Correlation and Prediction of Residual Oil Saturation for Gas Injection EOR Processes

1998 ◽  
Vol 1 (02) ◽  
pp. 127-133 ◽  
Author(s):  
E.A. Lange
Keyword(s):  
Interfacial Tension ◽  
Crude Oil ◽  
Gas Injection ◽  
Solubility Parameters ◽  
Residual Oil ◽  
Displacement Efficiency ◽  
Hydrocarbon Gases ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Eor Processes

Abstract A promising correlation has been developed that can be used to predict miscible or near-miscible residual oil saturation, Sorm, for a wide range of injected gases, crude oils, temperature, and pressure conditions. The correlation is based on representation of the chemical and physical properties of the crude oil and the injected gas through Hildebrand solubility parameters. This approach has the advantage that characteristics of both the injected gas and crude oil are included in the correlation, in contrast to correlations based solely on properties of the injected gas. The correlation was developed using available experimental data for tertiary recovery of eight crude oils in carbonate and sandstone cores with common EOR gases (CO2, N2, CH4, CH4 + liquefied petroleum gas). Results for 45 coreflood tests at reservoir conditions collapsed along a band when Sorm was plotted as a function of the difference in solubility parameter between the injected gas and the crude oil. Results for a pure oil, decane, with CO2 lay along the same band. The success of this correlation scheme may be due to the basic characterization of the fluids and to a relationship between solubility parameters and interfacial tension. Use of the correlation requires knowledge of only injected gas composition, injected gas density, oil average molecular weight, and temperature. This empirical correlation should have utility in screening studies or in process simulation as a simple means to forecast residual oil saturations as measured in coreflood tests. The correlation can be used to predict roughly the effects of changes in pressure, temperature, or injected gas composition on residual oil saturation. A new method to predict minimum miscibility pressure based on the solubility parameter concept is also described. Introduction The miscible residual oil saturation, Sorm, is a key property for simulation and screening studies of gas injection EOR processes. This property represents the oil saturation remaining in a porous media after injection of a large bank of a high pressure gas, such as CO2, N2, or CH4, after a waterflood. The miscible residual oil saturation thus represents the local displacement efficiency of oil by the injected gas in a ternary system of oil, gas, and water. Injected gases are frequently supercritical fluids, and proposed mechanisms of oil recovery include low interfacial tension displacement, extraction, and oil swelling. Within the industry, a common parameter used in design of these processes is the minimum miscibility pressure (MMP) or minimum miscibility enrichment (MME) level for hydrocarbon gases as determined from sandpack slim-tube tests. Recent work has suggested use of reservoir-condition coreflood data in design of gas injection EOR processes instead of MMP or MME levels. Miscible recovery processes have been studied extensively, and a variety of schemes have been developed to predict MMP. In contrast to the large number of predictive schemes for MMP, few methods have been proposed to predict Sorm. Use of a capillary number correlation has been suggested, but this approach requires knowledge of interfacial tension between equilibrated phases. A correlation of residual oil saturation with pore structure in carbonates has been suggested as well as correlations of Sorm with reduced density of the injected gas for one crude oil with several hydrocarbon gases. Although interesting, these approaches do not meet the need for a general method to predict Sorm for any injected gas and any crude oil, and laboratory coreflood tests at reservoir conditions are usually recommended to determine this important measure of local displacement efficiency.

Relationship between Residual Saturations and Wettability using Pore-Network Modeling

2021 ◽  
Author(s):  
Prakash Purswani ◽  
Russell T. Johns ◽  
Zuleima T. Karpyn
Keyword(s):  
Contact Angle ◽  
Oil Recovery ◽  
Network Modeling ◽  
Pore Network ◽  
Residual Oil ◽  
Residual Saturation ◽  
Oil Saturation ◽  
Pore Network Modeling ◽  
Residual Oil Saturation ◽  
Eor Processes

Abstract The relationship between residual saturation and wettability is critical for modeling enhanced oil recovery (EOR) processes. The wetting state of a core is often quantified through Amott indices, which are estimated from the ratio of the saturation fraction that flows spontaneously to the total saturation change that occurs due to spontaneous flow and forced injection. Coreflooding experiments have shown that residual oil saturation trends against wettability indices typically show a minimum around mixed-wet conditions. Amott indices, however, provides an average measure of wettability (contact angle), which are intrinsically dependent on a variety of factors such as the initial oil saturation, aging conditions, etc. Thus, the use of Amott indices could potentially cloud the observed trends of residual saturation with wettability. Using pore network modeling (PNM), we show that residual oil saturation varies monotonically with the contact angle, which is a direct measure of wettability. That is, for fixed initial oil saturation, the residual oil saturation decreases monotonically as the reservoir becomes more water-wet (decreasing contact angle). Further, calculation of Amott indices for the PNM data sets show that a plot of the residual oil saturation versus Amott indices also shows this monotonic trend, but only if the initial oil saturation is kept fixed. Thus, for the cases presented here, we show that there is no minimum residual saturation at mixed-wet conditions as wettability changes. This can have important implications for low salinity waterflooding or other EOR processes where wettability is altered.

Application of Air-Mercury and Oil-Air Capillary Pressure Data In the Study of Pore Structure and Fluid Distribution

1966 ◽  
Vol 6 (01) ◽  
pp. 55-61 ◽  
Author(s):  
J.J. Pickell ◽  
B.F. Swanson ◽  
W.B. Hickman
Keyword(s):  
Interfacial Tension ◽  
Pore Structure ◽  
Capillary Pressure ◽  
Fluid Distribution ◽  
Pore Geometry ◽  
Residual Oil ◽  
Pressure Data ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Phase Saturation

Abstract Many physical properties of the porous media-immiscible liquid system are dependent upon the distribution of fluids within the pores; this in turn, is primarily a function of pore structure, liquid-liquid interfacial tension and liquid-solid wetting conditions. The capillary pressure hysteresis process provides a means of investigating the influence of pore structure upon fluid distribution for consistent surface conditions. Investigations indicate that residual non-wetting-phase saturations following the imbibition process (i.e., wetting phase displacing non-wetting phase) are dependent upon both pore structure and initial non-wetting phase saturation and suggest that residual fluid is distributed to discontinuous globules, one to a few pore sizes in dimension, through the entire range of pore sizes originally occupied. It appears that air-mercury capillary pressure data adequately reflect the distribution of fluids in a water-oil system when strong wetting conditions prevail. An oil-air counter-current imbibition technique has also been found to provide a rapid means of obtaining residual-initial saturation data. In a majority of cases, residual saturations determined from the oil-air or air-mercury process reasonably approximate residual oil and saturation following water drive of a strongly water-wet medium. Introduction A reliable estimate of recoverable reserves depends not only on the amount of original oil-in-place but also on pore geometry and distribution of fluids within the pores. A critical parameter determining the recovery from a reservoir under waterflood, for example, is the amount and distribution of residual oil within the various rock types present. The purpose of this paper is to investigate the mechanism of capillary trapping and assess its importance in laboratory measurements of residual oil saturation. The degree of wettability of a reservoir rock is recognized as an important factor in waterflood or imbibition experiments. In this paper, however, only the water-wet case has been considered. Considerable experimental evidence1 suggests that for water-wet rocks, capillary forces predominate in the distribution of fluids and that viscous forces in the range normally of interest in the reservoir have a minimum influence on residual oil saturation. It follows that if the ultimate recovery is controlled by pore geometry, a unique residual non-wetting phase saturation should exist for a given set of initial conditions. Two laboratory procedures found to be extremely useful in the study of pore structure and degree of fluid interconnection at various saturations are described. Although air-mercury capillary injection curves have been used2 previously to characterize the drainage case, the withdrawal or imbibition case can provide valuable supplementary data. The air-mercury process, however, has several disadvantages; it is difficult to run in a sufficiently accurate manner, mercury does not always act as a strongly non-wetting liquid and in the air-mercury process the sample is rendered unsuitable for future analyses. An alternative process is described in which air is the non-wetting phase and naptha, heptane, octane or toluene is the wetting phase. Interfacial Tension and Capillary Pressure Interfacial tension between immiscible fluids is due to the difference in attraction of like molecules as compared with their attraction to molecules of the neighboring fluid. This net attraction results in a tension at the interface. To extend the interface; thus, interfacial tension s can also be thought of as free surface energy. Interfacial tension is normally expressed as dynes/cm, and interfacial energy is measured in ergs/cm2 hence, both have dimensions mLt-2 and are numerically equal.

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.

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.

Historical Overview and Future Perspective of Chemical EOR Project for Major Malaysian Offshore Oilfield: Case Study

2021 ◽  
Author(s):  
Ahmad Khanifar ◽  
Benayad Nourreddine ◽  
Mohd Razib Bin Abd Raub ◽  
Raj Deo Tewari ◽  
Mohd Faizal Bin Sedaralit
Keyword(s):  
Interfacial Tension ◽  
Field Trial ◽  
Oil Production ◽  
Residual Oil ◽  
Oil Saturation ◽  
Full Field ◽  
Residual Oil Saturation ◽  
Field Development ◽  
Well Spacing ◽  
Single Well

Abstract A major Malaysian offshore oilfield, which is currently operating under waterflooding for a quite long time and declining in oil production, plan to convert as chemical enhanced oil recovery (CEOR) injection. The CEOR journey started since the first oil production in year 2000 and proximate waterflooding, with research and development in determining suitable method, encouraging field trial results and a series of field development plans to maximize potential recovery above waterflooding and prolong the production field life. A comprehensive EOR study including screening, laboratory tests, pilot evaluation, and full field reservoir simulation modelling are conducted to reduce the project risks prior to the full field investment and execution. Among several EOR techniques, Alkaline-Surfactant (AS) flooding is chosen to be implemented in this field. Several CEOR key parameters have been studied and optimized in the laboratory such as chemical concentration, chemical adsorption, interfacial tension (IFT), slug size, residual oil saturation (Sor) reduction, thermal stability, flow assurance, emulsion, dilution, and a chemical injection scheme. Uncertainty analysis on CEOR process was done due to the large well spacing in the offshore environment as compared to other CEOR projects, which are onshore with shorter well spacing. The key risks and parameters such as residual oil saturation (Sorw), adsorption and interfacial tension (IFT) cut-off in the dynamic chemical simulator have been investigated via a probabilistic approach on top of deterministic method. The laboratory results from fluid-fluid and rock-fluid analyses ascertained a potential of ultra-low interfacial tension of 0.001 dyne/cm with adsorption of 0.30 mg/gr-of-rock, which translated to a 50-75% reduction in Sor after waterflooding. The results of four single well chemical tracer tests (SWCTT) on two wells validated the effectiveness of the Alkaline Surfactant by a reduction of 50-80% in Sor. The most suitable chemical formulation was found 1.0 wt. % Alkali and 0.075 wt. % Surfactant. The field trial results were thenceforth upscaled to a dynamic chemical simulation; from single well to full field modeling, resulting an optimal chemical injection of three years or almost 0.2 effective injection pore volume, coupled with six months of low salinity treated water as pre-flush and post-flush injection. The latest field development study results yield a technical potential recoverable volume of 14, 16, and 26 MMstb (above waterflooding) for low, most likely, and high cases, respectively, which translated to an additional EOR recovery factor up to 5.6 % for most-likely case by end of technical field life. Prior to the final investment decision stage, Petronas’ position was to proceed with the project based on the techno-commerciality and associated risks as per milestone review 5, albeit it came to an agreement to have differing interpretations towards the technical basis of the project in the final steering committee. Subsequently, due to the eventual plunging global crude oil price, the project was then reprioritized and adjourned correspondingly within Petronas’ upstream portfolio management. Further phased development including a producing pilot has been debated with the main objective to address key technical and business uncertainties and risks associated with applying CEOR process.

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