Reservoir Crude Oil Research Articles

Atomistic Molecular Dynamics Simulations of Surfactant-Induced Wettability Alteration in Crevices of Calcite Nanopores

Wettability alteration is an important mechanism in surfactant-facilitated enhanced oil recovery (EOR) in oil-wet carbonate reservoirs. An in-depth understanding of how surfactants influence the wettability of calcite surfaces is of crucial importance. In this study, atomistic molecular dynamics simulations were used to elucidate how the nonionic and anionic surfactants influence the wettability at the corners of angular calcite pores. A multicomponent oil model was constructed based on a chemical analysis of an unconventional reservoir crude oil. It was found that the inclusion of the calcite surface water layer caused a significant decrease in the attraction between the surface and the surfactant molecules from hundreds of kJ/mol to essentially zero. The surface water layer is therefore critical for an accurate description of calcite wettability. Simulated flooding of the oil-filled calcite pore with both types of surfactants was compared to that with blank brine. It was found that the tested surfactants alter the wettability of the calcite surface mainly by hydrophobic interactions with the adsorbed polar oil components and by weakening the interactions between polar and nonpolar oil components. The wettability alteration resulted in a 20–30° reduction in contact angles, while the ratio of the polar-to-nonpolar oil components within the pore decreased by approximately 50% by the surfactants as compared to just brine. The results presented in this work can provide guidance for selection of the most effective surfactants for oilfield applications.

Directional culture of petroleum hydrocarbon degrading bacteria for enhancing crude oil recovery

An oxygen-constrained system of crude oil reservoir environment was constructed to stimulate the growth of indigenous microbes, such as petroleum hydrocarbon-degrading bacteria. Addition of nitrogen and phosphorus sources was investigated for the growth of petroleum hydrocarbon-degrading bacteria. The results show that nitrates and phosphates stimulated the growth of the bacteria and promoted the biodegradation of crude oil as the sole carbon source in this process. The minimum surface tension was 29.63 mN/m when the amounts of the nitrogen (NaNO3: NH42SO4 = 2:1) and phosphorus (KH2PO4: NaH2PO4 = 5:2) sources added were 0.8 wt% and 1.4 wt%, respectively. Furthermore, the dominant petroleum hydrocarbon-degrading bacteria were shifted from Arcobacter in production water to Pseudomonas after the first subculture and then to Bacillus after the sixth subculture. The heteroatom groups in the crude oil were biodegraded simultaneously with normal alkanes and alkyl cyclohexanes. Addition of the nutrients resulted in microbial growth, microbial community shift, and enhanced microbial degradation.

Study Investigates Smart Waterflooding in Sandstone Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 193238, “Investigation of Smart Waterflooding in Sandstone Reservoirs: Experimental and Simulation Study, Part 2,” by Hasan N. Al-Saedi, SPE, Missouri University of Science and Technology and Missan Oil Company; Ralph E. Flori, SPE, Missouri University of Science and Technology; and Alsaba Mortadha, Australian College of Kuwait, prepared for the 2018 Abu Dhabi International Petroleum Exhibition and Conference, 12–15 November, Abu Dhabi. The paper has not been peer reviewed. In this paper, the authors consider the effect of water chemistry on water/rock interactions during seawater and smart waterflooding of reservoir sandstone cores containing heavy oil. Oil recovery, surface-reactivity tests, and multicomponent reactive-transport simulation were conducted to understand smart waterflooding better. The authors determine that lowering magnesium-ion (Mg2+) concentration results in lower additional oil recovery, and that lowering calcium-ion (Ca2+) concentration leads to higher additional oil recovery. Introduction “Smart water” (SW) can be defined as a water engineered by manipulating the ionic composition (adding or removing ions) regardless of the resulting salinity. An upward pH shift has been reported in the literature during low-salinity (LS) and/or smart waterflooding. That upward shift modifies the wettability of sandstone, thereby increasing oil recovery. When high salinity is displaced by LS water, Ca2+ will be desorbed from the clay surface because ion exchange occurs between hydrogen (H+) and Ca2+ at the negative sites of the clay surface. The organic materials will be then desorbed from the clay because of the reaction between the protonated basic and the acidic materials with hydroxide. The authors’ investigations on free-clay sandstone provided a different insight into such reactions. The observations from chromatographic columns of quartz showed an increase in the acetate detachment from the quartz surface with a significant pH jump during LS waterflooding. The oil-recovery observations from the quartz column supported the proposed mechanism. Previous systematic laboratory works indicated that the abundance of Mg2+ in the formation water (FW) is more effective than Ca2+ for a higher LS enhanced-oil-recovery (EOR) effect. Conversely, the abundance of Ca2+ in the injected LS water has a larger effect on LS EOR. When Mg2+ was present in the LS water, no oil-recovery improvement occurred. Methodology Brines. Synthetic FW and SW were prepared by dissolving sodium chloride (NaCl), calcium chloride (CaCl2), and magnesium chloride (MgCl2) in deionized water. Crude Oil. A reservoir crude oil was de-livered from eastern Kansas from the Bartlesville sandstone reservoir. The crude oil had a viscosity of approximately 600 cp at ambient temperature. The density is 0.83 gm/cc at 20°C. Reservoir Rock Description and Core Preparation. Five Bartlesville sandstone reservoir cores were drilled from the original 3-in. diameter to a 1-in. diameter preserved core from eastern Kansas. The preserved reservoir sandstone cores were delivered with 3-in. diameter. The most abundant mineral was quartz, followed by clays.

Dynamics of Changes in Composition and Stability of the Heavy Oil Sampled from the Usinskoye Oil Field as a Result of Formation Treatment with a Sol-Forming EOR System

The paper deals with a sol-forming system for oil recovery enhancement (EOR system) used to increase the rate of heavy oil displacement. The effect of sol-forming EOR system during the heavy oil displacement on the composition and stability of oil sampled from the Usinskoye oil field of Russia is investigated. The composition of a crude oil also plays an important role in changing its stability. The work is aimed to investigate stability of heavy crude oil in regards to asphaltene precipitation. For asphaltene toluene/n-heptane solutions, the aggregation stability of asphaltenes based on сhange in the optical density with time is investigated via spectrophotometry. SARA analysis is used to characterize the compositions of heavy oils. First, the content of asphaltenes precipitated from the oil samples is determined and then the samples of deasphalted crude oil (maltenes) are analyzed by the method of liquid adsorption chromatography for the purpose to study the composition of oil sampled from the wells before and after their treatment with the sol-forming EOR system. It is found out that the treatment of reservoir crude oil with the sol-forming EOR system results in changes in composition of saturated, aromatic hydrocarbons, resins, and asphaltenes (SARA components) and aggregative stability of produced oil. The results obtained showed that the aggregative stability of heavy oil depends not only on the content of SARA components in the dispersion medium but on the presence of metalloporphyrins in the oil. Metalloporphyrins could act as inhibitors of asphaltene precipitation, which is an additional factor responsible for the stabilization of the oil dispersed system

Screening of Spontaneous Ignition Feasibility During Air Injection EOR Process Based on Thermal Experiments

The feasibility of spontaneous ignition is extremely important to the success of AIP (air injection process) projects. However, no laboratory experiments were reported on the detection of crude oil spontaneous ignition during AIP. The initial intention of the thermal experiments is to screen candidate oil reservoirs for the application of AIP in a faster and less expensive way than combustion tube tests. However, instead of performing a feasibility study, most of the research only employed thermal experiments as a tool to obtain kinetic data and to characterize the thermal-oxidative behavior for different crude oil samples. The question of how to use the thermal experiments to determine the feasibility of spontaneous ignition has not been answered yet. This study proposes a practical method to investigate the spontaneous ignition feasibility during AIP, which directly relates the oil reactivity and reservoir properties. An example of the application of this method was presented in this paper, where a mixture of a light oil and sand was tested by the TGA and DSC to obtain the kinetic data and net heat. The obtained parameters were then used to evaluate the feasibility of spontaneous ignition. The results showed that the tested oil and sand mixture cannot lead to spontaneous ignition due to crude oil’s insufficient reactivity. Furthermore, the typical crude oil kinetic data and reservoir conditions were used to investigate the screening criteria for spontaneous ignition. The results indicated that the crude oil’s activation energy and frequency factor need to be less than 60 kJ/mole and higher than 2 s−1, respectively, in order to satisfy the need of spontaneous ignition.

Application Analysis of Oil Test Fracturing Technology in Deep Gas Wells

In the process of oil exploration, it is necessary to define the general orientation and distribution of underground reservoirs through oil testing and fracturing operations, and to obtain the specific conditions of detailed crude oil reservoirs. Because of the characteristics of high temperature and high pressure of deep gas, it is difficult to test and fracturing deep gas wells. Based on the analysis of the characteristics of deep gas and the development needs of oil testing technology, this paper analyses the oil testing and fracturing technology of deep gas wells through reservoir modification and fluid drainage.

An investigation of the optimum separation conditions in the Degassing stations of one of southern Iraqi oil Field

In field separation facilities operation, operators tend to determine the optimum conditions to maximize revenue.
 The object of this study is to investigate the present number of separation stages and their optimal conditions for degassing stations of oil Field. 
 A computer program model was written to predict the optimal conditions for oil field gas-oil separation stations subject to a given crude oil composition , flow rate and feed temperature and pressure using flash calculations with modified Soave-Redlich-Kwong Equation of state.
 Nine Bottom-hole well samples of reservoir crude oil was collected and subjected to PVT analysis commonly performed on crude oil, Surface stage separators gas samples at steady condition were taken and analyzed by gas chromatography apparatus to determine the gas composition.
 A good agreement was found by comparing theoretical and experimental prediction for gas composition.
 The results indicate that the present five separation stages is the optimum number and the values obtained for these optimum stages pressure are (514.7,119.7,42.7,26.7,14.7 psig) for Summer and (464.7,119.7,42.7,26.7,14.7 Psig) for Winter where the current operation pressures are (614.7,119.7,42.7,26.7,14.7 psi) for Summer and Winter. The total liquid yields in stock tank reaches (1.29, 1.31 %) for summer and winter respectively and the stock tank API Gravity reaches (0.41, 0.42) for summer and winter respectively.

An ANCOVA model for porosity and its uncertainty for oil reservoirs based on TORIS dataset

Porosity is one of the most important parameters to assess in-place oil or gas in reservoirs, and to evaluate recovery from enhanced production operations. Since it is relatively well-established to determine porosity using different laboratory and field methods, its value is usually determined at many locations across a reservoir as part of the common practice to capture reservoir heterogeneity and the variability in values. This suite of measurements and the distribution of values are most valuable for probabilistic reservoir assessments, and for spatial modeling if the exact data locations are known.Despite the importance of individual measurements to set the range of values for probabilistic studies, it is not always possible to access these data due to confidentiality. In most cases, commercial or publicly available databases that assessments may rely on usually report only mean values of porosity, like any other reservoir data, or they may not report a value at all. This makes both quantifying the mean value and the uncertainty around it difficult for probabilistic assessments.In this study, the TORIS (Tertiary Oil Recovery Information System) dataset of the National Petroleum Council and the U.S. Department of Energy was used to model porosity and the uncertainty around predicted values. TORIS is an integrated dataset of production data, reservoir properties, and project databases of crude oil reservoirs in the United States. The model presented in the paper was based on ANCOVA (Analysis of Co-Variance) of data from 1038 reservoirs from the TORIS dataset for porosity prediction, validation and testing for quantitative and qualitative parameters that may be readily available in most cases, and to estimate uncertainty around the mean values. This model also explored association of porosity values to different parameters, and to different depositional systems and diagenetic overprint conditions. Furthermore, an ANN (Artificial Neural Network) model was created to compare the predicted values of both models. Results showed that the ANN model was able to represent more of the variability, however it lacked the insights that might be gained from the ANCOVA model.

Fluorescence lifetimes of crude oils and oil inclusions: A preliminary study in the Western Pearl River Mouth Basin, South China Sea

The fluorescence lifetimes were measured for crude oils and oil inclusions in the Western Pearl River Mouth Basin, South China Sea. The results show that the fluorescence lifetimes are long for crude oils in the WC-A sag, short for those in the WC-B sag and moderate for those in the Qionghai and Shenhu uplifts. Two types of oil inclusions were identified in the reservoirs. The fluorescence lifetimes of type I oil inclusions are longer than those of the crude oils in the same reservoir; however, the fluorescence lifetimes of type II oil inclusions are slightly shorter than those of the crude oils in the same reservoir. The fluorescence lifetimes of crude oils have negative correlations with oil density, viscosity, sulfur content, and polar component content, including aromatics, resins and asphaltenes; however, they have a positive correlation with the saturates content of the crude oils. According to these correlations, the physical properties and gross chemical compositions of the two types of inclusion oils were inferred. The characteristics of the type I inclusion oils differ from those of the type II inclusion oils and reservoir crude oils, indicating that two oil charge events occurred in the reservoirs. The reservoirs in this area are inferred to have been first charged by high maturity oils sourced from the Wenchang Formation mudstones deeply buried in the WC-A sag, and then the reservoirs were charged by low maturity to high maturity oils sourced from the Enping Formation mudstones in the WC-A sag and partially mature oils sourced from the Wenchang Formation mudstones in the WC-B sag.

Mechanistic understanding of asphaltenes surface behavior at oil/water interface: An experimental study

Asphaltene precipitation during natural depletion and enhanced oil recovery (EOR) methods is one of the problematic challenges, which can affect the production in oil reservoirs. Asphaltenes as the most surface-active agents in the crude oil can interfacially interact with water molecules. As asphaltenes absorb to oil/water interface, water potentially can be involved and affect asphaltenes surface activity. This paper set out to investigate the surface activity of asphaltenes at the oil/water interface. Extensive sets of IFT tests were conducted with synthetic oil extracted from three different real reservoir crude oil samples in the presence of the distilled water. Results showed that IFT changes are not the dominant function of asphaltenes bulk concentration. However, it was revealed that asphaltenes surface concentration, which is dependent on the thermodynamic stability of asphaltenes within the bulk, controls IFT changes. Further, it was shown that IFT changes versus pressure are non-linear, indicating a non-linear function of asphaltenes surface behavior against pressure. Diluting a crude oil sample with normal heptane (n-C7) at various dilution ratios, indicated that dilution with a precipitant causes asphaltenes to be less surface active. The results of this study indicated that aging reduces asphaltenes surface activity only when the crude oil is diluted which revealed that asphaltene precipitation is a time-dependent phenomenon. Finally, it identified that sudden pressure shocks have no significant effect on asphaltenes behavior in crude oil. The results of this study shed new light on the mechanism of the asphaltenes surface behavior at oil/water interface which could be of crucial importance in flow assurance engineering as well as water flooding process.

Nanocrystal H[Fe, Al]ZSM-5 zeolites with different silica-alumina composition for conversion of dimethyl ether to gasoline

Non-petroleum route to produce transportation fuels is alternative way to address the fast depletion of the crude oil reservoir, especially in China. In this work, series of nanocrystal H[Fe, Al]ZSM-5 zeolite samples with different SiO2/Al2O3 ratio were prepared with hydrothermal method using sodium aluminate and tetraethyl orthosilicate as Al and Si sources, respectively, and the tetrapropylammonium hydroxide was used for structure-directing agent (SDA). The synthesized zeolites were characterized in detail by UV–Vis, X-ray diffraction, scanning electron microscope, N2 sorption, X-ray fluorescence, ammonia temperature-programmed desorption and pyridine-FTIR techniques. Fe species were incorporated into ZSM-5 framework, resulting in the formation of some new active sites. For the Iron-containing nanocrystal ZSM-5 samples with different SiO2/Al2O3 ratio, the B and L acid strength and amounts are determined by the coexistence and synergistic effect of Al- and Fe-based acid sites. The catalytic results illustrated that the H[Fe, Al]ZSM-5 zeolite with SiO2/Al2O3 ratio for 45 exhibited the best catalytic activity and stability due to its maximum B acid amount and higher B/L ratio. The DME conversion remains at >98% within the 135 h investigation. Moreover, the gasoline yield was up to 72.5%, and the selectivity for aromatics and durene could be reduced to 40% and 1%, respectively.

A laboratory investigation of carbon dioxide-enhanced oil recovery by focusing on CO2-oil physical properties

Carbon dioxide (CO2) miscible flooding has become an important method in enhanced oil recovery (EOR) for recovering residual oil. In addition it may help in protection of the environment as (CO2) is widely viewed as an important agent in global warming. Knowledge of the interactions between (CO2) and reservoir crude oil is very critical for any (CO2)-enhanced oil recovery (EOR) projects. This paper shows the effect of (CO2) miscible flooding application for Egyptian oil fields by swelling studies. The swelling test is a laboratory simulation of the process of injecting gradually different percentage of (CO2) gas into a reservoir containing under-saturated oil. The gas (injection solvent) can dissolve, causing the reservoir fluid to swell. This paper presents a summary of a wide range of laboratory tests conducted on ten different crude oils varying from 26.4 to 40.5 API. These were used to invested the use of (CO2) and its effect on parameters such as viscosity, density, gas solubility and swelling factor as a function of pressure at temperature from 620.3 to 706.0 °R.

Quantitative Characterization and Dynamic Law of Interlayer Interference for Multilayer Commingled Production in Heavy Oil Reservoirs by Numerical Simulation

This paper moves one step forward to build a numerical model to research quantitative characterization and dynamic law for interlayer interference factor (IIF) in the multilayer reservoir which was heavy oil reservoirs and produced by directional wells. There are mainly four contributions of this paper to the existing body of literature. Firstly, an equivalent simulation method of the pseudo start pressure gradient (PSPG) is developed to quantitatively predict the value of IIF under different geological reservoir conditions. Secondly, the interlayer interference is extended in time, and the time period of the study extends from a water cut stage to the whole process from the oil well open to produce a high water cut. Thirdly, besides the conventional productivity interlayer interference factor (PIIF), a new parameter, that is, the oil recovery interlayer interference factor (RIIF) is put forward. RIIF can be used to evaluate the technical indexes of stratified development and multilayer co-production effectively. Fourthly, the effectsof various geological reservoir parameters such as reservoir permeability and crude oil viscosity, etc. on the PIIF and RIIF’s type curves are discussed in detail and the typical plate is plotted. The research results provide a foundation for the effective development of multilayer heavy oil reservoirs.

ASP flooding in tight carbonate rocks

Alkaline-Surfactant-Polymer (ASP) floods can mobilize oil left behind by waterfloods by lowering the interfacial tension. However, conducting such floods in tight carbonate rocks presents several challenges, e.g., polymer transport in low permeability carbonates, presence of divalent ions, geochemical interactions with chemicals and rock surface, pore-scale heterogeneity, and oil-/mixed-wettability. This paper addresses the first three challenges. A systematic study of polymer transport in low permeability carbonate cores was performed. Shearing of high molecular weight polymers and successive filtration treatment were performed to improve polymer size distribution. Single phase polymer transport experiments were performed in low permeability carbonate rocks, and optimum pretreatment method was developed. Surfactant phase behavior and aqueous stability experiments were performed to develop ultralow tension ASP and SP formulations with a reservoir crude oil. ASP and SP corefloods were performed in oil-wet low permeability limestone rocks. The oil recovery, pressure drop, effluent ionic composition, effluent viscosity and effluent surfactant concentrations were measured. PHREEQC simulations were performed to understand geochemical reactions during ASP floods. The polymer treatment procedure was able to successfully transport polymer through low permeability Edwards Yellow limestone cores, but not through Texas Cream limestone due to differences in their pore structures. It was found that polymer hydrodynamic radius must be smaller than the pore throat radii of the rock for successful polymer transport. Therefore, mercury porosimetry data of the porous medium is critical for polymer selection, especially in case of low permeability rocks. Tertiary ASP floods resulted in improving the cumulative oil recovery to 77–87% OOIP, whereas SP flood improved the cumulative oil recovery to 85% in an outcrop core. Surfactant retentions during ASP and SP corefloods were found to be 0.4 mg/g-rock and 0.3 mg/g-rock, respectively, in outcrop cores.

Effects of Salinity and Individual Ions on Crude-Oil/Water Interface Physicochemical Interactions at Elevated Temperature

Summary Advanced waterflooding processes through injection of optimized-chemistry waters have recently become popular for enhanced oil recovery (EOR) in carbonate reservoirs. In this study, we describe the results from a series of experiments (including interfacial tension (IFT), interfacial shear rheology, and droplet-coalescence times) at elevated temperature to determine the effects of both salinity and individual water ions on different physicochemical interactions occurring at the crude-oil/water interface. In addition, the results from microscopy imaging of the interface and ζ-potential/average oil-droplet size in crude-oil/water/brine emulsions are reported at ambient temperature. Reservoir crude oil was used for these measurements, and ionic strengths of different brines were varied from high-salinity seawater (56,000 ppm total dissolved solids) to pure deionized (DI) water (zero salinity). The dynamic and equilibrium IFTs of crude-oil/brine interfaces were found to be lower than those of the crude-oil/DI-water interface. Both the 10-times-reduced-salinity seawater and 10-times-reduced-salinity seawater enriched with sulfates showed relatively higher IFT compared with high-salinity multivalent-ion brines, whereas the initial rate of IFT change with time was observed to be the lowest with sulfate-rich brine. The interfacial-rheology results showed that the transition times for the interface to become elastic-dominant from a viscous-dominant regime were found to be the lowest for low-salinity sulfate-rich brine and the greatest with high-salinity multivalent-ion brines. The coalescence times determined for crude-oil droplets in different brines showed delayed coalescence with sulfate-rich brine and DI water, whereas the fastest coalescence was observed with the high-salinity multivalent-ion brine containing magnesium (Mg2+) and calcium (Ca2+) ions. All these results on IFT, interfacial shear rheology, and crude-oil-droplet-coalescence times obtained at elevated temperature agreed well with previously reported ambient-temperature data to indicate similar trends for different water ion interactions occurring at the crude-oil/water interface. However, faster kinetics of interfacially active molecules together with reduced viscosities of fluid phases resulted in lower IFTs, shorter interfacial-film-transition times, and rapid coalescence times with DI water and different brines at elevated temperature. Microscopy-imaging results at ambient temperature showed formation of aggregates with DI water and two low-ionic-strength brines to demonstrate the better activity of interfacially active molecules to result in stable interfaces. The highest negative ζ-potentials were observed in DI water and sulfate-rich brine at ambient temperature. The oil-droplet diameters measured in crude-oil/brine emulsions showed the smallest droplet sizes with DI water and sulfate-rich brine. These measured data from different experimental techniques at both elevated and ambient temperatures therefore showed good consistency with each other, demonstrating the importance of having certain salinity levels and key ions, such as Mg2+ and Ca2+, in the injection water to enhance the coalescence between released oil droplets. Considering the importance of snap-off and oil-droplet coalescence on improving oil-phase connectivity, injection-water salinities and ionic compositions should be designed for optimal interactions at the crude-oil/water interface to capitalize on both of these effects in advanced waterflooding.

Numerical Simulation Based on High Pressure Jet Mud Impact Technology

Since crude oil is composed of colloidal solution, solid hydrocarbon, asphaltene, and fine sediment dispersal, the problem of sludge deposition will occur after the long-term operation of the underground crude oil storage. The high shear rate produced by the jet has a suction effect on the sludge. Based on the advantages of groundwater sealing reservoirs, this study uses CFD software to study the jet flow of underground crude oil reservoirs, and analyzes the effects of the flow on the sludge and the changes of the flow with time. The research shows that the jet stream has impact and entrainment in the convection field, and the jet at a certain speed can make the flow field circulate as a whole, and dissolve the sludge at the bottom of the reservoir. The energy of submerged jet decays rapidly in the process of advance.

Preservation of Ultradeep Liquid Oil and Its Exploration Limit

Crude oil in reservoirs may crack to gas with increasing buried depth and temperature, resulting in natural gas as the major exploration target in deep strata. Exploration of ultradeep targets in the Tarim Basin, Northwest China, unexpectedly discovered huge accumulations of liquid oil in Ordovician carbonate reservoirs with burial depths of >7000 m. Applying comprehensive two-dimensional gas chromatography/time-of-flight mass spectrometry, this paper analyzes the chemical compounds of crude oil in these ultradeep layers and has found that these oils are slightly cracked with low conversion of oil to gas, as evidenced by limited diamondoid compound analogues and low concentrations. Gold tube pyrolysis simulation and kinetic calculation suggest that the cracking temperatures of oil are in the range of 210–220 °C. The temperature implies that the deepest liquid oil surviving limit is inferred as 9000 m in this basin with the increase of the temperature. The major controlling factors on preserving abundant l...

Surfactant/Polymer Flooding: Chemical-Formulation Design and Evaluation for Raudhatain Lower Burgan Reservoir, Kuwait

Summary Surfactant/polymer (SP) flooding is an enhanced-oil-recovery (EOR) process that can lead to incremental oil recovery through two mechanisms: reducing oil/water interfacial tension (IFT) to decrease residual oil saturation and increasing the viscosity of the displacing fluid to improve overall sweep efficiency. IFT reduction allows better oil recovery by overcoming capillary effects, while the increased viscosity of the displacing fluid allows a more-homogeneous sweep of reservoir oil. Implementing chemical flooding in reservoirs with relatively high temperature and in-situ salinity (>200,000 ppm) is somewhat challenging. This paper describes the extensive laboratory work performed for the light-oil Raudhatain Lower Burgan (RALB) Reservoir (180°F/82°C) in Kuwait. Reservoir fluids were thoroughly characterized to preselect the most-suitable chemicals for the SP process. Reservoir crude oil was analyzed and recombined with gases (C1 through C3) depending on the reported gas/oil ratio (GOR) to reproduce the oil in place (OIP) at original reservoir conditions in terms of pressure, temperature, and oil composition. A shift of the live-oil equivalent alkane carbon number (EACN) was compared with the dead-oil EACN. Numerous surfactants were screened according to three main criteria: solubility in the envisioned injection brine, ultralow oil/water IFT, and chemical adsorption on reservoir rock. Different brine types were considered, and the use of adsorption inhibitors was also investigated. Furthermore, polymer screening involving temperature-resistant polymers was conducted by means of viscosity, long-term-aging, and adsorption tests. Polymer compatibility with the selected surfactants was also evaluated. The selected SP formulation was further evaluated through a series of coreflood experiments that were mainly dependent on chemical adsorption on reservoir rock and incremental oil recovery. An injection strategy was designed as a result of these experiments. Laboratory results obtained thus far are encouraging and provide a systematic methodology to design SP injection in high-temperature, high-salinity, and light-oil reservoirs that are similar to the RALB reservoir. Additional technoeconomic evaluation is in progress in preparation for field-scale deployment of SP injection at RALB Reservoir.

Estimation of minimum miscibility pressure of varied gas compositions and reservoir crude oil over a wide range of conditions using an artificial neural network model

Minimum miscibility pressure (MMP) is a key variable for monitoring miscibility between reservoir fluid and injection gas. Experimental and non-experimental methods are used to estimate MMP. Available miscibility correlations attempt to predict the minimum miscibility pressure for a specific type of gas. Here an artificial neural network (ANN) model is applied to a dataset involving 251 data records from around the world in a novel way to estimate the gas-crude oil MMP for a wide range of injected gases and crude oil compositions. This approach is relevant to sequestration projects in which injected gas compositions might vary significantly. The model is correlated with the reservoir temperature, concentrations of volatile (C1 and N2) and intermediate (C2, C3, C4, CO2 and H2S) fractions in the oil (Vol/Inter), C5+ molecular weight fractions in the oil and injected gas specific gravity. A key benefit of the ANN model is that MMP can be determined with reasonable accuracy for a wide range of oil and gas compositions. Statistical comparison of predictions shows that the developed ANN model yields better predictions than empirical-correlation methods. The ANN model predictions achieve a mean absolute percentage error of 13.46%, root mean square error of 3.6 and Pearson's correlation coefficient of 0.95. Sensitivity analysis reveals that injected gas specific gravity and temperature are the most important factors to consider when establishing appropriate miscible injection conditions. Among the available published correlations, the Yellig and Metcalfe correlation demonstrates good prediction performance, but it is not as accurate as the developed ANN model.

Interfacial Activity of Characterized Middle Eastern Asphaltenes

Asphaltene molecules play a pivotal role in reservoir fluid characterization. As a result of the high complexity of these molecules, there is still an active debate in the scientific community about their physicochemical properties and the structural elucidation, despite a myriad of published studies. It is commonly agreed that asphaltenes, a fraction of reservoir crude oils, exhibit strong interfacial activity and cause many production challenges. In this work, the structure and interfacial activity of 11 characterized asphaltene samples, extracted from 11 different reservoir crude oils from the Middle Eastern region, were analyzed using Raman spectroscopy and pendent drop tensiometry. Additionally, contact angle measurements and atomic force microscopy (AFM) were executed on selected samples. The Raman analysis revealed that the 11 asphaltene batches have similar structural characteristics with the annulated core ranging from 1.43 to 1.66 nm in diameter, which corresponds to 6–7 fused aromatic rings. In...