Variations of Gas/Condensate Relative Permeability With Production Rate at Near-Wellbore Conditions: A General Correlation

2006 ◽  
Vol 9 (06) ◽  
pp. 688-697 ◽  
Author(s):  
Mahmoud Jamiolahmady ◽  
Ali Danesh ◽  
D.H. Tehrani ◽  
Mehran Sohrabi
Keyword(s):  
Relative Permeability ◽  
Oil And Gas ◽  
Coupling Effect ◽  
Flow Behavior ◽  
Accurate Determination ◽  
Gas Condensate ◽  
Gas Oil ◽  
Fractional Flow ◽  
General Correlation ◽  
Fluid Saturation

Summary 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 with measurements at high-velocity conditions. Measurements of gas/condensate relative permeability at simulated near-wellbore conditions are very demanding and expensive. Recent experimental findings in this laboratory indicate that measured gas/condensate relative permeability values on cores with different characteristics become more similar if expressed in terms of fractional flow instead of the commonly used saturation. This would lower the number of rock curves required in reservoir studies. Hence, we have used a large data bank of gas/condensate relative permeability measurements to develop a general correlation accounting for the combined effect of coupling and inertia as a function of fractional flow. 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 developed correlation has been evaluated by comparing its prediction with the gas/condensate relative permeability values measured at near-wellbore conditions on reservoir rocks not used in its development. The results are quite satisfactory, confirming that the correlation can provide reliable information on variations of relative permeability at near-wellbore conditions with no requirement for expensive measurements. Introduction The process of condensation around the wellbore in a gas/condensate reservoir, when the pressure falls below the dewpoint, creates a region in which both gas and condensate phases flow. The flow behavior in this region is controlled by the viscous, capillary, and inertial forces. This, along with the presence of condensate in all the pores, dictates a flow mechanism that is different from that of gas/oil and gas/condensate in the bulk of the reservoir (Danesh et al. 1989). Accurate determination of gas/condensate relative permeability (kr) values, which is very important in well-deliverability estimates, is a major challenge and requires an approach different from 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 (Bardon and Longeron 1980; Asar and Handy 1988; Haniff and Ali 1990; Munkerud 1995). Danesh et al. (1994) were first to report the improvement of the relative permeability of condensing systems owing to an increase in velocity as well as that caused by a reduction in IFT. This flow behavior, referred to as the positive coupling effect, was subsequently confirmed experimentally by other investigators (Henderson et al. 1995, 1996; Ali et al. 1997; Blom et al. 1997). Jamiolahmady et al. (2000) were first to study the positive coupling effect mechanistically capturing the competition of viscous and capillary forces at the pore level, where there is simultaneous flow of the two phases with intermittent opening and closure of the gas passage by condensate. Jamiolahmady et al. (2003) developed a steady-dynamic network model capturing this flow behavior and predicted some kr values, which were quantitatively comparable with the experimentally measured values.

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

1999 ◽  
Vol 2 (04) ◽  
pp. 393-402 ◽  
Author(s):  
H.L. Chen ◽  
S.D. Wilson ◽  
T.G. Monger-McClure
Keyword(s):  
Interfacial Tension ◽  
Relative Permeability ◽  
North Sea ◽  
Flow Behavior ◽  
Water Injection ◽  
Gas Condensate ◽  
Gas Oil ◽  
Hydrocarbon Recovery ◽  
Gas Condensate Reservoirs ◽  
Gas Condensates

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.

Extended Fractional-Flow Model of Low-Salinity Waterflooding Accounting for Dispersion and Effective Salinity Range

SPE Journal ◽  
2019 ◽  
Vol 24 (06) ◽  
pp. 2874-2888 ◽  
Author(s):  
Hasan Al–Ibadi ◽  
Karl D. Stephen ◽  
Eric J. Mackay
Keyword(s):  
Relative Permeability ◽  
Flow Behavior ◽  
Flow Analysis ◽  
Salinity Range ◽  
Fractional Flow ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Low Salinity Waterflooding ◽  
Salinity Water ◽  
The Impact

Summary Low–salinity waterflooding (LSWF) is an emergent technology developed to increase oil recovery. Laboratory–scale testing of this process is common, but modeling at the production scale is less well–reported. Various descriptions of the functional relationship between salinity and relative permeability have been presented in the literature, with respect to the differences in the effective salinity range over which the mechanisms occur. In this paper, we focus on these properties and their impact on fractional flow of LSWF at the reservoir scale. We present numerical observations that characterize flow behavior accounting for dispersion. We analyzed linear and nonlinear functions relating salinity to relative permeability and various effective salinity ranges using a numerical simulator. We analyzed the effect of numerical and physical dispersion of salinity on the velocity of the waterflood fronts as an expansion of fractional–flow theory, which normally assumes shock–like behavior of water and concentration fronts. We observed that dispersion of the salinity profile affects the fractional–flow behavior depending on the effective salinity range. The simulator solution is equal to analytical predictions from fractional–flow analysis when the midpoint of the effective salinity range lies between the formation and injected salinities. However, retardation behavior similar to the effect of adsorption occurs when these midpoint concentrations are not coincidental. This alters the velocities of high– and low–salinity water fronts. We derived an extended form of the fractional–flow analysis to include the impact of salinity dispersion. A new factor quantifies a physical or numerical retardation that occurs. We can now modify the effects that dispersion has on the breakthrough times of high– and low–salinity water fronts during LSWF. This improves predictive ability and also reduces the requirement for full simulation.

Differences in Gas/Oil and Gas/Water Relative Permeability

1992 ◽  
Author(s):  
J.F. Berry ◽  
A.J.H. Little ◽  
R.C. Skinner
Keyword(s):  
Relative Permeability ◽  
Oil And Gas ◽  
Gas Oil

Experimental Investigation of Two-Phase Flow Properties of Heterogeneous Rocks for Advanced Formation Evaluation

2021 ◽  
Author(s):  
Pierre Aérens ◽  
Carlos Hassan Torres-Verdin ◽  
D. Nicolas Espinoza
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Two Phase Flow ◽  
Time Lapse ◽  
Phase Flow ◽  
Flow Properties ◽  
Fractional Flow ◽  
Two Phase ◽  
Fluid Saturation ◽  
Heterogeneous Rocks

Abstract An uncommon facet of Formation Evaluation is the assessment of flow-related in situ properties of rocks. Most of the models used to describe two-phase flow properties of porous rocks assume homogeneous and/or isotropic media, which is hardly the case with actual reservoir rocks, regardless of scale; carbonates and grain-laminated sandstones are but two common examples of this situation. The degree of spatial complexity of rocks and its effect on the mobility of hydrocarbons are of paramount importance for the description of multiphase fluid flow in most contemporary reservoirs. There is thus a need for experimental and numerical methods that integrate all salient details about fluid-fluid and rock-fluid interactions. Such hybrid, laboratory-simulation projects are necessary to develop realistic models of fractional flow, i.e., saturation-dependent capillary pressure and relative permeability. We document a new high-resolution visualization technique that provides experimental insight to quantify fluid saturation patterns in heterogeneous rocks and allows for the evaluation of effective two-phase flow properties. The experimental apparatus consists of an X-ray microfocus scanner and an automated syringe pump. Rather than using traditional cylindrical cores, thin rectangular rock samples are examined, their thickness being one order of magnitude smaller than the remaining two dimensions. During the experiment, the core is scanned quasi-continuously while the fluids are being injected, allowing for time-lapse visualization of the flood front. Numerical simulations are then conducted to match the experimental data and quantify effective saturation-dependent relative permeability and capillary pressure. Experimental results indicate that flow patterns and in situ saturations are highly dependent on the nature of the heterogeneity and bedding-plane orientation during both imbibition and drainage cycles. In homogeneous rocks, fluid displacement is piston-like, as predicted by the Buckley-Leverett theory of fractional flow. Assessment of capillary pressure and relative permeability is performed by examining the time-lapse water saturation profiles. In spatially complex rocks, high-resolution time-lapse images reveal preferential flow paths along high permeability sections and a lowered sweep efficiency. Our experimental procedure emphasizes that capillary pressure and transmissibility differences play an important role in fluid-saturation distribution and sweep efficiency at late times. The method is fast and reliable to assess mixing laws for fluid-transport properties of rocks in spatially complex formations.

scholarly journals About Relations between Natural Gas and Oil in Connection with Forecast of Their Reserves in Azerbaijan

2021 ◽  
Vol 5 (4) ◽  
pp. 288-296
Author(s):  
A. A. Feizullaev
Keyword(s):  
Natural Gas ◽  
Oil And Gas ◽  
Gas Condensate ◽  
The Other ◽  
Gas Oil ◽  
Oil Reserves ◽  
Ratio Data ◽  
The World ◽  
Deepwater Part ◽  
Deep Water Part

Azerbaijan is one of the oldest oil and gas provinces, where more than 2 bln tons of oil have been extracted over more than a century. At present, the oil production is declining and mainly determined by production from the Azeri-Chirag-Guneshli offshore block (AChG). Compared to oil, the opportunities for further growing natural gas reserves and production are very promising. For the latest years, a number of large gas condensate fields have been discovered in the deep-water part of South Caspian Sea, such as Shakh-Deniz, Apsheron, Umid. There are a number of prospects that have not yet been drilled in this part of the sea basin. The paper assesses their prospectivity, substantiates the priority exploration targets and, on the basis of the statistical analysis of the quantitative gas/oil ratio data for many other Azerbaijanian and world basins, an attempt is made to assess the reserves in the prospects. The total recoverable oil reserves in Azerbaijan are estimated at 3.5 bln tons, of which slightly above 2 bln tons have already been extracted. Based on the statistically estimated ratio between the volumes of gas and oil in various basins of the world, including Azerbaijan, the total possible natural gas reserves in Azerbaijan are estimated at about 4 trillion m3 . This is in agreement with the other available estimates. Of this volume of natural gas, 0.85 trillion m3 has already been extracted, and the approved geological reserves are estimated at 2.55 trillion m3 . Almost 83% of the extracted natural gas belonged to offshore fields. This trend will continue in the future, and, moreover, will be strengthened due to large volumes of gas condensate accumulations in the deepwater part of the basin. In this part of the basin, the most attractive prospects are Mashal, Shafag, and Israfil Huseynov, total reserves of which are expected at 0.6 trillion m3 of natural gas.

Creating the Integrated Model for Conceptual Engineering of Reservoir Management and Field Facilities Construction – Experience of Tazovskoe Oil and Gas-Condensate Field.

2021 ◽  
Author(s):  
Artem Igorevich Varavva ◽  
Renat Timergaleevich Apasov ◽  
Dmitry Alexeyevich Samolovov ◽  
Artem Viktorovich Elesin ◽  
Gaidar Timergaleevich Apasov ◽  
...  
Keyword(s):  
Growth Rates ◽  
Oil And Gas ◽  
High Growth ◽  
Integrated Model ◽  
Gas Condensate ◽  
Gas Oil ◽  
Full Field ◽  
Conceptual Engineering ◽  
Construction Experience ◽  
Oil Rim

Abstract The paper describes the experience of building a full-field integrated model (PK1 reservoir) of the Tazovskoye field, including a model of the reservoir, wells, and a gathering network, taking into account the external transportation system. In order to integrate the features of the field, such as the simultaneous development of a thin oil rim and a gas cap, high growth rates of the gas-oil ratio, oil wells - both ESP-operated and flowing, algorithms and tools have been developed, which are discussed in the paper. The results of the integrated model runs are given, main features of the solutions are highlighted.

scholarly journals Forecast of the position of promising sand reservoirs in the cross-section of the carboniferous gas-bearing stratum

2019 ◽  
Vol 109 ◽  
pp. 00051
Author(s):  
Viacheslav Lukinov ◽  
Mykola Zhykaliak
Keyword(s):  
Cross Section ◽  
Oil And Gas ◽  
Rapid Assessment ◽  
Gas Condensate ◽  
Gas Oil ◽  
Solid Mass ◽  
Coal Deposits ◽  
Overburden Stress ◽  
The Cross ◽  
Gas Bearing

The results of the study of the influence of overburden stress in a solid mass undisturbed by mine workings on the compaction of sandstones within mine fields, exploration areas of Donbas coal deposits and some gas condensate and oil and gas condensate deposits of the Dnipro-Donets Depression (DDD) are presented. Regularities of changes in gas-bearing properties of porous reservoirs with the increase of overburden stress in an undisturbed solid mass, or its decrease in mine conditions are considered. The possibilities of rapid assessment of the forecast position of prospective sand reservoirs in the cross-section of the gas-bearing stratum are shown. Methods are proposed for calculating the position of sandstones of gas-bearing stratum, in which it is advisable to search for gas accumulations and its extraction in the coal and gas, oil and gas condensate and gas condensate fields of Donbas and DDD.

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