Table of Content

10 August 2019, Volume 41 Issue 4

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SPECIALIST FORUM

EDFM-based Numerical Simulation of Horizontal Wells with Multi-stage Hydraulic Fracturing in Tight Reservoirs

ZHANG Liehui, LIU Sha, YONG Rui, LI Bo, ZHAO Yulong

2019, 41(4):  1-11.  DOI: 10.11885/j.issn.1674-5086.2018.11.21.05

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Fracture modeling for horizontal wells with multi-stage hydraulic fracturing (fracking) in tight reservoirs is extremely challenging, which means that evaluating the productivity of these wells is difficult. To address this problem, a threedimensional (3D) model of horizontal wells with multi-stage hydraulic fracturing in tight reservoirs, which accounts for the effects of gravity and stress sensitivity, was constructed using the embedded discrete fracture model (EDFM) with a rectangular grid. First, Saphir was used to examine the accuracy of this model. The numerical simulation of 3D tight reservoirs, tight naturally fractured reservoirs, and the effects of fracture distribution and morphology was then performed using this model. It was shown that EDFM produces an accurate depiction of fluid flow characteristics in both natural fractures and fracking-induced fracture networks. It was concluded that fracking should be performed in areas where natural fractures are well-developed. Moreover, it was found that well productivity is significantly affected by the distribution and morphology of fractures in a horizontal well with multi-stage fracking, where the greater the area of contact between the fracture network and matrix, the greater the well productivity. Therefore, one of the goals of massive hydraulic fracturing is to realize optimal fracture distribution.

GEOLOGY EXPLORATION

Preliminary Analysis on the Controls on Hydrocarbon Reserves by Transitional Facies Sedimentationin Saline Lacustrine Basins

XIA Zhiyuan, LI Senming, PANG Hao, LI Wenyan

2019, 41(4):  12-22.  DOI: 10.11885/j.issn.1674-5086.2018.05.04.01

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The sedimentary characteristics of transitional facies in saline lacustrine basins (delta fronts and shallow lake subfacies) differ significantly from those of freshwater lacustrine basins, especially with regard to the distribution of skeletal sand body microfacies. Research into the control mechanisms of sedimentation over hydrocarbon reserves leads to important developments of sedimentological theories regarding lacustrine basins and practical guidance for oil and gas exploration and exploitation in terrestrial basin clastic rocks in China. Core, logging and cast thin section data are used to analyze the major controlling factors of sedimentation in the delta front-shallow lake and high-quality reservoir formation of the Lower (N₂¹) and Upper (N₂²) Youshashan Formations in the Yingdong region of the Qaidam Basin. The results show that, there are primarily two types of reservoir microfacies for the delta front-shallow lake regions in the saline lacustrine basins, namely underwater distributary channels and beach sandbars. They are considerably different in terms of their sedimentary structures, particle size distributions, microscopic structures, and superposition of logging curves. Sedimentary microfacies provide the primary material for high-quality reservoir formation. Meanwhile, microfacies and salinization of water bodies in lacustrine basins jointly control the distribution of high-quality reservoirs. In general, saline lacustrine basin clastic rock reservoirs are relatively immature. Primary pores and relatively weak corrosion were observed, while secondary pores were less developed. Intensive carbonate cementation in the early diagenetic stages enhances the compression resistance of rocks. The reservoir properties are primarily determined by the particle sizes and cement content of rocks.

Fracture Characteristics of Ordovician Concealed Hills in the Anci Area and Their Significance in Petroleum Geology

XUE Hui, HAN Chunyuan, XIAO Boya, ZHAO Wenlong, LI Wenzhan

2019, 41(4):  23-32.  DOI: 10.11885/j.issn.1674-5086.2018.04.26.05

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To resolve issues such as high heterogeneity of reservoirs and significant yield discrepancies between wells of the Ordovician concealed hills in the Anci Area, information such as core, thin section, and logging data are used to analyze the types, development, and the effectiveness of fractures in the study area. It is concluded that there are three types of fractures in the site:structural fractures, corrosion fractures, and diagenetic fractures. Structural fractures are the most developed among the three and are mostly northeast-striking high-angle fractures. Lithology and faults control the degree of development of fractures. Thin and lithologically pure dolomite reservoirs adjacent to faults contain the most developed fractures. Aperture and degree of filling reflect the effectiveness of fractures. In the study area, the developed fractures are mostly partially filled or are unfilled, thus they are relatively effective. Drilling of multiple wells confirms that these fractures are significant in petroleum geology. They can improve the physical conditions of reservoirs and provide advantageous channels for oil and gas transfer, thus increasing yields from single-wells. Meanwhile, the formation periods and development positions of fractures control the transport and accumulation of oil and gas to form reservoirs. Fractures formed after the Neogene period are highly developed and effective. Fractures inside oil-gas reservoirs are in favour of oil and gas enrichment.

A Geological Modeling Method for Dual Porous Reservoirs in Granite Buried Hills

PAN Xiaoqing, SONG Laiming, NIU Tao, ZHANG Yuqing, GAO Yufei

2019, 41(4):  33-44.  DOI: 10.11885/j.issn.1674-5086.2018.04.28.01

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Fractured oil reservoirs in granite buried hills are influenced by tectonic motion, weathering, and corrosion. Since layers in these reservoirs are dual porous, geological modeling of these layers has been a difficult task but is also an important topic in the field. Hence, this work combines logging, seismic, core, and well testing data to thoroughly investigate the causes of fracturing. It is determined that faults and "gully ridge" landforms are the major factors that determine the fracture distribution in the region. Subsequently, the discrete fracture network (DFN) modeling technique was used to develop a geologic model for the fracture mechanism in the granite buried hills. Fracture distributions are created and used as a constraint to form a fracture network model for the granite buried hills. An equivalent fracture attribute model was obtained and its reliability was tested using information such as well logging and testing data. A geological method for the granite buried hills in the Bohai A Oilfield was constructed using this method. This model better characterizes the fracture distribution in the oil field and provides a foundation for formulating exploration plans.

The Genesis and Period of Authigenic Diagenetic Mineral in Triassic Yanchang Formation,the Southern Ordos Basin

YANG Chao, HE Yonghong, LEI Yuhong, PANG Fei, LI Xiaolu

2019, 41(4):  45-54.  DOI: 10.11885/j.issn.1674-5086.2018.05.18.02

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In order to understand the time and process of diagenetic mineral formation in the Triassic Yanchang Formation in the southern Ordos Basin, the occurrence of authigenic minerals and their alternative relationship with other types of minerals are examined. Furthermore, the liquid information of diagenetic minerals is recorded using fluid inclusion and the oxygen isotope data of carbonates. Based on these findings, the genesis and period of authigenic diagenetic minerals in the southern part of the Ordos Basin is discussed in detail. The study shows that mud-microcrystalline calcite, siderite, and dolomite (Xunyi Area) are diagenetic minerals precipitated at the early stages. Among these minerals, siderite is formed earlier than the authigenic chlorite coating, while the mud-microcrystalline calcite is formed at approximately the same time with siderite. The dolomite cement found in the Xunyi Area is formed at the same time with the mud-microcrystalline calcite and siderite found in the north source areas. The mid-late stage sparry calcite and ferroan calcite are both formed earlier than the dolomite and ferroan dolomite. The two generations associated with quartz secondary enlargement corresponds to 90.0~100.0℃ and 110.0~120.0℃, respectively. The growth period of authigenic microcrystalline quartz is slightly earlier than or the same as the formation time of authigenic chlorite. The authigenic chlorite coating is formed during early diagenesis, which often grows in two generations. The authigenic chlorite in the first generation is formed at 20.0~50.0℃ and mainly exists in the form of ring-edge occurrence of chlorite particles. The second generation authigenic chlorite, formed by compaction, is found to only grow on the particle surface in contact with the pore, or the surface of microcrystalline quartz crystals formed from the first-generation chlorite. The formation temperature of the second generation authigenic chlorite is around 50.0~70.0℃. The authigenic illite is found to be widely distributed in the Yanchang Formation in the research region. The authigenic illite is formed from multiple sources.

Multi-parameters Quantitative Evaluation for Carbonate Reservoir Based on Geological Genesis

CHEN Peiyuan, WANG Zhibo, GUO Lina, WANG Long, QI Mingming

2019, 41(4):  55-64.  DOI: 10.11885/j.issn.1674-5086.2018.04.25.02

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Carbonate reservoir in the study has various pore types, complex pore structure and strong heterogeneity, which cause obvious difference of single well productivity on the plane. Based on the analysis of capillary pressure curves, the reservoir can be divided into six flow zones by the flow zone index, and the high precision permeability interpretation model of each flow zone was established. Through the analysis of reservoir main controlling factors, selecting six parameters such as reservoir thickness, permeability heterogeneity coefficient, resistivity, porosity, shale content and paleogeomorphology, using the gray correlation analysis method to determine the weight of each evaluation parameter, and adopting the comprehensive evaluation index for quantitative classification of carbonate reservoir. The results show that the comprehensive evaluation result of single well is accordance with the actual productivity index. Further analysis shows that it is of high reliability by using the flow zone index method to interpret the permeability, adopting the gray correlation method to determine index weight, and applying the comprehensive evaluation index to evaluate the reservoir. This systematic method can be effective and efficient for guiding the reservoir research and well deployment, and providing a new thought for similar carbonate reservoir evaluation as well.

Mechanism of Dolomite Formation in Member Ma₅⁵ of Majiagou Formation,East of Sulige Gas Field

BAI Hui, FENG Min, HOU Kefeng, YANG Tebo, GUO Siwen

2019, 41(4):  65-73.  DOI: 10.11885/j.issn.1674-5086.2018.05.07.01

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It is a matter of some dispute on the genesis of dolomite in Member Ma₅⁵ of Majiagou Formation of Ordovician, east of Sulige Gas Field, Ordos Basin. Based on the study of Sedimentary background, the characteristics of lithology and geochemistry of dolomite in this area, it is indicated that the dolomite in Member Ma₅⁵ of Majiagou Formation of this area is dominated by intertidal-subtidal sediments. There are two main types of dolomite:penecon-temporaneous dolomite and buried dolomite, and the dolomitized fluid is seawater or relevant sea-source fluid, which were established two dolomitization models:penecontemporaneous dolomite and burial dolomite. The former is maidly dolomicrite and a minority of powder crystal dolomite, it is characterized by horizontally-laminated bed, gypsum mold and bird-eye texture, and it is always coexists with gypsum crystal, mainly idiomorphic crystal, the order degree of grains is bad. The trace element analysis indicates that the contents of sodium and strontium are higher, it shows that the sedimentary environment is a strong evaporation environment with shallow water, high salinity and dry climate, which belongs to penecon-temporaneous dolomite. Buried dolomite often keeps larger particles, mainly fine-grained and medium grained dolomite, subhedron, and intergranular pores are more developed, the order degree of grains is better. It is coexists with pyrite, and it shows agglomerate or uneven distribution, The trace element analysis indicates that the contents of iron and manganese are higher, and the values of δ¹⁸O_PDB display negative distribution. These evidences indicate that the dolomite is formed by buried reduction environment, is belongs to burial dolomite.

A Quantitative Evaluation of Fault Sealing of the TY Oilfield in the Weixinan Sag

WU Bibo, ZOU Mingsheng, LU Jiang, YAN Heng, ZENG Xiaoming

2019, 41(4):  74-80.  DOI: 10.11885/j.issn.1674-5086.2018.09.29.01

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Block 1 of the low uplifted TY Oilfield in the Weixinan Sag is within a fault trap of the Weizhou Formation and the F₂ fault at a higher position is the key factor in reservoir formation. This study assessed the mechanisms and influencing factors of fault sealing to comprehensively consider the mud content and compaction levels of rocks to establish the quantitative relationships between the driving pressure of rocks and their depth and mud content. Relationship equations were employed to calculate the driving pressure of the target reservoir layers and the fault rocks which serve as a blockage. The two values were compared in a quantitative evaluation of fault sealing. The proposed method was used to analyze the lateral sealing ability of the F₂ fault of Block 1 of the TY Oilfield in the Weixinan Sag. The results suggest that the driving pressure of the fault rocks connecting the two target layers H1 and H2 is greater than that of the reservoir layers; thus, the fault rocks are capable of sealing. Meanwhile, the faults rocks connecting H3 and H4 have a smaller driving pressure to that of the reservoir layers; thus, they cannot seal oil and gas.

Microscopic Formation Mechanism of Low Resistivity Oil Layers in the Wushi Sag of the Beibu Gulf Basin

YANG Yi, YUAN Wei, YANG Dong, TAN Wei, WU Jinbo

2019, 41(4):  81-89.  DOI: 10.11885/j.issn.1674-5086.2018.05.09.04

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The conglomerate sandstone oil reservoir from the Paleogene Liushagang Formation in the Wushi Sag of the Beibu Gulf Basin exhibits significant resistivity differences. High resistivity and low resistivity oil layers co-exist; they can be hardly distinguished based on their fluid properties, leading to difficulties in oil field exploitation. Thus, we conducted in-depth investigation of the formation mechanism of low resistivity oil layers using data from well logging, mud logging, well testing, and core analyses. The results show that mud intrusion, conductive minerals, and mineralization of formation water slightly influence resistivity, while irreducible water saturation is the major factor leading to the formation of oil layers with relatively low electrical resistivity. Based on this knowledge and detailed assessments of the microscopic pore structures, we found that the enrichment and accumulation of low resistivity oil layers results from a combination of primary intergranular pores and secondary mold pores. The development of planar and curved throats, large displacement pressures, small pore throat radii, and complex pore structures are the fundamental causes of irreducible water saturation in the reservoir layers.

OIL AND GAS ENGINEERING

A Study on the Characteristics of Deeply Buried Mud Shale and Drilling Fluid Techniques in Oil and Gas Fields of East China Sea

LUO Yong, ZHANG Haishan, WANG Jian, CAI Bin, WU Bin

2019, 41(4):  90-98.  DOI: 10.11885/j.issn.1674-5086.2018.09.14.01

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In view of the frequent occurrence of problems such as bit-bouncing, torque distortion, and tripping resistance caused by peeling and chipping during drilling operations across the Yuquan and Pinghu formations of the oil and gas fields of the East China Sea, the present study investigates the characteristics of mud shale and drilling fluid techniques in the oil and gas fields of the East China Sea. X-ray diffraction, physical and chemical property tests, scanning electron microscopy, and high-pressure mercury injection were adopted to analyze the mechanisms of borehole destabilization in the mud shales of the East China Sea area. Based on these analyses, nano/micro pore sealing and balanced activity drilling fluid techniques were proposed to resolve the aforementioned issues. On this basis, a set of offshore reverse-osmosis-based drilling fluid techniques suitable for stabilizing deep mud shale borehole walls in oil and gas fields were developed for the East China Sea. Laboratory evaluations and field applications of these techniques were performed, and it was observed that compared with a neighboring well, the reaming time of the experimental well of size 12(1/4)" decreased from 137.75 h to 39.50 h and the circulation time decreased from 56.75 h to 35.75 h, resulting in time savings of close to 5 d for reaming and circulation for a single well.

Analysis Method for the Production Data of Water Drive Gas Reservoirs and Its Application

ZHENG Yongjian, DUAN Yonggang, WEI Mingqiang

2019, 41(4):  99-106.  DOI: 10.11885/j.issn.1674-5086.2018.12.11.01

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Conventional production data analysis techniques are primarily applied to closed gas reservoirs having constant volume, but are not applicable to water drive gas reservoirs. Based on the unstable seepage theory, a seepage model for water drive gas reservoirs was established considering the water encroachment characteristics of gas reservoirs. Subsequently, the response solution of the unstable production of water drive gas reservoirs was derived using Laplace transform, and the typical curves of modern production-decline analysis were computed and plotted. From the results, four typical flow stages were categorized according to the characteristics of the curves. In addition, the effects of dimensionless water encroachment influx and time on a typical production-decline curve were discussed. Combined with modern production data analysis technology, a quantification method exploiting the relationship between the production and the pressure of gas wells was proposed for the quantitative evaluation of the intensity and starting time of water encroachment, as well as calculation of the dynamic reserve, permeability and other parameters of the gas reservoir. The results of the field production data analysis showed that this method was able to meet the engineering requirements of the dynamic analysis for water drive gas reservoir.

Experimental Study on Physical Simulation of In-situ Combustion in Offshore Heavy Oilfields

ZHENG Wei, ZHU Guojin, TAN Xianhong, LIU Xinguang, WANG Lei

2019, 41(4):  107-112.  DOI: 10.11885/j.issn.1674-5086.2018.06.15.01

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This study has conducted a physical simulation experiment on the in-situ combustion of offshore heavy oil in the Bohai heavy oil reservoir region to explore the possibility of further development of the in-situ combustion. It has analyzed the composition of crude oil in the Bohai heavy oil region using the method employed for determining the components of asphalt and crude oil. The kinetic parameters of high-temperature oxidation reactions, such as the activation energy, were evaluated using the thermogravimetric analysis and scanning thermal analyzer. This work has used a one-dimensional combustion tube for the simulation experiment to evaluate the combustion stability and oil displacement efficiency. The results demonstrate that the composition of crude oil in the Bohai heavy oil region is similar to that of the onshore oil fields in mainland China. The high-temperature oxidation activation energy of heavy oil is 157 kJ/mol, which is similar to that of the onshore oil fields; the burning front moves forwards steadily, and the highest temperature of the combustion front is estimated at approximately 773 K. The concentration of CO₂ at the outlet is estimated over 12%, and the high-temperature oxidation combustion is observed to be good. The oil displacement efficiency is estimated at 95.1%, and the air-oil ratio is 548 m³/t, It is established that the oil displacement efficiency is fairly satisfactory.

Technical Approach for Improving the Field Application Result of ASP Flooding

LI Yongtai, KONG Bailing

2019, 41(4):  113-119.  DOI: 10.11885/j.issn.1674-5086.2018.04.22.01

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The IV5~IV11 of Shuanghe Oilfield exhibit a temperature of 81℃, crude oil viscosity of 3.3 mPa·s, comprehensive water cut of 97.9%, and recovery rate of 53.3%, all of which manifest as typical characteristics of inefficient exploitation of aged oilfields by water flooding in eastern China. To improve the exploitation efficiency of the above-mentioned gas reservoirs and significantly increase their recovery rates, three key technologies were applied in conjunction, namely, the alkaline-surfactantpolymer(ASP) flooding with high displacement efficiency, well pattern arrangement for layer reconstruction with expanded swept volume, and profile control throughout the chemical flooding process with channeling prevention. Laboratory experiments and field applications showed that the integration of these three technologies introduced multiple synergetic effects, as the oil displacement efficiency was substantially increased in addition to the expanded swept volume, resulting in an increase in oil production and a decrease in water cut. As of December 2017, a 0.72 PV chemical system was injected into the IV5~IV11 layer. Consequently, oil production increased by 26.09×10⁴ t, peak water cut at the central area dropped from 97.9% to 90.2%, and daily oil production rose from 23.0 t to 106.1 t. Furthermore, while the recovery rate was increased by 10.2% at this stage, it is expected to finally increase by 14.2%.

Study on Influence of High CO₂ Content on Gas Deviation Factor of Natural Gas

LEI Xiao, DAI Jincheng, CHEN Jian, HAN Xin, LU Ruibin

2019, 41(4):  120-126.  DOI: 10.11885/j.issn.1674-5086.2018.06.20.01

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The gas deviation factor of natural gas is the basis for the calculation of the physical parameters and geological reserves of natural gas. It is affected by temperature and pressure and is also a function of natural gas composition and its components. At present, a high-precision calculation method of gas deviation factor suitable for natural gas with low CO₂ content already exists. However, its calculation precision is not guaranteed when applied to the calculation of gas deviation factor for natural gas with high CO₂ content, typically found in DF Gas Field. Targeting this problem, the influence of CO₂ content on the gas deviation factor of natural gas was analyzed using the PVT experimental method. Based on the experimental results, the empirical formula of the DAK method for calculating the gas deviation factor of natural gas was modified using the Levenberg-Marquardt algorithm and the general global optimization method. The results show that, similar to the effects of heavy hydrocarbons (ethane and propane), the presence of CO₂ significantly reduces the gas deviation factor of natural gas, and the magnitude of this influence gradually increases as CO₂ content increases. When CO₂ content is low, the DAK empirical formula can calculate the gas deviation factor of natural gas relatively accurately, whereas if CO₂ content becomes larger than 50%, the corrected DAK empirical formula can lead to satisfactory results.

Design and Principle Simulation Analysis of a Flow Control Device

ZHAO Xu

2019, 41(4):  127-134.  DOI: 10.11885/j.issn.1674-5086.2018.09.05.01

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Considering the problem of the early encounter of water in the production of horizontal wells with long horizontal segments, which reduces production efficiency in advance and low water control efficiency with regard to traditional flow control devices, research was carried out on the structural design of a new type of flow control device. A numerical simulation was used to analyze the internal flow trends inside the device, and the principle behind relevant design parameters of water control capability was studied. The internal structure of the flow control device was optimized, and the channels inside the flow restrictor for water and oil phases were changed, to use the different flow conditions of water and oil (owing to their different viscosities) to achieve oil/water control. The research indicates that the directions and quantity of the flow channel openings greatly influence the control capability of the water control device. The shape of the flow channels was optimized, such that it is possible to enhance the control capability of the inflow control device by changing the incident velocity and angle of the control chamber. The research results provide a new reference for designing a new type of adaptive water control device, which can be promoted and applied further.

Study of the Patterns of Well Casing Corrosion by the CO₂ Huff-and-puff Process and the Maximum Number of Huff-and-puff Cycles

ZHANG Zhi, SONG Chuang, DOU Xuefeng, YANG Kun, DING Jian

2019, 41(4):  135-143.  DOI: 10.11885/j.issn.1674-5086.2018.07.17.04

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In certain mature oilfields that have entered the late high water cut stage, the CO₂ huff-and-puff process can be implemented as a supplementary measure during waterflooding for enhanced oil recovery. This process has led to an increased CO₂ content in the produced water, which can cause severe corrosion in wellbore columns. Thus, the strength of wellbore and casing columns is reduced, leading to pitting corrosion or even column fractures. Therefore, based on the thermodynamic and kinetic principles of electrochemical corrosion and relevant theories of column mechanics, and considering the influences of temperature, pressure, water cut, CO₂ partial pressure, flow rate, deflection angle, and pH based on actual operating conditions at the site, a corrosion prediction model was used to calculate the corrosion rates of a CO₂ huff-and-puff well at different stages of the huff-and-puff process. Methods for calculation of the post-corrosion residual strength and the maximum number of huffand-puff cycles were established. A large number of simulation calculations were performed to predict the casing corrosion patterns and residual wall thickness of the huff-and-puff well under gas injection, soaking, pressure release, and production conditions, as well as the maximum number of huff-and-puff cycles for the well.

An Experimental Study on the Flow Patterns of Oil-water Two-phase Flow in an Upwardly Inclined Pipe

ZHU Shanshan, MOU Xingjie, LI Wang, SONG Xiaoqin, GU Li

2019, 41(4):  144-151.  DOI: 10.11885/j.issn.1674-5086.2018.05.30.01

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During the commissioning and operation of a large number of refined oil pipelines in China, it was found that water accumulation at low points in upwardly inclined pipelines caused by the adoption of water circulation for commissioning resulted in serious corrosion problems within these pipelines. Inflows of oil from the upstream sections can be used to carry away the water from the low points and effectively alleviate internal corrosion. In the present study, 0# diesel fuel and deionized water were used to observe oil-water two-phase flow patterns in an upwardly inclined pipeline with an internal diameter of 100 mm and the measurement of the critical water-carrying velocity of oil. The results show that as the oil viscosity and upward inclination angle of the pipeline increases, three types of flow patterns are sequentially induced in the oil-water two-phase flow, namely, stratified wavy flow, stratified wavy flow with water droplets, and oil-dominated dispersed flow. Within the same flow pattern, the minimum critical velocity for the oil phase to carry the water phase into the upwardly inclined section increases with an increase in inclination angle. When the inclination angle increases from 20° to 25°, the flow pattern transitions from stratified wavy flow to stratified wavy flow with liquid droplets, and the minimum critical velocity for the oil phase to carry the water phase into the upwardly inclined section decreases from 0.203 m/s to 0.187 m/s. When the upward inclination angle increases from 30° to 35°, the initial flow pattern transitions from stratified wavy flow with liquid droplets to water-in-oil dispersed flow, and the minimum critical velocity for the oil phase to carry the water phase into the upwardly inclined section decreases from 0.205 m/s to 0.194 m/s. An increase in the inclination angle causes a slight increase in the minimum critical velocity for the oil phase to fully carry the water phase away from the upwardly inclined section, while causing a reduction in the velocity at which flow pattern transitions occur.

An Experimental Study on Hydrate Formation and Blockage in a Pure Water System

LI Le, ZHU Qianyi, CHEN Xiaokang

2019, 41(4):  152-158.  DOI: 10.11885/j.issn.1674-5086.2018.09.15.01

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To ensure the safety of hydrate slurry flow in pipelines, an experiment on CO₂ hydrate synthesis and blockage was performed to investigate the morphological changes to CO₂ hydrates from the point of synthesis to pipeline blockage in a pure water system as well as the influences of system pressure and pump speed on the flow patterns of the hydrate slurry. The experimental results of this study are as follows:(1) In a pure water system, hydrates exist in the form of slurries or slush within pipelines, and the time interval between CO₂ hydrate synthesis and pipeline blockage is relatively short. (2) The critical pump speed during the experiment is 35 Hz. When the pump speed exceeds 35 Hz, the hydrates do not result in blockage during pipeline transportation; when the pump speed is below 35 Hz, an increase in pump speed delays the occurrence of hydrate blockage under conditions of identical system pressure. (3) Under conditions of identical pump speed, an increase in system pressure shortens the time interval between hydrate synthesis and blockage. At system pressures of 3.4 MPa and 2.4 MPa, hydrate blockages respectively occur at 2 100 s and 6 225 s after hydrate synthesis.

PETROLEUM MACHINERY AND OILFIELD CHEMISTRY

Structural Optimization of Mixing Impellers in Fracturing Sand Mixing Device

HUANG Tiancheng, ZHOU Sizhu, YUAN Xinmei, WANG Deguo

2019, 41(4):  159-165.  DOI: 10.11885/j.issn.1674-5086.2018.03.18.02

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To improve the mixing performance of fracturing sand mixing device, a method that combines the orthogonal test and CFD numerical simulation was adopted to study the influence of primary geometric dimensions of mixing impellers on mixing time. The mixing time was used as the experimental index, and the structural features of mixing impellers were considered. The optimal structural parameters of the impellers of mixing devices were obtained, providing theoretical support for the structural optimization of the mixing impellers. The results showed that the variation of the geometric dimensions of mixing impellers influenced the mixing time. The diameter of the upper impeller had the greatest influence, followed by the diameter of the lower impeller as well as the diameter ratio between the lower draft tube to the lower impeller, whereas the diameter ratio between the upper draft tube to the upper impeller had a relatively minor influence. The optimal configuration for the geometric dimensions of mixing impellers yielded the shortest mixing time of 11.0 s.

Vibrational Stability Based on Autocorrelation Analysis of Translating Window Signals

LIU Guangfu, ZHOU Kaidi, ZHU He, FENG Lianlei, YAO Aijun

2019, 41(4):  166-174.  DOI: 10.11885/j.issn.1674-5086.2018.03.26.02

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Targeting the limitations of the current analysis methods for vibration signals of electric submersible pumps, an autocorrelation analysis method based on translating window signals is proposed, and a stability index is defined to evaluate the stability of the vibration signals quantitatively. First, a window signal that can best represent the periodic characteristics of the vibration signals is obtained using the moving average method. Subsequently, the window signal is translated on the vibration signals while autocorrelation analysis is performed to obtain the autocorrelation coefficient series. Finally, the autocorrelation coefficient series is processed to obtain the stability index. Simulation and experiment results show that this method can effectively judge whether the signal has an unstable vibration amplitude or period to determine the electric pump with potential fault successfully, which verifies the feasibility and effectiveness of the method in evaluating the stability of vibration signals.

An Experimental Investigation of H₂S Production by Thermochemical Sulfate Reduction in Heavy Oil

MA Qiang, LIN Riyi, HAN Chaojie, YUAN Gaoliang, YU Wanmin

2019, 41(4):  175-182.  DOI: 10.11885/j.issn.1674-5086.2018.06.01.01

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The mechanism of H₂S formation during heavy oil recovery by steam injection was investigated by reacting five sulfates (Na₂SO₄, CaSO₄, MgSO₄, Fe₂(SO₄)₃, and Al₂(SO₄)₃) with heavy oil via thermochemical sulfate reduction(TSR). Significant variations were observed in the production of H₂S depending on the type of sulfate reacting with the heavy oil, as the number of charges carried by the sulfate cation governed the ease of the TSR reaction. More strongly charged sulfate cations facilitated the TSR reaction. The H₂S yields of the sulfates followed the order:Al₂(SO₄)₃ > Fe₂(SO₄)₃ > MgSO₄ > CaSO₄ > Na₂SO₄. However, the hydrocarbon yields were as follows:Fe₂(SO₄)₃ > Al₂(SO₄)₃ > MgSO₄ > CaSO₄ > Na₂SO₄. Fe₂(SO₄)₃ is unique among the sulfates as it can react with H₂S due to its oxidizing property. The solid-state Fourier transform infrared spectroscopy (FTIR) analyses showed that FeS₂ was present in addition to several metal oxides (CaO, MgO, Fe₂O₃, and Al₂O₃). Finally, the sulfur content of the oil phase with the TSR reaction of MgSO₄ was analyzed, and it was demonstrated that the post-TSR sulfur content of the oil phase was higher than that of crude oil. This confirmed that inorganic sulfur was converted to organic sulfur during the TSR reaction in heavy oil.