An Appropriate Waterflood or Waterdrive Performance Analysis for any Oil/Water Viscosity Ratio

2017 ◽  
Author(s):  
E. Tillero ◽  
J. L. Mogollon
Keyword(s):  
Performance Analysis ◽  
Viscosity Ratio ◽  
Water Viscosity ◽  
Oil Water

Imbibition in a cracked porous medium

1969 ◽  
Vol 47 (22) ◽  
pp. 2519-2524 ◽  
Author(s):  
A. P. Verma
Keyword(s):  
Differential Equation ◽  
Porous Medium ◽  
Viscosity Ratio ◽  
Perturbation Technique ◽  
Water Imbibition ◽  
Phase Saturation ◽  
Water Viscosity ◽  
Oil Water ◽  
The Relationship ◽  
Special Case

In this paper, one special case of oil–water imbibition phenomena in a cracked porous medium of a finite length is analytically discussed. The equation for the linear countercurrent imbibition is a nonlinear differential equation whose solution has been obtained by a perturbation technique. For definiteness, specific results have been used for the relationship between relative permeability and phase saturation) impregnation function, oil–water viscosity ratio, and capillary pressure dependence on phase saturation due to Jones, Bokserman et al., Evgen'ev, and Oroveanu, respectively. An expression for the wetting phase saturation has been derived.

scholarly journals A further study on Welge equation

2018 ◽  
Vol 36 (5) ◽  
pp. 1103-1113 ◽  
Author(s):  
Jinqing Zhang ◽  
Renfeng Yang
Keyword(s):  
Linear Function ◽  
Relative Permeability ◽  
Fluid Transport ◽  
Viscosity Ratio ◽  
Water Saturation ◽  
Permeability Model ◽  
Simple Method ◽  
Average Water ◽  
Water Viscosity ◽  
Oil Water

Buckley–Leverett theory and Welge equation is one of the most widely used methods for predicting fluid transport in porous media. However, the average water saturation in Welge equation is a function of both water saturation and water cut, which is inconvenient to be used. While the linear relationship (the slope is 2/3) of the average water saturation and outlet water saturation proposed by Зфрос provides a simple method the oil–water viscosity ratio greatly limits the application. In this paper, based on the analytical relative permeability model and Welge equation, a new average water saturation equation with a variable (the outlet water saturation) was derived and applied in some cases under different relative permeability parameters and oil–water viscosity. Moreover, a simplified equation was proposed through certain data regression. Thus, the coefficient calculation method of the linear function was introduced based on the actual production data. Results showed a nonlinear relationship between the average water saturation and outlet water saturation, which is mainly related to water and oil relative permeability, and oil–water viscosity ratio. For the outlet water saturation higher than frontal saturation, the equation can be simplified to a linear function, which is the derivation of Зфрос equation. However, it is a function of both relative permeability and oil–water viscosity ratio instead of a constant slope of 2/3. In view of the fact that oil–water viscosity is mostly bigger than 10 in most reservoirs, the new model is an important supplement to Buckley–Leverett theory and Welge equation.

scholarly journals Phase-Field Simulation of Imbibition for the Matrix-Fracture of Tight Oil Reservoirs Considering Temperature Change

Water ◽  
2021 ◽  
Vol 13 (7) ◽  
pp. 1004
Author(s):  
Junjie Shi ◽  
Linsong Cheng ◽  
Renyi Cao ◽  
Zhihao Jia ◽  
Gaoling Liu
Keyword(s):  
Viscosity Ratio ◽  
Structure Model ◽  
Water Contact ◽  
Rock Structure ◽  
Matrix Fracture ◽  
The Matrix ◽  
Injection Water ◽  
Water Viscosity ◽  
Oil Water ◽  
The Ideal

Injection water temperature is often different from that of the reservoir during water injection development in the tight reservoir. Temperature change causes different fluid properties and oil-water interface properties, which further affects the imbibition process. In this paper, a matrix-fracture non-isothermal oil-water imbibition flow model in tight reservoirs is established and solved by the finite element method based on the phase-field method. The ideal inhomogeneous rock structure model was used to study the influence of a single factor on the imbibition. The actual rock structure model was used to study the influence of temperature. The mechanism of temperature influence in the process of imbibition is studied from the micro-level. It is found that the imbibition of matrix-fracture is a process in which the water enters the matrix along with the small pores, and the oil is driven into the macropores and then into the fractures. Temperature affects the imbibition process by changing the oil-water contact angle, oil-water interfacial tension, and oil-water viscosity ratio. Reducing oil-water contact angle and oil-water viscosity ratio and increasing oil-water interfacial tension are conducive to the imbibition process. The increase in injection water temperature is usually beneficial to the occurrence of the imbibition. Moreover, the actual core structure imbibition degree is often lower than that of the ideal core structure. The inhomogeneous distribution of rock particles has a significant influence on imbibition. This study provides microscale theoretical support for seeking reasonable injection velocity, pressure gradient, injection temperature, and well-shutting time in the field process. It provides a reference for the formulation of field process parameters.

Analysis of Factors on Nan Pu Oilfield’s Weak Gel Flooding

2011 ◽  
Vol 135-136 ◽  
pp. 268-273
Author(s):  
Jian Wei Gu ◽  
Mei Wu
Keyword(s):  
Conceptual Model ◽  
Viscosity Ratio ◽  
Orthogonal Design ◽  
Model Parameters ◽  
Water Viscosity ◽  
Flooding Time ◽  
Weak Gel ◽  
Oil Water ◽  
Cross Linker

There are lots of factors effect on weak gel flooding.This paper based on the conceptual model by changing the model parameters and using orthogonal design to analyze the effects of different factors on weak gel flooding. The descending order of influence is slug size, flooding time, oil-water viscosity ratio, permeability range, concentration of polymer, slug combination and polymer-cross linker ratio.

Recovery of Heavy Oil From the Monterey Formation in Offshore California by Cyclic Injection of Light-Oil Diluent

2001 ◽  
Vol 4 (01) ◽  
pp. 51-58
Author(s):  
R.L. Garnett
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Viscosity Ratio ◽  
Oil Viscosity ◽  
Production Rates ◽  
Monterey Formation ◽  
Light Oil ◽  
Water Viscosity ◽  
Oil Water

Summary This paper describes a single-well pilot in which light-oil diluent was injected through tubing to lower in-situ oil viscosity and increase production from a low-gravity oil well. The pilot well is located on the Heritage platform in the Santa Ynez Unit and produces from the Monterey formation. The pilot validated laboratory data suggesting that large production-rate increases could result from high-rate diluent injection. Introduction The Monterey formation is a complex reservoir with intense structuring, fracturing, and highly variable rock properties. It is a dual-porosity system, with low-permeability matrix rock and extensive fracturing. The fractures provide the flow path to the wells and are well-connected to a very large aquifer. The fluid system is equally complex. The original oil column was 2,000 ft thick, and the oil gravity varied from 5 to 19°API. Gravity/depth relationships vary within the field area. Heavy oil, as defined in this paper, is oil with dead-oil gravities of approximately 11°API or less. Fig. 1 is a geothermal temperature-gradient curve for offshore California. Fig. 2 is an estimation of live-oil viscosities for Monterey crude as a function of temperature and dead-oil gravity. Recovering the heavier oil at economic rates without producing large volumes of water is a challenge owing to a strong aquifer, highly permeable fractures, and a poor oil/water viscosity ratio. Achieving the large drawdown required to produce heavy oil at the high rates needed for economic operations offshore can result in the oil being bypassed by water flowing through the fractures. Even if bypassing can be avoided, the flow rate of heavy oil to the wellbore can be low. Furthermore, cooling of the heavy oil as it reaches the seafloor results in additional producing problems. As seen in Fig. 2, a 10°API oil has an in-situ viscosity of 100 cp at 200°F. As the heavy oil flows to the surface and cools, viscosity can rise above 10,000 cp and cause severe lifting problems. Deep, long throw wells (6,000 to 10,000 ft subsea), an offshore operating environment, a fracture zone with an active aquifer, and low heavy-oil prices rule out most methods of heavy-oil recovery. The challenge is to find a low-cost method to lower the oil viscosity in both the near-well region and the tubing. This paper documents a simple and inexpensive way to lower viscosity by an order of magnitude or more through cyclic injection of light oil. Theory Darcy's Law for radial, steady-state flow describes fluid flow in porous media. This simple equation gives guidance and insight to solve many oil-production problems:Equation 1 This pilot focused on reducing viscosity (µo) as a method to increase production rate (q). While the other components are also important, they were less critical for the following reasons:Fracture permeability in the major producing intervals of the Monterey formation in the Santa Barbara Channel is excellent. Wells have produced at rates in excess of 9,000 STB/D from as little as 40 ft true vertical depth (TVD) of the perforated interval. Average permeabilities are in the multidarcy range.High drawdowns may be harmful in the long run because of an unfavorable oil/water viscosity ratio. High drawdowns can result in water coning and fingering through the fractures, leaving bypassed oil in the formation. In addition, alternative lifting methods to increase drawdown can be costly owing to long throws and deep completions in the offshore environment. Reducing in-situ oil viscosity can improve the oil/water viscosity ratio, reduce water coning and fingering, reduce water cut, reduce lifting problems, and increase production rates and oil recovery from fractured heavy-oil reservoirs. HE-26 Pilot Background. The Heritage platform began producing from the Pescado field in the Santa Ynez Unit in December 1993. Wells produce 10 to 17°API oil from the Monterey and 34°API oil from sandstone formations. The Monterey formation consists of thin beds of porcelanite, chert, calcite, dolomite, and shale. The beds are highly fractured and well-connected both areally and vertically by an extensive fracture network. The fractures provide the primary flow paths in the reservoir and result in well rates as high as 10,000 STB/D. Formation pressure is supported by re-injection of produced gas and by a large, well-connected aquifer. The original oil column was approximately 2,000 ft thick and contained undersaturated oil with gravities grading from 19°API at the crest of the structure to 5°API at the original oil/water contact. Wells either flow naturally or are produced by high-volume gas lift. The sandstone formations lie below the Monterey and contain light oil with an associated gas cap. Sandstone wells flow naturally without the need for artificial lift. HE-26 History. The HE-26 well was drilled and completed in July 1997 in the Monterey formation, with perforations at 6,956 to 6,997 and 7,416 to 7,437 ft subsea. The well was stimulated with a combination of xylene, HCL, and mud acid, using foam and ball sealers for diversion. After stimulation, the well produced approximately 100 STB/D of 10.2°API oil and water. These perforations were isolated with a through-tubing bridge plug, and the well was reworked higher to 6,751 to 6,801 ft subsea. The new perforations were stimulated in a similar fashion. Oil gravity increased slightly, but production rates were unchanged. The interval was isolated with another through-tubing bridge. A final interval was perforated at 6,667 to 6,702 ft subsea. Oil gravity was slightly higher (11.4°API), but oil production rates once again did not change.

scholarly journals A CFD study on horizontal oil-water flow with high viscosity ratio

2021 ◽  
Vol 229 ◽  
pp. 116097
Author(s):  
Jing Shi ◽  
Mustapha Gourma ◽  
Hoi Yeung
Keyword(s):  
Water Flow ◽  
Viscosity Ratio ◽  
High Viscosity ◽  
Oil Water

The Effect of Viscosity Ratio on the Hydrodynamics of Separation From an Oil-Coated Particle

2014 ◽  
Author(s):  
Sasan Mehrabian ◽  
Nima Abbaspour ◽  
Markus Bussmann ◽  
Edgar Acosta
Keyword(s):  
Oil Sands ◽  
High Speed ◽  
Oil Spills ◽  
Viscosity Ratio ◽  
Solid Particles ◽  
Water Separation ◽  
Viscous Forces ◽  
Coated Particle ◽  
Oil Water ◽  
Maximum Separation

Separating oil from solid particles is of great importance in many industrial processes including the extraction of bitumen from oil sands, and the remediation of oil spills. The usual approach is to separate the oil from the solid by introducing another liquid (e.g. water). Separation is often assisted by fluid mixing, and chemical addition. Yet while oil-water-particle separation has been well studied from a chemical standpoint, little research has taken into account the effect of hydrodynamics on separation. In this work, the separation of oil from a single oil-coated spherical particle falling through an aqueous solution was evaluated as a function of viscosity ratio. Solvents were used to modify the viscosity of the oil. The experiments were recorded using a high-speed camera and post-processed using the MATLAB image-processing toolbox. A CFD model has also been developed to study this phenomenon. The results indicate that when viscous forces are strong enough, the oil film deforms, flows to the back of the sphere, and forms a tail that eventually breaks up into a series of droplets due to a capillary wave instability. When the viscosity ratio is small (i.e. the oil is less viscous than the solution), a thin tail forms quickly, the growth rate of the instability is high, and hence the tail breaks very quickly into smaller droplets. When the viscosity ratio is high (i.e. the oil is more viscous), more time is required for the deformation/separation to initiate, and the tail is thicker and breaks more slowly into larger droplets. It was observed that when the viscosity ratio is close to 1, the rate of separation is increased and maximum separation is achieved.

scholarly journals Application of Gene Expression Programming (GEP) in Modeling Hydrocarbon Recovery in WAG Injection Process

Energies ◽  
2021 ◽  
Vol 14 (21) ◽  
pp. 7131
Author(s):  
Shokufe Afzali ◽  
Mohamad Mohamadi-Baghmolaei ◽  
Sohrab Zendehboudi
Keyword(s):  
Gene Expression ◽  
Viscosity Ratio ◽  
Gene Expression Programming ◽  
Flow In Porous Media ◽  
Dimensionless Numbers ◽  
Operational Conditions ◽  
Statistical Measures ◽  
Gas Viscosity ◽  
Water Viscosity ◽  
Wag Injection

Water alternating gas (WAG) injection has been successfully applied as a tertiary recovery technique. Forecasting WAG flooding performance using fast and robust models is of great importance to attain a better understanding of the process, optimize the operational conditions, and avoid high-cost blind tests in laboratory or pilot scales. In this study, we introduce a novel correlation to determine the performance of the near-miscible WAG flooding in strongly water-wet sandstones. We conduct dimensional analysis with Buckingham’s π theorem technique to generate dimensionless numbers using eight key parameters. Seven dimensionless numbers are employed as the input variables of the desired correlation for predicting the recovery factor of a near-miscible WAG injection. A verified mathematical model is used to generate the required training and testing data for the development of the correlation using a gene expression programming (GEP) algorithm. The provided data points are then separated into two subsets: training (67%) to develop the model and testing (33%) to assess the models’ capability. Conducting error analysis, statistical measures and graphical illustrations are provided to assess the effectiveness of the introduced model. The statistical analysis shows that the developed GEP-based correlation can generate target data with high precision such that the training phase leads to R2 = 92.85% and MSE = 1.38 × 10−3 and R2 = 91.93% and MSE = 4.30 × 10−3 are attained for the testing phase. The relative importance of the input dimensionless groups is also determined. According to the sensitivity analysis, decreasing the oil–water capillary number results in a significant reduction in RF in all cycles. Increasing the magnitudes of oil to gas viscosity ratio and oil to water viscosity ratio lowers the RF of each cycle. It is found that oil to gas viscosity ratio has a higher impact on RF value compared to oil to water viscosity ratio due to a higher viscosity gap between the gas and oil phases. It is expected that the GEP, as a fast and reliable tool, will be useful to find vital variables including relative permeability in complex transport phenomena such as three-phase flow in porous media.

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