API Gravity Research Articles

On the evaluation of crude oil oxidation during thermogravimetry by generalised regression neural network and gene expression programming: application to thermal enhanced oil recovery

Enhancing oil recovery using in-situ combustion (ISC) is an attractive alternative, especially for heavy crudes. During ISC, part of the hydrocarbon is pyrolysed/oxidised, which generates heat and deposits fuel in the combustion front. In this study, crude reactions during ISC are modelled after their thermogravimetry thermo-oxidative profiles using advanced machine learning systems. The model inputs include the weight per cent of asphaltenes, resins, and °API gravity of the oil as well as the heating rate and the temperature. Four types of artificial neural networks (ANNs); namely multilayer perceptron (MLP), generalised regression neural network (GRNN), cascade-forward neural network (CFNN), and radial basis function (RBF) neural network, were employed to develop models for accurate prediction of the weight per cent of residual crude oil based on 2289 experimental data points. Moreover, three optimisation algorithms; including Bayesian Regularisation (BR), Levenberg–Marquardt (LM), and Scaled Conjugate Gradient (SCG) were applied in the training step of MLP and CFNN to improve the prediction ability. GRNN provided the most accurate prediction with ∼2.3% overall average absolute per cent relative error and coefficient of determination of 0.9983. GRNN model is reliable for crude oils with °API gravity of 5–35 and up to 820°C. Lastly, a mathematical correlation was developed to estimate the residual crude oil from thermogravimetry analysis using gene expression programming (GEP). GEP also predicted the thermo-oxidative profile with high accuracy. On the basis of sensitivity analysis, residue formation during crude oil oxidation was impacted the most by the temperature, oil °API gravity, and asphaltenes content, respectively. The Leverage approach identified 2.9% of the data points as doubtful.

Ni:Fe:Mo and Ni:Co:Mo nanocatalysts to hydroprocessing to heavy crude oil: Effect of continue phase in the final metallic nanoparticles size

Nowadays, heavy crude oil is a significant source of energy due to its enormous reserves available throughout the planet. The hydroprocessing of heavy crude using dispersed catalysts makes it possible to convert this resource into lighter products. In this work, the effect of the ternary metal nanoparticles of Ni:Fe:Mo and Ni:Co:Mo on the hydroprocessing of heavy crude was studied in order to analyze the effect of nanosize of them. The trimetallic particles were prepared through water/oil emulsions. The nanoparticles formed in the reverse microemulsions were analyzed through of Dynamic Light Dispersion (DLS), Scanning Electron Microscopy-X-ray-Bright Field Energy Dispersion Spectroscopy (SEM-EDS) techniques. The catalysts were tested in a hydrotreatment reaction at 350 °C into a batch reactor with an initial H2 pressure of 1000 psi. After catalytic tests the physicochemical properties of final products were analyzed by °API gravity, asphalthenes content, and simulated distillation curves. Ni:Co:Mo nanocatalyst was the best material in catalytic activity than all series. Ni:Co:Mo nanocatalyst presented higher catalytic activity, this material produced naphtha (16 wt%), distillates (29 wt%), VGO (27 wt%), and less residue (28 wt%). The smaller particle size (<100 nm) and metals relation in the material play a role important in the Ni:Co:Mo series were more active than Ni:Fe:Mo serie in the catalytic tests.

An Experimental Investigation of In Situ Combustion in High Permeability Contrast Systems

Abstract A significant portion of world oil reserves reside in naturally fractured reservoirs and a considerable amount of these resources includes heavy oil and bitumen. Thermal enhanced oil recovery methods (EOR) are mostly applied in heavy oil reservoirs to improve oil recovery. In situ combustion (ISC) is one of the thermal EOR methods that could be applicable in a variety of reservoirs. Unlike steam, heat is generated in situ due to the injection of air or oxygen enriched air into a reservoir. Energy is provided by multi-step reactions between oxygen and the fuel at particular temperatures underground. This method upgrades the oil in situ while the heaviest fraction of the oil is burned during the process. The application of ISC in fractured reservoirs is challenging since the injected air would flow through the fracture and a small portion of oil in the/near fracture would react with the injected air. Only a few researchers have studied ISC in fractured or high permeability contrast systems experimentally. For in situ combustion to be applied in fractured systems in an efficient way, the underlying mechanism needs to be understood. In this study, the major focus is permeability variation that is the most prominent feature of fractured systems. The effect of orientation and width of the region with higher permeability on the sustainability of front propagation are studied. The contrast in permeability was experimentally simulated with sand of different particle size. These higher permeability regions are analogous to fractures within a naturally fractured rock. Several ISC tests with sand-pack were carried out to obtain a better understanding of the effect of horizontal, vertical, and combined (both vertical and horizontal) orientation of the high permeability region with respect to air flow to investigate the conditions that are required for a self-sustained front propagation and to understand the fundamental behavior. Within the experimental conditions of the study, the test results showed that combustion front propagated faster in the higher permeability region. In addition, horizontal orientation almost had no effect on the sustainability of the front; however, it affected oxygen consumption, temperature, and velocity of the front. On the contrary, the vertical orientation of the higher permeability region had a profound effect on the sustainability of the combustion front. The combustion behavior was poorer for the tests with vertical orientation, yet the produced oil API gravity was higher. Based on the experimental results, a mechanism has been proposed to explain the behavior of combustion front in systems with high permeability contrast.

An optimized thermal cracking approach for onsite upgrading of bitumen

Onsite partial upgrading is a promising strategy for facilitating pipeline transportation of bitumen without the use of diluent. In the present work, a one-step treatment using an autoclave is optimized toward upgrading Alberta bitumen of 9.6 API gravity and 925,000 cP viscosity. The thermal cracking process was kept simple in order to maintain an economic and environmental advantage. Optimum conditions entailed 75 min of reaction time at 420 °C, without quenching the reactor. These conditions corresponded to highest centrifuged oil product yield of 73.3 ± 1.1 wt%, viscosity of 34 ± 2 cP and API gravity of 18.9 ± 0.5. H-NMR, CHNS and FTIR measurements revealed thermally cracked asphaltenes having more aromatic parts with shorter aliphatic side chains. Subsequently, the P-value of the thermally cracked product was much lower (1.11) than the bitumen feed (3.9) and was not impacted by quenching. Nevertheless, the degradation of viscosity and API gravity of the oil product and its centrifuged cut were less than 5% after 12 days.

The offshore Mancos play in the San Juan Basin as a component of the Mancos total petroleum system

Historically, the offshore Mancos play of the San Juan Basin has produced oil from noncommercial to marginally commercial reservoirs consisting of dark-gray marine shale with thin beds and laminae of fine-grained sandstone of limited permeability. During the last decade, horizontal drilling with horizontal wells has resulted in substantially increased production. However, placement of the offshore Mancos play within the Mancos total petroleum system has been poorly understood. Here, the offshore Mancos play is interpreted as a carrier bed play within the Mancos total petroleum system. Unconventional reservoirs of the offshore Mancos play are stratigraphically equivalent to updip conventional reservoirs deposited nearer to the shoreline and to downdip source rocks matured to peak oil generation. Offshore Mancos facies include a proximal facies to the southwest, a medial facies, and a distal facies to the northeast. Oil production has been obtained from the proximal and medial facies. Mancos shales contain oil-generative kerogens that are within the upper oil window near conventional reservoirs in the south and have matured to peak oil generation downdip of and to the northeast of the offshore Mancos reservoirs. Uniform API gravities of light sweet produced oils that transcend thermal maturity variations of Mancos shales indicate that oils generated in downdip mature source rocks migrated updip through the carrier bed sandstones of the offshore play and into the conventional reservoirs. Residual oil saturations are consistent with the concept of migrating oils moving updip through only a small number of interconnected pathways within a carrier bed.

English

Oil reserves in the Niger Delta have been gradually decreasing due to the increased production. New large field discoveries are scarce, thus there is need to improve on the production from existing reserves. Low salinity surfactant flooding (LSSF) is a potential enhanced oil recovery process to increase oil production in the Niger Delta oil fields. In this study, sodium dodecyl sulphate and ethanol were used as surfactant to study the significance of the surfactants on oil recovery. Sand packs were used as formation sample in the laboratory. This was soaked with oil of 24.36&deg; API and specific gravity of 0.9436. Low salinity water was used as a displacing fluid in the secondary recovery mechanism. However, sodium dodecyl sulphate and ethanol (78% vol.) was introduced into the sand packs. The sodium dodecyl sulphate reduced the interfacial tension as obtained using tensiometer machine. Ethanol was used in the second case as surfactant.&nbsp; The result of the work shows that sodium dodecyl sulphate had oil recovery of 16.1, 16.9, 19.0 and 19.3% respectively at different surfactant concentrations 0.2, 0.3, 0.35and 0.38% wt. respectively; while ethanol (78% vol.) had oil recovery of 1.5%. The study noted that sodium dodecyl sulphate is a good surfactant for enhanced oil recovery for crude oil with the specified API gravity. In addition, interfacial tension reduction and change in rock wettability were the working mechanisms for the sodium dodecyl sulphate to increases oil recovery from reservoirs. The work showed that sodium dodecyl sulphate maintained low interfacial tension through the flood process. Key word: Sodium dodecyl sulphate, interfacial tension reduction, ethanol, crude oil

SARA fractions evaluation during microwave-assisted upgrading of an oil refinery vacuum residue: effects of operational conditions

The operational conditions effects on SARA fractions during upgrading of vacuum residue using microwave irradiation were investigated. The residue was from Tehran oil refinery, Iran. The vacuum residue specifications contained API gravity: 8.79, viscosity (at 60 °C): 16391 cSt, viscosity (at 80 °C): 1910 cSt, saturates and aromatics: 52.09 wt%, resins: 34.61 wt%, and asphaltenes: 13.3 wt%. The parameters included catalysts type (Fe, MoS2, Cu, Fe2O3, and Ni), processing time, active carbon as a sensitizer, power level, catalyst, NaBH4. The best conditions of the process included time: 60 min, carbon: 20 wt%, power level: 100%, catalyst: 20 wt%, NaBH4: 3 wt%, resulted that saturates and aromatics increased from 52.09 wt% to 77.64 wt%, resins decreased from 34.61 wt% to 21.59 wt%, asphaltenes decreased from 13.3 wt% to 0.77 wt%. In the best conditions, the product was similar to a crude oil entering an oil refinery. Highlights SARA fractions during upgrading vacuum residue using microwaves are investigated. The parameters include catalysts, power level, sensitizer, NaBH4, process time. The studied catalysts are iron, nickel, copper, MoS2, iron oxide. In optimal conditions, product was similar to a crude oil entering an oil refinery.

Artificial Neural Network to Forecast Enhanced Oil Recovery Using Hydrolyzed Polyacrylamide in Sandstone and Carbonate Reservoirs.

Polymer flooding is an important enhanced oil recovery (EOR) method with high performance which is acceptable and applicable on a field scale but should first be evaluated through lab-scale experiments or simulation tools. Artificial intelligence techniques are strong simulation tools which can be used to evaluate the performance of polymer flooding operation. In this study, the main parameters of polymer flooding were selected as input parameters of models and collected from the literature, including: polymer concentration, salt concentration, rock type, initial oil saturation, porosity, permeability, pore volume flooding, temperature, API gravity, molecular weight of the polymer, and salinity. After that, multilayer perceptron (MLP), radial basis function, and fuzzy neural networks such as the adaptive neuro-fuzzy inference system were adopted to estimate the output EOR performance. The MLP neural network had a very high ability for prediction, with statistical parameters of R2 = 0.9990 and RMSE = 0.0002. Therefore, the proposed model can significantly help engineers to select the proper EOR methods and API gravity, salinity, permeability, porosity, and salt concentration have the greatest impact on the polymer flooding performance.

Machine learning approach for predicting crude oil stability based on NMR spectroscopy

Crude oils are extremely complex organic mixtures, composed of various constituents ranging in size, shape and polarity. Obtaining a detailed insight into the petroleum composition is of highest priority for quality evaluation of crude oils and crude oil product performances. The stability of crude oils and their components represents one of the major challenges in petroleum industry, since there is no existing single method to determine the stability of all fractions. In this study, statistical multi-way analysis (MWA) and machine learning (ML) methods were coupled with diffusion-ordered NMR spectroscopy (DOSY) and compared to different crude oil stability affecting parameters in order to explore possibilities to predict crude oil stability. The potential of this approach was explored to identify and classify the crude oils of different origin according to their composition, stability, density and diffusion properties. With the application of MWA using the TUCKER3 decomposition model for a set of DOSY NMR spectra, the principal components were determined for the model (5,5,5), which described 99.89 % of the total variance. The reduced space of the first 3 principal components was used for the sample classification. Similar samples were identified, and reduced space was further utilized for the regression of measured stabilities. Extensive ML multivariate linear regression was carried out for modeling crude oil stability in relation to DOSY NMR spectra and other measured properties, such as aromaticity, API gravity, percentage of aliphatic chains, asphaltene content and relative diffusivities. In both MWA and ML cases the best predictive models were determined. For such complex mixtures as crude oils are, exceptionally good correlations were obtained, proving that this new and robust model can accurately predict crude oil stability and other important parameters relevant for petroleum industry thus showing a great potential for practical applications.

Effect of pour point depressants and diluents on exergy destruction during pipeline transportation of crude oil

Exergy destruction in pipeline flow of crude oils mixed with pour point depressants (PPD) and diluents has been investigated. Ethylene vinyl acetate with vinyl acetate content of 18% and 28% (EVA-18 and EVA-28) and Polymethyl methacrylate (PMMA) with concentrations of 200 ppm, 1000 ppm and 1500 ppm were chosen as the PPDs for this purpose. Four different diluents were considered viz. n-hexane, cyclohexane, n-butanol and toluene representing paraffins, naphthenes, alcohols and aromatics respectively. The viscosity reduction was found out experimentally. Using these results for a hypothetical pipeline, the effect of API gravity of crude oil, pipeline diameter, Reynolds number, PPD concentration and diluent type on exergy destruction was investigated. These findings would help in making a prudent choice of PPD and diluents for efficient transportation of crude oil through pipelines.

Cyclic Gas Injection EOR in Eagle Ford Can Increase Estimated Ultimate Recovery

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200427, “Evaluation of Eagle Ford Cyclic Gas Injection EOR: Field Results and Economics,” by George Grinestaff, SPE, Chris Barden, and Jeff Miller, SPE, Shale IOR, prepared for the 2020 SPE Improved Oil Recovery Conference, originally scheduled to be held in Tulsa, 18–22 April. The paper has not been peer reviewed. Cyclic-gas-injection-based enhanced oil recovery (CGEOR) in the Eagle Ford was begun in late 2012 by EOG Resources and, at the time of writing, has expanded to more than 30 leases by six operators (266 wells). An extensive EOR evaluation was initiated to analyze the results recorded in these leases. The authors write that CGEOR in Eagle Ford volatile oil can yield substantial increases in estimated ultimate recovery (EUR) with robust economics, depending on compressor use and field life. Introduction Eagle Ford Source Rock and Reservoir. The Eagle Ford shale represents some of the world’s richest source rocks. The Upper Cretaceous seafloor received abundant organic debris and preserved it in an anoxic environment. The low permeability of the shale and limestone helped generate hydrocarbons when pore pressure exceeded overburden pressure. The resulting natural fractures provided a means to expel oil, much of it migrating into the overlying Austin Chalk and Tertiary sandstones. The primary target area for produced-gas injection EOR is currently in the volatile oil window between 9,000 and 11,000 ft true vertical depth, which yields oil API gravity of greater than 40. Initial gas/oil ratio (GOR) typically ranges from 1,000 to 3,000 scf/bbl. Eagle Ford EOR History. The first large-scale CGEOR project was implemented in October 2014. Rapid development has occurred since then, but, in the complete paper, the authors present the first commercial EOR projects by EOG Resources because these have the longest CGEOR production history. Recent projects show more-efficient startup, cycling, and higher optimization of gas injection. Therefore, the analysis of EOR in this paper takes a conservative approach of using the first projects because they appear to have lower EOR recovery but more production history. Evaluation Methodology Unconventional EOR Work Flow. Analysis of CGEOR production and results has been completed using production history and reservoir simulation to provide a rigorous evaluation. The authors use a 14-component fracture element model with a very fine grid to predict well GOR, EUR, and reservoir behavior for the compositional process. The element model is then scaled up to mimic the average well for a given pad or lease, and then cycle operations are developed based on CGEOR simulation runs and criteria. Unconventional CGEOR provides a direct response after the first cycle of gas injection; however, the base depletion profile also is important for understanding economics for increased oil production or incremental EOR. A history match of the base depletion is first completed to match an average well at the pad level (approximately one 640-acre section with 10 to 14 wells). The element is then scaled up based on well completion, stimulated rock volume, and EUR for the base depletion.

Enhanced Representation of Thermal Cracking Chemistry in the Context of Bitumen Partial Upgrading

A detailed modeling framework to describe thermal cracking reactions during bitumen partial upgrading on a molecular basis is put forward in this study. The first block of the framework describes the molecular composition of a whole bitumen feedstock using statistical distributions in conjunction with structural descriptors for hydrocarbon classes, including solubility parameters to distinguish asphaltene components. The creation of a molecular ensemble mimicking the bitumen feedstock is accomplished via Monte Carlo simulation using input information from bulk property measurements and advanced analytical methods. This ensemble of molecules forms the starting point of the conversion model, which is the second block. Thermal cracking chemistry is organized in terms of reaction families, such as carbon–carbon bond cracking, sulfur–carbon bond cracking, dehydrogenation, and condensation, and the reactivity parameters are approximated using structure–reactivity correlations. Because of its considerable size, the reaction network is generated on the fly by means of a kinetic Monte Carlo algorithm, whereby molecule cracking reactions progress one by one over time. Reactivity parameters are tuned against an experimental data set generated in a visbreaking pilot plant. Besides describing the evolution of yield structure under different cracking severities, the model is able to track changes in API gravity, asphaltene content, and molecular distributions. Most importantly, the model explains how the different molecular reaction pathways impact product properties relevant to bitumen partial upgrading and provides directional predictions into other aspects of these technologies, such as product solubility and formation of olefins.

Relationship Between Tectonic Evolutions and Presence of Heavy Oil in The Central Sumatra Basin

Heavy oil is formed through biodegradation process of hydrocarbons, as well as water washing, in which light hydrocarbon fraction disappears and leaves the heavy fraction. Heavy oil is essentially an asphaltic, dense (low API gravity), and viscous that is chemically characterized by its high content of asphaltenes in the oil. Although variously defi ned, 25o API is set the upper limit for heavy oil. Heavy oil in the Central Sumatra Basin is evidently formed as a result of biodegradation and water washing (a hydrodynamic process within oil reservoir) mechanisms. These processes occur as result of tectonic uplift of the reservoir after it has been fi lled with hydrocarbons. Heavy oil reservoir depths in the Central Sumatra Basin are generally shallower than 1,000 feet (300-400 meters), at which surface water may may be associated with the reservoir hence enabling the heavy oil transformation. A combined geology, remote sensing/geographic information system ( GIS), geophysics, stratigraphy, and wellbased analyses is utilized to serve the study. It has been observed that within the northern part of the basin, heavy oil is mainly found in fi elds located within uphill fault blocks such as the up-thrown part of the Sebanga thrust fault with its Duri, Sebanga North, Kulin, Rantau Bais, Batang, Akar, and Genting fi elds. In the western part of the basin there are the Kumis, Kotalama and Pendalian heavy oil fi elds associated with Dalu-Dalu thrust fault and Gadang Island uplift. In total 51 fi elds/structures containing or suspected to contain heavy oil are associated with uplifted geological positions, hence showing the strong relations between tectonic evolutions and present day presence of heavy oil within the basin.

Subsurface Geological Evaluation of the Central Sumatra Basin in Relation to the Presence of Heavy Oil

Central Sumatra Basin has been proven as a mature basin that produces large amounts of conventional oil. In fact, some of the existing oil fi elds are heavy oil containing such as Duri, Sebanga, Rantau Bais, and Kulin fi elds with their API Gravity values of lower than 25o . Apart from those oil fi elds the Central Sumatra Basin is expected to bear signifi cant heavy oil potential. In this light, this paper emphasizes discussion of subsurface geological evaluation on suspected fi elds/areas that contain heavy oil. This evaluation serves as a preliminary step in investigation of heavy oil resources/reserves in the basin. Analysis results on stratigraphic sequence and seismic interpretation provide information support facts over presence of heavy oil that are usually associated to main faults of Dalu-Dalu, Rokan, Sebanga, Petapahan, Pulau Gadang, and Kotabatak. Large tectonic events as a compression phase in the Middle Miocene – recent developed regional uplift and formed main thrust faults system, anticline structures due to the creature of basement highs, during which the F3 was deposited. The thrust faults system are important in the process of heavy oil generation in which surface water encroached into uplifted oil traps hence triggering heavy oil transformation mechanisms of biodegradation and water washing. This study provides illustration over sequences the heavy oil is generated in and their dimension in relation to area of structural anticlines. Based on available data, evaluation on subsurface geology has shown that anticlinal structures containing heavy oil tend to be characterized by near surface uplift (Basement up to 500 - 750 ms), whereas structures with lesser certainty in heavy oil containment tend show lower degrees of uplift marked by basement depth around 1000 ms or deeper. In general, seismic interpretation has shown that heavy oil is contained some sequences within sequences of 4 to 7 (equivalent to Menggala, Bekasap, Bangko, and Duri-Telisa formations).

Study of linseed oil, its biodiesel and xylene as flow improver for Nigerian waxy crude oils

In this study, the physicochemical properties of linseed and linseed biofuel were studied and their effect on the flow properties of Nigerian waxy crude oil at different volume fractions was investigated. The Nigerian wax crude oil was characterized for its specific gravity, API gravity, wax content, pour point and cloud point. The properties of the linseed oil and linseed biodiesel investigated include: density, specific gravity, viscosity, pour point, cloud point and flash point. Upon esterification of the free fatty acid (FFA) contained in the linseed oil reduced from 3.5 to 0.75 and the viscosity of the seed oil reduces from 2169 to 362 mm2/s. The linseed oil and its biodiesel exhibited similar trend of reduced viscosity at higher shear rate, however, linseed biodiesel demonstrated the lowest viscosities, cloud points and pour points owing to reduced fatty contents. The effect of the linseed oil and its biodiesel on the pour point and cloud point of the waxy crude oil was determined; and the performance compared to that of xylene. A rapid drop in the pour point and cloud point was observed with the wax crude pre-heated with 0.1 v/v linseed oil, its biodiesel and xylene.

Purifying Crude Petroleum by Using Porous Ceramic Balls

Background: Background: In this study ceramic crude petroleum filter was prepared from Iraqi White Kaolin with ratio (70%) and Alumina (Al2O3) with ratio (30%), with natural additives Palm Frond with ratios (5,10,15,25,35 and 45)% in different partical size to produce pores, formed by dry pressing then fairing at 1100(˚C). The filters are harmless and environmentally friendly materials. Some assessments were carried out, such as (apparent porosity ratio, water absorption ratio, and apparent density). From the test results obtained the apparent porosity was 60.7% , water absorption was 89.3% and an apparent density of 0.68% with a 45% ratio of fine (P.F). Methods: Size and distribution of pores were characterized by using Scanning Electron Microscope (SEM). The crude petroleum treated with filters evaluated by tests such as (API Gravity, Sulfur Content, Asphaltenes Content, and Metallic Content). Results: The result of API Gravity before immersion crude petroleum filter balls was 24.70 and after immersion crude petroleum filter balls for 7 days for 30 % (P.F) increase to 31.0 and reach to 32.5 after immersion for 14 days. Sulfur Content before immersion crude petroleum filter balls was 3.76 and after immersion crude petroleum filter balls for 7 days for 30 % (P.F) decrease down to 3.1 and reach to 2.6 after immersion for 14 days. Conclusion: So Asphaltenes content before immersion crude petroleum filter balls was 6.68 and after immersion crude petroleum filter balls for 7 days 30 % (P.F) decreased down to 2 and reach to 1.6 after immersion for 14 days, metallic contact such as Vanadium and Nickel before immersion crude petroleum filter balls respectively was 86 ppm, 32 ppm while after immersion crude petroleum filter balls for 7 days they become 53.26 ppm and 15.35 ppm and for 14 days they reached to 47.52 ppm and 11.43 ppm respectively.

Oil characteristics and source rock potential of Abu Rudeis-Abu Zenima area, Central province, Gulf of Suez, Egypt

The Gulf of Suez region is one of the most important petroleum provinces in Egypt and the Abu Rudeis-Abu Zenima area (ARAZ) located in the central province of the Suez Gulf on the eastern side. The scope of the current work is to evaluate the oils in the ARAZ area to identify oils characteristics and source rock potential using the data of whole oil gas chromatography and gas chromatography-mass spectrometry (GC-MS), in addition to stable carbon isotope analysis and vanadium and nickel contents. The bulk oils composition in ARAZ area characterized by moderate saturates and aromatics contents, high sulfur and NSO &asphaltene contents and heavy and normal API gravity. The composition of oils differs primarily due to their degree of thermal maturity. The oils generated from algal marine material with little terrestrial materials deposited under anoxic depositional conditions suggested by a low Pristane/Phytane (Pr/Ph) ratio. Moreover, the oils generated from carbonate source rocks of Thebes and Duwi rock units indicated by high C31-C35 Hopanes (45-50%) and C35/C34 extended Hopane ratio (0.99 – 1.12). The oils reached the peak-oil generation stage (0.85% Ro) indicated by the sterane isomerization ratio (20S % C29) that is less than 55 %. The oils of ARAZ area are matched the oils of the Gulf of Suez.

Optimization of Cyclic Steam Stimulation Process Using Response Surface Methodology

Heavy oil has characteristics such as API gravity 10-20 and high viscosity (100-10,000 cp) at reservoir temperature. Several methods have been successfully applied to produce these reserves, such as cyclic steam stimulation (CSS). Cyclic steam stimulation is a thermal injection method that aims to heat the oil around production wells. This paper presents the investigation regarding CSS application in heavy oil using Response Surface Methodology. Several scenarios were done by varying the operating conditions to obtain the most realistic results and also evaluating the factors that most influence the success of CSS process. Optimization is performed to find the maximum recovery factor (RF) value and minimum steam oil cumulative ratio (CSOR). The operating parameters used are CSS cycle, steam injection rate, and steam quality. Then statistical modeling is carried out to test the most important parameters affecting RF and CSOR for 10 years. The simulation results show that the CSS cycle, steam injection rate, and steam quality affect the RF and CSOR. The maximum RF results with the minimum CSOR were obtained at 39 cycles, an injection rate of 300 bbl/day, and a steam quality of 0.9 with an RF and CSOR value is 24.102% and 3.5129 respectively.

Effect of temperature on the pyrolysis of plastic waste using zeolite ZSM-5 using a refinery distillation bubble cap plate column

The use of plastic is increasing every year, causing an accumulation of plastic waste that is detrimental to the environment. The purpose of this work is to determine the effect of temperature on the conversion of plastic waste into alternative energy through a pyrolysis-catalytic cracking process, using ZSM-5 as a catalyst, and pyrolysis product refinement using a distillation bubble cap plate column. In this study, the raw materials were polypropylene obtained from plastic waste and the catalyst zeolite ZSM-5 (500 ​g ​PP/50 ​g ZSM-5). A fixed bed reactor (D/H ​= ​1/4) was used under vacuum conditions (−3 ​mm ​H2O) to minimize the oxygen content in the reactor. The plastic waste degraded into vapor in the pyrolysis reactor and traveled through a distillation bubble cap plate column consisting of 4 trays that used reactor heat between 500 and 560 ​°C. It was found that the optimum liquid oil (68.43 ​wt%) was obtained at 560 ​°C, and based on API gravity, this oil consisted of gasoline on tray 1 (500–560 ​°C), tray 2 (500–600 ​°C), and tray 3 (580–620 ​°C). Kerosene was obtained on tray 2 (520–650 ​°C), tray 3 (620–650 ​°C), and tray 4 ​at 650 ​°C. The pyrolysis-catalytic cracking process using ZSM-5 at temperatures above 560 ​°C yielded a higher amount of gas, while the thermal process at temperatures above 580 ​°C yielded a high amount of wax polymer. The analysis results of the oil-fuel characteristics of density, calorific value, octane number, and function group, showed similar properties to those of fossil fuels.

Hybrid computing models to predict oil formation volume factor using multilayer perceptron algorithm

Achieving important and effective reservoir parameters requires a lot of time and cost, and also achieving these devices is sometimes not possible. In this research, a dataset including 565 datapoints collected from published articles have been used. The input data for forecasting oil formation volume factor (OFVF) were solution gas oil ratio (Rs), gas specific gravity (γg), API gravity (API0) (or oil density γo), and temperature (T). We have tried to introduce two hybrid methods multilayer perceptron (MLP) with artificial bee colony (ABC) and firefly (FF) algorithms to predict this parameter and compare their results after extraction. After essential investigations in this study, the results show that MLP-ABC gives the best accuracy for predicting OFVF. For MLP-ABC model OFVF prediction accuracy in terms of RMSE T> API> γg and these results show that the effect of Rs is more than other input variables and the effect of γg is the lowest.