ANALISIS PRESSURE BUILD-UP RESERVOIR GAS KONDENSAT DALAM FORMASI KARBONAT

Different flow region will form in the reservoir when the gas condensate fluid flows with a bottom hole pressure below the dew point pressure. This flow region can be identified by the pressure build-up test analysis. This analysis can be done well on reservoir with homogeneous system and becomes more complex on reservoir with heterogeneous system. The purpose of this study is to find informations and characteristics about carbonate reservoir with gas condensate. Reservoir parameters that can be obtained are initial reservoir pressure (pi), permeability (k), skin factor (s), reservoir boundary (boundary), drainage area, and average reservoir pressure ( pr ). "JD-1" exploratory well penetrated the carbonate formation with the gas condensate hydrocarbon content. The well test analysis conducted is pressure analysis with pressure build-up testing and theanalysis results show a reservoir with a two-layer model, permeability value of 154 md, skin 13.8, initial pressure 3286.3 psia, and average reservoir pressure of 3285.7 psia.

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The Effects of Production Rate and Initial Pressure Difference (pi–pdew) in Well Test Analysis of Gas Condensate Reservoirs

Petroleum Science and Technology ◽

10.1080/10916460902839255 ◽

2011 ◽

Vol 29 (5) ◽

pp. 449-461 ◽

Cited By ~ 1

Author(s):

G. H. Montazeri ◽

Z. Ziabakhsh ◽

S. H. Tabatabaie ◽

P. Pourafshari ◽

M. Haghighi

Keyword(s):

Production Rate ◽

Pressure Difference ◽

Initial Pressure ◽

Gas Condensate ◽

Well Test ◽

Well Test Analysis ◽

Test Analysis ◽

Gas Condensate Reservoirs

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Condensate blockage effects in well test analysis of dual-porosity/dual-permeability, naturally fractured gas condensate reservoirs: a simulation approach

Journal of Petroleum Exploration and Production Technology ◽

10.1007/s13202-015-0214-6 ◽

2015 ◽

Vol 6 (4) ◽

pp. 729-742 ◽

Cited By ~ 2

Author(s):

M. Safari-Beidokhti ◽

A. Hashemi

Keyword(s):

Gas Condensate ◽

Dual Porosity ◽

Well Test ◽

Simulation Approach ◽

Well Test Analysis ◽

Test Analysis ◽

Gas Condensate Reservoirs ◽

Naturally Fractured ◽

Condensate Blockage

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Two-Phase Well Test Analysis of Gas Condensate Reservoirs

10.2118/56483-ms ◽

1999 ◽

Cited By ~ 4

Author(s):

Shaosong Xu ◽

W. John Lee

Keyword(s):

Gas Condensate ◽

Well Test ◽

Well Test Analysis ◽

Two Phase ◽

Test Analysis ◽

Gas Condensate Reservoirs

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Well Test Analysis in Gas/Condensate Reservoirs

Journal of Petroleum Technology ◽

10.2118/1100-0068-jpt ◽

2000 ◽

Vol 52 (11) ◽

pp. 68-70 ◽

Cited By ~ 1

Author(s):

Karen Bybee

Keyword(s):

Gas Condensate ◽

Well Test ◽

Well Test Analysis ◽

Test Analysis ◽

Gas Condensate Reservoirs

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Condensate Bank Characterization from Well Test Data and Fluid PVT Properties

SPE Reservoir Evaluation & Engineering ◽

10.2118/89904-pa ◽

2006 ◽

Vol 9 (05) ◽

pp. 596-611 ◽

Cited By ~ 10

Author(s):

Manijeh Bozorgzadeh ◽

Alain C. Gringarten

Keyword(s):

Capillary Number ◽

Gas Condensate ◽

Test Interpretation ◽

Well Test ◽

Transient Pressure ◽

Compositional Simulation ◽

Well Test Analysis ◽

Test Analysis ◽

Inertia Effects ◽

The North

Summary Published well-test analyses in gas/condensate reservoirs in which the pressure has dropped below the dewpoint are usually based on a two- or three-region radial composite well-test interpretation model to represent condensate dropout around the wellbore and initial gas in place away from the well. Gas/condensate-specific results from well-test analysis are the mobility and storativity ratios between the regions and the condensate-bank radius. For a given region, however, well-test analysis cannot uncouple the storativity ratio from the region radius, and the storativity ratio must be estimated independently to obtain the correct bank radius. In most cases, the storativity ratio is calculated incorrectly, which explains why condensate bank radii from well-test analysis often differ greatly from those obtained by numerical compositional simulation. In this study, a new method is introduced to estimate the storativity ratios between the different zones from buildup data when the saturation profile does not change during the buildup. Application of the method is illustrated with the analysis of a transient-pressure test in a gas/condensate field in the North Sea. The analysis uses single-phase pseudo pressures and two- and three-zone radial composite well-test interpretation models to yield the condensate-bank radius. The calculated condensate-bank radius is validated by verifying analytical well-test analyses with compositional simulations that include capillary number and inertia effects. Introduction and Background When the bottomhole flowing pressure falls below the dewpoint in a gas/condensate reservoir, retrograde condensation occurs, and a bank of condensate builds up around the producing well. This process creates concentric zones with different liquid saturations around the well (Fevang and Whitson 1996; Kniazeff and Nvaille 1965; Economides et al. 1987). The zone away from the well, where the reservoir pressure is still above the dewpoint, contains the original gas. The condensate bank around the wellbore contains two phases, reservoir gas and liquid condensate, and has a reduced gas mobility, except in the immediate vicinity of the well at high production rates, where the relative permeability to gas is greater than in the bank because of capillary number effects (Danesh et al. 1994; Boom et al. 1995; Henderson et al. 1998; Mott et al. 1999).

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Determination of Average Reservoir Pressure from Pressure Buildup Tests

10.2118/4052-ms ◽

1972 ◽

Author(s):

Hossein Kazemi

Keyword(s):

Reservoir Pressure ◽

Well Test ◽

Well Test Analysis ◽

Test Analysis ◽

Gas Well ◽

Pressure Buildup ◽

Production History ◽

Calculated Average

Abstract Two simple and equivalent procedures are suggested for improving the calculated average reservoir pressure from pressure buildup tests of liquid or gas wells in developed reservoirs. These procedures are particularly useful in gas well test analysis irrespective of gas composition, in reservoirs with pressure-dependent permeability and porosity, and in oil reservoirs where substantial gas saturation has been developed. Long-term production history need not be known. Introduction For analyzing pressure buildup data with constant flowrate before shut in, two plotting procedures are mostly used: The Miller-Dyes-Hutchinson (MDH) plot (1,8) and the Horner plot (2,8). The Miller-Dyes-Hutchinson plot is a plot of pws vs log Δt. The Horner plot consists of plotting the bottom hole shut-in pressure, pws vs log [(tp + Δt)/Δt]. Δt is the shut-in time and tp is a pseudo-production time equal to the ratio of total produced fluid and the last stabilized flowrate prior to shut in. This method was first used by Theis (3) in the water industry.

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Well Test Analysis for a Well in a Constant Pressure Square

10.2118/4054-ms ◽

1972 ◽

Author(s):

Anil Kumar ◽

H. J. Ramey

Keyword(s):

Constant Pressure ◽

Outer Boundary ◽

Initial Pressure ◽

Fluid Injection ◽

Well Test ◽

Well Test Analysis ◽

Test Analysis ◽

Water Influx ◽

Mean Pressure ◽

Well Tests

Abstract Very little information exists for analyzing well tests wherein a part of the drainage boundary is under pressure support from water influx or fluid injection. An idealization is the behavior of a well in the center of a square whose outer boundary remains at constant pressure. A study of this system indicated important differences from the behavior of a well in a closed outer boundary square, the conventional system. At infinite shut in, the constant- pressure boundary case well will reach the initial pressure of the system, rather than a mean pressure resulting from depletion. But it is possible to compute the mean pressure in the constant-pressure case at any time during shut in. Interpretative graphs for analyzing drawdown and buildup pressures are presented and discussed. This case is also of interest in analysis of well tests obtained from developed five-spot fluid injection patterns. Introduction Well-test analysis has become a widely used tool for reservoir engineers in the last twenty years. The initial theory was reported by Horner1 for unsteady flow of single phase fluids of small but constant compressibility to a well producing at a constant rate in -infinite and closed boundary reservoirs. Extension of the theory to the finite reservoir case involves specification of the outer boundary condition. The two most commonly observed conditions are: (1) no flow at the outer boundary corresponding to a closed or depletion reservoir, and (2) constant pressure at the outer boundary corresponding to complete water-drive.

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