Hasil untuk "Petroleum refining. Petroleum products"

Wang Bing, Zhu Benwen, Wei Shuanghui et al.

To address the issues of low automation level， harsh working environment and high labor intensity of current offshore modular drilling rigs， an automated drilling rig system suitable for offshore fixed platform was newly developed. The drilling rig system is equipped with key drilling equipment such as dual driller ring network integrated control system， automatic horizontal catwalk， composite monkey board pipe racker， full hydraulic rotary table and five-cylinder mud pump for the first time on domestic platform， achieving automated transportation of pipes to/from drill floor， basic unmanned operation in drill floor wellhead and monkey board areas， and comfortable centralized operation in mud pump room and driller room. Field application results show that the supporting automation equipment effectively meets field operation requirements， significantly improving the working environment of personnel and greatly reducing labor intensity. The supporting dual driller integrated control system enables unified centralized management of drilling rig parameters and control， ensuring convenient and safe operation. The supporting five-cylinder drill pump achieves optimal operational performance while offering lighter total weight and more spacious field operation conditions， embodying a man-oriented operation and maintenance concept. The successful development and application of the drilling rig system provide reference basis and technical approaches for building new offshore modular drilling rigs and automation upgrading of aging platforms in the future.

CHEN Jun, WANG Haimei, CHEN Xi, TANG Yong, TANG Liangrui, SI Rong, WANG Huijun, HUANG Xianzhu, LENG Bing

To address the challenges of rapid production decline and low recovery of shale oil wells, it is imperative to supplement formation energy and explore innovative development methods. Compared with conventional waterflooding, CO2 exhibits superior injectivity and miscibility with crude oil, making it an effective oil displacement medium. Simultaneously, CO2 is a major greenhouse gas and a key target for emission reduction. Therefore, exploring CO2 huff-n-puff in shale oil reservoirs for enhanced oil recovery while simultaneously achieving carbon sequestration has significant practical value. However, Carbon Capture, Utilization and Storage (CCUS) technology in shale oil is still in its exploratory stage, facing challenges such as immature numerical simulation techniques and the lack of large-scale injection-production operations. To investigate the mechanisms and key controlling factors of enhanced oil recovery through CO₂ injection in shale oil, this study employed numerical simulation techniques, integrating logging data, geological parameters, and fracturing operation data to model the formation and distribution of hydraulic fractures. A composite discrete fracture network numerical model combining both artificial and natural fractures was established to analyze the oil recovery enhancement mechanisms of CO2 huff-n-puff. The study clarified the influence patterns of reservoir engineering parameters in CO₂ huff-n-puff on both cumulative oil increment and CO₂ storage capacity, and determined the primary controlling factors among these parameters. The results showed that CO2 huff-n-puff restored production capacity in shale oil wells by replenishing formation energy, extracting light and intermediate components from shale oil, and leveraging CO2 diffusion, oil viscosity reduction, and expansion effects. Considering both oil recovery and storage, the optimal injection strategy for a single well included: initiating when daily oil production declined to just above 8 m3, injecting 15 000-24 000 tons of CO₂ at a rate of 500-900 t/d, shut-in duration of 30-50 days, and conducting 2-3 huff-n-puff cycles. Among the shale oil reservoir engineering parameters, injection volume was identified as the primary factor, with a weight of 0.48. These findings provide technical guidance and evaluation support for the implementation of CCUS technology in shale oil reservoirs.

Daukaev A.A.

The article is devoted to the problem of searching for complexly constructed oil and gas traps on the territory of the Chechen Republic. The prospects for identifying complexly screened traps in the Lower Maikop, Cretaceous and Upper Jurassic strata are assessed. The characteristic complex features of Upper Cretaceous strata are described. The south-eastern part of the Chechen Republic, the edge zones of the Advanced Ranges and the Zaterechnaya Plain were identified as promising areas for identifying hydrocarbon accumulations associated with various types of complexly screened traps. The main tasks and recommendations for carrying out exploration activity to increase the resource base of hydrocarbons are listed.

Chistyakova N.F., Dravante V.V., Sivtsev A.I.

Analysis of the established maps of reservoir pressure activity in V5 and B1 productive levels to determine their piezomaxima and piezominima in the reservoir area, to substantiate the mechanism for the formation of anomalous reservoir pressures, the foci of the occurrence of water-hydrocarbon fluids of the catagenesis zone and to determine the sources of hydrocarbon in the Vendian - Lower Cambrian strata of the Midlle Botuoba oil-gas-condensate field.

Ali Amraeiniya, Soroush Shojaei, Amir Ali Mohseni et al.

The purpose of this research is to look into the augmentation of silica nanoparticles (NPs) with low salinity (LowSal) brine for EOR. A series of analyses, including oil/water interfacial tension (IFT) and rock wettability tests were undertaken to determine an optimal dispersion to flood into a porous carbonate core with a defined pore size distribution. At 60°C and 14.5 psi, the maximum drop (i.e., roughly 12.5 mN/m) in oil/water IFT by 0.3 wt% brine occurred, but when 0.08 wt% silica was added to the brine, the IFT reduced to 14.51 mN/m at 60°C and 14.5 psi. The wettability analysis revealed a significant reduction in contact angle, from 142° to 72° and 59°, using 0.04 and 0.08 wt% silica in LowSal brine, but the extent reduced by brine alone was insufficient. The results of rock pore size characterization were discussed in terms of the accomplishment of operating EOR in the porous medium in the presence of NPs. The addition of 0.08 wt% silica to the injected brine resulted in an additional oil recovery of 16.3% OOIP as well as a significant shift in the endpoints/cross-points of the oil/water relative permeability curves. The findings of this research might help improve oil recovery from asphaltenic oil reservoirs or, more environmentally friendly, remediate petroleum crude-oil polluted soil.

Bogdanov A.N., Khmyrov P.V., Abduraimov M.Kh. et al.

The article briefly outlines the results of exploration activity for oil and gas within the Ustyurt region of the Republic of Uzbekistan. Information is presented on the history of discoveries and development of fields in the Ustyurt region for the entire period of geological exploration activity for oil and gas, information on annual production, growth of hydrocarbon reserves and cumulative production for the entire period of development. The authors divided the entire period of geological exploration into 3 stages, in each of which the initial reserves and cumulative production are distributed over stratigraphic sections. The article attempts to justify such a division based on the analysis and generalization of the state of the hydrocarbon resource base, the degree of its exploration and development. As a result of summarizing the initial geological and geophysical information on individual accumulations of hydrocarbon, the authors performed a brief analysis of exploration activity and made proposals on the prospects for further increasing their resource potential with subsequent development, requiring the involvement of modern methods in the process. It is concluded that in the Ustyurt region, in which in recent years, thanks to the initiatives of the heads of state, large-scale exploration activity has been launched, which allowed increasing hydrocarbon reserves almost annually, due to the discovery of new accumulations and exploration of previously identified sites, which was the basis for the development petroleum industry of the country.

SANG Linxiang, LYU Bailin, LU Yingbo et al.

In the later stage of heavy oil reservoir development by steam injection,the steam channeling is serious and the development effect gets worse year by year.So it is urgent to apply relevant technologies to improve steam flooding performance.According to the characteristics of the heavy oil reservoir in Z32 Qigu Formation in Fengcheng Oilfield,the feasibility of steam flooding assisted by CO₂ injection to improve the development effect has been studied.In the process of steam injection in heavy oil reservoir,the injection of CO₂,N₂ or flue gas can make crude oil swell,increase formation elastic energy,reduce viscosity of crude oil and improve oil flow capacity of crude.The swell and viscosity reduction effects of different types of injected gas on heavy oil have been measured by high temperature and high pressure crude oil sampler and core flow experiment device.The volume expansion of crude oil is about 10 %～40 %,2 %～10 % and 4 %～16 % by injecting CO₂,N₂ and simulated flue gas respectively,the viscosity is reduced by 27.3 %～82.9 %,4.3 %～18.5 % and 10.2 %～45.8 %,respectively,and the oil recovery is enhanced by 5.83 %,3.08 % and 3.75 %,respectively.Therefore,CO₂ is recommended as the injection medium.Field application shows that after the new technology is implemented,the daily oil production of the well group increases from 26.6 t to 36.2 t,the oil steam ratio increases from 0.174 to 0.206,and the total oil production increases by 1 158 t.Remarkable economic benefits are obtained,which provides references for the scale application of this new technology.

Chengpeng SU, Rong LI, Guoshan SHI et al.

Based on a large number of field outcrops and cores taken systematically from boreholes, by microscopic observation, physical property analysis, mineralogy analysis, geochemical analysis etc., reservoir characteristics of the first member of Middle Permian Maokou Formation in Sichuan Basin (“Mao 1 Member” for short) are analyzed. (1) Rhythmic limestone-marl reservoirs of this member mostly exist in marl layers are a set of tight carbonate fracture-pore type reservoir with low porosity and low permeability, with multiple types of storage space, mainly secondary dissolution pores and fissures of clay minerals. (2) The clay minerals are mainly diagenetic clay minerals, such as sepiolite, talc and their intermediate products, aliettite, with hardly terrigenous clay minerals, and the reservoir in different regions have significant differences in the types of clay minerals. (3) The formation of high quality tight carbonate reservoir with limestone-marl interbeds is related to the differential diagenesis in the early seawater burial stage and the exposure karstification in the early diagenetic stage. It is inferred through the study that the inner ramp of southwestern Sichuan Basin is more likely to have sweet spots with high production, while the outer ramp in eastern Sichuan Basin is more likely to have large scale contiguous reservoir with low production.

Nayem Ahmed, Md. Saiful Alam, M. A. Salam

Abstract Loss of drilling fluid commonly known as mud loss is considered as one of the critical issues during the drilling operation as it can cause severe formation damage. To minimize fluid loss, researchers introduced numerous additives but did not get the expected result. Recently, the use of nanoparticles (NPs) in drilling fluid gives a new hope to control the fluid loss. A basic KCl–Glycol–PHPA polymer-based mud is made, and six different concentrations of 0.1, 0.5, 1.0, 1.5, 2.0, 3.0 wt% iron (III) oxide or Hematite (Fe2O3) NPs are mixed with the basic mud. The experimental observations reveal that fluid loss of basic mud is 5.9 ml after 30 min and prepared nano-based drilling mud results in a less fluid loss at all concentrations. Nanoparticles with a concentration of 0.5 wt% result in a 5.1 ml fluid loss at the API LTLP filter press test. On the other hand, nanoparticles with a concentration of 3.0 wt% enhance the plastic viscosity, yield point, and 10 s gel strength by 15.0, 3.0, and 12.5%, respectively. The optimum concentration of hematite NPs is found to be 0.5 wt% which reduces the API LPLT filtrate volume and filter cake thickness by 13.6 and 40%, respectively, as well as an improvement of plastic viscosity by 10%.

TAN Tao, GUO Chen, CHEN Yong et al.

Carbonate fractured-vuggy reservoirs in Tahe oilfield have complex geological characteristics, which is mainly reflected in the various forms such as pore, fracture and cave developed in the reservoir, poor continuity of spatial distribution, complex combination mode, and the residual fracture-vuggy storage space formed in surface karst system by weathering. During the development, it is easy to form the bottom water coning along the high angle crack. The remaining oil between the wells outside the water channels and the “attic oil” stored by the residual fault are enriched in large quantities. In the earlier stage, the macroscopic mechanism of gravity displacement by using density difference in N₂ injection of seam-hole reservoir is clarified by means of physical simulation. However, the displacement mechanism of the “attic oil” and the residual oil between wells is not clear. Through the simulation experiments of the effects of the injected N₂ on the physical properties of crude oil under the conditions of 55 MPa and 130 ℃, the micro mechanism such as the effects of N₂ on dissolution, expansion, capacity increase, extraction and dissolution of crude oil under the condition of high temperature and high pressure reservoir. Based on the fractured-vuggy geological characterization, visual physical model is made to observe the displacement mechanism of gravity displacement and water coning suppression during N₂ injection. After field application, the feasibility and popularization potential of the technology are further proved.

Mohamed Ragab Shalaby, Muhammad Izzat Izzuddin bin Haji Irwan, Liyana Nadiah Osli et al.

Abstract This research aims to conduct source rock characterization on the Narimba Formation in the Bass Basin, Australia, which is made of mostly sandstone, shale and coal. The geochemical characteristics and depositional environments have been investigated through a variety of data such as rock–eval pyrolysis, TOC, organic petrography and biomarkers. Total organic carbon (TOC) values indicated good to excellent organic richness with values ranging from 1.1 to 79.2%. Kerogen typing of the examined samples from the Narimba Formation indicates that the formation contains organic matter capable of generating kerogen Type-III, Type-II-III and Type-II which is gas prone, oil–gas prone and oil prone, respectively. Pyrolysis maturity parameters (Tmax, PI), in combination with vitrinite reflectance and some biomarkers, all confirm that all samples are at early mature to mature and are in the oil and wet gas windows. The biomarkers data (the isoprenoids (Pr/Ph), CPI, isoprenoids/n-alkanes distribution (Pr/nC17 and Ph/nC18), in addition to the regular sterane biomarkers (C27, C28 and C29) are mainly used to evaluate the paleodepositional environment, maturity and biodegradation. It has been interpreted that the Narimba Formation was found to be deposited in non-marine (oxygen-rich) depositional environment with a dominance of terrestrial plant sources. All the analyzed samples show clear indication to be considered at the early mature to mature oil window with some indication of biodegradation.

付悦, 吕维平, 陈波 et al.

After workover of low-yield gas wells in Qinghai, the existing velocity string snubbing technology has such problems as requiring additional special hanger, the main valve failed, and the wellhead and operation process needing reconstruction. To address the problems, by means of the zero pressure condition of the workover wellhead, and referring to the mandrel-type velocity string hanging technology similar to the conventional tubing hanging technique, the locating sub hanging velocity string technology and its low cost supporting tool are developed. The technology has the features of good operation connection, less operation support, high controllability of operation risk, and quick production after operation. The application in 2 wells in the Dongping gas field verified the feasibility of the process and the reliability of the supporting tools. The technology was proved to be adaptable, and had a great performance in reducing the labor intensity, speeding up the operation and lowering the cost. This technology provides an ideal method for running velocity string after low-yield gas well workover.

Kalpajit Hazarika, Subrata Borgohain Gogoi

Abstract The effect of alkali on immiscible alkali–surfactant (AS) flooding is studied by injecting surfactant individually and surfactant along with alkali. First, reservoir core samples were characterized with the help of X-ray diffraction (XRD), scanning electron microscope (SEM) and thin slide analysis. Based on the clay content of the reservoir, surfactant was selected. Second, AS formulations were designed through dynamic interfacial tension (IFT) and wettability alteration analysis. Third, adsorption of surfactant on porous media was studied with or without alkali to find out the amount of surfactant adsorbed along with the isotherm mechanism. Fourth, core flooding experiments were conducted to find out the recovery efficiency after secondary brine flooding. XRD, SEM and thin slide analysis showed the presence of kaolinite, smectite, illite, silica, quartz in the rock sample. Based on the clay types, sodium dodecyl sulfate (SDS) was selected as surfactant for this study. Ultra-low dynamic IFT in the range of 10−3 was observed with SDS. Addition of alkali further reduced the IFT of the system. Initially, wettability of the reservoir under study was toward water wet, but during AS flooding it was altered to strongly water wet. Adsorption of surfactant on the porous media was reduced by the application of alkali. During secondary brine flooding, maximum recovery was found to be 49% of Initial Oil in Place. Another 14% of residual oil after secondary flooding was achieved by AS flooding.

Fengrui Sun, Yuedong Yao, Guozhen Li

Abstract Horizontal well has been widely used for heavy-oil recovery in the petroleum industry. Besides, superheated steam has been proved effective in heavy-oil recovery by field practice. In this paper, a numerical model is established with the help of numerical simulator. The effect of bottom water on the productivity of cyclic superheated steam stimulation well has been studied. Some interesting findings show that: (a) the bottom water-channeling phenomenon becomes more severe when the horizontal well is approaching the bottom water. (b) The cyclic oil production fluctuates with periodic number when the horizontal well is close to the bottom water due to the fact that the injected water has an elastic push action on the bottom water. (c) A larger-bottom water size is able to supply a larger elastic energy. While the cyclic oil production of large-bottom water size for the first few cycles is smaller than that with a small-bottom water, it may be turned over for the last few cycles.

Wenping Liu, Jun Liu, Molun Cai et al.

Through the field emission scanning electronic microscope (FESEM) and the nitrogen adsorption test, pore type and structure of shale reservoir in the Longmaxi Formation in the Sichuan Basin were well studied. Result showed that the pore type includes organic pore, intercrystalline pore, dissolution intracrystalline pore and interparticle pore, and the organic pore was one of major pore types; among the organic pore, the micropore had large pore volume and specific surface area, and was the main storage space of shale gas. Through study on effect of total organic carbon (TOC), organic matter maturity (Ro), diagenesis and tectonism on shale porosity, influence of TOC on porosity could be divided into four stages: the rapid increasing stage (TOC from 0 to 2%), the slow decreasing stage (TOC from 2 to 3%), the rapid increasing stage (TOC from 3 to 4% or 6%) and the rapid decreasing stage (TOC > 4% or 6%); influence of the maturity on porosity of shale could be divided into three stages: the rapid decreasing stage (Ro from 1.5 to 2.2%), the rapid increasing stage (Ro from 2.2 to 2.7%) and the rapid decreasing stage (Ro > 2.7%); during the high thermal evolution stage, the organic diagenesis was stronger than the inorganic diagenesis; the tectonism had a great impact on porosity, and the more intense the tectonism was, the smaller the porosity would be. The evolution of shale porosity of the Longmaxi Formation underwent five stages: the immature rapid compaction stage (Ro<0.7%), the mature hydrocarbon generation and dissolution stage (Ro from 0.7 to 1.3%), the high mature pore closed stage (Ro from 1.3 to 2.2%), the overmature secondary pyrolysis stage (Ro from 2.2 to 2.7%) and the overmature slow compaction stage (Ro>2.7%); among which the mature hydrocarbon generation and dissolution stage and the overmature secondary pyrolysis stage were the most favorable shale pore development stages. Keywords: Organic pore, Inorganic pore, TOC, Organic matter maturity, Shale, Longmaxi formation

Zuo Qichuan, Liu Hongliang, Lei Guangjin et al.

To simulate the deep water and high pressure working environment of drilling and production equipment, and to systematically test and study the pressure bearing performance, sealing performance, action performance, safety and reliability of underwater equipment, a deep water high pressure simulation test compartment has been developed.The test cabin, with integrated flange, integrates the water pressure, hydraulic, power, information, monitoring and testing, facilitating unified management, integrated control, while reducing the number of high-pressure cabin openings and improving reliability and operability.The compartment allows internal and external hydraulic pressure test and function (action) test of underwater equipment at the same time, and also allows monitoring, testing and data acquisition at the same time.The deep water high pressure simulation tests of different products have proved that the high pressure compartment could simulate the pressure environment of 0~3 500 m water depth, and could satisfy the test and detection of oil drilling equipment in deep water environment.The developed deep-water high-pressure simulation test compartment is a safe and reliable multi-functional and comprehensive test platform, which could provide support and evaluation for underwater equipment test and development.

Ghasem Khatinzadeh, Mohammad Mahdyarfar, Ali Mehdizadeh et al.

<span style="font-family: Calibri;"><span style="font-size: medium;">Membrane-based pervaporation (PV) has attracted much attention in the dehydration of organic solvents. Permeate pressure and feed flow rate are two important parameters, which affect membrane performance in pervaporation. The effects of these two parameters on the performance of a commercial poly (vinyl alcohol) membrane in the dehydration of benzene have been investigated in this work. The experiments have been carried out at a constant temperature of 60°C, and pressure and feed flow rate range from 1 to 20 mmHg and from 200 to 1200 ml/min respectively. The results indicate that variations in vacuum, especially in permeate pressures of less than 10 mmHg, greatly affect flux and selectivity so that </span><span style="font-size: medium;">water flux and separation factor increase from 0.98 to 2.63 (gr/hm²</span><span style="font-size: medium;">) and from 160 to 310 respectively by decreasing permeate pressure from 10 to 1 mmHg. Furthermore, increasing flow rate improves membrane performance only at rates of below 1000 ml/min, and no changes are observed at higher feed flow rates.</span></span>

贾宏禹, 周思柱, 孙文斌 et al.

Specific calculation formula about the conveying capacity of large angle spiral sand conveyor is still not found.Based on analyzing the law of material movement,a theoretical model based on single particle method is established to analyze the mechanical and movement law of the material in steady state.The critical speed of revolution of the spiral sand conveyor is attained.The theoretical formula of sand conveying capacity with the angle,the blade surface friction coefficient,the cylinder wall friction coefficient,filling volume and material density in the critical state is also given.Establishment of the function relationship between the parameters in actual and critical state on base of the test results is proposed and then analyzed and verified by a 45°spiral sand conveyor.The results show that the conveying capacity theoretical formula can be established for spiral sand conveyor with any angle using the proposed method.The study could provide basis for design and calculation of high efficiency and energy saving spiral sand conveyor.