Computation and Interpretation of Capillary Pressure From a Centrifuge

Skuse, Brian; Firoozabadi, Abbas; Ramey, H.J.

doi:10.2118/18297-pa

Cited by 13 publications

(10 citation statements)

References 15 publications

(8 reference statements)

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“…The highest belongs to gas phase, the lowest one corresponds to liquid phase, and the intermediate one has no physical meaning. In some cases, the negative pressure determines the liquid phase density (see panel b of Figure 1) 89,93 . CPA EOS exhibits a behavior similar to cubic EOSs at the acceptable branches.…”

Section: Resultsmentioning

confidence: 99%

“…This eventually causes a decrease in the droplet radius (see Figure ). It should be mentioned that the liquid phase pressure in some cases will become negative that has a physical meaning (see Figure and refs and ) when the attraction parameter is fixed at a = 4/49. The thermodynamic inconsistency is notable; however, Li et al suggested a method to improve the thermodynamic consistency by improving the forcing scheme.…”

Section: Results and Discussionmentioning

confidence: 99%

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Central-Moments-Based Lattice Boltzmann for Associating Fluids: A New Integrated Approach

2020

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Dynamic and thermodynamic behavior of associating fluids play a crucial role in a variety of engineering and science disciplines. Cubic plus association equation of state (CPA EOS) is implemented in a central-moments-based lattice Boltzmann method (LBM) in order to mimic the thermodynamic behavior of associating fluids. The pseudopotential approach is selected to model the multiphase thermodynamic characteristics such as reduced density of associating fluids. The priority of central moments-based approach over multiple-relaxation-time collision operator is shown by performing double shear layers. The integration of central-moments-based LBM and CPA EOS is useful to simulate associating fluids at high flow rate conditions, which is extended to high-density ratio scenarios by increasing the anisotropy order of gradient operator. In order to increase the stability of the model, a higher anisotropy order of the gradient operator is implemented; about 34 present reduction in spurious velocities is noticed in some cases. The type of gradient operator considerably affects the model thermodynamic consistency. Finally, the model is validated by observing a straight line in the Laplace law test. Prediction of thermodynamic behaviours of associating fluids is of significance in biological processes as well as fluid flow in porous media.

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Section: Resultsmentioning

confidence: 99%

Section: Results and Discussionmentioning

confidence: 99%

Central-Moments-Based Lattice Boltzmann for Associating Fluids: A New Integrated Approach

2020

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“…The centrifuge capillary pressure curve result was calculated using the methodology published in the literature (25) .…”

Section: Resultsmentioning

confidence: 99%

Gravity Drainage-Lab Tests, Relative Permeability Calculation, and Field Simulation

Bonet

Cunha

Corrêa

et al. 2004

Journal of Canadian Petroleum Technology

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In order to confirm the expected high recoveries obtained in gravity drainage field operations we performed a series of lab tests, developed an oil relative permeability calculation, and used this data to conduct a reservoir simulation for a Brazilian offshore oil field. The lab tests were conducted at ambient temperature and low pressure, and were performed in long cores (90 - 252 cm long) with dead oil and conventional production where the oil was produced at the lower end of the vertically oriented core and air entered the upper end. For one test we performed a counter-current drainage test using live oil where the production was collected at the lower end of the core and the liberated dissolved gas was removed counter-currently from the upper end. The saturation evolution inside the core was monitored by an X-Ray system. Using the same rock and fluids, centrifuge tests were performed using 3 - 4 cm long plugs to compare to the core displacement test results. When the results did not agree, an explanation for the variance using a model of bundles of capillary tubes was postulated. Verification using the principle of minimum energy was performed. A computer program was implemented to calculate the oil relative permeability using the lab data, the results of which were compared with the published literature. The calculated relative permeability was used to simulate the behaviour of a Brazilian offshore oil field that was initially exploited with water injection, and then, due to the appearance of a secondary gas cap, subsequently subjected to gas injection into the crest of the structure. Introduction Numerous papers describe lab test results concerning gravity drainage(2–4, 7, 8, 10, 12, 14, 16, 19, 23, 24, 26, 27). We present the results of gravity drainage long core tests and centrifuge tests using samples with identical rock and fluid properties. In those situations where the results of the two methods did not agree, we calculated the results by considering a bundle of capillary tubes to understand the difference. The long core tests showed, in accordance with the literature, a very low residual oil saturation at the top of the core. The results of these tests were used to calculate the oil relative permeability to be used in to simulate the performance of an offshore Brazilian oil field with a 110.6 MMSTm3 OOIP has been under production for 13 years under peripheral water injection and, due to the appearance of a secondary gas cap, has been supplemented with a crestal gas injection. After a history match, we performed the production forecast for both water and combined water and gas injection. Methodology of the Experimental Tests Long Core Tests After the traditional core mounting process, the sequence of the tests can be summarized in the following steps:Measurement of rock and fluid properties;Water saturation of the sample under vacuum;Displacing the water by oil and establishing the initial water saturation; and,Drainage of oil in the presence of air.

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“…Just one year later in 1945 Hassler and Brunner presented a first mathematical model, which -with refinements -is still widely used in the petroleum industry today [5]. They presented a simple approximation to convert average saturation to end-face saturation [6]. Comparison with results found by porous-plate method showed good agreement of the drainage capillary pressure curves [7].…”

Section: Scheme 1) Possible Mechanisms For Fluid Loss During a Stimulmentioning

confidence: 98%

Measuring Capillary Pressure Tells More Than Pretty Pictures

Pagels

Hinkel²,

Willberg

2012

All Days

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Exploitation of shale reserves requires injection of large quantities of water-based fluids during hydraulic fracturing treatments. Damage to the fracture conductivity and to the near-fracture matrix permeability caused by residual water can be avoided by optimizing fracture cleanup. The wide variation in mineralogy, texture and lithology of kerogen rich shales entails a substantial variation in the wetting characteristics of these rocks on all scales, whether one is comparing rock from different reservoirs, formations, or even different zones within a formation. It is therefore critical to evaluate shale/fluid interactions. The contact angle is a quantitative measure of the relative wettability of a substrate with respect to two fluids brought into contact with it. To understand dynamic processes in the reservoir, dynamic contact angles need to be measured. Dynamic contact angles (advancing/imbibing and receding/draining fluids) differ substantially from static contact angles. For fracture cleanup the receding contact angle is most relevant. Obviously, static goniometer measurements that are presently used in the industry to infer fluid behavior within the rock matrix give wrong results that do not reflect the mixed wettability of shales with diverse pore types. The results of a macroscopic goniometer measurement, obtained on a polished surface cannot be projected down to pore scale with rough and diverse surfaces. In this document, we present a rapid and practical method to measure the saturation dependent capillary pressure in a shale sample pack. A new method has been developed to measure threshold pressures and receding contact angles on freshly prepared shale and mudstone surfaces. We introduce a fluid retention ratio as a meaningful way to directly compare additive performance with regards to fracture cleanup. This method is used to screen treatment fluid additives on a reasonably small amount of formation material. Rock samples from different shale formations have been tested with various additives. Measurement results show that different additives behave differently when exposed to shales from different reservoirs; different responses are even observed from well to well in the same reservoir and zone to zone in the same well.

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Computation and Interpretation of Capillary Pressure From a Centrifuge

Cited by 13 publications

References 15 publications

Central-Moments-Based Lattice Boltzmann for Associating Fluids: A New Integrated Approach

Central-Moments-Based Lattice Boltzmann for Associating Fluids: A New Integrated Approach

Gravity Drainage-Lab Tests, Relative Permeability Calculation, and Field Simulation

Measuring Capillary Pressure Tells More Than Pretty Pictures

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