Temperature Dependant Relative Permeabilities End-Points: Laboratory Experiments under Reservoir Conditions from Hot-Water Flood to Steamflood

2018 ◽  
Author(s):  
C. Lamy ◽  
J. Botua ◽  
U. Granone ◽  
J. Hy-Billiot ◽  
A. Brisset
Keyword(s):  
Laboratory Experiments ◽  
Hot Water ◽  
Relative Permeabilities ◽  
End Points ◽  
Reservoir Conditions ◽  
Temperature Dependant

Relative Permeabilities at Simulated Reservoir Conditions

1988 ◽  
Vol 3 (04) ◽  
pp. 1323-1327 ◽  
Author(s):  
Erie C. Donaldson ◽  
Faruk Civan ◽  
M.W. Ul Alam
Keyword(s):  
Relative Permeabilities ◽  
Reservoir Conditions

A New Model to Obtain Representative Field Relative Permeability for Reservoirs Produced under Solution Gas Drive

2005 ◽  
Vol 8 (04) ◽  
pp. 348-356 ◽  
Author(s):  
Fabrice Bauget ◽  
Patrick Egermann ◽  
Roland Lenormand
Keyword(s):  
Relative Permeability ◽  
History Matching ◽  
Phase Transfer ◽  
Bubble Nucleation ◽  
Relative Permeabilities ◽  
Solution Gas Drive ◽  
Reservoir Conditions ◽  
Depletion Rate ◽  
Gas Drive ◽  
Solution Gas

Summary Relative permeability curves (kr) control production and are of primary importance for any type of recovery process. In the case of production by displacement (waterflood or gasflood), the kr curves obtained in the laboratory can be used in numerical simulators to predict hydrocarbon recovery (after upscaling to account for heterogeneity). In the case of reservoirs produced under solution-gas drive (depressurized field, foamy oils), the experiments conducted in the laboratory depend on the depletion rate and cannot be used directly for reservoir simulations. We have developed a novel approach for calculating representative field relative permeabilities. This new method is based on a physical model that takes into account the various mechanisms of the process: bubble nucleation(pre-existing bubbles model), phase transfer (volumetric transfer function), and gas displacement (bubble flow). In our model, we have identified a few"invariant" parameters that are not sensitive to depletion rate and are specific to the rock/fluid system (mainly the pre-existing bubble-size distribution and a proportionality coefficient relating gas and oil velocity for the dispersed-phase regime). These invariant parameters are determined by history matching one experiment at a given depletion rate. The calibrated model is then used to generate synthetic data at any depletion rate, especially at very low depletion rates representative of the reservoir conditions. Relative permeabilities are derived from these"numerical" experiments in the same way as they are from real experiments. The calculated kr is finally used in commercial reservoir simulators. We have tested our model by using several series of published experiments with light and heavy oils. After adjusting the invariant parameters on one or two experiments, we are able to predict other experiments performed at different depletion rates with very good accuracy. Finally, we present an example of determination of relative permeabilities at reservoir depletion rates. Introduction In the case of conventional recovery processes (waterflooding and gasflooding), experiments that are conducted in the laboratory can mimic the conditions that prevail in the reservoir. Hence, the kr data derived from these experiments can be used in a practically straightforward manner for field-simulation purposes (upscaling is often needed to account for heterogeneities). The problem is more complicated for recovery by solution-gas drive. In this case, the laboratory experiments fail in reproducing the reservoir conditions. In reservoirs, the depletion rates are at least several times lower than what can be obtained in the laboratory. Because the depletion rate controls the gas topology (bubble density), the diffusion of gas from solution (out of equilibrium), and the gas displacement (dispersed flow), it also dramatically affects the shape of the kr curves. Therefore, the depletion experiments cannot be used to derive field kr data directly.

scholarly journals Semi-commercial hot water treatments for control of bull’s eye rot of apples

2019 ◽  
Vol 72 ◽  
pp. 284
Author(s):  
Luna Hasna ◽  
Kerry R. Everett ◽  
Michelle J. Vergara ◽  
I.P. Shamini Pushparajah ◽  
Peter N. Wood ◽  
...  
Keyword(s):  
Fungal Pathogen ◽  
Laboratory Experiments ◽  
Hot Water ◽  
Commercial Test ◽  
Commercial Trial ◽  
Fold Reduction ◽  
High Incidence ◽  
Pressure Water ◽  
Bull's Eye ◽  
Water Treatments

Bull’s eye rot (BER) of apples is caused by a postharvest fungal pathogen (Phlyctema vagabunda syn. Neofabraea alba). Previous laboratory experiments found hot water treatments (HWT) resulted in a significant reduction of BER incidence for artificially inoculated fruit so the feasibility of HWT to control naturally infected fruit in a semi-commercial trial was tested. One bin (1934 fruit) of naturally infected ‘Scired’ apples was harvested from a Hawke’s Bay orchard with a known high incidence of BER, then placed in a coolstore for 1 week until treated. All fruit were passed through a high-pressure water blaster then air dried. Approximately half the contents of the bin (1034 fruit) were packed into Friday trays in apple boxes with a plastic polyliner. The other half (900 fruit) were treated for 2 min with hot water at 51°C in a semi-commercial hot water bath before packing. All fruit were then coolstored for 20 weeks before assessment for BER. This HWT resulted in a 6-fold reduction of BER incidence so was an effective treatment for BER in a semi-commercial test.

scholarly journals Characterization of a Reservoir Fluid Based on an Analysis of Intrinsic Properties Using the Adaptive Batzle-Wang Method in Field “M”

2019 ◽  
Vol 17 (2) ◽  
Author(s):  
M. Syamsu Rosid ◽  
Muhammad` Iksan ◽  
Reza Wardhana ◽  
M. Wahdanadi Haidar
Keyword(s):  
Physical Properties ◽  
Laboratory Experiments ◽  
Fluid Model ◽  
Rock Physics ◽  
P Wave ◽  
Fluid Replacement ◽  
Intrinsic Properties ◽  
Temperature Conditions ◽  
Reservoir Conditions ◽  
Fluid Properties

The physical properties and phases of a fluid under reservoir conditions are different from those under surface conditions. The value of a fluid property may change as a result of changes in pressure and temperature. An analysis of the intrinsic properties of fluids is carried out to obtain a fluid model that corresponds to fluid conditions in a reservoir. This study uses the Adaptive Batzle-Wang model, which combines thermodynamic relationships, empirical data trends, and experimental fluid data from the laboratory to estimate the effects of pressure and temperature on fluid properties. The Adaptive Batzle-Wang method is used because the usual Batzle-Wang method is less suitable for describing the physical properties of a fluid under the conditions in the field studied here. The Batzle-Wang fluid model therefore needs to be modified to obtain a fluid model that adjusts to the fluid conditions in each study area. In this paper, the Adaptive Batzle-Wang model is used to model three types of fluid i.e. oil, gas, and water. By making use of data on the intrinsic fluid properties such as the specific gravity of the gases (G), the Gas-Oil Ratio (GOR), the Oil FVF (Bo), the API values, the Salinity, and the Fluid Density obtained from laboratory experiments, the Batzle-Wang fluid model is converted into the Adaptive Batzle-Wang model by adding equations for the intrinsic fluid properties under the pressure and temperature conditions in the field reservoir. The results obtained are the values of the bulk modulus (K), the density (ρ), and the P-wave velocity (Vp) of the fluid under reservoir conditions. The correlation coefficient of the Adaptive Batzle-Wang model with the fluid data from the laboratory experiments is 0.95. The model is well able to calculate the fluid properties corresponding to the conditions in this field reservoir. The model also generates a unique value for the fluid properties in each study area. So, it can adjust to the pressure and temperature conditions of the field reservoir under study. The Adaptive Batzle-Wang method can therefore be applied to fields for which laboratory fluid data is available, especially fields with a high reservoir pressure and temperature. The results of the fluid modeling can then be used for rock physics and Fluid Replacement Model analysis.

Reservoir Conditions Laboratory Experiments of CO2 Injection Into Fractured Cores

2006 ◽  
Author(s):  
Gholam Reza Darvish ◽  
Erik G.B. Lindeberg ◽  
Torleif Holt ◽  
Jon Kleppe ◽  
Svein Arild Utne
Keyword(s):  
Laboratory Experiments ◽  
Co2 Injection ◽  
Reservoir Conditions

Calculation Methods for Linear and Radial Steam Flow in Oil Reservoirs

1983 ◽  
Vol 23 (03) ◽  
pp. 427-439 ◽  
Author(s):  
J. van Lookeren
Keyword(s):  
Laboratory Experiments ◽  
Steam Injection ◽  
Injection Rate ◽  
Hot Water ◽  
Oil Reservoirs ◽  
Steam Flow ◽  
Volatile Components ◽  
Calculation Methods ◽  
Oil Viscosity ◽  
Injection Wells

Abstract The flow of oil and water in a reservoir as a result of steam injection is related to the shape of the growing steam zone. Analytical formulas describing the approximate shape of this zone have been derived both for linear flow in horizontal and dipping formations and for radial flow around injection wells in a horizontal formation. The theory is based on segregated-flow principles such as those previously used by Dupuit,1 Dietz,2 and others. The formulas take into account gravity overlay of steam zones and have been checked against results of scaled laboratory experiments, steam-injction projects in the field, and calculations with a numerical reservoir simulator. From the good agreement with the new calculation method it would seem that the shape of a steam zone is controlled mainly by one group of parameters including steam-injection rate, pressure, and effective formation permeability to steam. The equations can be used to analyze and explain field observations, such as the position of steam/liquid contacts in injection wells, estimates of effective permeability to steam in steam zones, and steam-zone thickness as noticed in observation wells. This paper shows, for example, how a cumulative oil/steam ratio for oil displaced from a steam zone depends on steam-zone pressure, injection rate, and time. With increasing oil viscosity, more bypassing of oil by steam owing to viscous forces will occur, leading to more overlay of steam zones and eventually to narrow tonguing in a lateral direction. The calculation methods provide an evaluation tool for steam drive and steam-soak processes to reservoir engineers engaged in field operations, project design, and research. Introduction The reservoir engineer is often confronted with many day-to-day problems in designing, planning, and starting up steam-injection projects and monitoring their performance analysis and improvement in which fast and simple, although approximate, engineering calculation methods could be used to advantage. By presenting calculation methods for linear and radial steam flow in oil reservoirs, a tool is provided to gain a better understanding of the shape and growth of steam zones in reservoirs subjected to steam injection. A selection has been made from reservoir engineering literature, laboratory experiments, and field data to introduce the essentials of the calculation methods for making estimates with respect to performance, sweep efficiency, optimization, etc., of steam-injection processes in actual oil reservoirs. Oil displaced from steam zones is calculated, but no attempt has been made to arrive at a full prediction tool for oil production from reservoirs by adding calculations for oil quantities displaced by cold- and hot-water drives and even miscible drives, if the oil has volatile components. With the present capacities of mathematical reservoir simulation programs, adequate integration of simultaneously occurring oil-displacement processes seems more appropriate for the large computer.

A New Tool-less Layered Fracturing Technology and Its Pilot Application in Deep Thick Formations

2016 ◽  
Author(s):  
Daobing Wang ◽  
Fujian Zhou ◽  
Hongkui Ge ◽  
Xiongfei Liu ◽  
Sergio Zlotnik ◽  
...  
Keyword(s):  
Pressure Difference ◽  
Laboratory Experiments ◽  
Degradation Rate ◽  
Oil Reservoir ◽  
Great Success ◽  
Test Results ◽  
Reservoir Conditions ◽  
Net Pressure ◽  
Temperature And Pressure ◽  
Fiber Ball

ABSTRACT Multi-layer fracturing technology is challenging because of the risk of packer failure and high cost in the deep thick formation. It depends largely on the effectiveness of packer tools. However, a new degradable fiber ball could be successfully used to temporarily block the open perforations, and then the layer with higher fracturing pressure is broken down. This paper presents a new tool-less layered fracturing technique and its pilot test results with this special material. A series of laboratory experiments were conducted to evaluate the feasibility of this new technique. Degradable fiber balls were applied to perforated pipes under simulated reservoir conditions. The ball carried by the fluid first sealed the perforation holes and then increased the pressure in the pipe to simulate the resistance to pressure. In addition, the fluid was heated up to 140°C to simulate the degradation rate of fiber balls. Throughout these processes, the flow rate, temperature and pressure were continuously monitored for subsequent analysis. Experimental and application results showed that: (1) fiber balls could be thoroughly degraded at 140°C temperature after six hours; (2) at a pressure difference of 50-70MPa, its deformation rate was less than 1.5%, which indicated its higher compression capability; (3) it could effectively block the perforation holes at 90°C and a pressure difference of 20MPa; (4) The blockage of perforations by the fiber ball could significantly enlarge the net pressure in the wellbore. This technique was applied for 35 wells in a deep and thick oil reservoir, which had achieved a great success and the post-treatment oil production was enhanced by 50-60% compared with conventional stimulation techniques.

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