|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Bentonite is not typically used as the primary fluid-loss agent in normal-density slurries. In low-density slurries, where higher concentrations can be used, it may provide sufficient fluid-loss control (400 to 700 cm 3 /30 min) for safe placement in noncritical well applications. Fluid-loss control, obtained through the use of bentonite, is achieved by the reduction of filter-cake permeability by pore-throat bridging. Microsilica imparts a degree of fluid-loss control to cement slurries because of its small particle size of less than 5 microns. The small particles reduce the pore-throat volume within the cement matrix through a tighter packing arrangement, resulting in a reduction of filter-cake permeability.
Zhang, D. Leslie (CNPC USA Corp.) | Qi, Chunyan (Beijing Huamei Century International Technology Co.) | Shi, Xiaodong (Exploration and Development Research Institute of Daqing Oilfield Company Ltd.) | Zhan, Jianfei (Exploration and Development Research Institute of Daqing Oilfield Company Ltd.) | Han, Xue (Exploration and Development Research Institute of Daqing Oilfield Company Ltd.) | Li, Xiangyun (Beijing Huamei Century International Technology Co. Ltd.) | Wang, Ze (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology)
Abstract Relative permeability is one of the most important petrophysical parameters to evaluate a reservoir’s production during primary and subsequent secondary or enhanced oil recovery processes. Yet measured relative permeability data for tight oil reservoirs are very scarce to find in the literature, mainly because the measurement is difficult and time consuming to make. In this paper the protocol and results of water/oil, surfactant /oil, CO2/oil, and N2/oil relative permeability are presented, and compared to the digital core analysis results where wettability was set to water-wet or mixed-wet, as well as the Brooks-Corey model. Amott-Harvey wettability index was measured to explain the differences. The target formation is a sandstone tight oil formation located in Songliao Basin, China. Its permeability is mostly in the 0.01-5mD range. Core and oil samples from the target formation were used in the wettability and relative permeability determination. Relative permeability was measured at reservoir conditions using a customized core flow setup. Core samples were cleaned then wettability restored. To match the reservoir fluid viscosity and avoid changing wettability, stock tank oil was blended with kerosene to reservoir fluid viscosity at reservoir temperature. Relative permeability was measured using the unsteady-state method. Amott-Harvey wettability index was measured on core samples from the same formation at reservoir temperature. Amott-Harvey wettability index results show that the restored wettability ranged from water-wet to oil-wet, with most samples being mixed-wt. The addition of non-ionic surfactant promoted wettability change toward more water-wetness. However, anionic surfactant had little effect on reversing wettability. Oil relative permeability (Kro) results obtained from the digital rock analysis (DRA) assuming uniform water-wetness are consistent with relative permeability calculated from mercury injection capillary pressure using Brooks-Corey model. When wettability of the digital rock model was set to mixed-wet, the resulted Kro matches the measured Kro of a sister plug to the sample used to build the digital rock model, which is consistent with the wettability measurements. The addition of surfactants increased both water and oil relative permeability through wettability alteration and IFT reduction. CO2 flood was conducted as an immiscible flood due to reservoir pressure lower than MMP. CO2 flood left high residual oil saturation compared with water floods. N2 flood left even more oil behind compared with CO2 flood. Relative permeability provides key input parameters for formation evaluation and the subsequent EOR processes such as huff-n-puff operations. There are very little published relative permeability data for tight oil reservoirs. This work extends the relative permeability database, and is a starting point for future EOR work.
Abstract A unique well-tracing design for three horizontally drilled wells is presented utilizing proppant tracers and water- and hydrocarbon-soluble tracers to evaluate multiple completion strategies. Results are combined to present an interpretation of them in the reservoir as a whole, where applicable, as well as on an individual well basis. The new approach consists of tracing the horizontal well(s) leaving unchanged segments along the wellbore to obtain relevant control group results not available otherwise. The application of the tracers throughout each wellbore was designed to mitigate or counterbalance variables out of the controllable completion engineering parameters such as heterogeneity along the wellbores, existing reservoir depletion, intra- and inter-well hydraulically driven interactions (frac hits) as well as to minimize any unloading and production biases. Completion strategies are provided, and all the evaluation methodologies are described in detail to permit readers to replicate the approach. One field case study with five horizontal wells is presented. Three infill wells were drilled between two primary wells of varying ages. All wells are shale oil wells with approximately 7,700 ft lateral sections. The recovery of each tracer is compared between the surfactant treated and untreated segments on each well and totalized to see how the petroleum reservoir system is performing. A complete project economic analysis was performed to determine the viability of a chemical additive (a production enhancement surfactant). Meticulous analysis and interpretation of the proppant image logs were performed to discern the cluster stimulation efficiency during the hydraulic fracturing treatments. Furthermore, comparisons of the cluster stimulation efficiency between the two mesh sizes of proppant pumped are also provided for each of the three new unconventional well completions. The most significant new findings are the surfactant effects on the wells’ production performance, and the impact the engineered perforations with tapered shots along the stages had on the stimulation efficiency. Both the right chemistry for the formation and higher cluster stimulation efficiencies are important because they can lead to increased well oil production. The novelty of this tracing design methodology rests in the ability to generate results with a statistically relevant sample size, therefore, increasing the confidence in the conclusions and course of action in future well completions.
Summary This study investigates the role of polar fractions of heavy oil in the surfactant-steamflooding process. Performance analyses of this process were done by examination of the dipole-dipole and ion-ion interactions between the polar head group of surfactants and the charged polar fraction of crude oil, namely, asphaltenes. Surfactants are designed to reduce the interfacial tension (IFT) between two immiscible fluids (such as oil and water) and effectively used for oil recovery. They reduce the IFT by aligning themselves at the interface of these two immiscible fluids; this way, their polar head group can stay in water and nonpolar tail can stay in the oil phase. However, in heavy oil, the crude oil itself has a high number of polar components (mainly asphaltenes). Moreover, the polar head group in surfactants is charged, and the asphaltene fraction of crude oils carries reservoir rock components with charges. The impact of these intermolecular forces on the surfactant-steam process performance was investigated with 10 coreflood experiments on an extraheavy crude oil. Nine surfactants (three anionic, three cationic, and three nonionic surfactants) were tested. Results of each coreflood test were analyzed through cumulative oil recovery and residual oil content. The performance differences were evaluated by polarity determination through dielectric constant measurements and by ionic charges through zeta potential measurements on asphaltene fractions of produced oil and residual oil samples. The differences in each group of surfactants tested in this study are the tail length. Results indicate that a longer hydrocarbon tail yielded higher cumulative oil recovery. Based on the charge groups present in the polar head of anionic surfactants resulted in higher oil recovery. Further examinations on asphaltenes from produced and residual oils show that the dielectric constants of asphaltenes originated from the produced oil, giving higher polarity for surfactant-steam experiments conducted with longer tail length, which provide information on the polarity of asphaltenes. The ion-ion interaction between produced oil asphaltenes and surfactant head groups were determined through zeta potential measurements. For the most successful surfactant-steam processes, these results showed that the changes on asphaltene surface charges were becoming lower with the increase in oil recovery, which indicates that once asphaltenes are interacting more with the polar head of surfactants, then the recovery rate increases. Our study shows that the surfactant-steamflooding performance in heavy oil reservoirs is controlled by the interaction between asphaltenes and the polar head group of surfactants. Accordingly, the main mechanism that controls the effectiveness of the process is the ion-ion interaction between the charges in asphaltene surfaces and the polar head group of crude oils. Because crude oils carry mostly negatively charged reservoir rock particles, our study suggests the use of anionic surfactants for the extraction of heavy oils.
Abstract Application of chemical enhanced oil recovery (C-EOR) processes to low-permeability sandstone reservoirs (in the 10-100 mD range) can be very challenging as strong retention and difficult in-depth propagation of polymer and surfactant can occur. Transport properties of C-EOR chemicals are particularly related to porous media mineralogy (clay content). The present experimental study aimed at identifying base mechanisms and providing general recommendations to design economically viable C-EOR injection strategies in low permeability clayey reservoirs. Polymer and surfactant injection corefloods were conducted using granular packs (quartz and clay mixtures) with similar petrophysical characteristics (permeability 70-130 mD) but having various mineralogical compositions (pure quartz sand, sand with 8 wt-% kaolinite and sand with 8 wt-% smectite). The granular packs were carefully characterized in terms of structure (SEM) and specific surface area (BET). The main observables from the coreflood tests were the resistance and residual resistance factors generated during the chemical injections, the irreversible polymer retention and the surfactant retention in various injection scenarios (polymer alone, surfactant alone, polymer and surfactant). A first, the impact of the clay contents on the retention of polymer and surfactant considered independently was examined. Coreflood results have shown that retention per unit mass of rock strongly increased in presence of both kaolinite and smectite, but not in the same way for both chemicals. For polymer, retention was about twice higher with kaolinite than with smectite, despite the fact that the measured specific surface area of the kaolinite was about 5 times less than that of the smectite. Conversely, for surfactant, retention was much higher with smectite than with kaolinite. Secondly, the impact of the presence of surfactant on the polymer in-depth propagation and retention was investigated in pure quartz and kaolinite-bearing porous media. In both mineralogies, the resistance factor quickly stabilized when polymer was injected alone whereas injection of larger solution volumes was required to reach stabilization when surfactant was present. In pure quartz, polymer retention was shown, surprisingly, to be one order of magnitude higher in presence of surfactant whereas with kaolinite, surfactant did not impact polymer retention. The results can be interpreted by considering adsorption-governed retention. The mechanistic pictures being that (a) large polymer macromolecules are not able to penetrate the porosity of smectite aggregates, whereas surfactant molecules can, and (b) that surfactant and polymer mixed adsorbed layers can be formed on surfaces with limited affinity for polymer. Overall, this study shows that C-EOR can be applied in low permeability reservoirs but that successful injection strategies will strongly depend on mineralogy.
Abstract This study designs a novel complex fluid (foam/emulsion) using as main components gas, low-toxicity solvents (green solvents) which may promote oil mobilization, and synergistic foam stabilizers (i.e. nanoparticles and surfactants) to improve sweep efficiency. This nanoparticle-enabled green solvent foam (NGS-foam) avoids major greenhouse gas emissions from the thermal recovery process and improves the performance of conventional green solvent-based methods (non-thermal) by increasing the sweep efficiency, utilizing less solvent while producing more oil. Surfactants and nanoparticles were screened in static tests to generate foam in the presence of a water-soluble/oil-soluble solvent and heavy crude oil from a Canadian oil field (1600 cp). The liquid phase of NGS-foam contains surfactant, nanoparticle, and green solvent (GS) all dispersed in the water phase. Nitrogen was used as the gas phase. Fluid flow experiments in porous media with heterogeneous permeability structure mimicking natural environments were performed to demonstrate the dynamic stability of the NGS-foam for heavy oil recovery. The propagation of the pre-generated foam was monitored at 10 cm intervals over the length of porous media (40 cm). Apparent viscosity, pressure gradient, inline measurement of effluent density, and oil recovery were recorded/calculated to evaluate the NGS-foam performance. The outcomes of static experiments revealed that surfactant alone cannot stabilize the green solvent foam and the presence of carefully chosen nanoparticles is crucial to have stable foam in the presence of heavy oil. The results of NGS-foam flow in heterogeneous porous media demonstrated a step-change improvement in oil production such that more than 60% of residual heavy oil was recovered after initial waterflood. This value of residual oil recovery was significantly higher than other scenarios tested in this study (i.e. GS- water and gas co-injection, conventional foam without GS, GS-foam stabilized with surfactant only and GS-waterflood). The increased production occurred because NGS-foam remained stable in the flowing condition, improves the sweep efficiency and increases the contact area of the solvent with oil. The latter factor is significant: comparing to GS-waterflood, NGS-foam produces a unit volume of oil faster with less solvent and up to 80% less water. Consequently, the cost of solvent per barrel of incremental oil will be lower than for previously described solvent applications. In addition, due to its water solubility, the solvent can be readily recovered from the reservoir by post flush of water and thus re-used. The NGS-foam has several potential applications: recovery from post-CHOPS reservoirs (controlling mobility in wormholes and improving the sweep efficiency while reducing oil viscosity), fracturing fluid (high apparent viscosity to carry proppant and solvent to promote hydrocarbon recovery from matrix while minimizing water invasion), and thermal oil recovery (hot NGS-foam for efficient oil viscosity reduction and sweep efficiency improvement).
Abstract Successful field trials of surfactant-based Production Enhancement (PROE) technology in different shale plays including Permian Basin, Bakken and Eagle Ford indicate that specially tailored surfactant formulations can improve the unconventional well productivity during flowback and production. One major challenge for the operator is to further optimize the surfactant dosage to maximize the economic return. Analysis of the residual surfactant concentration in the produced water (PW) might provide a new path to optimize the surfactant application in the field. Such quantitative measurements can help understand how much surfactant is consumed in the downhole and how much surfactant is in the flowback, and possibly correlate back to the well performance. Additionally, surfactant partitioning and adsorption behaviors can be studied through residual analysis, which will further provide guidance to develop next generation of surfactant formulations. In this study, a liquid chromatography-mass spectrometry (LC-MS) method was developed to accurately measure the residual surfactant concentration in the produced water. The liquid chromatograph (LC) separates the surfactant from sample matrix and avoids the possible interference, and then the mass spectrometer (MS) detects the separated surfactant, signal correlating to the residual concentration. This analytical method provides unrivalled selectivity and specificity compared to other methods reported in the literature. In addition, a Methyl Orange method was developed and can potentially be used in the field for quicker measurements. Produced water samples collected from a Huff-and-Puff treatment in the Permian Basin were evaluated using both methods. Our results indicate that both methods can successfully capture the trend of residual concentration vs. production time. The deviation between LC-MS and Methyl Orange measurements was due to the presence of ADBAC (alkyldimethylbenzylammonium chloride) in the produced water, which is a cationic amine surfactant typically used as biocide in the well stimulation. It produces positive interference and thus leads to a higher residual detection in the Methyl Orange test. Notably, the residual concentration of surfactant in produced water decreased with time after the well was placed back to production, which is consistent with the concept that more surfactant will adsorb to the rock surface or partition into the oil phase over production time. In summary, we believe the LC-MS and Methyl Orange methods can potentially be used to detect residual concentration for any type of surfactant-based applications in unconventional reservoirs including Huff-and-Puff, completion, frac protect, surfactant flooding and re-frac. The field application of surfactant-based chemistry followed by this type of residual analysis can help understand the underlying mechanisms of the surfactant and provide further guidance for production optimization of shales.
Abstract Foams are the divergent fluids that are employed in the upstream oil and gas industry to reduce fluid channeling and fingering in the high permeability region. Foams are usually generated in the high permeability reservoirs (e.g. glass beads) by the alternative injection of surfactant and gas. Conventional foaming systems exhibit stability issues at the high temperature and high salinity reservoir conditions. In this investigation, we study the stability and efficiency (in terms of both enhanced inflow performance and added oil recovery) of foams formed using surfactant solution with and without carbon Nanodots (CND). The study involved using different brine salinities, CND concentrations, temperature and pressure conditions, and types of surfactants. A multifaceted interrelationship of the various influencing mechanisms is demonstrated. Foams are examined using foam analyzer, HP/HT coreflood and microfluidic setup. In trace amounts (5-10 ppm), CND contributed to 60-70% improvement in foam stability in high salinity brine. The improvement is attributed by the reduction of the drainage rate of the lamellae and a delay of the bubble rupturing point. Both microfluidic and core-flood experiments showed noticeable improvement in mobility control with the addition of the CND. This is contributed to an improved foamability, morphology, strength, and stability of the foam.
Gudala, Manojkumar (Indian Institute of Technology, Madras) | Naiya, Tarun Kumar (Indian Institute of Technology (Indian School of Mines) Dhanbad) | Govindarajan, Suresh Kumar (Indian Institute of Technology, Madras)
Summary The present work focuses on the improvement of flow properties during the transportation of heavy oil via 0.0254-, 0.0381-, and 0.0508-m-diameter pipelines. The effect of temperature, water cut, natural extract Madhuca Longifolia (ML), and potato starch (PS) on pressure drop, shear viscosity, and flow behavior index (n) was experimentally investigated. Minimum pressure drop occurred in the 0.0508-m-inner-diameter (ID) pipeline because of the combined consequence of temperature and 2,000 ppm ML during the transportation of 85% heavy oil þ 15% water. A new correlation was developed to predict the friction factor for the heavy oil/emulsions during its transportation in a 0.0254-m-ID pipeline using the linear regression method for friction factor. Flow behavior index inclined toward Newtonian from shear-thinning behavior (i.e., n ¼ 0.2181 to 0.9834) after the addition of 2,000 ppm ML at 50 A new hybrid artificial intelligence (AI) technique was developed and used to optimize flow-influencing parameters to minimize the pressure drop and shear viscosity and improve flow behavior index. Minimum pressure drop (58,659.72 Pa), shear viscosity (1.56 Pas), and maximum flow behavior index (0.71) were achieved during the heavy oil flow in the 0.0508-m-ID pipeline after addition of 15% water, 1,320 ppm ML for 12.33-m However, from the studies, it was concluded that ML shows better performance compared with PS. Because both ML and PS are biodegradable and nontoxic, the petroleum industry may use both as a cost-effective alternative to decrease pour point and improve flowability for heavy crude oil. Introduction Because of a decrease in conventional light crude oil reserves, heavy oil has gained importance in the global hydrocarbon market in the last decade (Hein 2017). This fact leads to an increased economic interest in the exploration and production of heavy oil. The high viscosity of oil creates primitive problems in production and transportation (Speight 2013; Nadirah et al. 2014). It leads to the requirement of high pumping pressure, power, and consequently damage to the equipment, ultimately increasing the cost of heavy oil production and transportation. Heavy oil viscosity is decreased either by heating or emulsification or the addition of water with drag-reducing additives (DRAs) (Omer and Pal 2010; Martínez-Palou et al. 2011; Hart 2014).
Wang, Mingyuan (University of Texas at Austin) | Argüelles-Vivas, Francisco J. (University of Texas at Austin) | Abeykoon, Gayan A. (University of Texas at Austin) | Okuno, Ryosuke (University of Texas at Austin)
Summary The main objective of this research was to investigate the effect of initial water saturation on the oil recovery from tight matrices through surfactant-enhanced water imbibition. Two flooding/soaking experiments using fractured tight cores with/without initial water were performed. The experimental results were analyzed by the material balance for the components oil, brine, and surfactant. The analysis resulted in a quantitative evaluation of the imbibed fraction of the injected components (brine and surfactant). Results show that the surfactant enhanced the brine imbibition into the matrix through wettability alteration. The initial efficiency of the surfactant imbibition increased when brine was initially present in the matrix. The imbibition of brine was more efficient with no initial water in the matrix. A possible reason is that the presence of initial water in the matrix was able to increase the initial efficiency of the surfactant imbibition; however, the increased amount of surfactant in the matrix lowered the interfacial tension (IFT) between the aqueous and oleic phases; therefore, the efficiency of brine imbibition was reduced. Another possible reason is that capillary force was lower in the presence of initial water in the matrix, resulting in weaker imbibition of brine. Although the two cases showed different characteristics of the mass transfer through the fracture/matrix interface, they resulted in similar values of final water saturation in the matrix. Hence, the surfactant injection was more efficient for a given amount of oil recovery when there was no initial water in the matrix.