wet and oil-wet micromodels. In this paper results of a typical water-wet test is presented (results of the oil-wet and mixed wet tests will be presented in a subsequent paper). Water-wet micromodels were initially fully saturated with water and then displaced with oil to establish the connate water saturation. The micromodels were then flooded with water to observe the process of establishing the waterflood residual oil saturation (S orw ). Alternate cycles of gas and water injection were then conducted to observe three-phase flow and its associated oil recovery. The experiments were performed within the capillary dominated flow regime. The results highlighted the importance of corner filament flow of water in the recovery process, with the initial waterflood residual oil saturation being trapped mainly in the centre of the majority of pore space surrounded by layers of water, and not in only large pores. The successive WAG cycles redistributed the oil in a way which resulted in improved oil recovery, hence, the oil which otherwise would not have been mobile under either gas or water injection alone was mobilised and produced. It was identified that a limited number of WAG cycles were required to approach maximum oil recovery, after which additional recovery was minimal. All recovery processes were filmed and electronically stored using high resolution imaging, with oil recovery at the end of each flooding cycle being measured using image analysis techniques.

A Mechanistic Model of Gas-Condensate Flow in Pores

Recent experimental results reported in the literature indicate that the relative permeability of gas-condensate systems increases with rate (velocity) at some conditions. To gain a better understanding of the nature of the flow and the prevailing mechanisms resulting in such behaviour flow visualisation experiments have been performed, using high pressure micromodels. The observed flow behaviour at the pore level has been employed to develop a mechanistic model describing the coupled flow of gas and condensate phases. The results of the model simulating the observed simultaneous flow of gas and condensate phases have been compared with reported core experimental results. Most features of the reported rate effect are predictable by the developed single pore model, nevertheless, its extension to include multiple pore interaction is recommended.

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

Abstract 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.

Variations of gas/condensate relative permeability with production rate at near-wellbore conditions: a general correlation

It has been demonstrated, first by this laboratory and subsequently by other researchers, that the gas and condensate relative permeability can increase significantly by increasing rate contrary to the common understanding. There are now a number of correlations in the literature and commercial reservoir simulators accounting for the positive effect of coupling and the negative effect of inertia at near wellbore conditions. The available functional forms estimate the two effects separately and include a number of parameters, which should be determined using measurements at high velocity conditions. Measurements of gas-condensate relative permeability at simulated near wellbore conditions are very demanding and expensive. Intruduction The process of condensation around the wellbore in a gascondensate reservoir, when the pressure falls below the dew point, creates a region in which both gas and condensate phases flow. The flow behaviour in this region is controlled by the viscous, capillary and inertial forces. This along with

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.

Improving predictions of equation of state by modifying its parameters for super critical components of hydrocarbon reservoir fluids

The parameters of equations of state of van der Waals type have been generally correlated by matching the properties of pure substances, and extended to mixtures by employing mixing rules commonly with binary interaction parameters. It is proposed to use equilibrium data on binary systems to determine the attraction term in equations of state (EOS) for super critical components instead of data of pure substances. The proposed method was applied to the Peng-Robinson EOS, as an example, resulting in a significant improvement in predicting the phase behaviour of different types of fluids. As no binary interaction parameters are required in this method the computational requirement for flash calculations is drastically reduced for fluids with many components. The proposed method is particularly advantageous for predicting fluid phase equilibria in compositional reservoir simulators, where the reservoir fluid can be described with any desirable number of components without any significant increase in computational time.

A residual viscosity correlation for predicting the viscosity of petroleum reservoir fluids over wide ranges of pressure and temperature

Abstract The method of Lohrenz–Bray–Clark, which relates the residual viscosity to the reduced density, is the most widely used engineering tool to predict the viscosity of reservoir fluids. Systematic investigation of the viscosity of pure compounds at various pressure and temperature conditions indicated the requirement of including the structural and thermal effects for accurate viscosity prediction of dense fluids. The method has been modified to include the above-mentioned effects. Reliability of the modified method for calculating viscosity of mixtures and in particular of high-pressure high-temperature fluids has been demonstrated.

Oil Recovery by Near-Miscible SWAG Injection

Many of current oil reservoirs are approaching the end of their waterflooding life. At this stage a significant quantity of oil (40-60%) will still remain in the reservoir. It is known that using the Water- Alternating-Gas (WAG) injection some of that oil can be produced. The WAG scheme is a combination of two traditional techniques of improved hydrocarbon recovery: waterflooding and gas injection. In many reservoirs, injectivity during WAG cycles has been lower than expected. In many cases the low injectivity rates prolong injection time and play havoc with project economics. Therefore, injectivity loss is a crucial limiting factor in many projects involving WAG injection. In an example, the pre-WAG water injection rate of 286 m3/d (1800 BPD) was not pressure-limited, while after a couple of WAG cycles the gas and water injection rates were limited by pressure to about 160 and 130 m3/d (1000 and 800 BPD), respectively. Currently, there are no clear explanations of the factors influencing injectivity loss during WAG injection, nor methods available to mitigate this problem. In this paper we report results of an experimental study that was carried out to directly visualize the pore-scale events taking place during WAG injection in porous media. We show that, in the absence of other relevant causes, gas trapping causes relative permeability reduction and injectivity loss.