Oil Recovery by Gravity Drainage

1980 ◽  
Vol 20 (03) ◽  
pp. 139-150 ◽  
Author(s):  
J. Hagoort
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Recovery Process ◽  
Gravity Drainage ◽  
Gas Oil ◽  
Displacement Efficiency ◽  
Oil Saturation ◽  
Rock Types ◽  
Key Factor ◽  
A New Technique

Abstract Recent observations have indicated surprisingly high oil recoveries for gravity drainage. This has prompted us to reexamine gravity drainage as an prompted us to reexamine gravity drainage as an oil-recovery process. It is shown that oil relative pumeability is a key factor. For accurate measurement pumeability is a key factor. For accurate measurement of this oil relative permeability, we have developed a new method based on centrifugal gas/oil displacement in small cores. Several oil relative permeabilities for various rock types are presented. permeabilities for various rock types are presented. These relative permeabilities confirm that gravity drainage in water-wet, connate-water-bearing reservoirs can be very effective for oil-recovery. Introduction Gravity drainage is a recovery process in which gravity acts as the main driving force and where gas replaces the voidage volume. In other words, it is a gas/oil displacement in which gravity forces are dominating. It may occur in primary stages of oil production (gas-cap expansion drive or segregation production (gas-cap expansion drive or segregation drive), as well as in supplemental stages where gas is supplied from an external source.Two recent studies have indicated surprisingly high oil recoveries for gravity drainage. During their capillary-pressure studies, Dumore and Schols discovered that residual oil saturation after gas invasion in highly permeable sandstone cores containing connate water can be extremely low (5%). They also found low residual oil saturations in sandpack gravity-drainage experiments.A field study by King and Stiles concerns the East Texas Hawkins reservoir, in which a very high displacement efficiency for gravity drainage was reported (87%).These findings prompted us to reexamine the gravity-drainage process. Using the classical description of immiscible two-phase flow applied to a one-dimensional vertical gravity-drainage system, we easily can pinpoint the key factors of the process. One of the most important quantities appears to be the oil relative permeability. For quick and accurate measurement of the oil relative permeability, we present a new technique based on centrifugal gas/oil present a new technique based on centrifugal gas/oil displacement.The results of this study enable us to evaluate gravity drainage better. Using the results of the simple one-dimensional description, we can make quick first judgements of the process. Further, the new measuring technique provides basic input data for more comprehensive mathematical simulation studies. Vertical Displacement Efficiency of Gravity Drainage Classical Description We can think of gravity drainage as a displacement process in which gas displaces oil. Then, by using the process in which gas displaces oil. Then, by using the concepts of relative permeability and capillary pressure, together with the continuity equation and pressure, together with the continuity equation and Darcy's law, the displacement can be described mathematically. For the simple case of a stable, vertical, downward displacement of oil by gas (Fig. 1), we end up with a single equation:(1) where fo is the oil fractional flow function as defined in Appendix A.To gain more insight into the effect of the various parameters, we put Eq. 1 in dimensionless form. parameters, we put Eq. 1 in dimensionless form. Therefore, we introduce the reduced oil saturation and reduced porosity: SPEJ P. 139

scholarly journals Differences of microscopic seepage mechanisms of water flooding and polymer flooding and prediction models of final oil recovery for conglomerate reservoir

2019 ◽  
Vol 74 ◽  
pp. 13
Author(s):  
Fengqi Tan ◽  
Changfu Xu ◽  
Yuliang Zhang ◽  
Gang Luo ◽  
Yukun Chen ◽  
...  
Keyword(s):  
Pore Structure ◽  
Polymer Solution ◽  
Oil Recovery ◽  
Particle Surface ◽  
Polymer Flooding ◽  
Water Flooding ◽  
Residual Oil ◽  
Displacement Efficiency ◽  
Oil Saturation ◽  
Oil Displacement Efficiency

The special sedimentary environments of conglomerate reservoir lead to pore structure characteristics of complex modal, and the reservoir seepage system is mainly in the “sparse reticular-non reticular” flow pattern. As a result, the study on microscopic seepage mechanism of water flooding and polymer flooding and their differences becomes the complex part and key to enhance oil recovery. In this paper, the actual core samples from conglomerate reservoir in Karamay oilfield are selected as research objects to explore microscopic seepage mechanisms of water flooding and polymer flooding for hydrophilic rock as well as lipophilic rock by applying the Computed Tomography (CT) scanning technology. After that, the final oil recovery models of conglomerate reservoir are established in two displacement methods based on the influence analysis of oil displacement efficiency. Experimental results show that the seepage mechanisms of water flooding and polymer flooding for hydrophilic rock are all mainly “crawling” displacement along the rock surface while the weak lipophilic rocks are all mainly “inrushing” displacement along pore central. Due to the different seepage mechanisms among the water flooding and the polymer flooding, the residual oil remains in hydrophilic rock after water flooding process is mainly distributed in fine throats and pore interchange. These residual oil are cut into small droplets under the influence of polymer solution with stronger shearing drag effect. Then, those small droplets pass well through narrow throats and move forward along with the polymer solution flow, which makes enhancing oil recovery to be possible. The residual oil in weak lipophilic rock after water flooding mainly distributed on the rock particle surface and formed oil film and fine pore-throat. The polymer solution with stronger shear stress makes these oil films to carry away from particle surface in two ways such as bridge connection and forming oil silk. Because of the essential attributes differences between polymer solution and injection water solution, the impact of Complex Modal Pore Structure (CMPS) on the polymer solution displacement and seepage is much smaller than on water flooding solution. Therefore, for the two types of conglomerate rocks with different wettability, the pore structure is the main controlling factor of water flooding efficiency, while reservoir properties oil saturation, and other factors have smaller influence on flooding efficiency although the polymer flooding efficiency has a good correlation with remaining oil saturation after water flooding. Based on the analysis on oil displacement efficiency factors, the parameters of water flooding index and remaining oil saturation after water flooding are used to establish respectively calculation models of oil recovery in water flooding stage and polymer flooding stage for conglomerate reservoir. These models are able to calculate the oil recovery values of this area controlled by single well control, and further to determine the oil recovery of whole reservoir in different displacement stages by leveraging interpolation simulation methods, thereby providing more accurate geological parameters for the fine design of displacement oil program.

scholarly journals Mysteries behind the Low Salinity Water Injection Technique

2014 ◽  
Vol 2014 ◽  
pp. 1-11 ◽  
Author(s):  
Emad Waleed Al-Shalabi ◽  
Kamy Sepehrnoori ◽  
Gary Pope
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
History Matching ◽  
Water Injection ◽  
Residual Oil ◽  
Oil Saturation ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Low Salinity Water Injection

Low salinity water injection (LSWI) is gaining popularity as an improved oil recovery technique in both secondary and tertiary injection modes. The objective of this paper is to investigate the main mechanisms behind the LSWI effect on oil recovery from carbonates through history-matching of a recently published coreflood. This paper includes a description of the seawater cycle match and two proposed methods to history-match the LSWI cycles using the UTCHEM simulator. The sensitivity of residual oil saturation, capillary pressure curve, and relative permeability parameters (endpoints and Corey’s exponents) on LSWI is evaluated in this work. Results showed that wettability alteration is still believed to be the main contributor to the LSWI effect on oil recovery in carbonates through successfully history matching both oil recovery and pressure drop data. Moreover, tuning residual oil saturation and relative permeability parameters including endpoints and exponents is essential for a good data match. Also, the incremental oil recovery obtained by LSWI is mainly controlled by oil relative permeability parameters rather than water relative permeability parameters. The findings of this paper help to gain more insight into this uncertain IOR technique and propose a mechanistic model for oil recovery predictions.

scholarly journals Modeling Wettability Variation during Long-Term Water Flooding

2015 ◽  
Vol 2015 ◽  
pp. 1-11 ◽  
Author(s):  
Renyi Cao ◽  
Changwei Sun ◽  
Y. Zee Ma
Keyword(s):  
Oil Recovery ◽  
Water Flooding ◽  
Residual Oil ◽  
Displacement Efficiency ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Polar Substance ◽  
Oil Displacement Efficiency ◽  
Reservoir Wettability

Surface property of rock affects oil recovery during water flooding. Oil-wet polar substances adsorbed on the surface of the rock will gradually be desorbed during water flooding, and original reservoir wettability will change towards water-wet, and the change will reduce the residual oil saturation and improve the oil displacement efficiency. However there is a lack of an accurate description of wettability alternation model during long-term water flooding and it will lead to difficulties in history match and unreliable forecasts using reservoir simulators. This paper summarizes the mechanism of wettability variation and characterizes the adsorption of polar substance during long-term water flooding from injecting water or aquifer and relates the residual oil saturation and relative permeability to the polar substance adsorbed on clay and pore volumes of flooding water. A mathematical model is presented to simulate the long-term water flooding and the model is validated with experimental results. The simulation results of long-term water flooding are also discussed.

A Pore-Network-Modeling Approach To Predict Petrophysical Properties of Diatomaceous Reservoir Rock

2007 ◽  
Vol 10 (06) ◽  
pp. 597-608 ◽  
Author(s):  
Liping Jia ◽  
Cynthia Marie Ross ◽  
Anthony Robert Kovscek
Keyword(s):  
Multiphase Flow ◽  
Capillary Pressure ◽  
Network Model ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Pore Network ◽  
Reservoir Rock ◽  
Pore Network Model ◽  
Rock Types ◽  
Capillary Pressure Curves

Summary A 3D pore-network model of two-phase flow was developed to compute permeability, relative permeability, and capillary pressure curves from pore-type, -size, and -shape information measured by means of high-resolution image analysis of diatomaceous-reservoir-rock samples. The diatomite model is constructed using pore-type proportions obtained from image analysis of epoxy-impregnated polished samples and mercury-injection capillary pressure curves for diatomite cores. Multiple pore types are measured, and each pore type has a unique pore-size and throat-size distribution that is incorporated in the model. Network results present acceptable agreement when compared to experimental measurements of relative permeability. The pore-network model is applicable to both drainage and imbibition within diatomaceous reservoir rock. Correlation of network-model results to well log data is discussed, thereby interpolating limited experimental results across the entire reservoir column. Importantly, our method has potential to predict the petrophysical properties for reservoir rocks with either limited core material or those for which conventional experimental measurements are difficult, unsuitable, or expensive. Introduction Model generation for reservoir simulation requires accurate entering of physical properties such as porosity, permeability, initial water saturation, residual-oil saturation, capillary pressure functions, and relative permeability curves. These functions and parameters are necessary to estimate production rate and ultimate oil recovery, and thereby optimize reservoir development. Accurate measurement and representation of such information is, therefore, essential for reservoir modeling. Relative permeability and capillary pressure curves are the most important constitutive relations to represent multiphase flow. Often, it is difficult to sample experimentally the range of relevant multiphase-flow behavior of a reservoir. In addition to the availability of rock samples, measurements are frequently time consuming to conduct, and conventional techniques are not suitable for all rock types (Schembre and Kovscek 2003). It is impossible, therefore, to measure all the unique relative permeability functions of different reservoir-rock types and variations within a rock type. This lack of constitutive information limits the accuracy of reservoir simulators to predict oil recovery. Simply put, other available data must be queried for their relevance to multiphase flow and must be used to interpret the available relative permeability and capillary pressure information.

scholarly journals A New Measurement of Anisotropic Relative Permeability and Its Application in Numerical Simulation

Energies ◽  
2021 ◽  
Vol 14 (16) ◽  
pp. 4731
Author(s):  
Congcong Li ◽  
Shuoliang Wang ◽  
Qing You ◽  
Chunlei Yu
Keyword(s):  
Numerical Simulation ◽  
Relative Permeability ◽  
Residual Oil ◽  
Displacement Efficiency ◽  
Two Phase ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Displacement Direction ◽  
Oil Water ◽  
The Law

In this paper, we used a self-developed anisotropic cubic core holder to test anisotropic relative permeability by the unsteady-states method, and introduced the anisotropic relative permeability to the traditional numerical simulator. The oil–water two-phase governing equation considering the anisotropic relative permeability is established, and the difference discretization is carried out. We formed a new oil–water two-phase numerical simulation method. It is clear that in a heterogeneous rock with millimeter to centimeter scale laminae, relative permeability is an anisotropic tensor. When the displacement direction is parallel to the bedding, the residual oil saturation is high and the displacement efficiency is low. The greater the angle between the displacement direction and the bedding strike, the lower the residual oil saturation is, the higher the displacement efficiency is, and the relative permeability curve tends towards a rightward shift. The new simulator showed that the anisotropic relative permeability not only affects the breakthrough time and sweep range of water flooding, but also has a significant influence on the overall water cut. The new simulator is validated with the actual oilfield model. It could describe the law of oil–water seepage in an anisotropic reservoir, depict the law of remaining oil distribution of a typical fluvial reservoir, and provide technical support for reasonable injection-production directions.

Effect of Fractional Flow Hysteresis on Recovery of Tertiary Oil

1980 ◽  
Vol 20 (06) ◽  
pp. 508-520 ◽  
Author(s):  
Robert E. Gladfelter ◽  
Surendra P. Gupta
Keyword(s):  
Water Flow ◽  
Oil Recovery ◽  
Leading Edge ◽  
Recovery Process ◽  
Breakthrough Time ◽  
Fractional Flow ◽  
Oil Saturation ◽  
Saturation Region ◽  
Tertiary Oil Recovery ◽  
Oil Water

Abstract This paper deals with the oil/water bank propagation in a tertiary oil recovery process. Oil/water bank propagation was studied in a series of laboratory micellar floods and simultaneous oil/water flow tests using a microwave scanning apparatus for measuring in-situ dynamic oil saturation. It was observed that a high oil saturation region, or hump, developed at the leading edge of the oil/water bank and grew linearly with distance. A lower steady-state oil saturation region was observed behind the hump. As the hump was produced from the core, high initial oil fractions were observed, as often seen in laboratory micellar floods. This is the result of the observed hysteresis in fractional flow behavior. A graphical method of predicting the occurrence of a hump, its rate of growth, and saturations within an oil/water bank was developed using the observed hysteresis in fractional flow. Using this prediction procedure, it was concluded that in a tertiary oil recovery process, oil breakthrough time or rate of advance of the oil/water bank, oil saturation at the leading edge, and initial produced oil fractions are only functions of the oil-saturation-increasing fractional flow curve and are not necessarily indications of oil recovery efficiency. Introduction During a tertiary oil recovery process, a small slug of displacing fluid (e.g., a micellar fluid) mobilizes residual oil and water and forms an oil/water bank. It is important to understand the propagation behavior of the oil/water bank in a tertiary oil recovery process since it affects the oil breakthrough time and initial oil cuts. This understanding also will aid in the interpretation of oil displacement tests. Moreover, oil breakthrough time and initial oil cuts have been used for judging the efficiency of a tertiary oil recovery process. Oil/water bank propagation was studied in a series of micellar floods and oil/water flow tests using a microwave scanning apparatus for measuring in-situ dynamic oil saturation profiles. Experimental Details The microwave scanning apparatus used is similar to that discussed by Parsons1 and Parsons and Jones.2 Microwaves are transmitted through a core where they are partially absorbed by the water molecules. The measured microwave power attenuation, or degree of absorption of the microwave energy, is a direct measure of the quantity of water and, consequently, of the oil saturation in an oil/water system since the oil does not absorb the microwave energy. The microwave scanning apparatus is capable of measuring the dynamic oil saturation profiles during pressure-monitored laboratory micellar floods and other oil/water flow tests. Fig. 1 is a schematic of the apparatus. Additional experimental details are given in Appendix A. Displacement tests were conducted at room temperature in 120-cm-long rectangular Berea cores (1.91 cm thick×7.62 cm wide). The brine permeability range of these cores was from 418 to 714 md, and pore volumes varied from 377 to 395 cm3. Three tertiary micellar floods were conducted in separate Berea cores with Second Wall Creek crude oil. Table 1 shows the fluid injection sequence and compositions3 for the micellar floods. In addition, simultaneous oil/water injection tests were conducted in separate Berea cores using both Second Wall Creek crude oil and refined oils (see Table 2 for the fluid injection sequence).

Micellar Flooding - Compositional Effects on Oil Displacement

1979 ◽  
Vol 19 (02) ◽  
pp. 116-128 ◽  
Author(s):  
Surendra P. Gupta ◽  
Scott P. Trushenski
Keyword(s):  
Crude Oil ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Capillary Number ◽  
Field Application ◽  
Displacement Efficiency ◽  
Micellar Phase ◽  
Oil Displacement ◽  
Relative Permeability Curves

Abstract Key variables that govern oil displacement in a micellar flood are capillary number (velocity x viscosity/interfacial tension) and chemical loss. At high capillary numbers, oil displacement is very efficient if various phases propagate at the same velocity. Chemical loss, however, is not always low when oil displacement efficiency is high. Compositions developed in situ often alter the ability of the micellar fluid to displace oil. Oil recovery can be predicted from static equilibrium fluid properties, providing the in situ compositions are known.The displacement of the wetting phase requires a capillary number of 10 times higher than that required to displace the nonwetting phase. This implies less efficient oil displacement in oil-wet systems. The correlation of oil recovery vs capillary number also varies with rock structure and wettability. Hence, for field application, immiscible oil displacement with micellar fluids should be determined in reservoir rocks. The decrease in final oil saturation with increase in capillary number indicates that relative permeability changes with capillary number. A numerically study showed that both the end-points and the shape of the relative permeability curves affect oil recovery at high permeability curves affect oil recovery at high capillary number in a slug process. The shape of the relative-permeability curves also affects the design of micellar slug viscosity. Thus, for field application, it is important to know the shape of relative-permeability curves at anticipated capillary numbers. Introduction In a micellar flood, the injected fluid banks interact with one another and with the reservoir brine, crude oil, and reservoir rock. This places stringent requirements on the design of the micellar flood. Initially, the micellar fluid may be miscible with crude oil and reservoir brine. However, because of dilution and surfactant adsorption, the flood can degenerate to an immiscible displacement. If low interfacial tension (IFT), or more specifically, high capillary number (velocity x viscosity/IFT) is maintained between all the phases, the displacement efficiency is good.There are many phenomena that can decrease oil recovery efficiency. The most important are chemical (surfactant or sulfonate) losses from adsorption by the rock, precipitation by high-salinity and high-hardness brines, interaction with polymer, partitioning into an immobile phase, and trapping of partitioning into an immobile phase, and trapping of the surfactant-rich phase. Recovery efficiency also can be poor when unfavorable in situ compositions develop. This occurs when the micellar fluid is diluted, develops undesirable salinity and hardness environment, experiences selective adsorption of surfactant, or undergoes selective partitioning of components into phases moving at different velocities.A micellar phase (or microemulsion) can exist in equilibrium with excess oil, water, or both. Winsor designated such phase behavior as Type I, II, and III, respectively. More recently, Healy et al. identified this behavior as lower phase (where the micellar phase is in equilibrium with excess oil), upper phase (where the micellar phase is in equilibrium with excess water), and middle phase (where the micellar phase is in equilibrium with excess oil and water). The importance of phase behavior has been the subject of considerable discussion in the literature.Since the function of the micellar fluid is to displace crude oil, not water, it would be desirable if the micellar fluid remained miscible with oil and immiscible with water during the immiscible displacement portion of a flood. This is achieved with upper-phase micellar systems. Since only a small bank of micellar fluid is injected, it must be displaced effectively by the succeeding polymer water bank. However, the upper-phase micellar fluid is not miscible with the polymer water; therefore, some of the micellar phase may be trapped as an immobile saturation (much as residual oil is trapped). SPEJ p. 116

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