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.

Three-Phase Pore-Network Modeling for Reservoirs With Arbitrary Wettability

SPE Journal ◽  
2012 ◽  
Vol 18 (02) ◽  
pp. 285-295 ◽  
Author(s):  
Adnan Al-Dhahli ◽  
Sebastian Geiger ◽  
Marinus I.J. van Dijke
Keyword(s):  
Network Model ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Network Modeling ◽  
Pore Scale ◽  
Residual Oil ◽  
Oil Saturation ◽  
Pore Network Modeling ◽  
Three Phase ◽  
Flow Functions

Summary Oil reservoirs have structural heterogeneities across multiple length scales and, particularly in carbonates, complexly distributed wettabilities. The interplay of structural and wettability heterogeneities is the fundamental control for sweep efficiency and oil recovery. This interplay must be captured in physically robust flow functions, such as relative permeability and capillary pressure functions. Such flow functions then allow us to choose the best improved-oil-recovery (IOR) or enhanced-oil-recovery (EOR) process and forecast oil recovery with adequate precision. Obtaining flow functions for reservoir rocks with varying wettability is a challenging task, especially when three fluid phases coexist. In this work, we use pore-network modeling, a reliable and physically based simulation tool, to predict three-phase flow functions. We have developed a new pore-scale network model for rocks with variable wettability. Unlike other models, this model combines three new and important features. (1) Our network model comprises a novel thermodynamic criterion for the formation and collapse of oil layers. This captures film/layer flow of oil adequately, which affects the oil relative permeability at low oil saturation. We can therefore predict residual oil more accurately. (2) We implemented multiple displacement chains, in which injection of one phase at the inlet triggers a chain of interface displacements throughout the network. This allows us to accurately model the mobilization of disconnected phase clusters that arise during higher-order [water-alternating-gas (WAG)] floods. Again, this feature is key to a better prediction of residual oil saturation (ROS). (3) Our model takes realistic 3D pore networks extracted from pore-space reconstruction methods and X-ray computerized-tomography (CT) images as input. This preserves both topology and pore shape of the rock, providing better estimates of phase conductivities and relative permeability. We have validated our model by use of available experimental data for a range of wettabilities and demonstrated the impact of single vs. multiple displacement on residual oil. We also used a proof-of-concept study in which we use flow functions for different wettabilities that have been computed with our model in field-scale reservoir simulations to forecast oil recovery during tertiary gas injection. These results are compared with predictions that used empirical flow functions. Flow functions computed by our network model gave higher oil recovery than corresponding flow functions calculated by empirical models; oil recovery increases with decreasing water-wetness. This shows that the pore-scale physics encapsulated in our new network model leads to the right emergent behavior at the reservoir scale.

scholarly journals SURFACTANT-POLYMER FLOODING PERFORMANCE IN HETEROGENEOUS TWO-LAYERED POROUS MEDIA

2011 ◽  
Vol 12 (1) ◽  
pp. 31-38 ◽  
Author(s):  
Muhammad Taufiq Fathaddin ◽  
Asri Nugrahanti ◽  
Putri Nurizatulshira Buang ◽  
Khaled Abdalla Elraies
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Polymer Flooding ◽  
Water Flooding ◽  
Residual Oil ◽  
Oil Saturation ◽  
Reservoir Heterogeneity ◽  
Residual Oil Saturation ◽  
Layered Porous Media ◽  
Multiple Porosity

In this paper, simulation study was conducted to investigate the effect of spatial heterogeneity of multiple porosity fields on oil recovery, residual oil and microemulsion saturation. The generated porosity fields were applied into UTCHEM for simulating surfactant-polymer flooding in heterogeneous two-layered porous media. From the analysis, surfactant-polymer flooding was more sensitive than water flooding to the spatial distribution of multiple porosity fields. Residual oil saturation in upper and lower layers after water and polymer flooding was about the same with the reservoir heterogeneity. On the other hand, residual oil saturation in the two layers after surfactant-polymer flooding became more unequal as surfactant concentration increased. Surfactant-polymer flooding had higher oil recovery than water and polymer flooding within the range studied. The variation of oil recovery due to the reservoir heterogeneity was under 9.2%.

Laboratory Tests on Heavy Oil Recovery by Steam Injection

1983 ◽  
Vol 23 (03) ◽  
pp. 417-426 ◽  
Author(s):  
Philip J. Closmann ◽  
Richard D. Seba
Keyword(s):  
Pore Size ◽  
Heat Loss ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Steam Injection ◽  
Residual Oil ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
The Core ◽  
Unconsolidated Sand

Abstract This paper presents results of laboratory experiments conducted to determine the effect of various parameters on residual oil saturation from steamdrives of heavy-oil reservoirs. These experiments indicated that remaining oil saturation, both at steam breakthrough and after passage of several PV of steam, is a function of oil/water viscosity ratio at saturated steam conditions. Introduction Considerable attention has been given to thermal techniques for stimulating production of underground hydrocarbons, particularly the more viscous oils production of underground hydrocarbons, particularly the more viscous oils and tars. Steam injection has been studied as one means of heating oil in place, reducing its viscosity, and thus making its displacement easier. place, reducing its viscosity, and thus making its displacement easier. A number of investigators have measured residual oil saturations remaining in the steam zone. Willman et al. also analyzed the steam displacement process to account for the oil recoveries observed. A number of methods have been developed to calculate the size of the steam zone and to predict oil recoveries by application of Buckley-Leverett theory, including the use of numerical simulation. The work described here was devoted to an experimental determination of oil recovery by steam injection in linear systems. The experiments were unscaled as far as fluid flow rates, gravity forces, and heat losses were concerned. Part of the study was to determine recoveries of naturally occurring very viscous tars in a suite of cores containing their original oil saturation. The cores numbered 95, 140, and 143 are a part of this group. Heterogeneities in these cores, however, led to the extension of the work to more uniform systems, such as sandpacks and Dalton sandstone cores. Our interest was in obtaining an overall view of important variables that affected recovery. In particular, because of the significant effect of steam distillation, most of the oils used in this study were chosen to avoid this factor. We also studied the effect of pore size on the residual oil saturation. As part of this work, we investigated the effect of the amount of water flushed through the system ahead of the steam front in several ways:the production rate was varied by a factor of four,the initial oil saturation was varied by a factor of two, andthe rate of heat loss was varied by removing the heat insulation from the flow system. Description of Apparatus and Experimental Technique Two types of systems were studied: unconsolidated sand and consolidated sandstone. The former type was provided by packing a section of pipe with 50–70 mesh Ottawa sand. Most runs on this type of system were in an 18-in. (45.72-cm) section of 1 1/2 -in. (3.8 1 -cm) diameter pipe, although runs on 6-in. (15.24-cm) and 5-ft (152.4-cm) lengths were also included. Consolidated cores 9 to 13 in. (22.86 to 33.02 cm) long and approximately 2 1/4 in. (5.72 cm) in diameter were sealed in a piece of metal pipe by means of an Epon/sand mixture. A photograph of two 9-in. (22.86-cm) consolidated natural cores (marked 95 and 143) from southwest Missouri, containing original oil, is shown as Fig. 1. In all steamdrive runs, the core was thermally insulated to reduce heat loss, unless the effect of heat loss was specifically being studied. Flow was usually horizontal except for the runs in which the effects of flushing water volume and of unconsolidated-sand pore size were examined. Micalex end pieces were used on the inlet end in initial experiments with consolidated cores to reduce heat leakage from the steam line to the metal jacket on the outside of the core. During most runs, however, the entire input assembly eventually became hot. SPEJ p. 417

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.

Thermal Stability of Surfactants for Reservoir Application (includes associated papers 11323 and 11597 )

1982 ◽  
Vol 22 (05) ◽  
pp. 722-730 ◽  
Author(s):  
L.L. Handy ◽  
J.O. Amaefule ◽  
V.M. Ziegler ◽  
I. Ershaghi
Keyword(s):  
Nonionic Surfactant ◽  
Oil Recovery ◽  
Half Life ◽  
Elevated Temperatures ◽  
Effect Of Temperature ◽  
Residual Oil ◽  
Chemical Additives ◽  
Thermal Stabilities ◽  
Oil Saturation ◽  
Residual Oil Saturation

Abstract The thermal stabilities of several sulfonate surfactantsand one nonionic surfactant have been evaluated. Thedecomposition reactions have been observed to followfirst-order kinetics. Consequently, a quantitativemeasure of a surfactant's stability at a given temperatureis its half-life. Furthermore, the activation energy can beestimated from rate data obtained at two or moretemperatures. This permits limited extrapolation of theobserved decomposition rates to lower temperatures forwhich the rates are too low for convenient measurement.The surfactants we investigated are being considered forsteamflood additives and need to be relatively stable atsteam temperatures.None of the surfactants evaluated to date has therequisite stability for use in steamfloods. The most stablepetroleum sulfonate we have investigated has a half-lifeof 11 days at 180 degrees C (356 degrees F). With this half-life, substantial overdosing would be required tomaintain the minimum effective surfactant concentration forthe life of the flood. On the other hand, the estimatedhalflife for this surfactant at 93 degrees C (200 degrees F), calculated by extrapolation, would be 33 years.Tests with the nonionic surfactant, nonylphenoxy-polyethanol, have shown this material to have a very short half-life at steam temperatures, but it doesappear to be more stable at concentrations greater than thecritical micelle concentration(CMC). In limited tests, the sulfonates showed increased stability in the presenceof a 2-M salt solution. Introduction Several chemical additives are being considered for usewith steamfloods to reduce the producing steam/oilratios and to increase oil recovery from steam projects.The emphasis to date has been on inorganic chemicaladditives. Sodium hydroxide has been used in the fieldwithout success. We have been investigating thepotential benefits of using organic surfactants. This hasbeen discusssed recently by Brown et al. and byGopalakrishnan et al. The surfactant would be introducedinto the reservoir along, with the steam at the beginning ofthe steamflood and, possibly, intermittently during the floodprocess. The surfactant would be injected in diluteconcentrations and would be expected to travel in thatportion of the reservoir being flooded by hot water.Although the residual oil saturation in the steam zone has been observed to be very low, residual saturation in thehot water portion of the steamflood is expected to be thenormal waterflood residual. A surfactant in the hot watermay reduce this residual oil saturation. A synergistic effect could be observed between the surfactant and thetemperature to give better performance than would beobserved for a surfactant flood at normal reservoirtemperatures.For the process to work as anticipated, the surfactantmust move in the heated portion of the reservoir, and it must be sufficiently stable at elevated temperatures tofunction as an effective recovery agent for the life of theflood. Therefore, two aspects of the process are beingstudied simultaneously. One of these is the effect oftemperature on adsorption of the surfactants, and theother is the effect of heat on the stability of thesurfactants. The effect of temperature on adsorption will bediscussed in a later paper. The objective of this paper isto discuss the experimental evaluation of the thermalstability of some surfactant types that could haveapplication in reservoir floods. The effect of temperatureon adsorption and stability of these surfactants also willbe important in micellar floods at higher reservoirtemperatures. Experimental Procedures Several anionic and noninoic surfactants were selectedfor evaluation. SPEJ P. 722^

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.

Peripheral Low Salinity Water Injection Handil Case Study

2021 ◽  
Author(s):  
Julfree Sianturi ◽  
Bayu Setyo Handoko ◽  
Aditya Suardiputra ◽  
Radya Senoputra
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Water Flooding ◽  
Residual Oil ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Low Salinity Water Injection

Abstract Handil Field is a giant mature oil and gas field situated in Mahakam Delta, East Kalimantan Indonesia. Peripheral Low Salinity Water injection was performed since 1978 with an extraordinary result. The paper is intending to describe the success story of this secondary recovery by low salinity water injection application in the peripheral of Handil field main zone, which successfully increased the oil recovery and brought down the remaining oil saturation beyond the theoretical value of residual oil saturation number. Water producer wells were drilled to produce low salinity water from shallow reservoirs 400 - 1000 m depth then it was injected to main zone reservoirs where the main accumulation of oil situated. This low salinity water reacted positively with the rock properties and in-situ fluids which was described as wettability alteration in the reservoir. It is related to initial reservoir condition, connate water saturation, rock physics and connate water salinity. This peripheral scheme then observed having the sweeping effect on top of pressure maintenance due to long period of injection. The field production performance was indicating the important reduction of residual oil saturation in some reservoirs with continuous low salinity water injection. From static Oil in Place calculation, some reservoirs have high current oil recovery up to 80%. This was proved by in situ residual oil saturation measurement which was performed in 2007 and 2011. It was indicating the low residual saturation as low as 8% - 15%. This excellent result was embraced by a progressive development plan, where water flooding with pattern and chemical injection will be performed later on. The continuation of this peripheral injection is in an on-going development with patterns injection which is called water flooding development. An important oil recovery can be achieved with a simple scheme of low salinity injection, performed in a close network injection, where the water treatment is simple yet significant oil gain was recovered. This innovation technique brings more revenue with less investment compared to chemical EOR injection.

Heavy Oil Recovery by Alkaline-Cosolvent-Polymer Flood: A Multi-Scale Research Using CT Imaging

2021 ◽  
Author(s):  
Hang Su ◽  
Fujian Zhou ◽  
Lida Wang ◽  
Chuan Wang ◽  
Lixia Kang ◽  
...  
Keyword(s):  
Computed Tomography ◽  
Ct Scan ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Micro Ct ◽  
Residual Oil ◽  
Micro Computed Tomography ◽  
Total Acid ◽  
Oil Saturation ◽  
Residual Oil Saturation

Abstract For reservoirs containing oil with a high total acid number, alkali-cosolvent-polymer (ACP) flood can potentially increase the oil recovery by its saponification effects. The enhanced oil recovery performance of ACP flood has been studied at core and reservoir scale in detail, however, the effect of ACP flood on residual oil saturation in the swept area still lacks enough research. Medical computed tomography (Medical-CT) scan and micro computed tomography (Micro-CT) scan are used in combination to visualize micro-scale flow and reveal the mechanisms of residual oil reduction during ACP flood. The heterogeneous cores containing two layers of different permeability are used for coreflood experiment to clarify the enhanced oil recovery (EOR) performance of ACP food in heterogeneous reservoirs. The oil saturation is monitored by Medical-CT. Then, two core samples are drilled in each core after flooding and the decrease of residual oil saturation caused by ACP flood is further quantified by Micro-CT imageing. Results show that ACP flood is 14.5% oil recovery higher than alkaline-cosolvent (AC) flood (68.9%) in high permeability layers, 17.9% higher than AC flood (26.3%) in low permeability layers. Compared with AC flood, ACP flood shows a more uniform displacement front, which implies that the injected polymer effectively weakened the viscosity fingering. Moreover, a method that can calculate the ratio of oil-water distribution in each pore is developed to establish the relationship between the residual oil saturation of each pore and its pore size, and reached the conclusion that they follow the power law correlation.

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