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"a… Oil recovery by imbibition vs. imbibition time and "b… oil recovery by waterflooding vs. pore volumes of brine injected for crude oilÕbrineÕrock "COBR… systems at different aging times "S wi Ä15%….
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Previous studies of crude oil/brine/rock (COBR) and related systems showed that wettability and its effect on oil recovery depend on numerous complex interactions. In the present work, the wettability of COBR systems prepared using Prudhoe Bay crude oil, a synthetic formation brine, and Berea Sandstone was varied by systematic change in initial wat...
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... Increase in recovery by imbibition over that for very strongly water-wet conditions has been attributed to increased microscopic displacement efficiency. 13,14 The effect of aging time on the relationships between oil recov- ery by waterflooding R w f and pore volumes of brine injected at initial water saturations of 15, 20, and 25% is shown in Figs. 2b, 3b, and 4b, respectively. Oil recovery by waterflooding increases with increase in aging time. Comparison of recovery curves by imbibition Figs. 2a, 3a, and 4a with recovery curves by water- flooding Figs. 2b, 3b, and 4b shows that, as imbibition rate de- creases, oil recovery by waterflooding increases. Results for re- covery of Soltrol ...
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... The study of connate water primarily focuses on its distribution within the pore spaces, 13-15 the mechanisms governing its production, 16,17 and its impact on well productivity and gas recovery. [18][19][20][21][22][23] Zhu et al. 24 conducted core flooding experiments and nuclear magnetic resonance (NMR) testing. They found that water primarily occupies small pore spaces and the inwall of large pores, while gas is distributed within the central region of large pores. ...
The late-stage development of gas reservoirs often encounters the paradox of significant remaining formation pressure coupled with low wellhead pressure, which indicates small drainage volume, low gas production rate, and low recovery efficiency, reducing gas supply and economic benefit. Owing to the lack of experimental research, the reasons behind this contradiction between gas production and producing pressure differential are unclear. The key factors affecting the development outcomes are reservoir permeability and initial water saturation, while the evaluation parameters include gas and water production rates, reservoir pressure, and recovery efficiency. Based on the characteristic properties of typical gas fields, physical simulation experiments of constant-rate gas production are conducted on spliced long cores with average permeabilities of 2.300, 0.486, and 0.046 millidarcy (mD). Furthermore, leveraging the multi-point embedded pressure measurement technique, the pressure drawdown propagations and the macroscopic and microscopic characteristics of connate water production at the initial water saturations of 0%, 20%, 40%, and 55% are investigated. By connate water, we mean water that occurs naturally within the pores of rock. Pre- and post-experiment core weighing and nuclear magnetic resonance testing are performed. In addition to the mercury injection tests, the results indicate that during gas reservoir depletion, connate water primarily stems from macropores and mesopores, with micropores and nanopores capturing water through capillary imbibition. Moreover, lower permeability and higher initial water saturation lead to greater pressure gradients, increased connate water production, and reduced recovery efficiency. Reservoirs with permeabilities below 0.1 mD are significantly affected by connate water, exhibiting steep pressure profiles. Owing to connate water, the near-wellbore pressure quickly decreases, while distant reservoir pressure barely decreases, implying a limited drainage area. To enhance the recovery efficiency, measures like infill drilling and reservoir stimulation are recommended for low-permeability gas reservoirs.
... Из этого следует, что невозможно привести все эксперименты к одинаковым условиям. В рамках данной работы рассмотрены четыре наиболее подходящих для данных моделей эксперимента -работы Бурбио, Хатибоглу, Жанга и Жоу [23]- [26]. ...
... Последняя рассматриваемая экспериментальная работа -серия экспериментов, проведенных Жоу [26]. От остальных работ она отличается тем, что образец погружали в воду, не изолируя никакие грани, из-за чего пропитка происходит одновременно прямоточная и противоточная, через все грани и во всем объеме керна. ...
In this paper, a comparative analysis of various approaches to modeling the process of capillary imbibition in oil-saturated rocks is carried out. Today, the permeability of developed oil fields is decreasing, due to which capillary processes begin to make a significant contribution to filtration. Therefore, the issue of reservoir-scale imbibition modeling is becoming increasingly relevant. Capillary imbibition is a process of spontaneous filtration of a liquid into a porous medium under the action of capillary forces. The aim of the study is to analyze approaches to the mathematical description of this process. To do this, one-dimensional models of single-phase imbibition by Handy, Lee and Horn, Benavente and Kai are considered, the Schmid one-dimensional two-phase imbibition equation is solved, and the ability of the filtration model in the tNavigator software package to predict imbibition is checked. For verification, real experiments on core are simulated. Based on the simulation results, conclusions are drawn that single-phase models have an increased error due to the interaction of water with the second phase and non-physical values of free parameters, which is why it is not recommended to scale them to large rock volumes. The two-phase model does not consider gravity, due to which the error increases at the last stages of vertical imbibition, so this approach must be modified to consider gravitational forces in the imbibition equation. A numerical one-dimensional experiment on a hydrodynamic simulator using the proposed core modeling technique showed the best convergence with experimental data with an error of 1 to 4%, which is why it is recommended for modeling capillary processes on the scale of a well.
... The former corresponds to when the system is arranged with boundary conditions and geometry such that oil and water flow in opposite directions. Typically, this is arranged by exposing the matrix to water (assumed to be wetting) on all open sides, as is done in the Amott test (Amott 1959;Ma et al. 1997;Zhou et al. 2000). By letting parts of the matrix surface be exposed to oil (assumed to be non-wetting) however, there will be a net flow of oil and water from the water exposed side towards the oil exposed side and the majority of oil production occurs there ( A main interest of performing SI tests is to understand the recovery potential by capillary forces from matrix blocks in naturally fractured reservoirs (Aronofsky et al. 1958). ...
... By letting parts of the matrix surface be exposed to oil (assumed to be non-wetting) however, there will be a net flow of oil and water from the water exposed side towards the oil exposed side and the majority of oil production occurs there ( A main interest of performing SI tests is to understand the recovery potential by capillary forces from matrix blocks in naturally fractured reservoirs (Aronofsky et al. 1958). Positive capillary forces, which corresponds to the rock having some water-wetness, is necessary for SI to occur (Anderson 1987;Zhou et al. 2000). It is important that the SI process occurs efficiently such that the injected water results in a significant oil production, as such reservoirs are associated with rapid water breakthrough and high water cut (Bratton et al. 2006; Alcantara et al. 2019). ...
... Spontaneous imbibition is a strong indicator of wettability in the sense that the water uptake, and hence oil production, is limited by the degree of water-wetness (Kovscek et al. 1993;Zhou et al. 2000). If the rock is strongly oil-wet there is no uptake, while stronger water-wetness means more uptake (Anderson 1987a). ...
... Additionally, we consider MW relative permeabilities and J-function from Behbahani and Blunt (2005) (Fig. 16a). They ran pore scale simulation of wetting conditions and matched experiments by Zhou et al. (2000) with upscaled functions. We vary oil viscosity (from 0.1 to 1000 cP), obtain Λ n (Fig. 16b), calculate z a,b , estimate A, RF tr and lr (Tables 4 and 5), unscale T n to get RF(t) and compare with numerical simulations in Fig. 15b (the two cases with lowest viscosity are similar). ...
Solutions are investigated for 1D linear counter-current spontaneous imbibition (COUSI). It is shown theoretically that all COUSI scaled solutions depend only on a normalized coefficient \({\Lambda }_{n}\left({S}_{n}\right)\) with mean 1 and no other parameters (regardless of wettability, saturation functions, viscosities, etc.). 5500 realistic functions \({\Lambda }_{n}\) were generated using (mixed-wet and strongly water-wet) relative permeabilities, capillary pressure and mobility ratios. The variation in \({\Lambda }_{n}\) appears limited, and the generated functions span most/all relevant cases. The scaled diffusion equation was solved for each case, and recovery vs time \(RF\) was analyzed. RF could be characterized by two (case specific) parameters \(RFtr\) and \(lr\) (the correlation overlapped the 5500 curves with mean \({R}^{2}=0.9989\)): Recovery follows exactly \(\mathrm{RF}={T}_{n}^{0.5}\) before water meets the no-flow boundary (early time) but continues (late time) with marginal error until \(RFtr\) (highest recovery reached as \({T}_{n}^{0.5}\)) in an extended early-time regime. Recovery then approaches 1, with \(lr\) quantifying the decline in imbibition rate. \(RFtr\) was 0.05 to 0.2 higher than recovery when water reached the no-flow boundary (critical time). A new scaled time formulation \({T}_{n}=t/\tau {T}_{\mathrm{ch}}\) accounts for system length \(L\) and magnitude \(\overline{D }\) of the unscaled diffusion coefficient via \(\tau ={L}^{2}/\overline{D }\), and \({T}_{\mathrm{ch}}\) separately accounts for shape via \({\Lambda }_{n}\). Parameters describing \({\Lambda }_{n}\) and recovery were correlated which permitted (1) predicting recovery (without solving the diffusion equation); (2) predicting diffusion coefficients explaining experimental recovery data; (3) explaining the challenging interaction between inputs such as wettability, saturation functions and viscosities with time scales, early- and late-time recovery behavior.
... Different parameters impact residual oil saturation to water (Cubitt and Wales, 2015), and in particular wettability is one of the most important parameters influencing waterflood oil recovery (Moore and Slobod, 1955). Several studies have found that the lowest residual oil saturation after conventional waterflooding is at neutral-wet, weakly water-wet or mixed-wet conditions (Rathmell et al., 1973;Salathiel, 1973;Jadhunandan and Morrow, 1995;Zhou et al., 2000). ...
Polymer retention is one of the controlling aspects of an effective polymer flooding process. Very few studies discussed the effect of rock wettability on polymer retention, with no consensus on the outcome. While some studies described that oil-wet rocks have low polymer retention, others reported the opposite. This work investigates the effect of rock wettability on the retention of an ATBS-based polymer onto carbonates at high salinity and moderate temperature conditions. In this study, static and dynamic retention tests of an ATBS-based polymer onto high permeable Indiana limestone outcrops were conducted in both absence and presence of oil. These tests were conducted at 50 °C using representative crude oil and formation water (167,114 ppm) of Middle East carbonate reservoir conditions. For the two-phase dynamic tests, the cores were aged at 90 °C for different times (8 hours, 3 and 14 days) to create different wettability conditions, which were verified by Amott index to water. Then, polymer retention and in-situ rheology, including RF and RRF, were determined. Similar procedure was followed for dynamic single-phase tests, but without core aging. Furthermore, single- and two-phase static tests were conducted under identical experimental conditions to compare the retention values.
The results of Amott index to water showed that the selected aging times were suitable for creating different wettability conditions, where cores with longer aging times had a wettability more towards oil-wetting state. It was observed that three-days period of aging was enough to restore the wettability of Indiana limestone outcrops used in this study. Also, polymer dynamic retention was found lower in the presence of oil by about 35 to 47% as opposed to its absence. A further decrease in polymer retention by 14% was obtained for cores with a more oil-wetting condition resulting in a retention level of about 25 µg/g-rock. This is because oil-wet cores have a larger and effective surface area covered by the oil film, leading to a lower surface area left for polymer adsorption as opposed to cores with a wettability towards a more water-wetting state. On the other hand, single- and two-phase static adsorption tests showed non-comparable and very high retention values in the range of 305-337 µg/g-rock. This finding indicates that aging of the rock in such tests does not play a decisive role in obtaining representative polymer retention levels comparable to the dynamic tests. This study is one of the very few works that discuss the effect of rock wettability on polymer retention in carbonates. The study provides an essential insight into the inconclusive results in the literature by highlighting the role of wettability effect on polymer retention based on both static and dynamic retention tests.
... Manual shaking of the Amott cell (Graue et al., 1999;Cobos et al., 2021) or scratching the core plug surface with a teflon road (Morrow et al., 1999;Zhou et al., 2000) helped minimize this effect, but did not yield completely smooth recovery profiles. Some authors conducted imbibition experiments with a core plug placed horizontally to minimize the effect of buoyancy displacement (Zhou et al., 2000;Ghedan et al., 2009). ...
... Manual shaking of the Amott cell (Graue et al., 1999;Cobos et al., 2021) or scratching the core plug surface with a teflon road (Morrow et al., 1999;Zhou et al., 2000) helped minimize this effect, but did not yield completely smooth recovery profiles. Some authors conducted imbibition experiments with a core plug placed horizontally to minimize the effect of buoyancy displacement (Zhou et al., 2000;Ghedan et al., 2009). In other works, the flow was restricted in radial direction by sealing the top and bottom faces of a core plug with epoxy resin (Xie and Morrow, 2001;Sukee et al., 2022). ...
The improved oil recovery techniques, such as customized ionic composition waterflood or "smart-water" flood, are being developed to increment crude oil production. Counter-current spontaneous imbibition of brine into oil-saturated rock is a critical mechanism of recovery of the crude oil bypassed in highly-heterogeneous carbonate rocks. In laboratory, spontaneous imbibition in the Amott cell experiment is the main instrument to explore oil recovery from oil-saturated core plugs at different wettability conditions. The classical Amott test, however, masks a number of flaws that hinder interpretation of the physical phenomena in recovery dynamics and precise modeling of the cumulative recovery profiles. In this work, we identify these flaws in the spontaneous imbibition experiments with mixed-wet limestone samples saturated with crude oil. We describe an improved Amott method and study crude oil recovery from mixed-wet carbonate core plugs. The introduced modifications of the Amott test ensure reliable and reproducible results for both non-wetting mineral and crude oils. Finally, we show that the resulted smooth recovery profiles of oil production can be described with a mathematical model with high accuracy. For the first time, we show that generalized extreme value (GEV) distribution can be applied to model cumulative oil production from mixed-wet carbonate core samples.
... The heterogeneity of the rock, particularly different amounts of micro-porosity, leads to a wide range of initial water saturation, S wi , for the different samples (Table 5) [32]. In general, lower S wi , is associated with more oil-wet conditions and a lower imbibition recovery from these cores is expected [32]. ...
... The heterogeneity of the rock, particularly different amounts of micro-porosity, leads to a wide range of initial water saturation, S wi , for the different samples (Table 5) [32]. In general, lower S wi , is associated with more oil-wet conditions and a lower imbibition recovery from these cores is expected [32]. The core with the lowest S wi thus also had the lowest recoveries. ...
Enhanced oil production can maximise yield from depleted reservoirs, and in the face of dwindling global oil reserves can reduce the need for exploratory drilling during the transition away from fossil fuels. A hybrid technique, merging a magnetic field (MF) and magnesium oxide (MgO) nanoparticles (NPs), was investigated as a potential method of enhancing oil production from oil-wet carbonate reservoirs. The impact of this hybrid technique on rock wettability, zeta potential, and interfacial tension was also investigated. Displacement experiments were carried out on oil-wet Austin chalk – a laboratory carbonate rock analogue – using MgO NPs in deionized water (DW) and salt water (SW), in the presence of an MF up to 6000 G in strength. It was found that the addition of MgO NPs to DW before the spontaneous imbibition of the solution into initially oil-wet rock samples increased the recovery factor (RF, defined as the volume of oil recovered divided by the initial oil in place). For 0.005 wt% and 0.0025 wt% MgO NPs mixed in DW, the RF was 12.5% and 15.9% respectively. When DW was replaced with SW as the imbibing fluid, the RF increased by a further 0.7% of initial oil in place for the 0.0025 wt% MgO NPs. This additional increase in oil recovery was attributed to the presence of potential determining ions, which made the rock more water-wet. To avoid pore-clogging and thus the limited ingress of the solution into the rock, the NPs’ concentration was kept low. This hybrid technique is a cleaner alternative to conventional enhanced oil recovery techniques and will enable oil industries to produce oil more efficiently from existing reservoirs: when used in conjunction with Carbon Capture and Storage (CCS), this provides a useful short to medium-term option to support energy production during the transition to net zero.
... Wettability has been unanimously established as a major criterion affecting improved and enhanced oil recovery (Zhou et al., 2000;Morrow and Mason, 2001;Hirasaki and Zhang, 2003). Wettability is the feature of a fluid to move around and attach onto a solid surface when another immiscible liquid is present (Crain, 2002). ...
Most oil fields today are mature, and the majority of the reservoirs in the Middle East are carbonate rocks characterized by high temperature high salinity (HTHS), heterogeneous mineral composition, and natural fractures. Enhanced oil recovery (EOR) methods are used for boosting oil recovery from the aged reservoirs beyond primary and secondary recovery stages. Nevertheless, it can be a challenging task to employ EOR techniques in these aged carbonate reservoirs. This is because carbonate reservoirs have mixed-to-oil-wet wettability with temperatures exceeding 85 °C and salinity of over 100,000 ppm, which renders secondary EOR-methods such as waterflooding ineffective. Therefore, even though carbonate reservoirs contain 60–65% of world's remaining oil, with immense intrinsic economic prospects, the oil recovery process from carbonate reservoirs remains a considerable challenge. Chemical-EOR (cEOR) techniques, like SP based cEOR, have shown marked promise in improved oil recovery, mainly from clastic reservoirs with medium temperature and salinity, unlike carbonate reservoirs. During SP-floodings, the surfactants get adsorbed due to the mineral composition of the carbonate rocks, and polymer degradation occurs due to HTHS conditions. Consequently, new surfactants and polymers have been structurally conformed and tested to improve their robustness and related recovery efficacy. For instance, Guerbet alkoxy-carboxylate surfactants demonstrated good stability at temperatures over 100 °C and salinities up-to 275,000 ppm, yielding tertiary recovery of 94.5% and low adsorption of 0.086 mg/g of rock. The cationic Gemini surfactants, zwitterionic or amphoteric class of surfactants are also suitable for HTHS carbonates. Besides, effective biosurfactants sourced from plant such as, soy, corn, etc., are non-toxic and readily biodegradable. The hydrophobically associating polyacrylamide (HAPAM) and its modified nanocomposite derivative can act as replacement surfactants, due to their wettability altering and robust characteristics. Novel polymers viz., NVP-based, novel smart thermoviscosifying polymers (TVP), soft microgel, and sulfonated polymers, are also relevant to HTHS carbonate applications. Xanthan gum, scleroglucan, and schizophyllan biopolymers have been noted to resist HTHS and low permeability conditions, requiring lower concentration and having low adsorption. Recent surfactant-polymer (SP) formulations also can be applicable for HTHS carbonates with excellent ternary recoveries (93.6%) and minimal retention (0.083 μg/g of rock). Such low retention values suggest low surfactants cost with minimal environmental impact. Moreover, several successful field applications in carbonates were conducted in preceding years; however, the performance of some novel surfactants under HTHS carbonates is yet to be fully understood. Hence, this comprehensive review aims to provide renewed perspectives on surfactant and polymer optimizations for field applications in HTHS carbonates. A list of recommendations is presented as guidelines for efficient SP-flooding designs. This critical literature appraisal furnishes an array of potential manifestations for successful field application of SP-flooding in HTHS carbonates, which holds both economic and environmental feasibility.
... Counter-current SI has been investigated thoroughly to understand the impact of fluidrock parameters, wettability, geometry, flow mechanisms etc., with the intention of accurate upscaling to reservoir matrix block scales [28][29][30][31][32]. An important feature of SWW media is that SI can yield as high a recovery as forced imbibition, while in more oil-wet media SI yields, it yields a lower recovery than forced imbibition [33]. Scaling relations accounting for changes in the stated parameters have been developed, where we note that Ma et al. [29] suggested an effective length to convert arbitrary boundary conditions (closed or open to water) and geometries to a 1D linear system with one side open and the other closed. ...
Forced and spontaneous imbibition of water is performed to displace oil from strongly water-wet Gray Berea (~130 mD) and Bentheimer (~1900 mD) sandstone core plugs. Two nonpolar oils (n-heptane and Marcol-82) were used as a non-wetting phase, with viscosities between 0.4 and 32 cP and brine (1 M NaCl) for the wetting phase with viscosity 1.1 cP. Recovery was measured for both imbibition modes, and pressure drop was measured during forced imbibition. Five forced imbibition tests were performed using low or high injection rates, using low or high oil viscosity. Seventeen spontaneous imbibition experiments were performed at four different oil viscosities. By varying the oil viscosity, the injection rate and imbibition modes, capillary and advective forces were allowed to dominate, giving trends that could be captured with modeling. Full numerical simulations matched the experimental observations consistently. The findings of this study provide better understanding of pressure and recovery behavior in strongly water-wet systems. A strong positive capillary pressure and a favorable mobility ratio resulting from low water relative permeability were main features explaining the observations. Complete oil recovery was achieved at water breakthrough during forced imbibition for low and high oil viscosity and the recovery curves were identical when plotted against the injected volume. Analytical solutions for forced imbibition indicate that the pressure drop changes linearly with time when capillary pressure is negligible. Positive capillary forces assist water imbibition, reducing the pressure drop needed to inject water, but yielding a jump in pressure drop when the front reaches the outlet. At a high injection rate, capillary forces are repressed and the linear trend between the end points was clearer than at a low rate for the experimental data. Increasing the oil viscosity by a factor of 80 only increased the spontaneous imbibition time scale by five, consistent with low water mobility constraining the imbibition rate. The time scale was predicted to be more sensitive to changes in water viscosity. At a higher oil-to-water mobility ratio, a higher part of the total recovery follows the square root of time. Our findings indicate that piston-like displacement of oil by water is a reasonable approximation for forced and spontaneous imbibition, unless the oil has a much higher viscosity than the water.
... The reason for such a modest modification may be related to the high levels of connate water during the ageing process, above 30 %. It is well-known that the alteration of wettability when aging rock samples in crude oil is strongly depending on the amount of water saturation in cores (Hamon, 2000;Zhou et al., 2000). The end point oil saturations measured in the three experiments are quite similar. ...
Laboratory core flooding experiments performed are used to predict fluid flow behaviour in the reservoir. Most reservoirs are in a reduced state. However, iron minerals in the extracted cores may become oxidized going from the reservoir to the laboratory. Oxidation of the core can affect wettability and thereby relative permeability curves used for reservoir simulation studies. The aim of this work was to study the potential effect of core oxidation on relative permeability.
Steady state relative permeability experiments with in-situ saturation measurements and use of live oil have been performed on one composite core at 10 different saturations. The core was tested under three different conditions: oxidized (Exp. 1), reduced (Exp. 2) and re-oxidised (Exp. 3). The core was cleaned, fluid saturated and aged before each test. In Exp. 2, the core plug was chemically reduced. All fluids used in this experiment were oxygen free. In Exp. 3 the core plug was treated using fluids to oxidise the core. Fluids injected and extracted, and core samples were analysed using a range of methods.
Results showed that the measured relative permeability curves from Exp. 2 and 3 were similar and significantly different from the results from Exp. 1. The attempt to restore the core material to the initial state (oxidized) after Exp. 2 by exposing the core material to fluids with oxygen was seemingly not successful. The observation was also supported by unsteady state flooding measurements which indicated that as long as the core remained fluid saturated, it behaved as a reduced core, even after extensive exposure to oxygen containing liquids. The crossing point of the oil and water relative permeabilities indicate that the core was more water wet in reduced state compared to before the oxidized state. Differences in chemical composition were also detected between extracts from Exp. 1 - 3.
The conclusion is that significant differences in steady state relative permeabilities of oil and water in oxidized and reduced states were observed for the iron containing core investigated. The results also indicate that if the core is kept fluid saturated, effects of oxidation may be significantly delayed.
