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

Abstract

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. Introduction Reservoirs bearing gas condensates are becoming more commonplace as developments are encountering greater depths, higher pressures, and higher temperatures. In the North Sea, gas condensate reservoirs comprise a significant portion of the total hydrocarbon reserves. Accuracy in engineering computations for gas condensate systems (e.g., estimating reserves, sizing surface facilities, and predicting productivity trends) depends upon a basic understanding of phase and flow behavior interrelationships. For example, gas productivity may be curtailed as condensate accumulates by pressure depletion below the dew point pressure (Pd). Conceptual modeling on gas condensate systems suggests that relative permeability (kr) curves govern the magnitude of gas productivity loss.1,2 Unfortunately, available gas and condensate relative permeability (krg and krc) results for gas condensates are primarily limited to synthetic systems. Such results show that higher CCS and less krg reduction were observed for a conventional gas/oil system compared to a gas condensate system.3,4 If condensate accumulates as a continuous film due to low interfacial tension (IFT), then high IFT gas/oil and water/oil kr data may not be applicable to gas condensates.5 Water invasion of gas condensate reservoirs may enhance hydrocarbon recovery or trap potential reserves. Laboratory results suggest water invasion of low IFT gas condensates may not be represented using high IFT water/oil and water/gas displacements.6 Subsequent blowdown may remobilize hydrocarbons trapped by water invasion. The presence of condensate may hinder gas remobilization, thus conventional gas/water blowdown experiments may not be appropriate in evaluating the feasibility of depressurization for gas condensates.7,8 Other laboratory evaluations of gas condensate flow behavior indicate measured results depend upon experimental procedures, fluid properties, and rock properties.3,9–20 Factors to consider include the history of condensate formation (i.e., imbibition or drainage), how condensate was introduced (i.e., in-situ dropout versus external injection or inflowing gas), flow rate, differential pressure, system pressure, IFT, connate water saturation, core permeability, and core orientation. Experiments performed to evaluate the consequences of water invasion suggest optimum conditions depend upon IFT, initial gas saturation, and core permeability.7,21,22 Reported blowdown experiments imply gas recovery depends upon the degree of gas expansion.7,8 The kr results obtained in this study represent gas condensate flow between the far-field and the near-wellbore region. The results are useful input for numerical simulation, especially to test rate- or IFT-sensitive relative permeability functions. Results on hydrocarbon recovery and trapping from water injection and blowdown are beneficial in evaluating improved recovery options for gas condensates. Experimental Procedures Coreflooding experiments were performed under reservoir conditions using rock and fluid samples from two distinct North Sea gas condensate reservoirs. A detailed description of the experimental methods is provided in the Appendix. Briefly, the experiments were conducted in a horizontal coreflood apparatus equipped with in-line PVT and viscosity measuring devices. The entire system experienced in-situ condensate drop out by constant volume depletion (CVD) from above Pd to either the pressure corresponding to CCS, or to the pressure of maximum condensate saturation Scmax Steady-state krg was measured by injecting equilibrated gas (before CCS). Steady-state krg and krc were measured by injecting gas condensate repressurized to above Pd (after CCS). The gas/oil fractional flow rate was defined by the pressure level in the core which was controlled by the core outlet back-pressure regulator. During krg measurements, the injection rate was varied to access rate effects. After the krg or krg and krc measurements to Scmax were completed, water injection was performed to quantify hydrocarbon trapping and recovery. Blowdown followed to evaluate additional hydrocarbon recovery. Recombined Reservoir Fluid Properties. Two North Sea gas condensate reservoir fluids were recombined using separator oil and synthetic gas. Tables 1 and 2 list compositions and PVT properties for the reconstituted fluids. The Pd was 7,070 psig at 250°F for Reservoir A, and 6,074 psig at 259°F for Reservoir B (Table 2). The maximum liquid dropout under constant composition expansion (CCE) was 31.7% for Reservoir A, and 42.5% for Reservoir B (Fig. 1). Reservoir B is a richer gas condensate and exhibits more near-critical phase behavior than Reservoir A.

A Model for Relative Permeabilities Under Gas Liberation or Condensate Precipitation in Porous Medium

“…The data on a carbonate rock by Afidick, Kaczorowski, and Bette (1994) and by Gravier et al (1986); and the data for a sandstone reservoir rock by Chen, Wilson, and Monger-McClure (1999). Gravier et al (1986) studied the effect of precipitation of the condensate droplets from gas condensate on the relative permeability for gas.…”

“…Afidick, Kaczorowski, and Bette (1994) studied the performance loss of the Arun gas condensate limestone field due to the droplet condensation using the well-test data. Chen, Wilson, and Monger-McClure (1999) measured the effect of condensation on the effective permeability of the two North Sea reservoirs with the properties characteristic of the sandstone reservoirs experimentally.…”

“…Fig.8The model adjusted to data for cores from reservoirs A (a) and B (b), byChen, Wilson, and Monger-McClure (1999). A sandstone rock (𝑍𝑍 = 8).…”

Permeability Characterisation of Sedimentological Facies in the Bunter Sandstone Formation, Endurance CO2 Storage Site, Offshore UK

“…Many studies have been conducted on permeability variations associated with heterogeneity in different geological settings and deposits (Stalkup & Ebanks, 1986;Prosser et al, 1995;Ringrose et al, 1999;Possemiers et al, 2012). The main purpose of these studies was to understand their impact on hydrocarbon recovery efficiency (Lewis, 1988;Honarpour & Saad, 1994;Honarpour et al, 1995;Chen et al, 1999;Ringrose et al, 1999;Stephen et al, 2001;Rashid et al, 2012;Pantou, 2014;Gao & Li, 2016) and groundwater flow through aquifers (Freeze & Witherspoon, 1967;Cheng, 1984;Neuzil, 1986;Keller et al, 1988;Gotkowitz, 1993;Huysmans et al, 2008). These studies show that permeability heterogeneity occurs at different scales and they are strongly influenced by sedimentary architectures and clay contents, especially in high porosity sandstone units (Prosser et al, 1995;Ringrose et al, 1999;Possemiers et al, 2012).…”