Abstract Improving oil recovery from ultra-tight reservoirs remains a critical challenge due to their inherently low permeability, restricted pore connectivity, and poor sweep efficiency. This study presents a systematic experimental investigation of water-based enhanced oil recovery (EOR) techniques applied to core samples from the Tarim Basin. Coreflooding tests were conducted using conventional methods (waterflooding, CO₂ injection), hybrid strategies including Water Alternating Gas (WAG), Gas Alternating Water (GAW), and Alkali–Surfactant–Polymer (ASP), and advanced chemical-assisted schemes, including four Carbonated Water Alternating Gas (CWAG) variants and a novel Active Carbonated Water Alternating Gas (ACWAG) method. Results showed that ACWAG achieved the highest oil recovery (85.3%) and the lowest residual oil saturation (15.7%), outperforming all other techniques. Key performance indicators such as pressure behavior, wettability alteration, and slug size sensitivity confirmed the importance of injection sequencing and chemical formulation. This study provides new insights into the design of EOR strategies for ultra-tight formations and introduces a promising hybrid approach that could be scaled for field application.
The adsorption behavior of methane in kerogen is of great significance for shale gas reserve evaluation and production prediction. However， there is still a lack of clear understanding of the hysteresis phenomenon and its micro-causes in the process of methane desorption. Therefore， based on the real kerogen model， the grand canonical Monte Carlo and molecular dynamics （GCMC-MD） coupling method was used to systematically investigate the adsorption-desorption behavior of methane under different conditions and the pore structure evolution characteristics of kerogen. The results show that the volumetric strain of kerogen shows a continuous growth during the methane adsorption process. This positive feedback mechanism of “adsorption， expansion， and readsorption” effectively expands the available pore space and significantly improves the methane storage capacity of the kerogen. Under the same pressure conditions， the methane’s absolute adsorption amount in the depressurization stage is higher than that in the pressurization stage， thus showing a significant hysteresis loop on the isothermal adsorption-desorption curve. The fundamental mechanism is that the kerogen skeleton undergoes partial irreversible structural deformation， making the thermodynamic path of the adsorption-desorption process do not coincide. The increase of temperature will weaken the interaction between methane molecules and pore wall， reduce the adsorption capacity， and alleviate the hysteresis in the desorption process. Under high temperature conditions， the overall deformation response ability of kerogen decreases. Compared with the type III-A kerogen， the type II-A kerogen has a higher proportion of micropores， which leads to a higher energy barrier to methane in the desorption process， thus aggravating the difficulty of desorption.
Chemical technology, Petroleum refining. Petroleum products
LIANG Yukai, ZHENG Hua’an, ZENG Qianyi, SONG Jifeng, TIAN Zhongyuan, JIANG Shu
The Yinggehai Basin is a key area for natural gas exploration in the western South China Sea. In recent years, commercially viable gas formations and abundant high-temperature formation water have been discovered in the Huangliu Formation of the X gasfield, indicating promising prospects for hydrothermal geothermal resource development. However, geothermal resource evaluation for this system are still lacking. Taking the X gasfield in the Yinggehai Basin as a case study, a heterogeneous 3D geothermal reservoir geological model was constructed by integrating drilling, logging, core, and seismic data. Key properties such as porosity, permeability, temperature, and water saturation were modeled and assigned in a gridded format. During the model construction, multiple stochastic simulations and seismic attribute constraints were introduced to enhance the rationality and accuracy of the spatial distribution of geological parameters. Based on this model, the volumetric method was applied to evaluate the geothermal resource potential of the Huangliu Formation, and the main geothermal resource-rich zones were identified. The results showed that the reservoir temperatures in the Huangliu Formation ranged from 167.0 ℃ to 197.6 ℃, with an average of 186.5 ℃, indicating favorable conditions for high-temperature geothermal development. The total geothermal resource was estimated to be 3.84×10¹⁶ kJ, equivalent to 1 310.5×10⁶ t of standard coal, with fine sandstone serving as the main reservoir lithology. Assuming a recovery coefficient of 8%, the recoverable resource was approximately 0.31×1016 kJ, equivalent to standard coal of 104.8×10⁶ t. The spatial distribution of resources revealed two major geothermal-rich zones, both located in the sand bodies of deepwater turbidite channels of the Huangliu Formation. These zones were characterized by high temperatures, favorable physical properties, and well-developed fine sandstone, making them preferred areas for future development. Meanwhile, water saturation model analysis indicated high water content in both the eastern and western parts of the Huangliu Formation, suggesting the presence of isolated water bodies that could serve as potential development areas. The research results provide clearer insights into the distribution characteristics and development potential of geothermal resources in the Yinggehai Basin and offer important guidance for promoting the integrated development of offshore gas fields and geothermal energy in China.
Petroleum refining. Petroleum products, Gas industry
T. A. Novikova, G. Bezrukova, N. A. Kochetova
et al.
Introduction: Minimizing job-related health risks is one of the priorities for implementing strategic objectives of the demographic policy of the Russian Federation. Objective: To assess the group risk of work-related diseases in employees of modern petroleum product manufacturing. Materials and methods: The study involved 467 men aged 41.56 ± 9.24 years with 14.87 ± 9.39 years of duration of current employment. Comprehensive hygienic and epidemiological studies of working conditions and health of core personnel of a petroleum refinery were conducted. The causal relationship between working conditions and health disorders was assessed using the relative risk (OR), its 95 % confidence interval (CI) and etiologic fraction (EF). Assessment and categorization of occupational risk levels of work-related diseases and evaluation of their acceptability were performed in accordance with R 2.2.3969–23, Russian Guidelines for Assessing Occupational Risks to Workers’ Health: Organizational and Methodological Foundations, Principles and Criteria for Assessment. Microsoft Excel and Statistica10.0 were used for statistical data analysis. Results: We have established that working conditions in petroleum product manufacturing are noted for combined exposure to classes 2 to 4 hazardous chemicals, noise, heavy work and heating microclimate (secondary refining) and are classified as harmful (degrees 2 to 3) and posing occupational risks to workers’ health. Statistically significant cause-and-effect relationships were revealed between working conditions and moderate musculoskeletal and connective tissue diseases (OR = 1.77; EF = 43 %) and severe diseases of the eye and adnexa (OR = 4.496; EF = 78 %). The levels of group occupational risk of diseases ranged from moderate (0.65 × 10–2) for myopia to medium (3.28 × 10–2) for obesity and high (3.28 × 10–2) for dorsalgia, all being unacceptable. The risk of health disorders was found to be determined by factors of the occupational environment at different stages of the technological process. Workers engaged in primary oil refining were at high risk of dorsalgia (6.65 × 10–2) and obesity (3.98 × 10–2); those engaged in secondary refining were at medium risk of disorders of refraction and accommodation (2.09 × 10–2); workers of the electrical equipment operation shop were at high risk of disorders of refraction and accommodation (5.55 × 10–2) and at moderate risk of dorsalgia (0.94 × 10–2), all being unacceptable. Conclusion: Occupational risk of a high (unacceptable) level is the basis for the development of targeted measures of disease prevention in oil refining workers given their involvement at different stages of the technological process.
Petroleum oil without undesirable impurities, so-called refined petroleum, is the basic resource for the production of a wide range of consumer lubrication oils. The undesirable impurities to be re-moved include resinous substances and polycyclic aromatic hydrocarbons. Selective oil refining is a widely used raw oil purification method that involves the extraction of impurities with a selective sol-vent. The efficiency of this process depends on the extraction temperature and extraction agent con-centration for a specific type of raw material. The instability of its hydrocarbon composition along with the lack of constant target quality control for refined petroleum is one of the key problems. In this context, selecting and maintaining optimal production process parameters become difficult to achieve. This article presents a mathematical model of a virtual analyzer to control the quality of refined petroleum. The refraction index was selected as a quality indicator for the finished product. The model was based on the results of pressure, temperature, and flow measurements at specific production setup points, and it can assess the quality of the produced refined petroleum in real time to generate prompt control responses. The comparison of the model data obtained on an operating setup and the laboratory analysis data showed that the error of refraction index assessment does not exceed 1%.
Husnu Gerengi, Muhammed Maraşlı, Marziya Rizvi
et al.
This study evaluated the corrosion behavior of steel hooks embedded in GFRC, which were protected by a zinc-rich (96% Zn) galvanizing coating. The coating provided the hooks with active cathodic protection and a passive physical shield. Macrocell corrosion may form when the anode is smaller than the total steel surface. Thus, the steel hooks at the embedment juncture were additionally sealed against water ingress and air exchange using a construction sealant. The study was conducted in three phases in a salt-spray chamber. First, the electrogalvanized steel hooks embedded in GFRC were allowed to freely corrode for 7 days. In the second phase, the electrogalvanized steel hooks were painted with the zinc-rich coating and observed over 7 days. In the third phase, the steel hooks were protected by the zinc-rich coating together with a primer and construction sealant, and observed over 7 days. To evaluate the electrogalvanized hooks and the corrosion products formed, the thickness of the material was measured. Corrosion on the metal surface was inferred by studying the surface morphology of the hooks at various points of contact and after different periods of time.
Oils, fats, and waxes, Petroleum refining. Petroleum products
Based on the results of drilling, tests and simulation experiments, the shales of the Cretaceous Qingshankou Formation in the Gulong Sag of the Songliao Basin are discussed with respect to hydrocarbon generation evolution, shale oil occurrence, and pore/fracture evolution mechanism. In conjunction with a substantial amount of oil testing and production data, the Gulong shale oil enrichment layers are evaluated and the production behaviors and decline law are analyzed. The results are drawn in four aspects. First, the Gulong shales are in the stage of extensive hydrocarbon expulsion when Ro is 1.0%–1.2%, with the peak hydrocarbon expulsion efficiency of 49.5% approximately. In the low–medium maturity stage, shale oil migrates from kerogen to rocks and organic pores/fractures. In the medium–high maturity stage, shale oil transforms from adsorbed state to free state. Second, the clay mineral intergranular pores/fractures, dissolution pores, and organic pores make up the majority of the pore structure. During the transformation, clay minerals undergo significant intergranular pore/fracture development between the minerals such as illite and illite/smectite mixed layer. A network of pores/fractures is formed by organic matter cracking. Third, free hydrocarbon content, effective porosity, total porosity, and brittle mineral content are the core indicators for the evaluation of shale oil enrichment layers. Class-I layers are defined as free hydrocarbon content equal or greater than 6.0 mg/g, effective porosity equal or greater than 3.5%, total porosity equal or greater than 8.0%, and brittle mineral content equal or greater than 50%. It is believed that the favourable oil layers are Q2–Q3 and Q8–Q9. Fourth, the horizontal wells in the core area of the light oil zone exhibit a high cumulative production in the first year, and present a hyperbolic production decline pattern, with the decline index of 0.85–0.95, the first-year decline rate of 14.5%–26.5%, and the single-well estimated ultimate recovery (EUR) greater than 2.0×104 t. In practical exploration and production, more efforts will be devoted to the clarification of hydrocarbon generation and expulsion mechanisms, accurate testing of porosity and hydrocarbon content/phase of shale under formation conditions, precise delineation of the boundary of enrichment area, relationship between mechanical properties and stimulated reservoir volume, and enhanced oil recovery, in order to improve the EUR and achieve a large-scale, efficient development of shale oil.
Due to the unique landform in northern Shaanxi,the gas transmission pipeline through this area is found with considerable undulation.Liquid accumulation is likely to occur in low points and up-dip sections of pipelines,associated with frequent slug flow,which seriously impact the normal production of gas field.The prediction of critical liquid-carrying velocity is of great significance to reduce the harm brought by liquid accumulation and guide the design of the surface wet gas pipeline.Therefor,the critical liquid-carrying velocity prediction model for wet gas pipelines with undulation was built based on the minimum gradient method combined with uniform design and BP neural network,using the extended dual-fluid separated flow model.The model was validated using the field operation data of the Yan'an gas field.The wellhead temperature,pipeline operation pressure,water volumetric fraction,up- and down-slope angles,and pipe diameter were discussed with respect to their effects on the critical liquid-carrying velocity and their interactions,and then ranked through grey relational analysis(GRA).The results show that the critical liquid-carrying velocity is negatively correlated with the pipeline operation pressure and down-slope angle,and positively correlated with the wellhead temperature,water volumetric fraction,up-slope angle and pipe diameter.It is found that the proposed model is practical and operable for predicting the critical liquid-carrying velocity for the undulating surface pipelines of the Yan'an gas field and provides theoretical support for the prediction and prevention of liquid accumulation.
Chemical engineering, Petroleum refining. Petroleum products
The geological characteristics and production practices of the major middle- and high-maturity shale oil exploration areas in China are analyzed. Combined with laboratory results, it is clear that three essential conditions, i.e. economic initial production, commercial cumulative oil production of single well, and large-scale recoverable reserves confirmed by the testing production, determine whether the continental shale oil can be put into large-scale commercial development. The quantity and quality of movable hydrocarbons are confirmed to be crucial to economic development of shale oil, and focuses in evaluation of shale oil enrichment area/interval. The evaluation indexes of movable hydrocarbon enrichment include: (1) the material basis for forming retained hydrocarbon, including TOC>2% (preferentially 3%–4%), and type I–II1 kerogens; (2) the mobility of retained hydrocarbon, which is closely related to the hydrocarbon composition and flow behaviors of light/heavy components, and can be evaluated from the perspectives of thermal maturity (Ro), gas-oil ratio (GOR), crude oil density, quality of hydrocarbon components, preservation conditions; and (3) the reservoir characteristics associated with the engineering reconstruction, including the main pore throat distribution zone, reservoir physical properties (including fractures), lamellation feature and diagenetic stage, etc. Accordingly, 13 evaluation indexes in three categories and their reference values are established. The evaluation indicates that the light shale oil zones in the Gulong Sag of Songliao Basin have the most favorable enrichment conditions of movable hydrocarbons, followed by light oil and black oil zones, containing 20.8×108 t light oil resources in reservoirs with Ro>1.2%, pressure coefficient greater than 1.4, effective porosity greater than 6%, crude oil density less than 0.82 g/cm3, and GOR>100 m3/m3. The shale oil in the Gulong Sag can be explored and developed separately by the categories (resource sweet spot, engineering sweet spot, and tight oil sweet spot) depending on shale oil flowability. The Gulong Sag is the most promising area to achieve large-scale breakthrough and production of continental shale oil in China.
The upper Paleozoic Marine shale in middle Guangxi Depression, namely Guizhong Depression, has experienced complex tectonic evolution and thermal evolution. As the main production layer of shale gas, the microscopic pore structure characterization and reservoir pore evaluation of the shale in lower Carboniferous need to be studied urgently. Focus on the Lower Carboniferous Luzhai Formation shale reservoir in the northern Guizhong Depression, the material composition and reservoir pores of the shale are characterized and evaluated in detail by rock thin section, scanning electron microscope, Xray diffraction, porosity and isothermal adsorption tests on samples both from fields and cores. The results show that the <i>TOC</i> in the shale of Luzhai Formation is 0.4 % ~ 6.6 %. The organic matter is in the stage of high mature to over-mature thermal evolution. The content of brittle minerals such as quartz is high, with a good fracturing ability. The shale in Luzhai Formation, with an average porosity of 2.91 % and an average permeability of 0.007 9 ×10<sup>-3</sup>μm<sup>2</sup>, is a kind of low porosity, ultra-low permeability and good breakthrough pressure shale gas reservoir. There are five types of pores in the shale reservoir: the residual intergranular pore, intergranular pore, intragranular dissolved pore, clay minerals interlayer pore and organic pore. The main contributors are the clay minerals interlayer pores, the organic pores and the pyrite intergranular pores. The aperture rangs from 17 nm to 65 nm, most of which are microporous or mesoporous with the scale less than 50 nm. The connectivity between the pores is poor and there is a certain connectivity inside the pores.
Petroleum refining. Petroleum products, Gas industry
Several international oil companies had conducted petroleum exploration, but failed to make any commercially viable discoveries in the Doseo Basin for over 30 years. In this article, an integrated analysis, based on the latest seismic and drilling data combined with exploration practice and tectonic, sedimentary as well as petroleum-geological characteristics of the basin, has been conducted with the aim to disclose the key factors of hydrocarbon accumulation and enrichment and then to find the potential petroleum plays. The Doseo Basin in Chad is a Meso-Cenozoic lacustrine rift basin developed on the Precambrian crystalline basement in the Central African Shear Zone. It is a half graben rift controlled by the strike-slip fault at the northern boundary, and can be divided into two sub-basins, an uplift and a slope. The basin experienced two rifting periods in the Cretaceous and was strongly inverted with the erosion thickness of 800–1000 m during the Eocene, and then entered the depression and extinction period. Structurally, a large number of normal faults and strike-slip faults are identified in the basin, and the boundary faults are inverted faults with normal at first. The main structural styles include inverted anticlines, fault noses, complex fault-blocks and flower structures. The Lower Cretaceous is the main sedimentary strata, which are divided into the Mangara Group, Kedeni, Doba and Koumra Formations from bottom to up. Two transgressive-regressive cycles developed in the Lower Cretaceous indicates with mainly lacustrine, fluvial, delta, braided-delta, fan-delta sandstone and mudstone. The effective source rock in the basin is the deep-lacustrine mudstone of the Lower Cretaceous containing the type I and type II1 organic matters. Furthermore, Inverted anticlines and fault-complicated blocks comprise the main trap types and the Kedeni Uplift is the most favorable play, followed by the Northern Steep Slope and Southern Gentle Slope. Lateral sealing capacity of faults controls the hydrocarbon abundance.
Abstract Understanding the formation damage surrounding the well during the drilling operation is the key to predict damage degree and protect the formation in oil/gas reserviors. Based on the core drainage results, we obtained an empirical relationship between the invasion volume of drilling fluid and permeability reduction of formation. Furthermore, the equation is incorporated into a commercial reservior numerical simulation simulator to characterize the behaviors of drilling fluid invasion process. The results show that, although the invasion depth in low permeability reservoirs is short with the range of 1.7–2.5 m, the effect on recovery factor is significant due to the narrow seepage area in the near fracture region. When considering the formation damage, the pressure in the near-fracture damage region drops sharply, leading to a three-stage shape in pressure distribution curve. In addition, we found that high viscosity and low density oil-based slurry and shorter soaking period are conducive to decrease the formation damage during drilling operation. This work reveals the fundamental mechanisms of formation damage in low permeability reservoirs, which is a theoretical basis in formulation drilling fluids and optimization operation parameters.
Drilling through active shale formations has been a challenging practice in the oil and gas industry for a long period of time, given the complexity of shale structure and its interaction with Water Based Muds (WBMs). Although there have been many additives and methodologies proposed for a safe drilling through shale formations using WBMs, little success has been reported to the application of these methods once tested under different field conditions. In this paper, a new WBM formulated by nanomaterials was proposed to stabilize active shale layers during drilling. A series of rheological, density, filtration loss, bentonite dispersion and shale recovery tests were conducted on the mud samples formulated by nanosilica and Nano Glass Flakes (NGFs). The results indicated that NGF, as a cheap but effective nanomaterial, is able to significantly reduce the flirtation loss without posing any significant impacts on the density and the rheology of WBMs. It also appeared that the bentonite molecules were incapable to either hydrate or disperse in the drilling fluid system in the presence of NGFs. It seems that NGFs can stabilize clay minerals and reduce the filtration loss as remarkably efficient additive, but caution must be taken to ensure that they are properly disperse in the WBMs.
Petroleum refining. Petroleum products, Engineering geology. Rock mechanics. Soil mechanics. Underground construction
Abstract Sand production is a problem that affects hydrocarbon production from unconsolidated sandstone reservoirs. Several factors, such as the strength of the reservoir, its lithification and cementation and reduction in pore pressure, may cause sand to be separated from the rock and transported by hydrocarbons to the well. Producing sand commonly causes erosion and corrosion of downhole and surface equipment, leading to production interruptions and sometimes forces operators to shut-in wells. Several different methods of sand control are available to reduce the impact of sand production. The reviewed papers suggest that the most suitable methods for unconsolidated sandstone reservoirs are stand-alone screens and gravel packs. Because of the cost and complexity of gravel packs, stand-alone screens are usually the first choice. These screens have different geometries, and selection of the most suitable screen depends on the particle size distribution of the grains in the formation and other reservoir and production parameters. A screen retention test, run in a laboratory with screen samples and typical sands, is often used to ensure that the screen is suitable for the reservoir. This paper reviews the main causes of sand production, the properties of unconsolidated sandstones that predispose reservoirs to sand production problems and the selection criteria for the most suitable mitigation method. The process of selecting a screen using experimental screen retention tests is reviewed, and the limitations of these tests are also discussed. Some numerical simulations of experimental tests are also reviewed, since this represents a very cost-effective alternative to laboratory experiments.
Abstract Stavropol Region is one of the oldest petroleum provinces on South of Russian Federation. Today, most of its fields are depleted and prospects for the discovery of new large hydrocarbon deposits considered exhausted. However, our studies allow us to talk about the possibility of the existence of previously undiscovered oil reservoirs, clamped in the source rocks associated with North-Stavropol tectonic element. In the middle of the last century, similar deposits have been identified within Prikumsk-Tyulenevskiy (Praskoveyskoe, Achikulakskoye, Ozek-Suat and a number of other fields) and Chernolesskiy (Zhuravskoye, Vorobyevskoye) tectonic elements. However, these findings were largely spontaneous due to lack of approved and unified approach to the petrophysical evaluation of dedicated reservoirs from well logs. At the same time the experience of shale reservoirs studies, as well as the results of its implementation to evaluation of deposits of Zhuravsky-Vorobyevsky petroleum accumulation zone, allows to revise existing well log materials for deep wells of explorational and depleted structures, and to identify promising intervals for further re-exploration and testing. In this work, Paleocene sediments of Blagodarnenskaya explorational structure of the Stavropol Region were studied. Despite the approval of the oil bearing of these deposits within the Prikumsk-Tyulenevskiy tectonic element and the positive signs of hydrocarbon saturation from initial well logs data, its evaluation and testing within Blagodarnenskaya structure associated with North-Stavropol tectonic element, were not conducted. However, the results of well logs analysis performed by us with the use of interpretation technique approved on reservoirs of Zhuravsky-Vorobyevsky petroleum accumulation zone, as well as the core tests indicate the presence of oil-saturated reservoirs in the Paleocene sediments of Blagodarnenskaya structure.
Nigeria is generally referred to as an ‘oil economy’ because of the country’s large amount of oil reserves Yet, the petroleum sector in Nigeria currently contributes less than 10 percent of the country’s gross domestic product (GDP). In comparison, some Gulf states petroleum sector’s GDP contribution is usually more than 30 percent. A fundamental reappraisal of the Nigeria’s petroleum sector’s relationship with the economy is required. This paper posits that the missing link between the petroleum sector and Nigeria’s GDP growth is the country’s petroleum refining capacity. Capacity utilization of Nigeria’s refineries dropped to 14 percent in 2014 against a global average refining capacity utilization of 90 percent. The constraints of crude oil supply to Nigeria’s refineries are revealed as well as policy interventions by the Federal Government of Nigeria aimed to increase in-country oil refining capacity. Refining capacity is suggested as an antidote to Nigeria’s so-called ‘resource curse’.
A thermal simulation experiment of diagenesis, hydrocarbon generation and evolution of the organic matter-rich shale was carried out to investigate formation and evolution of organic pores under the constraint from immature, low mature, mature, high mature to overmature geological conditions. The argon ion polishing–field emission scanning electron microscope was used to analyze microscopic features of original samples and simulated samples of various evolution stages. Results showed organic pores could be formed during hydrocarbon generation from biochemical and hypothermal processes in the immature and low mature stages, and the shale shallow-buried depth might be favorable for preservation of organic pores; the generation and evolution of organic pores were of heterogeneity, and the maturity was not a decisive factor which controlled formation and development of organic pores, while the difference in physiochemical structure of organic matter played an important role in formation and evolution of organic pores; the organic pore development was obviously related with the retained oil, and the organic pores formed in the oil generation stage were easily filled by pyrolysis asphalt; organic contraction fractures/organic marginal pores might be important storage spaces for shale gas occurrence, and their development was mainly controlled by the physiochemical structure and evolution degree of organic matters when the chemical adsorbed organic matter was converted into the physical adsorbed organic matter and the free organic matter. Keywords: Thermal simulation experiment, Organic pores, Thermal evolution stage, Heterogeneity, Plane porosity, Retained oil, Shale
Oils, fats, and waxes, Petroleum refining. Petroleum products
The finite element calculation of the lower gear box has been carried out by using the APDL parameterized language, so as to check the strength and stiffness of the lower gear box under the specified design conditions. On this basis, the side and the bottom wall thickness effects on the stiffness of lower gear box structure have been studied. The results show that the maximum stress at the hinge pin of the lifting ring of the lower gear box is 628 MPa, and the 35CrMo material can meet the safety requirements of structure strength design. Under the vertical load, the normal deformation is the main deformation, and the maximum deformation locates at the contact surface of lower gear box and the loading bearing flange, which meets the safety requirements of the design of the lower gear box structure under the perspective of every stiffness parameters. The side and bottom wall thickness could influence the structure strength and stiffness of the lower gear box. The optimal structural parameters could be attained by optimizing the correspondence relation of the variables and the state variables. The study results could provide numerical bases for the optimum design of the lower gear box structure.
Chemical engineering, Petroleum refining. Petroleum products