Graeme D Henderson

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.

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.

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

An 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

Pore-level visual investigation of miscible and immiscible displacements

Abstract The mechanisms of oil recovery by gas injection, with particular interest in the generation of highly viscous oil residues and asphaltene flocculation and the resulting permeability impairment, have been studied. The flow visualisation experiments were performed in high pressure heterogeneous micromodels reproduced from real rock micrographs. The visual micromodels were also employed in series with a compatible glass bead pack. Displacement experiments simulating secondary and tertiary recovery of a North Sea crude oil at 27.5 MPa and 33°C were conducted. Methane, propane and water were injected. The displacement video observations and the measurements made are presented. The pore-level investigation of immiscible gas drive revealed the importance of wettability and capillary pressure on the spontaneous movements of the fluid interfaces. Fractions of pores occupied by oil become oil-wet. Thin films of oil on these segments keep the oil phase continuous and results in the flow and recovery of oil trapped in narrow sections of the pores, even at very low capillary numbers. Further observations on oil, gas and connate water movements are also presented. Miscible displacement of oil with propane did not induce any significant precipitation of asphaltenes in pores. However, bulk mixing of propane and oil can promote asphaltenes flocculation, pore plugging and permeability impairment. The deposited materials can be partially dissolved and removed by contacting with fresh oil.

The Effect of Velocity and Interfacial Tension on the Relative Permeability of Gas Condensate Fluids in the Wellbore Region

High pressure core flood experiments using gas condensate fluids in long sandstone cores have been conducted to determine the effect of flow rate and interfacial tension (IFT) on relative permeability. The experimental data are intended to be applied to near wellbore flow in gas condensate reservoirs, as viscous forces increase over capillary during the course of the tests.

An experimental investigation of waterflooding of gas condensate reservoirs and their subsequent blowdown

Abstract The phase and flow behaviour of water, gas and condensate in pores at reservoir conditions have been visually investigated using glass micromodels, with the pore dimensions and pore geometry of the micromodels being varied between tests. The displacement of hydrocarbons, both above and below the dewpoint, by the advancing water was studied. The model at residual hydrocarbon saturation was depleted and the remobilisation behaviour of the trapped gas-condensate phases was investigated. Preliminary core-flooding results obtained at conditions similar to the micromodel tests confirm the observed phenomena. The micromodel investigations has enabled the mechanisms of water encroachment in gas-condensate reservoirs to be visualised at pressures above and below dewpoint, and has highlighted the differences between flow in this system and the more conventional three-phase flow processes. The continuity of condensate throughout the pore space results in its efficient displacement ahead of encroaching water. Condesate recovery is strongly affected by the rate of advancing water and the distribution of condensate in the pores, with the residual gas-condensate saturation being dependant on the water advancement rate and degree of pore heterogeneity. The extent of the isolation of residual gas-condensate pockets in pores determines the increase in residual hydrocarbon saturation required for gas remobilisation by depletion. This paper explains some ambiguities in the residual hydrocarbon and its remobilisation as recently reported in literature, and the results should assist in improving our understanding of gas-condensate recovery and hence in the management of gas-condensate reservoirs.

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 the presence of condensate in all the pores dictate a flow mechanism that is different to that of gas-oil and also gascondensate in the bulk of the reservoir. Accurate determination of gas-condensate relative permeability (kr) values, which is very important in well deliverability estimates, is a major challenge and requires a different approach compared to that for conventional gas-oil systems. It has been widely accepted that relative permeability (kr) values at low values of interfacial tension (IFT) are strong functions of IFT as well as fluid saturation. Danesh et al. were first to report the improvement of relative permeability of condensing systems due to an increase in velocity as well as that caused by a reduction in interfacial tension. This flow behaviour, named as the positive coupling effect, was subsequently confirmed experimentally by other investigators. Jamiolahmady et al. were first to study the positive coupling effect mechanistically capturing the competition of viscous and capillary forces at the pore level where there is a simultaneous flow of the two phases with intermittent opening and closure of gas passage by condensate. Jamiolahmady et al. developed a steady-dynamic network model capturing this flow behaviour and predicted some kr values, which were quantitatively comparable with the experimentally measured values. There are also several empirical correlations in the literature and commercial simulators accounting for the positive effect of coupling at near wellbore conditions as a function of capillary number (ratio of viscous to capillary forces). These correlations can be divided into two main classes: (1) using Corey functions in which the Corey coefficients are interpolated between the immiscible and miscible limits and (2) interpolation between miscible and immiscible relative permeability curves. In both methods the interpolation is weighted by capillary number (Nc) dependent functions. Blom and Haggort reviewed fifteen different correlations, all of which had capillary number and saturation as the main independent variables. At high velocities where the inertial effect (non-Darcy flow) is significant the competition of inertial and coupling effects complicates the flow in this region even further. Henderson et al., through some steady state kr measurements, confirmed the significant effect of positive coupling effect even at very high velocities contrary to the conventional view that kr would reduce with increasing velocity. They observed that the presence of condensate initially decreased the permeability due to inertia, before the positive coupling effect became dominant. Henderson et al. calculated the contribution of inertia at high velocities by subtracting the pressure loss predicted by the coupling effect from the experimentally measured values in this Laboratory. This difference is equivalent to the value of additional term in Forchhemier equation, which includes the two-phase inertia factor (βg). Then, they developed a correlation for calculating the two-phase inertial factor for SPE 83960 Variations of Gas-Condensate Relative Permeability with Production Rate at Near Wellbore Conditions: A General Correlation M. Jamiolahmady, A. Danesh, G. Henderson, and G.D. Tehrani