A New Approach for Phase Behavior and Well Productivity Studies in the Deep Gas-Condensate Reservoir with Low Permeability

2007 ◽  
Author(s):  
Zhilin Qi ◽  
Shouping Wang ◽  
Zhimin Du ◽  
Baosheng Liang ◽  
Ruijian Deng ◽  
...  
Keyword(s):  
Phase Behavior ◽  
Gas Condensate ◽  
Low Permeability ◽  
Well Productivity ◽  
New Approach ◽  
Condensate Reservoir

Phase Behavior Study in the Deep Gas-Condensate Reservoir with Low Permeability

2007 ◽  
Author(s):  
Zhilin Qi ◽  
Baosheng Liang ◽  
Ruijian Deng ◽  
Zhimin Du ◽  
Shouping Wang ◽  
...  
Keyword(s):  
Phase Behavior ◽  
Gas Condensate ◽  
Low Permeability ◽  
Behavior Study ◽  
Condensate Reservoir

Measurements of Relative Permeabilities for Calculating Gas-Condensate Well Deliverability

2000 ◽  
Vol 3 (06) ◽  
pp. 473-479 ◽  
Author(s):  
R.E. Mott ◽  
A.S. Cable ◽  
M.C. Spearing
Keyword(s):  
Relative Permeability ◽  
Capillary Number ◽  
Gas Condensate ◽  
Relative Permeabilities ◽  
Well Productivity ◽  
Gas Condensate Reservoirs ◽  
Liquid Saturation ◽  
Condensate Reservoir ◽  
Deep Reservoir ◽  
The Relationship

Summary Well deliverability in many gas-condensate reservoirs is reduced by condensate banking when the bottomhole pressure falls below the dewpoint, although the impact of condensate banking may be reduced due to improved mobility at high capillary number in the near-well region. This paper presents the results of relative permeability measurements on a sandstone core from a North Sea gas-condensate reservoir, at velocities that are typical of the near-well region. The results show a clear increase in mobility with capillary number, and the paper describes how the data can be modeled with empirical correlations which can be used in reservoir simulators. Introduction Well deliverability is an important issue in the development of many gas-condensate reservoirs, especially where permeability is low. When the well bottomhole flowing pressure falls below the dewpoint, condensate liquid may build up around the wellbore, causing a reduction in gas permeability and well productivity. In extreme cases the liquid saturation may reach values as high as 50 or 60% and the well deliverability may be reduced by up to an order of magnitude. The loss in productivity due to this "condensate banking" effect may be significant, even in very lean gas-condensate reservoirs. For example, in the Arun reservoir,1 the productivity reduced by a factor of about 2 as the pressure fell below the dewpoint, even though the reservoir fluid was very lean with a maximum liquid drop out of only 1% away from the well. Most of the pressure drop from condensate blockage occurs within a few feet of the wellbore, where velocities are very high. There is a growing body of evidence from laboratory coreflood experiments to suggest that gas-condensate relative permeabilities increase at high velocities, and that these changes can be correlated against the capillary number.2–8 The capillary number is a dimensionless number that measures the relative strength of viscous and capillary forces. There are several gas-condensate fields where simulation with conventional relative permeability models has been found to underestimate well productivity.1,9,10 To obtain a good match between simulation results and well-test data, it was necessary to increase the mobility in the near-well region, either empirically or through a model of the increase in relative permeability at high velocity. This effect can increase well productivity significantly, and in some cases may eliminate most of the effect of condensate blockage. Experimental Data Requirements Fevang and Whitson11 have shown that the key parameter in determining well deliverability is the relationship between krg and the ratio krg/ kro. When high-velocity effects are significant, the most important information is the variation of krg with krg/k ro and the capillary number Nc. The relevant values of krg/kro are determined by the pressure/volume/temperature (PVT) properties of the reservoir fluids, but typical values might be 10 to 100 for lean condensates, 1 to 10 for rich condensates, and 0.1 to 10 for near-critical fluids. There are various ways of defining the capillary number, but in this paper we use the definition (1)Nc=vgμgσ, so that the capillary number is proportional to the gas velocity and inversely proportional to interfacial tension (IFT). The capillary numbers that are relevant for well deliverability depend on the flow rate, fluid type, and well bottomhole pressure, but as a general rule, values between 10?6 and 10?3 are most important. Experimental Methods In a gas-condensate reservoir, there are important differences between the flow regimes in the regions close to and far from the well. These different flow regimes are reflected in the requirements for relative permeability data for the deep reservoir and near-well regions. Far from the well, velocities are low, and liquid mobility is usually less important, except in reservoirs containing very rich fluids. In the near-well region, both liquid and gas phases are mobile, velocities are high, and the liquid mobility is important because of its effect on the relationship between krg and krg/kro. Depletion Method. Relative permeabilities for the deep reservoir region are often measured in a coreflood experiment, where the fluids in the core are obtained by a constant volume depletion (CVD) on a reservoir fluid sample. Relative permeabilities are measured at decreasing pressures from the fluid dewpoint, and increasing liquid saturation. In this type of experiment, the liquid saturation cannot exceed the critical condensate saturation or the maximum value in a CVD experiment, so that it is not possible to acquire data at the high liquid saturations that occur in the reservoir near to the well. The "depletion" experiment provides relative permeability data that are relevant to the deep reservoir, but there can be problems in interpreting the results due to the effects of IFT. Changes in liquid saturation are achieved by reducing pressure, which results in a change of IFT. The increase in IFT as pressure falls may cause a large reduction in mobility, and Chen et al.12 describe an example where the condensate liquid relative permeability decreases with increasing liquid saturation. Steady-State Method. The steady-state technique can be used to measure relative permeabilities at the higher liquid saturations that occur in the near-well region. Liquid and gas can be injected into the core from separate vessels, allowing relative permeabilities to be measured for a wide range of saturations. Results of gas-condensate relative permeabilities measured by this technique have been reported by Henderson et al.2,6 and Chen et al.12 .

scholarly journals Influence of geological reservoir heterogeneity on exploitation conditions of Garadagh field / underground gas storage (Azerbaijan)

2021 ◽  
Vol 6 (2) ◽  
pp. 105-113
Author(s):  
A. A. Feyzullayev ◽  
A. G. Gojayev
Keyword(s):  
Oil And Gas ◽  
Gas Storage ◽  
Gas Condensate ◽  
Underground Gas Storage ◽  
Gas Reservoirs ◽  
Well Productivity ◽  
Reservoir Heterogeneity ◽  
Reservoir Development ◽  
Condensate Reservoir ◽  
Lithological Composition

Underground oil and gas reservoirs (formations) are characterized by spatial variability of their structure, material composition and petrophysical properties of its constituent rocks: particle size distribution, porosity, permeability, structure and texture of the pore space, carbonate content, electrical resistivity, oil and water saturation and other properties. When assessing development and exploitation conditions for underground gas storages, created in depleted underground oil and gas reservoirs, the inherited nature of the reservoir development should be taken into account. Therefore, identifying the features of variations in well productivity is a crucial task, solution of which can contribute to the creation of more efficient system for underground gas storage exploitation. The paper presents the findings of comparative analysis of spatial variations in well productivity during the exploitation of the Garadagh underground gas storage (Azerbaijan), created in the depleted gas condensate reservoir. An uneven nature of the variations in well productivity was established, which was connected with the reservoir heterogeneity (variations in the reservoir lithological composition and poroperm properties). The research was based on the analysis of spatial variations of a number of reservoir parameters: the reservoir net thickness, lithological composition and poroperm properties. The analysis of variations in the net thickness and poroperm properties of the VII horizon of the Garadagh gas condensate field was carried out based on the data of geophysical logging of about 40 wells and studying more than 90 core samples. The data on of more than 90 wells formed the basis for the spacial productivity variation analysis. The analysis of productivity variation in the space of well technological characteristics (based on data from 18 wells) in the Garadagh underground gas storage (UGS) was carried out through the example of the volume of cyclic gas injection and withdrawal in 2020–2021 season. The studies allowed revealing non-uniform spacial variations in the volumes of injected and withdrawn gas at the Garadagh UGS, created in the corresponding depleted gas condensate reservoir. The features of the UGS exploitation conditions are in good agreement with the features of the reservoir development conditions (variations in the well productivity). The inherited nature of the reservoir development and the underground gas storage exploitation is substantiated by the reservoir heterogeneity caused by the spatial variability of the reservoir lithological composition and poroperm properties. Assessing and taking into account the reservoir heterogeneity when designing underground gas storage exploitation conditions should be an important prerequisite for increasing UGS exploitation efficiency.

scholarly journals Progress on Modeling of Dynamic Productivity of Fractured Gas Condensate Reservoir Based on a Fluid-Solid Coupling Method

2021 ◽  
Vol 9 ◽  
Author(s):  
Shuai Wang ◽  
Xianhong Tan ◽  
Yang Xia ◽  
Bo Tian ◽  
Bin Liang
Keyword(s):  
Pressure Gradient ◽  
Large Scale ◽  
Eastern China ◽  
Gas Condensate ◽  
Dew Point ◽  
Coupling Method ◽  
Low Permeability ◽  
Gas Field ◽  
Condensate Reservoir ◽  
Starting Pressure Gradient

Bozhong 19-6 gas field is the first discovered large-scale gas condensate field in eastern China, which is also one of the largest metamorphic rock gas condensate fields in the world. It is a buried hill type, low permeability reservoir, with ultra-high condensate content where the fluid is nearly at its dew point pressure. No similar experience with such reservoirs have previously been reported in the context of gas field development in China and step-by-step progresses is been made to characterize this reservoir. Overall, documentation concerning this type of reservoir is rarely seen worldwide. This paper includes key successful results from multiple perspectives including experiments correlations, numerical modeling and the significance of incorporating certain details. Based on a fluid-solid coupling method, the simulations consider several factors including the fracture distribution, low permeability, medium deformation, and condensate characteristics, as well as their effects on the gas productivity. In the laboratory experiments, the stress sensitivity of the rock was tested using representative core samples. Here, experiment-based correlations of the starting pressure gradient of the gas condensate reservoir are proposed. The starting pressure gradient of different fluid types, such as black oil and gas condensate are highlighted as accurately simulating the reservoir. As a result, the numerical model to predict the dynamic productivity of a single well was successfully established considering all those factors. This paper can serve as a reference for studying other studies of metamorphic, fractured gas condensate reservoirs.

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