Gas Condensate Relative Permeability of Low permeability Rocks: Coupling Versus Inertia

2009 ◽  
Author(s):  
Mahmoud Jamiolahmady ◽  
Mehran Sohrabi ◽  
Shaun Ireland
Keyword(s):  
Relative Permeability ◽  
Gas Condensate ◽  
Low Permeability

Gas/Condensate Relative Permeability of a Low Permeability Core: Coupling vs. Inertia

2010 ◽  
Vol 13 (02) ◽  
pp. 214-227 ◽  
Author(s):  
Mahmoud Jamiolahmady ◽  
Mehran Sohrabi ◽  
Panteha Ghahri ◽  
Shaun Ireland
Keyword(s):  
Relative Permeability ◽  
Gas Condensate ◽  
Low Permeability

WELL TESTING HORIZONTALGAS-CONDENSATE WELLS

2017 ◽  
pp. 56-61
Author(s):  
M. L. Karnaukhov ◽  
O. N. Pavelyeva
Keyword(s):  
Comparative Analysis ◽  
Skin Effect ◽  
Horizontal Wells ◽  
Gas Condensate ◽  
Low Permeability ◽  
Well Testing ◽  
Flow Capacity ◽  
Formation Zone ◽  
Horizontal Wellbore

The well testing of gas-condensate horizontal wells are discussed in the article and the comparative analysis of borehole flow capacity, depending on the mode of it’s operation is presented. Extra attention is focused on the issue of timely identification of the reasons for the reduction of fluid withdrawal from the reservoir. The presence of high skin effect is proved, which confirms the existence of low-permeability of bottomhole formation zone related to condensation in the immediate area of the horizontal wellbore.

scholarly journals Near Critical Gas Condensate Relative Permeability of Carbonates

2006 ◽  
Author(s):  
Huseyin Calisgan ◽  
Birol Demiral ◽  
Serhat Akin
Keyword(s):  
Relative Permeability ◽  
Gas Condensate

scholarly journals THE TEST RESULTS OF LOW-PERMEABILITY SHALE DEPOSITS WHEN DRILLING THE PRE-CRETACEOUS COMPLEX AT THE KARMALINOVSKOYE GAS CONDENSATE FIELD

2019 ◽  
pp. 45-58
Author(s):  
A. A. Zakharov ◽  
S. V. Korotkov ◽  
A. I. Gritsenko ◽  
R. A. Ivakin ◽  
V. G. Griguletsky
Keyword(s):  
Hydraulic Fracturing ◽  
Flow Rate ◽  
Gas Condensate ◽  
Low Permeability ◽  
Test Results ◽  
North West ◽  
The North ◽  
Exploratory Wells

The article reports the results of the analysis of the field prospecting activities of five exploratory wells at the Karmalinovskoye gas condensate field. We have found that the eastern part of the licensed area is characterized by the lack of fructuring in Paleozoic deposits, and the development of the productive deposit extends in the north-west direction. Hydraulic fracturing made it possible to get a stable gas and gas condensate flow rate in well № 4. This volume exceeds 3,8 times as large than flow rate in wells № 1 and № 2, which were tested after drilling without conducting hydraulic fracturing.

Calculation of Oil and Water Relative Permeability for Extra Low Permeability Reservoir

2010 ◽  
Author(s):  
Renjing Liu ◽  
Huiqing Liu ◽  
Xiusheng Li ◽  
Jing Wang ◽  
Changting Pang
Keyword(s):  
Relative Permeability ◽  
Low Permeability ◽  
Low Permeability Reservoir

A COMPREHENSIVE MODEL FOR OIL–WATER RELATIVE PERMEABILITIES IN LOW-PERMEABILITY RESERVOIRS BY FRACTAL THEORY

Fractals ◽  
2020 ◽  
Vol 28 (03) ◽  
pp. 2050055
Author(s):  
HAIBO SU ◽  
SHIMING ZHANG ◽  
YEHENG SUN ◽  
XIAOHONG WANG ◽  
BOMING YU ◽  
...  
Keyword(s):  
Fractal Dimension ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Fractal Theory ◽  
Low Permeability ◽  
Comprehensive Model ◽  
Relative Permeabilities ◽  
Oil Water ◽  
Seepage Characteristics ◽  
Low Permeability Reservoirs

Oil–water relative permeability curve is an important parameter for analyzing the characters of oil and water seepages in low-permeability reservoirs. The fluid flow in low-permeability reservoirs exhibits distinct nonlinear seepage characteristics with starting pressure gradient. However, the existing theoretical model of oil–water relative permeability only considered few nonlinear seepage characteristics such as capillary pressure and fluid properties. Studying the influences of reservoir pore structures, capillary pressure, driving pressure and boundary layer effect on the morphology of relative permeability curves is of great significance for understanding the seepage properties of low-permeability reservoirs. Based on the fractal theory for porous media, an analytically comprehensive model for the relative permeabilities of oil and water in a low-permeability reservoir is established in this work. The analytical model for oil–water relative permeabilities obtained in this paper is found to be a function of water saturation, fractal dimension for pores, fractal dimension for tortuosity of capillaries, driving pressure gradient and capillary pressure between oil and water phases as well as boundary layer thickness. The present results show that the relative permeabilities of oil and water decrease with the increase of the fractal dimension for tortuosity, whereas the relative permeabilities of oil and water increase with the increase of pore fractal dimension. The nonlinear properties of low-permeability reservoirs have the prominent significances on the relative permeability of the oil phase. With the increase of the seepage resistance coefficient, the relative permeability of oil phase decreases. The proposed theoretical model has been verified by experimental data on oil–water relative permeability and compared with other conventional oil–water relative permeability models. The present results verify the reliability of the oil–water relative permeability model established in this paper.

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.

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