An introduction to reservoir engineering: Advances in conventional and unconventional recoveries

Satter, Abdus; Iqbal, Ghulam M.

doi:10.1016/b978-0-12-800219-3.00001-2

Cited by 18 publications

(26 citation statements)

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“…There is, however, more data needed to ensure that this correlation is valid beyond the experimental conditions reported here. An additional factor favoring larger droplets might be the enhanced compressibility of the gas-saturated oil compared to the “dead” oil: The local shear stress leading to breakup of droplets could be partly absorbed by the higher elasticity of the droplets. This temporary compression of the “live” oil would reduce the turbulent kinetic energy of the jet, resulting in fewer breakups and a larger median diameter.…”

Section: Resultsmentioning

confidence: 99%

Oil Droplet Size Distributions in Deep-Sea Blowouts: Influence of Pressure and Dissolved Gases

Malone

Pesch

Schlüter

et al. 2018

Environ. Sci. Technol.

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To date, experimental investigations to determine the droplet size distribution (DSD) of subsea oil spills were mostly conducted at surface conditions, i.e. at atmospheric pressure, and with dead, i.e. purely liquid, oils. To investigate the influence of high hydrostatic pressure and of gases dissolved in the oil on the DSD, experiments with a downscaled blowout are conducted in a high-pressure autoclave at 150 bar hydrostatic pressure. Jets of "live", i.e. methane-saturated, crude oil and n-decane are compared to jets of "dead" hydrocarbon liquids in artificial seawater. Experiments show that methane dissolved in the liquid oil increases the volume median droplet diameter significantly by up to 97%. These results are not in good accordance with state-of-the-art drop formation models, which are based on oil-only experiments at atmospheric pressure, and therefore show the need for a modification of such models which incorporates effects of hydrostatic pressure and dissolved gases for the modeling of deep-sea oil spills and blowouts.

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Section: Resultsmentioning

confidence: 99%

Oil Droplet Size Distributions in Deep-Sea Blowouts: Influence of Pressure and Dissolved Gases

Malone

Pesch

Schlüter

et al. 2018

Environ. Sci. Technol.

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“…The fluid saturation can be defined as the percent or fraction of the pore volume occupied by that fluid. The total sum of all fluid volume (oil, water, and gas) must be equal to one . In the early lifetime of an oil reservoir, the zone of oil includes both oil and water or can be changed according to the distance from oil–water contact from zero to one.…”

Section: Introductionmentioning

confidence: 99%

New Correlation for Calculating Water Saturation Based on Permeability, Porosity, and Resistivity Index in Carbonate Reservoirs

et al. 2022

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Water saturation assessment is recognized as one of the most critical aspects of formation evaluation, reserve estimation, and prediction of the production performance of any hydrocarbon reservoir. Water saturation measurement in a core laboratory is a time-consuming and expensive task. Many scientists have attempted to estimate water saturation accurately using well-logging data, which provides a continuous record without information loss. As a result, numerous models have been developed to relate reservoir characteristics with water saturation. By expanding the use and advancement of soft computing approaches in engineering challenges, petroleum engineers applied them to estimate the petrophysical parameters of the reservoir. In this paper, two techniques are developed to estimate the water saturation in terms of porosity, permeability, and formation resistivity index through the use of 383 data sets obtained from carbonate core samples. These techniques are the nonlinear multiple regression (NLMR) technique and the artificial neural network (ANN) technique. The proposed ANN model achieved outstanding performance and better accuracy for calculating the water saturation than the empirical correlation using NLMR and Archie equation with a high coefficient of determination (R 2) of 0.99, a low average relative error of 1.92, a low average absolute relative error of 13.62, and a low root mean square error of 0.066. To the best of our knowledge, the current research establishes a novel foundation using the ANN model in the estimation of water saturation.

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“…Abnormality in injectivity during WAG cycles is one of the main limiting factors preventing better performance . Injectivity is defined as the injection rate over the pressure difference between an injector and a producer . It can be applied to both the water phase and the gas phase during cyclical WAG injection.…”

Section: Introductionmentioning

confidence: 99%

“… 7 Injectivity is defined as the injection rate over the pressure difference between an injector and a producer. 8 It can be applied to both the water phase and the gas phase during cyclical WAG injection. Injectivity loss, therefore, can be defined as the reduction in the amount of water that can be injected for a given pressure differential.…”

Section: Introductionmentioning

confidence: 99%

Wettability Alteration Using Silane to Improve Water-Alternating-Gas Injectivity

2022

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Wettability is a main component that determines multiphase flow characteristics in a porous medium. Altering the wettability of a rock has a wide range of applications in the field of geosystems engineering, such as enhanced oil recovery, improving gas well deliverability, and geological CO2 sequestration. Considering how injectivity in many field water-alternating-gas (WAG) processes is lower than expected, wettability alteration is especially suitable to address the reduction in relative permeability encountered during water injection. Several methods for injectivity improvement exist, including the use of surfactants, nanoparticles, salts, and alkalis. Using silanes to modify wettability has been a prominent technique in surface chemistry for decades but has very rarely been applied to porous mineral rocks, especially carbonates. This work explores the use of silanes to render sandstone and limestone surfaces more hydrophobic, thereby reducing gas blockage that causes injectivity loss. Contact angle measurements were taken and showed good wettability alteration away from water wet, exhibiting contact angles well above 90°, regardless of treatment conditions. Centrifuge tests were carried out, and the resulting residual fluid saturations and capillary pressure curves proved that the treatment is also effective on the pore scale. Corefloods conducted in sandstone and limestone cores showed a 45 and 65% increase in water relative permeability after WAG cycles after treatment, respectively. This translates directly to improvements in injectivity based on this treatment method.

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An introduction to reservoir engineering: Advances in conventional and unconventional recoveries

Cited by 18 publications

References 0 publications

Oil Droplet Size Distributions in Deep-Sea Blowouts: Influence of Pressure and Dissolved Gases

Oil Droplet Size Distributions in Deep-Sea Blowouts: Influence of Pressure and Dissolved Gases

New Correlation for Calculating Water Saturation Based on Permeability, Porosity, and Resistivity Index in Carbonate Reservoirs

Wettability Alteration Using Silane to Improve Water-Alternating-Gas Injectivity

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