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We present a technique that enables the determination of the minimum miscibility pressure (MMP) of a CO2 – oil system using a short 20 ft slim tube in less than two weeks, about a third of what it normally takes using the conventional 80 ft slim tube. MMP is a crucial parameter in designing a CO2 enhanced oil recovery project and its value needs to...
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... all cases, the pressures for the displacement were 500, 750, 1000, 1800, 2500 and 3500 psig. Table 1 represents the results for the six runs at 3500, 2500, 1800, 1000, 750 and 500 psig, for the five light crude oil samples used in our work. The recovery factors measured at the three lower pressures of 500, 750 and 1000 psig show a strong dependency on pressure, which indicates that miscibility has not yet been reached. ...
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Citations
... The slim tube test is widely used to determine the MMP and is considered the most accurate experimental method for this purpose (Amao et al., 2012). However, the slim tube test is time-consuming and expensive (Adel et al., 2016). To overcome these limitations, the simulation of slim tube test was utilized in this study. ...
The article shows research into the non-fuel use of brown coal derivatives for the modification of bitumen. The work used petroleum road grade bitumen BND 60/90 with a flash point in an open crucible of 260 °C, a softening temperature (using the ring and ball method) of 48 °C, resin after lignite thermal destruction and rubber waste. and powder. Based on the fact that the most relevant technologies for the non-fuel use of brown coal concern areas aimed at obtaining wax, humane preparations, adsorbents, obtaining valuable derivatives in the form of resins, GR, etc., an assessment was made of the non-fuel use of brown coal derivatives for modification bitumen. Analysis of the experimental results showed that the studied quality indicators of the composition samples, which include waste rubber powder, have an increased complex of both thermophysical and physical-mechanical characteristics. This is obviously due to the fact that, as a result of thermal destruction of rubber powder, the swelling process occurs faster compared to crumb rubber with a size of 2.5–4.5 mm. However, the process of destruction and dispersion in both cases does not occur completely, of course, and the volume of edematous rubber particles contains resins and polyaromatic components that affect the value of both thermophysical and physical-mechanical characteristics. Thus, it has been established that the optimal composition for creating effective polymer-modified bitumens with an increased complex of thermo-physical and physical-mechanical characteristics is 40 % by weight of rubber powder and 5 % by weight. brown coal resins after thermal destruction. It is shown that the results of laboratory studies have proven the prospects of using brown coal tar after thermal destruction for the modification of road bitumen. Summarizing research into the direction of non-fuel use of brown coal derivatives in the form of liquid products – tar resins of brown coal after thermal destruction for the modification of bitumen materials, it should be noted that the results obtained are moderate in comparison with existing directions for the production of polymer-modified bitumens. Modification of bitumen with primary and secondary polymers makes it possible to significantly improve their adhesion and performance characteristics compared to brown coal resins after thermal destruction. The use of brown coal resins after thermal destruction is much less effective in improving the elasticity, heat resistance and reducing the fragility of bitumen compositions compared to the use of thermoplastic and thermoelastomer modifiers in the production of polymer-modified bitumens.
... Therefore, the impact of reservoir temperature has received more attention. The details of the investigational setups and procedures have already been described [46][47][48]; thus, they will not be discussed in detail here. The findings demonstrate that oil recovery is strongly correlated with the temperature at low pressures, implying that miscibility has not yet been achieved. ...
The current and latest technology to produce unconventional oil reservoirs is the cyclic gas injection method. Over the last decade, extensive experiments have been conducted to produce tight reservoirs, and a wide variety of parameters have been considered. However, the influence of key factors such as gas-phase miscibility and miscibility mode on oil recovery remains unclear. Additionally, previous studies have focused mostly on conventional procedures that fail to satisfactorily represent depleted oil field conditions. These assumptions may be the justification for the disappointing outcomes of some pilot tests, in spite of the outstanding demonstration of competence of the lab scale. This study attempts to explore the sensitivity of CO2 phase miscibility and CO2 miscibility mode in enhancing the bypassed oil recovery. Prior to the cyclic gas process, oil is bypassed in tight sandstone cores using the immiscible soaking step. The findings indicate that increasing CO2 injection pressure may not be the only factor contributing to extracting residual oil; the CO2 phase properties may also play a significant role in producing remaining oil. The use of supercritical CO2 resulted in the highest bypassed oil recovery rate of up to 30.40%. However, the compressed liquid CO2 phase recovered slightly more initial oil, particularly at pressures less than or equal to the minimum miscibility pressure (MMP). Increasing the CO2 soaking time plays a major role in extracting the bypassed oil. However, 50% of the oil can be extracted within the first cycle. Therefore, a long soaking period is not recommended in the subsequent cycles.
... MMP is a crucial parameter for any gas injection projects, as injecting gas below, near, or above the MMP can result in varying recovery factors [91]. There are several methods available to determine MMP, including the slim tube test, the vanishing interfacial tension method, the rising bubble method, pressure/composition diagrams, and numerical simulation [92][93][94]. Of these methods, the slim tube test is the most widely used and provides the most accurate results, but it is also the most time-consuming, typically taking 4 to 5 weeks to complete [93]. ...
... The slim tube test is recognized to be the most accurate experimental method for determining MMP. However, the slim tube test is expensive and takes a long time to measure MMP [41]. To overcome the limitations, slim tube test simulation has been widely used. ...
... 2021, 11, x FOR PEER REVIEW 7 of 14 experimental method for determining MMP. However, the slim tube test is expensive and takes a long time to measure MMP [41]. To overcome the limitations, slim tube test simulation has been widely used. ...
Dimethyl ether (DME) is a compound first introduced by Shell as a chemical solvent for enhanced oil recovery (EOR). This study aims to investigate the efficiency of EOR using the minimum miscible pressure (MMP) and viscous gravity number when a mixed solvent of CO2 and DME is injected. Adding DME to the CO2 water-alternating-gas process reduces the MMP and viscous gravity number. Reduction in MMP results in miscible conditions at lower pressures, which has a favorable effect on oil swelling and viscosity reduction, leading to improved mobility of the oil. In addition, the viscous gravity number decreases, increasing the sweep efficiency by 26.6%. Numerical studies were conducted through a series of multi-phase, multi-component simulations. At a DME content of 25%, the MMP decreased by 30.1% and the viscous gravity number decreased by 66.4% compared with the injection of CO2 only. As a result, the maximum oil recovery rate increased by 31% with simultaneous injection of DME and CO2 compared with only using CO2.
... Therefore, the miscibility of CO 2 with the respective crude oil plays a relevant role. In this regard, the so-called minimum miscibility pressure (MMP), as a quasi-critical point, has been thoroughly investigated by use of the slim-tube method [23], or the method of vanishing interfacial tension (VIT) [24,25]. Conventional core flooding tests using CO 2 are scarce because of the difficulty in sealing the core towards CO 2 [26,27]. ...
A systematic study was carried out on the governing mechanisms during extraction of hydrocarbonsfrom tight rock formations using supercritical carbon dioxide at pressures between 15 and 40 MPa at40 to 60◦C. Despite reasonable porosity, extraction kinetics are strongly diffusion controlled due to lowpermeability arising from small pore diameters and little pore interconnectivity. Other system propertieswere determined such as interfacial tension, contact angle, sorption and diffusivity, all related to thetransport mechanisms inside the rock pores. The interfacial tension of hydrocarbons in CO2decreasesas a function of pressure yet maintains a fairly constant value between 15 and 40 MPa, which showsresemblance to heavy oil behavior. Concurrently the contact angle of formation water increases withpressure which helps mobilize and remove the aqueous phase. A feasible way of combining hydrocarbonextraction and CO2sequestration in tight rock formations is shown at moderate pressure and temperatureconditions.
... The slim tube method is considered the most accurate way to determine the MMP. This method, being one dimensional, avoids the unfavorable conditions such as gravity override, unfavorable viscosity ratios and fingering, making this method the most accurate way to determine the MMP (Adel et al. 2018;Adel et al. 2016). ...
Field observations, along with experimental laboratory, exhibit evidence that enhancing production by CO2 huff-n-puff process is a potential EOR technique that improves the, commonly low, ultimate oil recovery in unconventional liquid reservoirs (ULR). As pressure goes beyond the MMP, intermediate components of oil vaporize into the CO2 and consequently condense at room pressure and temperature. In addition, Surfactant-Assisted Spontaneous Imbibition (SASI) process has been widely believed to enhance oil recovery in ULR, which has been investigated by several laboratory and numerical studies. During the hydraulic fracturing with surface active additives, surfactant molecules interact with rock surfaces to enhance oil recovery through wettability alteration and interfacial tension reduction. The wettability alteration leads to the expulsion of oil from the pore space as well as water being imbibed into the matrix spontaneously. However, the understanding of hybrid EOR technologies, combining both gas injection and surfactant imbibition, to enhance recovery in ULR is not well studied.
In this manuscript, we assess the potential of combining both CO2 huff-n-puff and surfactant imbibition techniques in optimizing oil recovery in ULR. Sidewall core samples retrieved from ULR were first cleaned utilizing the Dean-Stark methodology and then saturated by pressurizing them with their corresponding oil for three months. CO2 huff-n-puff experiments were operated on shale core samples under different pressures in a set-up integrated into a CT-scanner. Those cores were then submerged in the surfactant solution, in a modified Amott cell, to observe whether any additional oil is produced through the process of SASI. Total production from these two different methods, which was done sequentially, will provide insight into the possibility of hybrid EOR technology. CO2 huff-n-puff experiments were performed below and above the MMP which was previously determined by the slim-tube method. Contact angle (CA), interfacial tension (IFT) were also measured on the saturated shale core samples. CT-Scan technology was used to visualize the process of oil being expelled from the core plugs in both CO2 huff-n-puff and spontaneous imbibition experiments.
Experimental results provide a promising outcome on the application of hybrid EOR technology, CO2 huff-n-puff and SASI, improving oil recovery from ULR. Oil recovery was observed to reach around 50% of measured OOIP from CO2 huff-n-puff alone with an addition of 10% recovery from SASI after the CO2 treatment. A detailed description of the correlated experimental workflows is presented to investigate the hybrid EOR technology in enhancing oil recovery in ULR. In addition, a discussion on the difference in mechanism of oil production from the huff-n-puff and SASI method is also included alongside several additional novel findings regarding the color shift of the produced oil. MMP data of CO2 and oil measured as well as a change of contact angle (CA) and interfacial tension (IFT) when the surfactant is introduced into the system are also provided to support insight on the mechanism of the production improvement. All measured and compiled data deliver the required information for this study to demonstrate the possibility of combining both CO2 EOR and SASI EOR, a hybrid EOR, as a practical method to produce a significant amount of oil from unconventional shale oil reservoirs.
... Methods of improving the production of oil from shale plays are being explored to enhance these low recovery factors (Adel et al. 2018b;Zou and Schechter 2017). Gas injection, where miscibility plays a significant factor (Adel et al. 2016), as well the addition of surfactant into completion fluid are two of the most widely implemented EOR methods Zhang et al. 2018a). The addition of surfactants into completion fluids is being successfully used as an EOR method in ULR. ...
Experimental laboratory evidence of enhanced production by spontaneous imbibition via the addition of surfactants into completion fluids, as well as field observations, indicate a significant improvement in EUR with the use of surfactants to improve oil recovery from unconventional liquid reservoirs (ULR). During a hydraulic fracture treatment, the surfactant molecules interact with the rock surface, altering its wettability and interfacial tension. The wettability alteration of the rock surface from oil-wet to water-wet enables the spontaneous imbibition of water into the matrix, which expels the oil out of the pore space towards the fractures. Several laboratory and numerical studies have investigated the effectiveness of surfactant-assisted spontaneous imbibition (SASI) on various ULR. However, the understanding of surfactant selection for the optimization of enhancing recovery in ULR is not well studied.
Capillary pressure is the dominant force for spontaneous imbibition process. Contact angle (CA) and interfacial tension (IFT) are essential terms in the Young-Laplace capillary pressure equation as well as in published scaling analysis of the spontaneous imbibition process. With the large amount of data released on SASI, it is natural to develop a correlation between the two properties to the recovery factor. However, no work has been conducted to investigate the relationship of contact angle and IFT on ultimate recovery by spontaneous imbibition in ULR. In this manuscript, a compilation of CA, IFT, and spontaneous imbibition experiments from two of the most prolific shale reservoirs is presented to give an insight into the relationship between the three variables. Then, based on the observed trends and correlations, a new scaling model for SASI in ULR is proposed. The ultimate goal is to develop a surfactant selection method based on scaling analysis results and laboratory data for optimal performance in ULR.
A total of 35 independent SASI correlated experiments data were compiled, which includes CA, IFT, recovery factor, porosity, core plug dimensions, and capillary pressure calculated from the Young-Laplace equation. Experimental procedure on each data point followed the robust data gathering methodology that was already developed for the past four years. The reliable procedure ensures the representability of the reservoir condition in the laboratory measurements to provide an accurate description of the effectivity of different surfactants on a corresponding oil/water/rock system. Two systems were analyzed and assembled into three groups, Wolfcamp, Eagle Ford A, and Eagle Ford B. An inversely proportional correlation between CA and recovery factor was observed, while on the IFT and recovery factor analysis, a less apparent correlation was found. Theoretically, a directly proportional correlation between capillary pressure and recovery factor can be expected due to spontaneous imbibition that is primarily dominated by capillary forces, which is consistent with experimental data analysis. The high dependence of recovery factor on contact angle and the less significant effects from IFT lead us to conclude that a substantial wettability altering surfactant is highly preferred to enhance through SASI. In addition, based on the observed correlation, a new dimensionless scaling equation fully accounting for the effect of surfactant addition was developed to generalize the flow behavior of SASI.
... We determined the MMP using the slim tubing technique with a column 80 ft in length, an outside diameter of 0.25 in, and of wall thickness of 0.063 in. The experimental procedure for the determination of MMP has been described elsewhere (Adel, Tovar, and Schechter 2016, Tovar, Barrufet, and Schechter 2015, Adel 2016). The recovery factor as a function of pressure for crude oil 1 and crude oil 2 are presented in Figure 10. ...
We present the first comprehensive experimental evaluation of gas injection for EOR in organic rich shale. Experiments in preserved core demonstrated the potential of CO2 to extract the naturally occurring oil in organic rich shale reservoirs, whereas tests in re-saturated core plugs were used to compute accurate recovery factors, and evaluate the effect of soak time, operating pressure, and the relevance of slim-tube MMP on recovery. 18 core-flooding experiments were conducted in sidewall cores from different shale plays.
The cores re-saturated with crude oil, were first cleaned by Dean-Stark extraction, and submitted to porosity and compressibility determination. The re-saturation, confirmed by CT-scanning, was attained by aging the core plugs at high pressure for two to four months. In all experiments, glass beads surrounding core samples were used to simulate the proppant and physically recreate in the laboratory a hydraulic fracture connected to the shale matrix. The slim-tube MMP was measured with CO2, and core-flooding experiments were performed below, close to, and above the MMP. The displacement equipment was coupled to a medical CT-scanner that enabled us to track the changes in composition and saturation taking place within the shale cores during the experiments. Continuous CO2 injection and huff-and-puff were evaluated using soak time from zero to 22 hours. Fixed reservoir temperature was used in all the experiments.
Recovery factors ranged from 1.7 to 40%. The wide variation was the result of different experimental conditions for pressure and soak time. Both operational parameters were found to significantly affect the recovery. Increasing soak time at constant pressure consistently resulted in significant increase in recovery. The increase varied from 78 to 464% for different pressures and oil composition. Similarly, increasing operating pressure at constant soak time resulted in significant increase in recovery factor from 44 to 338% depending on soak time and oil composition. Unlike the typical response during CO2 EOR in conventional rocks, in organic rich shale, further pressure increases beyond the slim-tube MMP continued to increase the recovery factor significantly. In all runs, almost all oil recovery occurred within three days from the start of the experiment, and in all huff-and-puff tests the highest rate of recovery was observed in the first cycle, implying oil recovery with CO2 is a fast process, in comparison to oil re-saturation of the samples which occurs at a significantly slower rate.
This investigation demonstrates CO2 EOR is a technically feasible method to extract significant amounts of crude oil from organic rich shale reservoirs and it provides operational understanding of how to manage pressure and soak time to maximize recovery. The recovery factors obtained in this investigation, in the context of the vast reserves of crude oil contained in organic rich shale, can sustain a second shale revolution and further capitalize oilfield infrastructure.
... Unconventional liquid reservoirs (ULR) have played a significant role in domestic oil production for almost a decade and has led the United States to become one of the largest oil producers in the world ( Adel et al. 2016). The recent success in developing these reservoirs is driven by multistage hydraulic fracturing technology, a necessity due to the ultralow permeability that characterizes ULR. ...
Field experience along with laboratory evidence of spontaneous imbibition via the addition of surfactants into the completion fluid is widely believed to improve the IP and ultimate oil recovery from unconventional liquid reservoirs (ULR). During fracture treatment with surface active additives, surfactant molecules interact with the rock surface to enhance oil recovery through wettability alteration combined with interfacial tension (IFT) reduction. The change in capillary force as the wettability is altered by the surfactant leads to oil being expelled as water imbibes into the pore space. Several laboratory studies have been conducted to observe the effectiveness of surfactants on various shale plays during the spontaneous imbibition process, but there is an insufficient understanding of the physical mechanisms that allow scaling the lab results to field dimensions.
In this manuscript, we review and evaluate dimensionless, analytical scaling groups to correlate laboratory spontaneous imbibition data in order to predict oil recovery at the field scale in ULR. In addition, capillary pressure curves are generated from imbibition rate theory originally developed by Mattax and Kyte (1962). The original scaling analysis was intended for understanding the rate of matrix-fracture transfer for a rising water level in a fracture-matrix system with variable matrix block sizes. Although contact angle and interfacial tension (IFT) are natural terms in scaling theory, virtually no work has been performed investigating these two properties. To that end, we present scaling analysis combined with numerical simulation to derive relative permeability curves, which will be imported into a discrete fracture network (DFN) model. We can then compare analytical scaling methods with conventional dual porosity concepts and then progressed to more sophisticated Discrete Fracture Network concepts. The ultimate goal is to develop more accurate predictive methods of the field-scale impact due to the addition of surfactants in the completion fluid.
Correlated experimental workflows were developed to achieve the aforementioned objectives including contact angle (CA) and IFT at reservoir temperature. In addition, oil recovery of spontaneous imbibition experiments was recorded with time to evaluate the performance of different surfactants. Capillary pressure-based scaling is developed by modifying previously available scaling models based on available surfactant-related properties measured in the laboratory. To ensure representability of the scaling method; contact angle, interfacial tension, and ultimately spontaneous imbibition experiments were performed on field-retrieved samples and used as a base for developing a new scaling analysis by considering dimensionless recovery and time. Based on the capillary pressure curves obtained from the scaling model, relative permeability is approximated through a history matching procedure on core-scale numerical models. CT-Scan technology is used to build the numerical core plug model in order to preserve the heterogeneity of the unconventional core plugs and visualize the process of water imbibition in the core plugs. Time-lapse saturation changes are recorded using the CT scanner to visualize penetration of the aqueous phase into oil-saturated core samples. The capillary and relative permeability curves can then be used on DFN realizations to test cases with or without surfactant. The results of spontaneous imbibition showed that surfactant solutions had a higher oil recovery due to wettability alteration combined with IFT reduction. Our upscaling results indicate that all three methods can be used to scale laboratory results to the field. When compared to a well without surfactant additives, the optimum 3-year cumulative oil production of well that is treated with surfactant can increase by more than 20%.
... Methods of improving the production of oil from shale plays are being explored to enhance these low recovery factors ( Adel et al. 2018a; Zou and Schechter 2017). Gas injection, where miscibility plays a significant factor ( Adel et al. 2016), as well the addition of surfactant into completion fluid are two of the most widely implemented EOR methods ( Adel et al. 2018b;Zhang et al. 2018a). The addition of surfactants into completion fluids is being successfully used as an EOR method in ULR. ...
