Gas-water relative permeability measurement of high temperature and high pressure tight gas reservoirs

Tight-gas reservoirs have low permeability and significant damage. When drilling the tight formations, wellbore liquid invades the formation and increases water saturation of the near wellbore area and significantly deceases permeability of this area. Because of the invasion, the permeability of the invasion zone near the wellbore in tight-gas formations significantly decreases. This damage is mainly controlled by wettability and capillary pressure (Pc). One of the methods to improve productivity of tight-gas reservoirs is to reduce IFT between formation gas and invaded water to remove phase trapping. The invasion of wellbore liquid into tight formations can damage permeability controlled by Pc and relative permeability curves. In the case of drilling by using a water-based mud, tight formations are sensitive to the invasion damage due to the high-critical water saturation and capillary pressures. Reducing the Pc is an effective way to increase the well productivity. Using the IFT reducers, Pc effect is reduced and trapped phase can be recovered; therefore, productivity of the TGS reservoirs can be increased significantly. This study focuses on reducing phase-trapping damage in tight reservoirs by using reservoir simulation to examine the methods, such use of IFT reducers in water-based-drilled tight formations that can reduce Pc effect. The Pc and relative permeability curves are corrected based on the reduced IFT; they are then input to the reservoir simulation model to quantitatively understand how IFT reducers can help improve productivity of tight reservoirs.

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Using relative permeability curves to evaluate phase trapping damage caused by water- and oil-based drilling fluids in tight-gas reservoirs

The APPEA Journal ◽

10.1071/aj11048 ◽

2012 ◽

Vol 52 (1) ◽

pp. 595 ◽

Cited By ~ 1

Author(s):

Geeno Murickan ◽

Hassan Bahrami ◽

Reza Rezaee ◽

Ali Saeedi ◽

Tsar Mitchel

Keyword(s):

Capillary Pressure ◽

Relative Permeability ◽

Drilling Fluid ◽

Tight Gas ◽

Gas Reservoirs ◽

Tight Gas Reservoirs ◽

Water Based ◽

Tight Formations ◽

Relative Permeability Curves ◽

Tight Formation

Low matrix permeability and significant damage mechanisms are the main signatures of tight-gas reservoirs. During the drilling and fracturing of tight formations, the wellbore liquid invades the tight formation, increases liquid saturation around the wellbore, and eventually reduces permeability at the near wellbore zone. The liquid invasion damage is mainly controlled by capillary pressure and relative permeability curves. Due to high critical water saturation, relative permeability effects and strong capillary pressure, tight formations are sensitive to water invasion damage, making water blocking and phase trapping damage two of the main concerns with using a water-based drilling fluid in tight-gas reservoirs.Therefore, the use of an oil-based mud may be preferred in the drilling or fracturing of a tight formation. Invasion of an oil filtrate into tight formations, however, may result in the introduction of an immiscible liquid-hydrocarbon drilling or completion fluid around the wellbore, causing the entrapment of an additional third phase in the porous media that would exacerbate formation damage effects. This study focuses on phase trapping damage caused by liquid invasion using a water-based drilling fluid in comparison with the use of an oil-based drilling fluid in water-sensitive, tight-gas sand reservoirs. Reservoir simulation approach is used to study the effect of relative permeability curves on phase trap damage, and the results of laboratory experiments of core flooding tests in a West Australian tight-gas reservoir are shown, where the effect of water injection and oil injection on the damage of core permeability are studied. The results highlight the benefits of using oil-based fluids in drilling and fracturing of tight-gas reservoirs in terms of reducing skin factor and improving well productivity.

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ANALYSIS OF PRESSURE-DEPENDENT RELATIVE PERMEABILITY IN PERMEABILITY JAIL OF TIGHT GAS RESERVOIRS AND ITS INFLUENCE ON TIGHT GAS PRODUCTION

Journal of Porous Media ◽

10.1615/jpormedia.2019026122 ◽

2019 ◽

Vol 22 (13) ◽

pp. 1667-1683

Author(s):

Fei Mo ◽

Zhimin Du ◽

Xiaolong Peng ◽

Baosheng Liang ◽

Yong Tang ◽

...

Keyword(s):

Relative Permeability ◽

Gas Production ◽

Tight Gas ◽

Gas Reservoirs ◽

Tight Gas Reservoirs

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Overcoming Hydraulic Fracturing Challenges in High Temperature and Tight Gas Reservoirs of Saudi Arabia with an Enhanced Fracturing Fluids System

10.3997/2214-4609-pdb.395.iptc-17686-ms ◽

2014 ◽

Author(s):

S.M. Al-Driweesh ◽

A.A. Dashash ◽

A.R. Malik ◽

J. Leal ◽

E. Soriano ◽

...

Keyword(s):

Saudi Arabia ◽

High Temperature ◽

Hydraulic Fracturing ◽

Tight Gas ◽

Gas Reservoirs ◽

Tight Gas Reservoirs ◽

Fracturing Fluids

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Mitigation of Condensate Banking Using Thermochemical Treatment: Experimental and Analytical Study

Energies ◽

10.3390/en12050800 ◽

2019 ◽

Vol 12 (5) ◽

pp. 800 ◽

Cited By ~ 7

Author(s):

Amjed Hassan ◽

Mohamed Mahmoud ◽

Abdulaziz Al-Majed ◽

Ayman Al-Nakhli ◽

Mohammed Bataweel ◽

...

Keyword(s):

Relative Permeability ◽

Capillary Forces ◽

Co2 Injection ◽

Tight Gas ◽

Reaction Products ◽

Gas Reservoirs ◽

Tight Gas Reservoirs ◽

The Creation ◽

Chemical Activator

Condensate banking is a common problem in tight gas reservoirs because it diminishes the gas relative permeability and reduces the gas production rate significantly. CO2 injection is a common and very effective solution to mitigate the condensate damage around the borehole in tight gas reservoirs. The problem with CO2 injection is that it is a temporary solution and has to be repeated frequently in the field in addition to the supply limitations of CO2 in some areas. In addition, the infrastructure required at the surface to handle CO2 injection makes it expensive to apply CO2 injection for condensate removal. In this paper, a new permanent technique is introduced to remove the condensate by using a thermochemical technique. Two chemicals will be used to generate in situ CO2, nitrogen, steam, heat, and pressure. The reaction of the two chemicals downhole can be triggered either by the reservoir temperature or a chemical activator. Two chemicals will start reacting and produce all the mentioned reaction products after 24 h of mixing and injection. In addition, the reaction can be triggered by a chemical activator and this will shorten the time of reaction. Coreflooding experiments were carried out using actual condensate samples from one of the gas fields. Tight sandstone cores of 0.9 mD permeability were used. The results of this study showed that the thermochemical reaction products removed the condensate and reduced its viscosity due to the high temperature and the generated gases. The novelty in this paper is the creation of micro-fractures in the tight rock sample due to the in-situ generation of heat and pressure. These micro-fractures reduced the capillary forces that hold the condensate and enhanced the rock relative permeability. The creation of micro-fractures and in turn the reduction of the capillary forces can be considered as permanent condensate removal.

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