SPE Members Abstract Laboratory experiments on gas condensate flow behavior were conducted under reservoir conditions. Two North Sea gas condensate reservoirs that have distinct rock and fluid properties were studied. The objectives of the corefloods were to investigate the effects of rock and fluid characteristics on critical condensate saturation (CCS), gas and condensate relative permeabilities during in-situ condensation, hydrocarbon recovery and trapping by water injection, and incremental hydrocarbon recovery by subsequent blowdown. It was found that 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 drop out can be somewhat restored by increasing production rate. Phase behavior and interfacial tension influence the extents of gas relative permeability reduction and condensate mobility. 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. Approximately 27 %PV gas was trapped by water injection. 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. 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. 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. 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. 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. Other laboratory evaluations of gas condensate flow behavior indicate measured results depend upon experimental procedures, fluid properties, and rock properties. Factors to consider include the history of condensate formation (i.e., imbibition or drainage), how condensate was introduced (i.e., in-situ drop out versus external injection or in-flowing 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. P. 699

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.

Detecting and mitigating near-wellbore fines migration is important in order to avoid formation damage in many gas wells. This has bearing not only on gas production but also carbon capture through the geological storage of Carbon dioxide (CO2), in pressurised, deep saline aquifers. Fines migration may occur because of weakened electrostatic forces caused by an introduced fluid which also makes fines more prone to movement by viscous drag, or where the drag forces are sufficient to physically break or lift clay crystals from their original location and transport them through the pore network. Potential near-wellbore fines migration is typically assessed via coreflood tests. In an ideal scenario, such tests will be conducted using reservoir core material, with reservoir gas at rates and pressures comparable to the reservoir. However, due to practicality and cost constraints, tests are often conducted using available outcrop core and scaled down reservoir conditions. Laboratory tests reduce higher field pressures down to lab scale. In certain scenarios, simulating the total gas flux in a given near-wellbore system is achieved by increasing gas flow rates. Although, in some investigations, the need to utilise field realistic pressures in the lab is also becoming more of a requirement. This paper aims to address differences in lab protocols by examining both field realistic and scaled down conditions to aid best practice for formation damage identification and remediation. The potential utility, and challenges associated with a variety of hydrocarbon gas analogues in scenarios where increased gas density is required is also discussed. The fines migration potential of a clay rich (Blaxter) sandstone was demonstrated using salinity and flux related fines migration methods, demonstrating that under certain conditions, selected cores are susceptible to fines migration. Test results with CO2 at low and medium pressure conditions demonstrated that pressure and flow rate variation in the laboratory had no notable effect on the fines migration of Blaxter sandstone samples, under the conditions examined. Additional tests conducted at higher pressures of 7250 psig did not yield fines migration although a 10% permeability loss was observed. While this was the case for Blaxter sandstone, caution is advised when testing with field substrate under these conditions, as reservoir rocks may be more susceptible to damage. Field cores typically display a well-developed crystal structure and surface area/volume ratios more normally associated with kaolinite booklets and platelets of clays, which may expose them to higher drag forces. Therefore, the minimal permeability reduction effects observed at high pressure may potentially be multiplied in field cores. Additional core flood tests were conducted to evaluate the use of hydrocarbon gas analogues (such dodecane) as a substitute for dense gases in core flood testing. This allows lower pressures than that would be required for compressed gases. Results showed that dodecane can be used as a gas analogue under appropriate conditions. A note of caution in the use of dodecane is that results from the high-pressure tests showed that, under the conditions examined, dodecane induced a 24% permeability reduction in the core. The work presented in this paper aims to improve the use of coreflood tests as a tool for identifying formation damage, particularly in gas wells. This work provides useful guides and shows that while testing at atypical pressures is not prevalent, it can be performed and may be required for more robust formation damage identification programs in specific scenarios.

We report the development of a model to support matrix-based stimulation treatments in limestone reservoirs that takes information directly from data obtained during core flooding, such that the model can be calibrated against a variety of novel stimulation fluids under conditions directly representative of the candidate field. The model builds on an earlier stimulation model developed for clastic reservoirs, which primarily addressed stimulation as a formation-damage-removal phenomenon; it maintains the 3-dimensional aspects of the earlier model but incorporates the substantially greater complexity required in coupling the damage-dissolution reactions to the hydrodynamic phenomena associated with the formation of wormholes. Wormholes are an ideal method of stimulating carbonate reservoirs (in the absence of massive hydraulic fracturing) but their formation is stochastic, anisotropic, and involves greater morphological changes. Hence, successful stimulation depends on formulation chemistry, application rates, rock morphology, pressure, and temperature. This initial model has been calibrated to describe the behaviour of a selection of non-standard stimulation fluids, which have been evaluated in part through core-flood performance. The reaction-rate data for these novel fluids was abstracted from a series of core flood experiments with effluent and morphological analyses. The user interface provides easy condition input and selection and provides a clear output of results. Future developments will expand the model to a broader range of conditions and chemical formulations.