scholarly journals Study on the relationship between the water cutting rate and the remaining oil saturation of the reservoir by using the index percolating saturation formula with variable coefficients

2020 ◽  
Vol 10 (8) ◽  
pp. 3649-3661
Author(s):  
Meiling Zhang ◽  
Jiayi Fan ◽  
Yongchao Zhang ◽  
Yinxin Liu
Keyword(s):  
Relative Permeability ◽  
Water Saturation ◽  
Variable Coefficients ◽  
Absolute Permeability ◽  
Oil Saturation ◽  
Rock Samples ◽  
Remaining Oil ◽  
Cutting Rate ◽  
Water Cutting ◽  
The Relationship

Abstract The water cutting rate is recorded dynamically during the production process of a well. If the remaining oil saturation of the reservoir can be deduced based on the water cutting rate, it will give guidance to improve the reservoir recovery and can save expensive drilling costs. In the oil–water two-phase seepage experiment on core samples, the oil and water relative permeability reflects the relationship between the water cutting rate and water saturation, that is, percolating saturation formula. The relative permeability test data of 17 rock samples from six seal coring wells in Daqing Changyuan were used to optimize and construct the coefficients of the index percolating saturation formula that vary with the pore structure parameters of reservoirs, to form an index percolating saturation formula with variable coefficients that is more consistent with the regional geological characteristics of the reservoir. Based on this, the formula of water saturation calculated by the water cutting rate is deduced. And the high-precision formula for calculating the irreducible water saturation and residual oil saturation by effective porosity, absolute permeability, and shale content is given. The derivative formula of water saturation on the water cutting rate was established, and the parameters of 17 rock samples were calculated. It was found that the variation velocity of water saturation of each sample with the water cutting rate presented a “U” shape, which was consistent with the actual characteristics that the variation velocity of the water saturation in the early, middle, and late stages of oilfield development first decreased, then stabilized, and finally increased rapidly. The research results were applied to the prediction of remaining oil saturation in the research area, and the water saturation about six producing wells was calculated by using their present water cutting rates, and the remaining oil distribution profile was predicted effectively. The analysis of four layers of two newly drilled infill wells and reasonable oil recovery suggestions were given to achieve good results.

Oil Saturation Log Prediction Using Neural Network in New Steamflood Area

2020 ◽  
Author(s):  
A. Syahputra
Keyword(s):  
Neural Network ◽  
Water Saturation ◽  
Prediction Method ◽  
Neural Model ◽  
Training Model ◽  
Acquisition Time ◽  
Oil Saturation ◽  
Full Field ◽  
Remaining Oil ◽  
Observation Wells

Surveillance is very important in managing a steamflood project. On the current surveillance plan, Temperature and steam ID logs are acquired on observation wells at least every year while CO log (oil saturation log or SO log) every 3 years. Based on those surveillance logs, a dynamic full field reservoir model is updated quarterly. Typically, a high depletion rate happens in a new steamflood area as a function of drainage activities and steamflood injection. Due to different acquisition time, there is a possibility of misalignment or information gaps between remaining oil maps (ie: net pay, average oil saturation or hydrocarbon pore thickness map) with steam chest map, for example a case of high remaining oil on high steam saturation interval. The methodology that is used to predict oil saturation log is neural network. In this neural network method, open hole observation wells logs (static reservoir log) such as vshale, porosity, water saturation effective, and pay non pay interval), dynamic reservoir logs as temperature, steam saturation, oil saturation, and acquisition time are used as input. A study case of a new steamflood area with 16 patterns of single reservoir target used 6 active observation wells and 15 complete logs sets (temperature, steam ID, and CO log), 19 incomplete logs sets (only temperature and steam ID) since 2014 to 2019. Those data were divided as follows ~80% of completed log set data for neural network training model and ~20% of completed log set data for testing the model. As the result of neural model testing, R2 is score 0.86 with RMS 5% oil saturation. In this testing step, oil saturation log prediction is compared to actual data. Only minor data that shows different oil saturation value and overall shape of oil saturation logs are match. This neural network model is then used for oil saturation log prediction in 19 incomplete log set. The oil saturation log prediction method can fill the gap of data to better describe the depletion process in a new steamflood area. This method also helps to align steam map and remaining oil to support reservoir management in a steamflood project.

The Effect of Temperature on Relative and Absolute Permeability of Sandstones

1975 ◽  
Vol 15 (05) ◽  
pp. 376-384 ◽  
Author(s):  
R.M. Weinbrandt ◽  
H.J. Ramey ◽  
F.J. Casse
Keyword(s):  
Relative Permeability ◽  
Temperature Increase ◽  
Absolute Permeability ◽  
Effect Of Temperature ◽  
Residual Oil ◽  
Relative Permeabilities ◽  
Permeability Ratio ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
The Individual

MEMBERS SPE-AIME Abstract Equipment was constructed to perform dynamic displacement experiments on small core samples under conditions of elevated temperature. Oil-water flowing fraction and pressure drop were recorded continuously for calculation of both the relative permeability ratio and the individual relative permeability ratio and the individual relative permeabilities. Imbibition relative permeabilities permeabilities. Imbibition relative permeabilities were measured for five samples of Boise sandstone at room temperature and at 175deg.F. The fluids used were distilled water and a white mineral oil. The effect of temperature on absolute permeability was investigated for six Boise sandstone samples and two Berea sandstone samples. Results for all samples were similar. The irreducible water saturation increased significantly, while the residual oil saturation decreased significantly with temperature increase. The individual relative permeability to oil increased for all water saturations below the room-temperature residual oil saturation, but the relative permeability to water at flood-out increased with permeability to water at flood-out increased with temperature increase. Absolute permeability decreased with temperature increase. Introduction Test environment is generally acknowledged to have a significant effect on measurement of relative permeability. The environment consists not only permeability. The environment consists not only of the temperature and pressure, but also of the fluids used and the core condition. Several workers have used the approach of completely simulating the reservoir conditions in the laboratory experiment. Such methods are termed "restored state." Restored state data are generally different from "room condition" data; since several variables are involved, it is difficult to determine the importance of each variable. Another approach used attributes the changes in relative permeability to changes in the rock-fluid interaction or wettability. Wettability, however, depends on many variables. Specifically, wettability depends on the composition of the rock surface, the composition of the fluids, the saturation history of the rock surface, and the temperature and pressure of the system. The purpose of this study is to isolate temperature as a variable in the relative permeability of a given rock-fluid system. Work on isolation of temperature as a variable in relative permeability has been conducted since the early 1960s. Edmondsons established results in 1965 for a Berea sandstone core using both water/refined oil and water/crude oil as fluid pairs. He showed a change in the relative permeability ratio accompanied by a decrease in the residual oil saturation with temperature increase. Edmondson showed no data for water saturations below 40 percent, and his curves show considerable scatter in the middle saturation ranges. Edmondson's work was the only study to use consolidated cores to investigate the effect of temperature on relative permeability measurements. Poston et al. presented waterflood data for sand packs containing 80-, 99-, a nd 600-cp oil, and packs containing 80-, 99-, a nd 600-cp oil, and observed an increase in the individual relative permeabilities with temperature increase. The permeabilities with temperature increase. The increase in the oil and the water permeability was accompanied by an increase in irreducible water saturation and a decrease in the residual oil saturation with temperature increase. Poston et al. was the only work to present individual oil and water permeability. Davidsons presented results for displacement of No. 15 white oil from a sand pack by distilled water, steam, or nitrogen. However, he found little permeability-ratio dependence in the middle permeability-ratio dependence in the middle saturation ranges. Davidson, too, found a decrease in the residual oil saturation with temperature increase, but he did not include data on irreducible water saturation. SPEJ P. 376

Experimental Study on Effect of Temperature on Heavy Steam/Oil Relative Permeability

2014 ◽  
Vol 522-524 ◽  
pp. 1562-1566
Author(s):  
Li Ping He ◽  
Ping Ping Shen ◽  
Qi Chao Gao ◽  
Meng Chen ◽  
Xiang Yang Ma
Keyword(s):  
High Precision ◽  
Relative Permeability ◽  
Water Saturation ◽  
Laboratory Simulation ◽  
Effect Of Temperature ◽  
Oil Saturation ◽  
Steam Flooding ◽  
Irreducible Water Saturation ◽  
Relative Permeability Curves ◽  
Base Data

Because of the instability of steam and tough requirement of HTHP equipments in steam flooding laboratory simulation, it is rather difficult to obtain representative Steam/Oil relative permeability curves with high precision. In addition, although the effect of temperature on Water/Oil relative permeability curves has been studied a lot both at home and aboard, there are still some controversy perspectives, and research on temperature effect on Steam/Oil relative permeability is rare. As to the above issue, an improved steam flooding experimental method is launched to obtain accurate base data, and then simplified JBN method is applied for data processing. The Result revealed that the improved experimental methods and simplified JBN formulas can obtain representative Steam/Oil relative permeability with high precision, and temperature affects steam/oil relative permeability in various aspects, as temperature increased, oil relative permeability and irreducible water saturation increased while steam relative permeability and residual oil saturation decreased.

scholarly journals Promediando curvas de permeabilidad relativa en yacimientos de metano en mantos de carbón con flujo bifásico en Queensland, Australia.

2017 ◽  
Vol 4 (1) ◽  
pp. 129-140
Author(s):  
Jorge Ordóñez ◽  
José Villegas ◽  
Alamir Alvarez
Keyword(s):  
Relative Permeability ◽  
Water Saturation ◽  
Single Layer ◽  
Absolute Permeability ◽  
Phase Flow ◽  
Two Phase ◽  
Desorption Process ◽  
Gas Desorption ◽  
Relative Permeability Curves ◽  
Single Set

En el presente trabajo se propone el uso de un único set de curvas de permeabilidad a ser empleado en los estudios de simulación y caracterización de yacimientos de gas en mantos de carbón (CBM), en vez del uso común de un set de curvas para cada estrato individual. Para comprobar la aplicabilidad de este procedimiento, se simula un yacimiento usando ambos métodos: el resultado de producción debe ser similar en ambas simulacionesEl modelo para promediar la permeabilidad absoluta en un flujo monofásico, fue usado para el caso de predecir un promedio de permeabilidad relativa para un yacimiento con flujo bifásico. Luego de correr varios casos y corroborar que la ecuación propuesta no cumplía las expectativas, el enfoque del trabajo fue explicar el por qué del no funcionamiento de la ecuación propuesta. Una posible explicación fue la no consideración de la gravedad, que acorde a varias simulaciones presentadas, es un parámetro principal en las curvas de producción. La saturación de agua tampoco puede excluirse de la ecuación que prediga este promedio.  Por tanto si se quiere presentar una ecuación para el cálculo de promedio de permeabilidades relativas, es fundamental que tanto la gravedad como la saturación de agua estén incluidas en esta ecuación.Abstract This paper tries to average relative permeability in a way that instead of using different sets of relative permeability curves to different layers, one single set could be used in one single layer, and to get similar production results as if different layers and different relative permeability were used instead. The model to average absolute permeability in a single-phase flow system was used to predict two-phase flow average relative permeability. After running different cases and corroborating that the equation proposed did not match the expectations. The focus of this work was changed in order to explain why the equation was not working. A possible explanation of why the equation is not accurate could be that the equation is not considering the influence of gravity. Gravity plays a very important role in reservoirs. After gas desorption process occurs, free gas migrates to top layers and water migrates to bottom layers. Water saturation could not be excluded from the equation that averages relative permeability curves. The effects of gravity should be considered too, if you want to get an equation to predict production behaviour by using one average equation in a single layer.

scholarly journals Geophysical appraisal for the sandy levels within Abu Roash C and E members in Abu Gharadig Field, Western Desert, Egypt

2021 ◽  
Vol 11 (3) ◽  
pp. 1101-1122
Author(s):  
Mohammad Abdelfattah Sarhan
Keyword(s):  
Relative Permeability ◽  
Water Saturation ◽  
Effective Porosity ◽  
Western Desert ◽  
Absolute Permeability ◽  
Normal Faults ◽  
Shale Volume ◽  
Bulk Volume ◽  
Zone Ii ◽  
Water Cut

AbstractThe present work concerns with the geophysical assessment for the sandstones of Abu Roash C and E members for being potential hydrocarbon reservoirs at Abu Gharadig Field, Western Desert, Egypt. The analysis of seismic data covers Abu Gharadig Field showing ENE–WSW anticline fragmented by NW–SE normal faults. The presence of these structures is due to the dextral wrench corridor that extensively deformed the north area of the Western Desert within Late Cretaceous episode. The examination of well-log data of Abu Gharadig-6 Well revealed that the favourable zone locates between depths 9665–9700 ft (zone I) within Abu Roash “C” Member. The second promising zone in Abu Gharadig-15 Well occurs between depths 9962–9973 ft (zone II) in Abu Roash “E” Member. The quantitative evaluation indicated that zone I has better reservoir quality than zone II since it is characterised by low shale volume (0.01), high effective porosity (0.22), low water saturation (0.14), low bulk volume of water (0.03), higher values of absolute permeability (113 mD), high relative permeability to oil and low water cut, whereas zone II has 0.13 shale volume, 0.16 effective porosity, 0.39 water saturation, 0.06 bulk volume of water, lower values of absolute permeability (27 mD), low relative permeability to oil and relatively high water cut. The obtained results recommended that the drilling efforts should be focused on the sandy levels within Abu Roash C Member (1st priority) and the sand levels within Abu Roash E Member (2nd priority) in Abu Gharadig Basin and its surroundings.

An Approach for Exploring the Application of the Flow Zone Index Concept in Describing Petrophysical Properties Using Available SCAL Data Relative Permeability

2021 ◽  
Author(s):  
Efeoghene Enaworu ◽  
Tim Pritchard ◽  
Sarah J. Davies
Keyword(s):  
Relative Permeability ◽  
Water Saturation ◽  
Petrophysical Properties ◽  
Residual Oil ◽  
Flow Zone ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Core Samples ◽  
Irreducible Water Saturation ◽  
Permeability Data

Abstract This paper describes a unique approach for exploring the Flow Zone Index (FZI) concept using available relative permeability data. It proposes an innovative routine for relating the FZI parameter to saturation end-points of relative permeability data and produces a better model for relative permeability curves. In addition, this paper shows distinct wettabilities for various core samples and validated functions between FZI and residual oil saturation (Sor), irreducible water saturation (Swi), maximum oil allowed to flow (Kro, max), maximum water allowed to flow (Krw, max),and mobile/recoverable oil (100-Swi-Sor). The wettability of the core samples were defined using cross-plots of relative permeability of oil (Kro), relative permeability of water (Krw), and water saturation (Sw). After classifying the data sets into their respective wettabilities based on these criteria, a stepwise non-linear regression analysis was undertaken to develop realistic correlations between the FZI parameter, initial water saturation and end-point relative permeability parameters. In addition, a correlation using Corey's type generalised model was developed using relative permeability data, with new power law constants and well defined curves. Other parameters, including Sor, Swi, Kro, max, Krw,max and mobile oil, were plotted against FZI and correlations developed for them showed unique well behaved plots with the exception of the Sor plot. A possible theory to explain this unexpected behaviour of the FZI Vs Sor cross plot was noted and discussed. These derived functions and established relationships between the FZI term and other petrophysical parameters such as permeability, porosity, water saturation, relative permeability and residual oil saturation can be applied to other wells or reservoir models where these key parameters are already known or unknown. These distinctive established correlations could be employed in the proper characterization of a reservoir as well as predicting and ground truthing petrophysical properties.

scholarly journals Seepage Characteristics of a Low Permeability Sandstone Reservoir in Mobei Oilfield, Junggar Basin

Lithosphere ◽  
2021 ◽  
Vol 2021 (Special 4) ◽  
Author(s):  
Qi Lisha ◽  
Jiang Zhibin ◽  
Wang Xiaowei ◽  
Wang Jie ◽  
Qian Chuanchuan
Keyword(s):  
Relative Permeability ◽  
Water Saturation ◽  
Junggar Basin ◽  
Water Phase ◽  
Low Permeability ◽  
Two Phase ◽  
Oil Saturation ◽  
Large Channel ◽  
Sandstone Reservoir ◽  
Water Cut

Abstract The microscopic pore structure characteristics and the oil-water two-phase seepage law in the low permeability sandstone reservoir in Mobei oilfield in Junggar Basin were analyzed through laboratory experiments. The results of mercury pressure, constant velocity mercury pressure, thin slice of casting, and CT scan analyses showed that the reservoir had strong microheterogeneity with the presence of local large channels. The large channel had a small volume but considerably contributed to the permeability, which played a crucial role in the reservoir seepage. The relative permeability curve showed that with the increase of water saturation, the relative permeability of the oil phase decreased rapidly; the water phase relative permeability of glutenite, gravel-bearing sandstone, and coarse sandstone increased slightly; and the water cut increased rapidly. The relative permeability of the water phase of medium and fine sandstone increased, the water cut increased rapidly, and the residual oil saturation was high. In the process of core displacement, on-line CT scanning monitoring showed that before the breakthrough of the water drive front, the oil saturation decreased greatly along the way. After the breakthrough of the water drive front, the water cut increased rapidly and directly entered the ultrahigh water cut stage. Owing to the serious heterogeneity of the micropore structure, the fingering phenomenon was obvious in the process of displacement.

Experimental Study of Temperature Effect on Oil Relative Permeability in Porous Media

2013 ◽  
Vol 336 ◽  
pp. 19-27 ◽  
Author(s):  
Mohammad Afkhami Karaei ◽  
Ali Ahmadi ◽  
Hooman Fallah ◽  
Abdolreza Dabiri
Keyword(s):  
Porous Media ◽  
Relative Permeability ◽  
Water Saturation ◽  
Water Injection ◽  
Thermal Recovery ◽  
Engine Oil ◽  
Absolute Permeability ◽  
Scale Model ◽  
Oil Viscosity ◽  
Different Diameters

In the modeling of thermal recovery processes of heavy oil, it is important to know the oil primary relative permeability in the reservoir; moreover we have to be aware of effects of the temperature on oil relative permeability as well. In this study, a sand pack of quartz (SiO2) has been used to simulate and make a porous medium. Quartz is naturally water wet. During experiments there was no change in the pore volume of the media at different temperatures because of the low expansion coefficient of quartz. The fluid used in experiments is engine oil 50. Glass pipes with length of 91cm and diameter of 2.6cm have been used in the experiments. At first, columns have been filled with sand, which sand grains had different diameters, then carbon dioxide was injected to the columns to deplete the air in the pores , then the porous media have been saturated with water to calculate the porosity using the scale model. In addition according to Darcys law in steady state, the absolute permeability was calculated. In the next step, oil was injected to columns until the water saturation reached connate water saturation and finally, water injection was begun to get residual oil saturation (Sor). Experiments results showed that increase of temperature increases the oil relative permeability, note that wetability was constant. Increasing the temperature decreases the oil viscosity then this reduction causes the fluid to move easier and its velocity increases as well.

scholarly journals Laboratory Measurements of the Relative Permeability of Coal: A Review

Energies ◽  
2020 ◽  
Vol 13 (21) ◽  
pp. 5568
Author(s):  
Shaicheng Shen ◽  
Zhiming Fang ◽  
Xiaochun Li
Keyword(s):  
Carbon Dioxide ◽  
Relative Permeability ◽  
Coalbed Methane ◽  
Water Saturation ◽  
Gas Production ◽  
Absolute Permeability ◽  
Permeability Measurement ◽  
Mixed Gas ◽  
Practical Engineering ◽  
Relative Permeability Curves

The relative permeability of coal to gas and water is an essential parameter for characterizing coalbed methane (CBM) reservoirs and predicting coal seam gas production, particularly in numerical simulations. Although a variety of studies related to the relative permeability of coals have been conducted, the results hardly meet the needs of practical engineering applications. To track the dynamic development of relative permeability measurements in the laboratory, discover the deficiencies, and discuss further work in this field, this paper investigates the relative permeability measurement preparation work and laboratory methods and summarizes the development of techniques used to determine the water saturation during experimentation. The previously determined relative permeability curves are also assembled and classified according to coal rank and the absolute permeability. It is found that the general operations in the relative permeability measurement process are still not standardized. The techniques applied to determine the water saturation of coal in experiments have been refined to some extent, but no optimal technique has been recognized yet. New techniques, such as the incorporation of high-precision differential pressure gauges, can be used to determine the water production during relative permeability measurement. In addition, the existing relative permeability data are limited, and no study has focused on supercritical carbon dioxide-water and mixed gas (methane and carbon dioxide)-water relative permeability measurements. To meet the requirements of actual projects, further research on this topic must be conducted.

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