Depletion oil recovery for systems with widely varying initial composition

The principal depletion drive mechanism is the expansion of oil and gas initially in the reservoir—neglecting water influx. The main factors in depletion drive reservoir performance are total cumulative compressibility, determined mostly by initial composition (gas–oil ratio), saturation pressure, PVT properties, and relative permeability. In this paper, we systematically study the effect of initial composition on oil recovery, all other parameters held constant. We also evaluate other aspects of reservoir performance, but the main emphasis is surface oil recovery including condensate.To analyze the effect of initial composition, a series of fluid systems was selected by a recombination of separator samples at varying gas–oil ratios. The systems ranged from low-GOR oils to high-GOR gas condensates, with a continuous transition from gas to oil through a critical mixture.Black oil and compositional material balance calculations, 2D fine-grid, and 3D coarse-grid models have been used to investigate the effect of initial fluid composition on reservoir depletion performance. Systematic variation of relative permeabilities was also used to map the range of fluid systems, which were most sensitive to relative permeability.For reservoir oils, the depletion recovery of surface oil initially increases with increasing initial gas–oil ratio. Oil recovery reaches a maximum for moderate-GOR oil reservoirs, followed by decreasing oil recoveries with increasing initial solution GOR. A minimum oil recovery is reached at a near-critical oil. For gas reservoirs, depletion drive condensate recovery increases monotonically from a near-critical gas towards near 100% condensate recovery for very-high GOR systems.STO recovery from oil reservoirs depends increasingly on gas–oil relative permeabilities as initial solution GOR increases, up to a point. At higher initial solution GORs, oil recovery becomes less dependent on relative permeability and, as the fluid system transitions to a gas at the critical point, relative permeability dependence rapidly diminishes. Condensate recovery from gas condensate systems is more or less independent of gas–oil relative permeabilities, with only slight dependence for near-critical gases.     

Recycling of used motor oil as an alternative method for production feedstock for the conversion processes

Abstract

Used lubricating motor oil is a high pollutant material that requires responsible management. It may cause damage to the environment when dumped into the ground or into water streams including sewers. This may result in groundwater and soil contamination. Recycling of such contaminated materials will be beneficial in reducing lubricating motor oil costs. In addition, it will have a significant positive impact on the environment.

Used oil can be refined to yield base oils that are blended into lubricating products, thus reducing the consumption of virgin oils and it can be used as a feedstock for hydro conversion for production fuels and fuel oil.

This work investigates refining of used lubricating motor oil using solvent extraction method. The laboratory experiment was based on a full factorial design and two categorical factors with two levels were nominated which were solvent to used oil ratio and solvent type (2-Propanol and n-Butanol, MEK and blended the solvents with gazoline).

The type of solvent used and the mixing ratio applied for different runs has shown significant effects on the yield of recovered oil. The yield with bisolvent type MEK+gasoline was higher than the other solvents. The yield of treated oil with butanol mixed with gasoline is 87.5% and it is so close to the yield when we used the butanol alone which is 88.6%.     

Microscopic Study of Oil Flocculation and Coalescence Processes for Understanding the Role of Surfactants in EOR Performance

Abstract

A preliminary microscopic study of oil/oil droplet interactions in surfactant-added water is carried out to understand the oil/water interface changes with time and its effects on oil/oil droplet coalescence. This study is carried out on two oils (olive and crude oil) with varying concentrations of surfactant water ratios. The radii of curvature of the interface between coalescing oil droplets is used as a measure to reflect the change in surface energy. As oil droplets were placed in surfactant-added water, the radii of curvature were measured at three different states. Early state shows very little effect on oil/oil interfaces; in the later state, the effect is greater and interfacial tension decreases rapidly. At quasi-steady state, the state between the early and later, faster rate stage reduces with surfactant concentration in the case of olive oil. Increasing the surfactant concentration does not show the same effect on crude oil. The radii of curvature increase with time by increasing surfactant concentrations in olive oil; an inverse effect is found in crude oil. A natural surfactant prepared from the outer shell of pericarp of soapnut fruit was also used to study droplet formation and coalescence as well as to investigate the impact in interfacial tension and oil mobility.     

An Environment-Friendly Alkaline Solution for Enhanced Oil Recovery

Abstract

The injection of alkali and alkali/polymer solutions is a well-known enhanced oil recovery technique. This article demonstrates how wood ash can be used as a source of low cost alkali instead of synthetic alkali that is also environmentally friendly. From the experimental studies, it is found that the pH value of 6% wood ash extracted solution is very close to the pH value of 0.5% synthetic NaOH or of 0.75% Na₂SiO₃ solution. A preliminary microscopic study of oil/oil droplets interaction in natural alkaline solution was carried out in order to understand the oil/water interface changes with time and its effect on oil/oil droplet coalescence. Also, interfacial tension (IFT) was measured for both synthetic and natural alkaline solutions. The IFT values in the presence of acidic crude oil show comparable results.     

The application of nanofluids for recovery of asphaltenic oil

In the recent years, requirement of suitable enhanced oil recovery (EOR) technique as a more proficient technology becomes significant because of increasing demand for energy. Nanofluids have great potential in order to improve oil recovery. In our study, the effect of SiO₂, Al₂O₃, and MgO nanoparticles on oil recovery was investigated by using core flooding apparatus. Zeta potential and particle size distribution measurements were carried out to investigate the stability of nano particles and results showed SiO₂ has more stability than other ones. Interfacial tension and contact angle measurements between nanofluids and crude oil used to demonstrate that how nanoparticles enhance oil recovery. Experimental data reveals that SiO₂ nanoparticles introduce as the greatest agent among these nanoparticles for enhanced oil recovery. Lowest damage for SiO₂ nanofluids was observed and also it was observed that the concentration and injection rate have straight effects on permeability reductions.     

New Empirical Correlations for Predicting Crude Oil Properties

Abstract

Pressure–volume–temperature (PVT) properties of crude oil are essential parameters used for prediction of fluid flow both in porous media and through transmission pipelines. Whenever laboratory works are absent, the engineer should use regionally developed correlations. A large portion of all crude oil resources is located in the Persian Gulf countries, and they have more or less similar API ranges and acidities, so that any empirical PVT correlation based on data from one region can adequately predict the behavior of others in this large geological basin. In this study, a new set of black oil–type correlations for bubble point pressure (P_b), solution gas–oil ratio (GOR; R_s), and formation volume factor (Bo) is proposed based on more than 400 Iranian crude oil PVT lab data. Moreover, previous works were reviewed, most of which were not suitable to model Iranian crude PVT behavior. Although the new correlations are developed over Iranian crudes, they can be used for prediction over any crude oil with similar compositional properties (API and acidity). Then the accuracy of these correlations is compared with the newly presented set and the superiority of this work for predicting those parameters is demonstrated.     

高矿化度稠油流动的影响因素及改善原油流动的方法

探讨了压力、温度、掺入剂等外加因素对高矿化度稠油流动性的影响,提出了改善原油流动的方法。稠油掺入稀油降黏所用的"稀油"对改变原油的流动性的影响十分明显,加入少量混合芳烃能使原油本体黏度大大降低,同时也大幅度减少稀油的用量。如果加入油溶性活性剂,则效果更好。当稀油资源受到限制时,加入乳化降黏剂更是廉价有效的方法。如果原油黏度特别高及储层水的矿化度高达15×104mg/L、且碱土金属也高达2×104mg/L时,稠油降黏所用的活性剂必须耐盐,并且须加入油水稳定剂和降摩阻剂。这样调整油水的流度比能使原油和水同步上升,使原油在地层和井筒中的摩擦力降低,有效地避免由于油水乳状液在盐的作用下的不稳定性所引起的地层含水率升高、产油量降低的问题。     

The Artificial Neural Network's Prediction of Crude Oil Viscosity for Pipeline Safety

Abstract

Predicting crude oil viscosity is a challenge faced by reservoir engineers in production planning. Some early researchers have propounded some theories based on crude oil properties and have encountered various problems leading to errors in forecasted values. This article discusses work carried out with a model using an artificial neural network (ANN) for predicting crude oil viscosity of Nigerian crude oil. The model was started through adoption of a classical regression technique empirical method for dead oil viscosity as a function of American Institute for Petroleum (API) and reduced temperature. The Peng–Robinson equation of state and other thermodynamic properties are introduced, coupled with the Standing model for calculating bubble point pressure (P_b). The developed model was evaluated using existing measured real-life data collected from 10 oil fields within the Niger Delta region of Nigeria. Both the predicted and measured viscosities were plotted against each corresponding reservoir pressure to establish the model's level of reliability. The superimposition of the pressure-viscosity relationship shows that at each point, the viscosity model captures the physical behavior of viscosity variations with pressure. In each case, the ANN does not require a data relationship to predict the crude oil viscosity but rather relies on the field data obtained for training. For this reason, it is recommended that the ANN approach should be applied in oil fields for reduction in error, computational time, and cost of overproduction and underproduction.     

Value assessment for reservoir recovery optimization

This paper analyzes the managerial flexibility embedded in oil and gas exploration and production. The analysis includes the economic impact of using different production techniques on the valuation of oil reserves. Two methodologies are used to evaluate the simulation of engineering techniques: (i) the real option approach; and (ii) the discounted cash flow (DCF) method. Given the external variables (e.g., oil price, interest rate), this paper evaluates the best engineering technique for oil recovery by using a valuation approach. We conclude that by appropriately combining different production techniques, the value of oil reserves can increase under the real option approach and can be higher than the value assessed under the DCF method. Since oil recovery includes many managerial choices, we argue that the real option approach is more appropriate than the DCF method. The paper concludes that concession time and dividend yield are the most sensitive parameters for the valuation of oil reserves.     

A correlation between interfacial tension,emulsifying ability and oil displacement efficiency of ASP system for Daqing crude oil

Abstract

Interfacial tension and emulsification are important to enhance oil recovery. There is almost none quantitative research on their correlation for Daqing crude oil. Experiments are performed to find out the correlation between different interfacial tension, emulsification and chemical flooding oil displacement efficiency. The authors changed the structure of surfactant to make characteristics of interfacial tension different significantly and build the relationship between interfacial tension parameters and chemical flooding oil displacement efficiency by physical simulate experiments. The ultralow interfacial tension index (expressed by S) is established by orthogonal test and actual significance of interfacial tension curves. The fitting formula between S and chemical flooding oil displacement efficiency (E) is: E = 0.856 ln(S) + 13.849. The emulsifying ability includes two aspects O/W and W/O. Authors changed the structure of surfactant to make characteristics of ASP systems have similar interfacial property but different emulsification property. Compared the oil displacement efficiency of these systems, built the correlation between emulsifying ability and chemical flooding oil displacement efficiency for Daqing crude oil.

This paper established the index of ultralow interfacial tension and emulsification, and summed up the formulae based on that with oil displacement efficiency. The quantitative evaluation of ASP system can optimize the existing evaluation methods and deepen understandings on flooding mechanism for Daqing crude oil.     

Double alkyl chain copolymers as flow improvers for heavy oil

As flow improvers for heavy crude oil, two oil-soluble copolymers (DM-S-VA, DA-S-VA) were successfully synthesized and characterized by ¹H NMR and GPC. A rich alkyl chain and appropriate molecular weight of copolymer play fundamental role in viscosity reduction of heavy oil. Furthermore, synergistic effect of surfactants on polymers can promote the viscosity reduction, and the best formulation can increase the viscosity reduction rate to 78% to oil A. Comparing with the apparent viscosity of the different heavy oil mixing system in a wide shear rate range (0.1–200 s^?1), the results show good stability and viscosity reducing effect.     

Interfacial Mass Equations for In Situ Combustion

Abstract

The multiphase flow of oil, water, and gas through porous media is presented when the in situ combustion technique is applied in oil reservoirs. This technique implies phenomena such as phase change, chemical reactions, and heat transfer among the phases, at their interfaces and common lines. The mathematical modeling of such a technique requires the deduction of mass, momentum, and energy equations taking into account the phenomena mentioned. In this work, the interfacial mass transport equations averaged in volume for gas (g), oil (o), and water (w) flowing simultaneously through a homogeneous, isotropic, rigid, and nonpermeable porous media (s) were obtained. The averaged interfacial mass transport equation for the deposited coke (c) on the porous media, was also obtained. To obtain the averaged equations, the local interfacial mass equations as well as their corresponding jump conditions, were used as starting point. For the interfacial region the following were taken into account: (1) the gas compressibility, (2) the mass generation of coke due to the chemical reaction of oil, (3) the mass generation of gas due to the combustion reaction between coke and oxygen, and (4) the mass transfer due to the phase change of oil and water. The closure and constitutive equations for oil and water phase change on the interfaces and common lines and an interfacial mass generation term for the deposition of coke were proposed.     

Dimensionless groups for three-phase gravity drainage flow in porous media

The downward displacement of oil by gas (either through gas cap expansion or by gas injection) at the crest of the reservoir is an attractive method of oil recovery. The drainage of oil under gravity forces is a potentially efficient method as it can reduce the remaining oil saturation to below that obtained after waterflooding. This paper describes a series of experiments of gas invasion under gravity-dominated conditions with special attention to the effects of wettability and water saturation on three-phase flow. The experiments were performed in bead-pack models by spontaneous gas invasion at both low and high water saturations with a spreading oil. Different oil recovery rates were observed depending on the wettability of the beads and initial water saturation. At irreducible water saturation, the process appeared to be less efficient for the oil-wet conditions, while similar oil recoveries are observed for both oil-wet and water-wet media at residual oil saturation. Different recovery rates occur with different fluid morphology, which depend on the matrix wettability and the balance between gravity, viscous and capillary forces. The results have been analysed using dimensionless groups. The Bond (N_B) and capillary numbers (N_C) were modified to include the 3-phase effects of gas, oil and water. However, for these cases the Bond and capillary numbers alone were insufficient to fully describe the dynamics of oil recovery by gravity drainage. Therefore, a new dimensionless group combining the effects of gravity and viscous forces to capillary forces was defined as: N=N_B+A(μ_d/μ_g)N_C, where A is a scaling factor (in all our experiments A=−17225) and (μ_d/μ_g) is the viscosity ratio between the displaced and displacing phase. A linear relationship was found between this new group and the total recovery for all the scenarios tested. The slope was approximately 40 for three cases, i.e., water-wet case at irreducible water saturation, and water-wet and oil-wet cases at residual oil saturation. The oil-wet case at irreducible water saturation has a larger slope, probably due to the blocking effect of water. These experimental results may be used as a benchmark to test theoretical models of three-phase flow under gravity dominated conditions. The new dimensionless group should improve the understanding of the pore scale mechanisms so that these processes can be included in the development of network models and in the processes of upscaling laboratory results.     

Investigation of a Centrifugal Separator for In-Well Oil Water Separation

Abstract

A liquid–liquid centrifuge has been tested for possible application as a downhole method for separating crude oil from produced water. Centrifugal separators of various sizes (from 2- to 25-cm rotor diameter) have been built and operated over the past three decades at various US Department of Energy facilities. These units have several characteristics that make them attractive for downhole applications, including excellent phase separation, reliability in remote applications with >20,000 h of operation prior to maintenance, and the ability to handle high volumetric throughput with a very low residence time. In these studies, water-to-oil feed ratios of 10:1 to 1:19 were tested with a light Gulf of Mexico crude oil, and the separator operated efficiently for the full range of feed ratios. Air was added to the oil stream in one test to model the effect of gas in the oil. Air additions up to 20% of the feed flow rate (the maximum tested) did not have any impact on the performance of the separator. The separator also effectively processed a very viscous North Sea heavy crude oil. The heavy crude was used to determine the effect of higher temperatures on the performance of the separator. Increasing the temperature of the oil and water feed stream improved overall performance and decreased the concentration of oil in the water discharge stream.     

利用地化参数预测稠油油藏开采难度

生物降解原油的粘度与生物降解程度相关,而原油中生物标志物的分布则随生物降解程度的不同而有差异.原油粘度与原油中饱和烃含量呈负相关,与极性化合物浓度呈正相关;与w(Pr+Ph)/w(nC₁₇+nC₁₈)值呈正相关,与w(Pr+Ph)/w(C₃₀藿烷)值呈负相关.原油粘度与w(Pr+Ph)/w(胡萝卜烷)值关系也很密切.利用相应地化参数可预测原油粘度,并进而初步预测原油开采难度.对辽河油田冷43块S₃²段6个油组的预测结果表明,原油粘度随埋深增加而升高,在油水界面附近达到最高值.该油藏的开采难度具有与之相似的特征.     

Evaluation of empirically derived PVT properties for Pakistani crude oils

This study evaluates the most frequently used pressure-volume-temperature (PVT) empirical correlations for Pakistani crude oil samples. The evaluation is performed by using an unpublished data set of 22 bottomhole fluid samples collected from different locations in Pakistan. Based on statistical error analysis, suitable correlations for field applications are recommended for estimating bubblepoint pressure, oil formation volume factor (FVF), oil compressibility and oil viscosity.     

Performance of low.salinity water flooding for enhanced oil recovery improved by SiO2 nanoparticles

flooding changes the ion composition or brine salinity for improving oil recovery. Recently, the application of nanoparticles with low-salinity water flooding has shown remarkable results in enhanced oil recovery (EOR). Many studies have been performed on the effect of nanofluids on EOR mechanisms. Their results showed that nanofluids can improve oil recovery when used in low-salinity water flooding. In this work, the effects of injection of low-salinity water and low-salinity nanofluid (prepared by adding SiO₂ nanoparticles to low-salinity water) on oil recovery were investigated. At first, the effects of ions were investigated with equal concentrations in low-salinity water flooding. The experimental results showed that the monovalent ions had better performance than the divalent ions because of them having more negative zeta potential and less ionic strength. Also, low-salinity water flooding recovered 6.1% original oil in place (OOIP) more than the high-salinity flooding. Contact angle measurements demonstrated that low-salinity water could reduce the contact angle between oil and water. Then in the second stage, experiments were continued by adding SiO₂ nanoparticles to the K⁺ solution which had the highest oil recovery at the first stage. The experimental results illustrated that the addition of SiO₂ nanoparticles up to 0.05 wt% increased oil recovery by about 4% OOIP more than the low-salinity water flooding.     

Silica nanofluid flooding for enhanced oil recovery in sandstone rocks

Enhanced oil recovery is proposed as a solution for declining oil production. One of the advanced trends in the petroleum industry is the application of nanotechnology for enhanced oil recovery. Silica nanoparticles (SiNPs) are believed to have the ability to improve oil production, while being environmentally friendly and of natural composition to sandstone oil reservoirs.In our work, we investigated the effect of silica nanoparticles flooding on the amount of oil recovered. Experiments were carried using commercial silica of approximately 20 nm in size. We used sandstone cores in the core flooding experiments. For one of the cores tertiary recovery is applied where brine imbibition was followed by nanofluid imbibition. While in the other cores secondary recovery was applied where primary drainage is directly followed by nanofluid imbibition. We investigated the effect of concentration of nanofluid on recovery; in addition, residual oil saturation was obtained to get the displacement efficiency. Silica nanofluid of concentration 0.01 wt%, 0.05 wt%, 0.1 wt% and 0.5 wt% were studied.The recovery factor improved with increasing the silica nanofluid concentration until optimum concentration was reached. The maximum oil recovery was achieved at optimum silica nanoparticles concentration of 0.1 wt%. The ultimate recovery of initial oil in place increased by 13.28% when using tertiary flooding of silica nanofluid compared to the recovery achieved by water flooding alone. Based on our experimental study, permeability impairment was investigated by studying the silica nanoparticles concentration, and the silica nanofluid injection rate. The permeability was measured before and after nanofluid injection. This helped us to understand the behavior of the silica nanoparticles in porous media. Results showed that silica nanofluid flooding is a potential tertiary enhanced oil recovery method after water flooding has ceased.     

Three-phase flow in water-wet porous media: gas/oil relative permeabilities for various spreading conditions

This paper addresses the impact of oil-on-water spreading energy (which governs the ability of the oil phase to spread on water in the presence of gas) on three-phase gas/oil relative permeabilities and residual oil saturation.Experimental tests, including simultaneous injections of oil and gas in porous media (steady state) as well as displacements of oil by gas (unsteady state) in the presence of connate water, were performed in two different rocks, Fontainebleau and Clashach sandstones.Gas and oil relative permeabilities were calculated directly from the steady-state data or evaluated by history matching of the experimental displacement production curves. The values obtained by the two methods often differ significantly; the relative permeabilities obtained by the steady-state method cannot represent a displacement.Oil recovery and relative permeabilities are higher for spreading than for non-spreading conditions for gas drainage displacements. Gas relative permeabilities at low oil saturations seem to be lower for non-spreading than for spreading conditions due to an important gas blocking effect caused by the oil/gas menisci. In this case, the measured relative permeabilities include a capillary effect.Oil relative permeabilities are compared to theoretical curves derived from an analytical model that takes into account, through the fractal dimension, the surface irregularities of a real porous medium; the model presented in this paper can be used to calculate the relative permeability of the intermediate phase (oil) during gas injection in a porous medium in the presence of water, for low oil saturations where film flow predominates; very good agreement is obtained for spreading conditions.Gas and oil relative permeabilities obtained by fitting the displacement curves for experiments performed with the reservoir rock and fluids under representative conditions may thus be used for prediction or modeling purposes on a reservoir scale.     

“十四五”我国油气发展路径选择

自20世纪50年代以来,我国油气发展经历了4次重大战略转型,极大地推动了油气工业的发展,使我国由贫油贫气国发展成为油气生产大国,并在海外建成五大油气合作区。我国能源安全的核心在油气,短板也在油气。21世纪以来,我国油气对外依存度大幅攀升,油气安全风险大增,亟需大力提升国内油气勘探开发力度,发挥国内油气供应的“压舱石”作用。系统梳理分析了我国油气发展战略演变历程,认为新形势下实施“稳油增气”战略是保障我国油气安全的现实选择,建议“十四五”期间将“稳油增气”上升为国家能源战略,并就推动我国原油产量2×108t长期稳定、天然气产量持续增长,提出未来我国油气发展战略部署;在用海用地、技术创新、体制机制及财税政策等方面提出保障措施与建议。