Download or read book Analysis of Capillary Pressure and Relative Permeability Effects on the Productivity of Naturally Fractured Gas condensate Reservoirs Using Compositional Simulation written by Bander Nasser Al Ghamdi and published by . This book was released on 2009 with total page 125 pages. Available in PDF, EPUB and Kindle. Book excerpt: The developments of gas-condensate reservoirs are highly dependent on the thermodynamic behavior of the fluids in place. During the depletion of gas-condensate reservoirs, the gas condenses as the pressure of the reservoir reduces below the hydrocarbon dew point pressure, which introduces a liquid phase called retrograde condensate. In such conditions, the productivity experience a reduction in recovery due to the appearance of condensate near the production channels, which in turn reduces the overall flow of hydrocarbons to the surface. The phase behavior of the fluids in place impacts the production scheme of gas-condensate reservoirs, since the recovery of condensate is highly dependent on the changes in composition. In this study, the productivity of naturally fractured gas-condensate reservoirs is addressed using a compositional simulation model to examine the effects of capillary pressure and relative permeability on the recovery of gas-condensate fluids. Capillary pressure is a function of saturation and it controls the distribution of fluids in the pore spaces of a reservoir. The role of capillary pressure in the distribution of fluids in the reservoir can become more relevant in naturally fractured reservoirs, where the transport of fluids between the matrix and the fractures depends on the capillary pressure. In addition, the deliverability of gas-condensate reservoirs in such conditions is controlled by the transport properties, which are the relative permeabilities between the fluids in a pore-scale. Therefore, this study is devoted to evaluate the growth of condensate coating by examining different compositions (light/heavy) with the activation of the capillary pressure forces, while keeping the depletion rate constant, and deactivating the diffusion effect in the system. A compositional simulation model was utilized for the evaluation of the influence of fluid characteristics on the severity of condensate coating while assigning tight matrix permeability of 0.001 md, 1 psi/day for depletion rate, and zero capillary pressures. The analysis of the condensate coating on the edges of the matrix blocks lead to the conclusion that the saturation pressure point is controlled by the concentration of heavy components. The sooner the saturation pressure is reached, the sooner condensate appears and hinders the overall recovery of fluids. Using the same conditions applied to the different composition concentration while activating the capillary pressure effect at different pore size distribution indexes (1.5 to 7); the fluid distribution, movement, and recovery, had a similar behavior indicating that the capillary pressure had insignificant influence on the reservoir fluids behavior. On the other hand, the effect of relative permeabilities showed dependency on the amount of condensate content in the reservoir. The more condensation that takes place, the more influence is applied by the relative permeability curves. The major variable that enhanced the oil-gas relative permeability curve was the fracture parameter (ë) obtained by van Genuchten's (1980) to calculate the oil and gas relative permeabilities. Several values were used to address the fracture parameter to influence the position of the oil-gas relative permeability curve. As a result, it appeared that the influence depends on the amount of condensate content in the reservoir. The more condensation that takes place, the more influence is applied by the relative permeability curves.
Download or read book Compositional Three phase Relative Permeability and Capillary Pressure Models Using Gibbs Free Energy written by Sajjad Sadeghi Neshat and published by . This book was released on 2016 with total page 376 pages. Available in PDF, EPUB and Kindle. Book excerpt: Both relative permeability and capillary pressure depend on composition as well as saturation, but classical models neglect this dependence. The objective of this research was to develop coupled three-phase relative permeability and capillary pressure models for implementation in a four-phase flow compositional equation-of-state simulator. The models applied to several complex but practical reservoir simulation problems. Models independent of phase label have many advantages in terms of both numerical stability and physical consistency. Identification of hydrocarbon and aqueous phases based on their molar Gibbs Free Energy (GFE) is a key feature of the new model. Instead of using labels (gas/oil/2nd liquid/aqueous) to define permeability parameters such as end points, residual saturation and exponents, the parameters are continuously interpolated between reference values using the Gibbs free energy of each phase at each time step. Consequently, the formulation used to implement other relevant physical parameters must be consistent with the new approach. A comprehensive but simple vii algorithm was developed for this purpose. The algorithm allows for very general threephase hysteresis in both relative permeability and capillary pressure. An important part of this thesis is analyzing the results of a recent series of experiments on the effect composition on relative permeability. These new data were used to calibrate the new GFE relative permeability model and apply it in a compositional reservoir simulator. The robustness of the new GFE model was shown through complex simulations such as solvent flooding, miscible/immiscible WAG processes, well stimulation processes using solvents to remove condensate and/or water blocks in both conventional and unconventional formations and other challenging applications involving both mass transfer between phases and phase changes. The interpolation of relative permeability parameters based on GFE instead of phase labels completely solves the discontinuity problem caused by phase flipping or misidentification. Therefore, simulations run significantly faster and are physically correct. The novelty of this research is in integrating and unifying relevant physical parameters including trapping number, hysteresis and capillary pressure into one rigorous algorithm with compositional consistency and in the development and application of a practical procedure for numerical compositional reservoir simulations.
Download or read book Naturally Fractured Reservoirs written by Roberto Aguilera and published by PennWell Books. This book was released on 1980 with total page 730 pages. Available in PDF, EPUB and Kindle. Book excerpt: This book deals exclusively with naturally fractured reservoirs and includes many subjects usually treated in separate volumes. A highly practical edition, Naturally Fractured Reservoirs is written for students, reservoir geologists, log analysts and petroleum engineers.
Download or read book Petroleum Abstracts Literature and Patents written by and published by . This book was released on 1990 with total page 1416 pages. Available in PDF, EPUB and Kindle. Book excerpt:
Download or read book Chemical Stimulation of Gas Condensate Reservoirs written by Viren Kumar and published by . This book was released on 2006 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: Well productivity in gas condensate reservoirs is reduced by condensate banking when the bottom hole flowing pressure drops below the dewpoint pressure. Several methods have been proposed to restore gas production rates after a decline due to condensate blocking. Gas injection, hydraulic fracturing, horizontal wells and methanol injection have been tried with limited success. These methods of well stimulation either offer only temporary productivity restoration or are applicable only in some situations. Wettability alteration of the rock in the near well bore region is an economic and efficient method for the enhancement of gas-well deliverability. Altering the wettability of porous media from strongly water-wet or oil-wet to intermediate-wet decreases the residual liquid saturations and results in an increase in the relative permeability to gas. Such treatments also increase the mobility and recovery of condensate from the reservoir. This study validates the above hypothesis and provides a simple and cost-efficient solution to the condensate blocking problem. Screening studies were carried out to identify the chemicals based on structure, solubility and reactivity at reservoir temperature and pressure. Experiments were performed to evaluate these chemicals to improve gas and condensate relative permeabilities. The improvement in relative permeability after chemical treatment was quantified by performing high pressure and high temperature coreflood experiments in Berea sandstone, Texas Cream limestone and reservoir cores using synthetic gas mixtures at reservoir conditions. Experiments were done at high flow rates and for long time periods to evaluate the durability of the treatment. Single well simulation studies were conducted to demonstrate the performance of the chemical treatment in the field. The experimental relative permeability data was modeled using a trapping number dependent relative permeability model and incorporated in the simulations. Effect of connate water saturation, drawdown pressure, skin, treatment radius and the timing of the treatment during the life of the reservoir were investigated using a compositional simulator. Spectroscopic studies using a scanning electron microscope, neutron magnetic resonance and time of flight-secondary ion mass spectroscopy were used to determine the structural and reactive chemistry of the chemicals used and to evaluate the extent of treatment on the rock surface. The study allows us to postulate and partly verify a detailed mechanism of interaction between the rock surface and the chemical.
Download or read book The Journal of Canadian Petroleum Technology written by and published by . This book was released on 2009 with total page 464 pages. Available in PDF, EPUB and Kindle. Book excerpt:
Download or read book A New Relative Permeability Model for Compositional Simulation of Two and Three Phase Flow written by Chengwu Yuan and published by . This book was released on 2010 with total page 612 pages. Available in PDF, EPUB and Kindle. Book excerpt: Chemical treatments using solvents and surfactants can be used to increase the productivity of gas-condensate wells with condensate banks. CMG's compositional simulator GEM was used to simulate such treatments to gain a better understanding of design questions such as how much treatment solution to inject and to predict the benefits of such treatments. GEM was used to simulate treatments in vertical wells with and without hydraulic fractures and also horizontal wells. However, like other commercial compositional simulators, the flash calculations used to predict the phase behavior is limited to two phases whereas a three-phase flash is needed to accurately model the complex phase behavior that occurs during and after the injection of treatment solutions. UTCOMP is a compositional simulator with three-phase flash routine and attempts were made to use it to simulate such well treatments. However, this is a very difficult problem to simulate and all previous attempts failed because of numerical problems caused by inconsistent phase labeling (so called phase flipping) and the discontinuities this causes in the relative permeability values. In this research, a new relative permeability model based on molar Gibbs free energy was developed, implemented in a compositional simulator and applied to several difficult three-phase flash problems. A new way of modeling the residual saturations was needed to ensure a continuous variation of the residual saturations from the three-phase region to the two-phase region or back and was included in the new model. The new relative permeability model was implemented in the compositional reservoir simulator UTCOMP. This new relative permeability model makes it is unnecessary to identify and track the phases. This method automatically avoids the previous phase flipping problems and thus is physically accurate as well as computationally faster due to the improved numerical performance. The new code was tested by running several difficult simulation problems including a CO2 flood with three-hydrocarbon phases and a water phase. A new framework for doing flash calculations was also developed and implemented in UTCOMP to account for the multiple roots of the cubic equation-of-state to ensure a global minimum in the Gibbs free energy by doing an exhaustive search for the minimum value for one, two and three phases. The purpose was to determine if the standard method using a Gibbs stability test followed by a flash calculation was in fact resulting in the true minimum in the Gibbs free energy. Test problems were run and the results of the standard algorithm and the exhaustive search algorithm compared. The updated UTCOMP simulator was used to understand the flow back of solvents injected in gas condensate wells as part of chemical treatments. The flow back of the solvents, a short-term process, affects how well the treatment works and has been an important design and performance question for years that could not be simulated correctly until now due to the limitations of both commercial simulators and UTCOMP. Different solvents and chase gases were simulated to gain insight into how to improve the design of the chemical treatments under different conditions.
Download or read book Petroleum Abstracts written by and published by . This book was released on 1995-04 with total page 572 pages. Available in PDF, EPUB and Kindle. Book excerpt:
Download or read book Alleviation of Effective Permeability Reduction of Gas condensate Due to Condensate Buildup Near Wellbore written by Jose Gilberto Carballo Salas and published by . This book was released on 2006 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: When the reservoir pressure is decreased below dew point pressure of the gas near the wellbore, gas-condensate wells start to decrease production because condensate is separated from the gas around the wellbore causing a decrease in gas relative permeability. This effect is more dramatic if the permeability of the reservoir is low. The idea proposed for reducing this problem is to eliminate the irreducible water saturation near the wellbore to leave more space for the gas to flow and therefore increase the productivity of the well. In this research a simulation study was performed to determine the range of permeabilities where the cylinder of condensate will seriously affect the well's productivity, and the distance the removal of water around the wellbore has to be extended in order to have acceleration of production and an increase in the final reserves. A compositional-radial reservoir was simulated with one well in the center of 109 grids. Three gas-condensate fluids with different heptanes plus compositions (4, 8 and 11mole %), and two irreducible water saturations were used. The fitting of the Equation of State (EOS) was performed using the method proposed by Aguilar and McCain. Several simulations were performed with several permeabilities to determine the permeabilities for which the productivity is not affected by the presence of the cylinder of condensate. At constant permeability, various radii of a region of zero initial water saturation around the wellbore were simulated and comparisons of the effects of removal of irreducible water on productivity were made. Reservoirs with permeabilities lower than 100 mD showed a reduction in the ultimate reserves due to the cylinder of condensate. The optimal radius of water removal depends on the fluid composition and the irreducible water saturation of the reservoir. The expected increase in reserves due to water removal varies from 10 to 80 % for gas production and from 4 to 30% for condensate production.
Download or read book Phase Behavior written by Curtis H. Whitson and published by Society of Petroleum Engineers. This book was released on 2000 with total page 248 pages. Available in PDF, EPUB and Kindle. Book excerpt: Phase Behavior provides the reader with the tools needed to solve problems requiring a description of phase behavior and specific pressure/volume/temperature (PVT) properties.
Download or read book Simultaneous Interpretation of Permeability and Capillary Pressure From Wireline Formation Testing Measurements written by Xiangnan Liu and published by . This book was released on 2019 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: As for designing its appropriate development scheme, it is crucial to accurately determine petrophysical properties (e.g., absolute and relative permeability) of a hydrocarbon reservoir, both of which can be traditionally determined either by performing steady-state or unsteady-state experiments or by conducting conventional well tests. However, the laboratory method is time-consuming and its measurements may not be representative for the field-scale cases. Since the conventional well testing theories are based on single-phase flow, it is a challenging task to accurately obtain relative permeability for multiple phases in porous media. Alternatively, flow rates together with pressure responses collected from a wireline formation testing (WFT) tool can be used to interpret absolute and relative permeability as well as capillary pressure of a given formation. Physically, capillary pressure plays an important role during multiphase flow for the WFT measurements, though its effect on the permeability interpretation has not been addressed. In this study, techniques have been developed to simultaneously interpret absolute permeability and relative permeability together with capillary pressure in a naturally fractured carbonate formation as well as to simultaneously interpret three-phase relative permeability and water-oil capillary pressure in a tight carbonate formation from WFT measurements. By using pressure and flow rate field data collected by a dualpacker WFT tool, high-resolution cylindrical near-wellbore numerical models are developed for each dataset. After validating grid quality, simulations and history matching are performed for both the measured pressure drawdown and buildup profiles, while absolute permeability is determined and relative permeability is interpreted with and without considering capillary pressure for the naturally fractured formation. As for the tight carbonate formation, water-oil relative permeability, oil-gas relative permeability, and water-oil capillary pressure are interpreted based on power-law functions and under the assumption of a water-wet reservoir and an oil-wet reservoir, respectively. Subsequently, three-phase relative permeability for the oil phase is determined by using the modified Stone II model. Compared with the experimentally measured values, relative permeability interpreted with consideration of capillary pressure has a better match than those without considering capillary pressure in the naturally fractured carbonate formation. In such a formation, absolute permeabilities in the vertical and the horizontal directions of the upper layer are determined to be 201.0 mD and 86.4 mD, respectively, while those of the lower layer are found to be 342.9 mD and 1.8 mD, respectively. Such a large vertical permeability of the lower layer reflects the contribution of the extensively distributed natural fractures in the vertical direction. In the tight carbonate formation, both the relative permeability and the capillary pressure of a water-oil system interpreted under an oil-wet condition match well with the measured values, while the relative permeability of an oil-gas system and the three-phase relative permeability bear a relatively high uncertainty. Not only is the tight reservoir determined as oil-wet, but also the initial oil saturation is found to impose an impact on the interpreted water relative permeability under an oil-wet condition. Changes in water and oil viscosities and mud filtrate invasion depth affect the range of the movable fluid saturation of the interpreted water-oil relative permeabilities.
Download or read book Three phase Relative Permeability Effects and Well Productivity for Gas Condensate Reservoirs written by and published by . This book was released on 2009 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt:
Download or read book Journal of Petroleum Technology written by and published by . This book was released on 1990 with total page 1326 pages. Available in PDF, EPUB and Kindle. Book excerpt:
Download or read book Dissertation Abstracts International written by and published by . This book was released on 2008 with total page 994 pages. Available in PDF, EPUB and Kindle. Book excerpt:
Download or read book Society of Petroleum Engineers Journal written by Society of Petroleum Engineers of AIME. and published by . This book was released on 1972 with total page 614 pages. Available in PDF, EPUB and Kindle. Book excerpt:
Download or read book RELATIVE PERMEABILITY OF PETROLEUM RESERVOIRS written by Mehdi Honarpour and published by Springer. This book was released on 1986-01-24 with total page 160 pages. Available in PDF, EPUB and Kindle. Book excerpt:
Download or read book COMPREHENSIVE MODELLING OF GAS CONDENSATE RELATIVE PERMEABILITY AND ITS INFLUENCE ON FIELD PERFORMANCE written by and published by . This book was released on 2005 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: NK so that the new model is more sensitivity to temperature that represents implicitly the effect of interfacial tension. The new model generated the results were in good agreement with the literature data and the laboratory test results. Additionally, the end point relative permeability data and residual saturations satisfactorily correlate with literature data. The proposed model has fairly good fitness results for the condensate relative permeability curves compared to that of gas case. This model, with typical parameters for gas condensates, can be used to describe the relative permeability behavior and to run a compositional simulation study of a single well to better understand the productivity of the field.
