Proceedings of the International Field Exploration and Development Conference 2023

Inflow performance relationship (IPR) as a critical method representing the deliverability of well has been used for a long period in the petroleum industry. This method is proposed in the form of simple correlations of flowing bottom hole pressures (BHP) and flowing rates of wells from the very beginning and has been continuously developed in the following time. In recent years, the appearance of new types of IPRs extends the original concept of IPR and expand its application areas.This work reviews different IPR methods that are proposed from a very early time to recent times. There are three main types of IPRs introduced in this paper that are classified as follows: the traditional (steady or pseudo-steady) IPRs for conventional reservoirs, the transient IPRs for unconventional reservoirs experiencing long-term transient flows, and the dynamic IPRs for coupled reservoir-wellbore systems. The calculation principles, applicable conditions, advantages and disadvantages of the above three types of IPR are discussed.In addition, the advanced artificial intelligence techniques, as a hot trend in all engineering areas, that utilized to generate IPRs are summarized, such as the artificial neural network and fuzzy mathematics, etc. Finally, the future research work is prospected.The review of the development of IPRs can provide a better view of the current research levels of productivity research and identify existing research issues and directions for future development. At the end of the paper, some open suggestions for future work are mentioned.

With the continuous vertical development of oil exploration and development, the depth of deep and ultra-deep oil and gas gradually increases from 8000 m to 9000 m, and the number of ultra-high temperature and ultra-high pressure wells is also increasing continuously. The pressure of perforating construction has exceeded 210 MPa, but the highest pressure rating of existing perforating equipment at home and abroad is 210 MPa. So, through the research of type 89 245 MPa ultra-high pressure perforating equipment, a set of perforating equipment with a pressure up to 245 MPa, including perforating guns, perforating bullets, detonating equipment, and shock absorber, has been researched and developed, and the 245 MPa ultra-high pressure perforating technology has been perfected. The on-site test results indicate that this technology is safe and reliable, and can meet the technical requirements of ultra-deep well perforating operations, promoting the development of ultra-deep well oil testing technology.

Shale oil and gas resources are abundant, and weak surfaces such as stratification and lithological interfaces are developed in the longitudinal direction of the reservoir. Hydraulic fractures are prone to extend along weak surfaces leading to restricted longitudinal transformation, which seriously affects the fracturing effect. However, the mechanism of artificial fracture extension in shale reservoirs with complex weak surface distribution is still unclear. Based on the cohesive pore pressure unit method, a seepage flow-stress-damage finite element fracture extension model was established, and the finite element software was secondarily developed to study the influence law of each main influencing factor on hydraulic fracture penetration under the single bedding and the influence law of multi-bedding spacing on the hydraulic fracture height, and the main controlling factors affecting the hydraulic fracture height of bedding shale were analyzed by the orthogonal experiment method. The results show that the larger the vertical stress difference, the dimensionless strength of the bedding plane, Young's modulus, fluid injection displacement, and fracturing fluid viscosity, the smaller the bedding dip angle, the easier it is to achieve penetration. Tensile damage occurs in the main seam and the initial damage to the bedding surface is mainly shear damage. The main controlling factors affecting the seam height are, in descending order, the cementation strength of the bedding surface, the vertical principal stress difference, the bedding inclination angle, the fracturing fluid viscosity, the injection displacement, the bedding spacing, and Young's modulus. The influence of all factors on fracture height and longitudinal complexity is relatively consistent. The easier it is to achieve longitudinal penetration, the lower the longitudinal complexity is. This study reveals the hydraulic fracture height extension mechanism of single-layer and multilayer shale, which is potentially instructive for the optimal design and field application of fracturing in shale reservoirs.

In the process of oilfield development, due to changes in water injection adjustment, formation sand production, and formation pressure drop, the liquid production and dynamic liquid level of the oil well changes. It is necessary to adjust parameters to improve the system efficient of the pumping well. In this paper, a method of parameters optimization of the pumping well based on multiple constraints is proposed. Firstly, the law of oil well production, polish rod power and energy consumption is analyzed. Then, aiming at economic benefits, the optimization model of pumping well parameters is established, and solved to determine the optimal parameters of pumping well. The method is applied to the T oilfield, the optimized stroke frequency is applied, and good results are obtained. After adjustment, the pump efficiency increases from 49.3% to 68.0%, and the system efficiency increases from 27.1% to 29.8%. This method can optimize pumping well parameters under complex conditions; it can optimize parameters quickly and achieve continuous parameter adjustment. The method considers multiple constraints of pumping well, making the optimization feasible, and it can be used as a reference for keeping the balanced state between reservoir supply and well production, improving system efficiency and saving energy.

Carbonate reservoirs commonly use acid fracturing process technology for reservoir reconstruction. And non-uniform etching features play an important role in slowing down the fracture closure and maintaining the high conductivity. Currently, the simulation studies about the morphological change process of the fracture surface are generally geometrically simplified for the morphological features such as the micro-convex structure, resulting in the model not reflecting the true situation of the non-uniformly etching fracture surface. In this paper, limestone cores are selected for acid-etching experiments. The 3D model conforming to the true morphological features is constructed based on 3D scans of acid-etching cores. By ABAQUS software, simulate the morphological changes of the fracture surface under different rock mechanical properties and stress loading conditions, comparing and analyzing the variation of results between this model and the conventional simplified model. The result shows that compared with the convention model, this model can accurately reflect the stress and strain distribution on the non-uniformly etched fracture surface. And with the increase of stress load, the fracture surface roughness decreases continuously, and the supporting effect of the micro-convex structure decreases, leading to further or even complete closure of the fractures.

As a reservoir reconstruction, fracturing fluid plays the role of transmitting pressure and carrying proppant, but it is also the main source of reservoir damage, which brings different degree of damage to the reservoir, and even causes production reduction or no production of oil well. How to correctly evaluate and analyze the damage degree of fracturing fluid in shale oil reservoirs plays an important guiding role in the effective development of low permeability reservoirs. The experimental study of fracturing fluid damage evaluation based on pressure oscillation method is established by using the self-developed fracturing fluid damage evaluation instrument. The damage of common fracturing fluid system on Jimsar shale oil reservoir core was systematically studied. The results show that compared with the conventional steady-state method, the pressure oscillation method is suitable for cores with permeability less than 0.01 mD. The experimental method is fast, simple and reproducible. It is clear that confining pressure, injection pressure and temperature have obvious influence on permeability. It is verified that the pressure oscillation method can effectively evaluate the damage degree of guanidine gum system and polymer system to the core of Jimsar shale oil reservoir.

C6 reservoir in the Ordos Basin is mainly composed of medium fine-grained arkose with a burial depth of 1500–2000 m. The pore structure of reservoir space is complex, the throat is fine and the sorting is poor. The average permeability of the reservoir is 0.01–100.00 mD, and the porosity is generally less than 19%. It is a low permeability reservoir. Based on the geological and engineering parameters of the reconstructed well and the post-fracturing effect data, the influence degree and law of geological and engineering parameters on the fracturing effect are comprehensively analyzed by using the method of grey correlation theory. A multi-factor analysis model combining the status and trends of system development with information utility is developed to explore the weights of fracturing parameters that affect hydrocarbon productivity after fracturing. The analysis using a single method lacks determination of each applicability, and the results obtained often deviate from the actual project. In our study, firstly, the grey-correlation method model and entropy-method model are established to get two kinds of weights. Secondly, two types of weights are merged into a combined weight. Eventually, the in-situ data of 100 horizontal wells in the C6 formation of the Q block are substituted into the model. And the primary and secondary relationships of the influential factors are clarified according to the result. The correlation and influence degree between each influencing factor and fracturing effect are clarified. Taking the Block C reservoir in the Q block as an example, the fracturing design parameters are optimized, and further clarify the influencing factors and laws of the C6 horizon reconstruction effect in Block C, B, E, D, A, and other blocks of the Q block, which is based on grey correlation theory and method. It provides a reference and guiding method for the optimization of well fracturing design in this block.

The fracturing technology for offshore oil well is developed to improve productivity of oil well, in view of the difficulties such as low natural productivity, poor operation condition, high requirements of safety and environmental protection for fracturing stimulation, and the inapplicability in offshore Chengbei oilfield of DG but effective technologies on land. In this paper, the research and development of new high-efficiency backflow and non-organometallic ion high temperature cross-linked agent were carried out, and the safe and environmental high temperature fracturing fluid suitable for offshore oil well was prepared with the special equipments and the safe operation technology being equipped for offshore fracturing. And finally the fracturing technology for offshore oil well was formed after using the three-dimensional fracturing software to optimize the process parameters and preparing the operation specifications of offshore fracturing. The fracturing technology was carried out through adopting non-dynamic positioning ships with wind resistance of no less than force 8 winds, and the operation equipments were fixed by welding. The layout on the ship deck meets the stability calculation requirements. The developed environmental high temperature resistant fracturing fluid does not contain methanol and can withstand temperature 165 ℃. The surface tension of the gel-out liquid is 20.7 mN/m and the interfacial tension is 0.24 mN /m. The 3D fracturing software was used to simulate and optimize the viscosity, operation scale and displacement of fracturing fluid system, and the strings with hydraulic pump was adopted, the maximum daily oil production reached 59.3t after fracturing for 17 Wells, with an average production increase being 13.5 times. The successful breakthrough of this technology has realized the large-scale application of fracturing in offshore oil wells, which provides the main technical model for upgrading and efficient development of Chengbei low-fault stage reserves.

When gravity displacement gas invasion occurs in fractured reservoirs, it is easy to cause blowout accidents if not handled properly. Based on ANSYS software, a model of horizontal well intersecting vertical fracture was established to simulate the phenomenon of gas-liquid displacement under formation conditions, explore the influence law of drilling fluid density, viscosity and fracture width on the size of gravity displacement window, and compare the influence of changing drilling fluid density, viscosity and applying wellhead back pressure on the gas influx rate and loss rate during gravity displacement. And the following research results are obtained. First, after the intrusive gas enters the vertical well section, the gas migration rate increases and the intrusive gas gradually diffused from one side of the annulus to the whole annulus. Second, the larger the fracture width, the larger the displacement window. Third, different from that in the vertical well section, the fracture width in the horizontal well section is the main factor affecting the displacement window, and the fracture height, drilling fluid density and viscosity have little influence on the displacement window, and the displacement interval is mainly in the negative pressure interval. Fourth, the displacement window of horizontal well displacement gas invasion is sensitive to the change of wellhead back pressure, and the slight increase or decrease of wellhead pressure will lead to the transition of gravity displacement to pure leakage or gas invasion. By simulating the dynamic process of horizontal well displacement gas invasion, this study explores the mechanism of horizontal well displacement gas invasion, which has certain guiding significance for the design of countermeasures for horizontal well displacement gas invasion.

Jiangsu oilfield has entered the development stage of high water cut, and some water injection well formations have formed composite scales such as carbonate, sulfate, and oil sludge. Conventional acidification techniques are difficult to dissolve sulfate and organic scales, and the operating cost is high. Therefore, a non acid plugging agent is developed, which is mainly composed of ultra-low molecular weight polymers and added with auxiliary agents such as organic salts and non ionic surfactants. It is prepared using micro speed stirring and low-temperature synthesis. The experimental results show that: The non-acid plugging agent has good dissolution effect on marble, gypsum and mixed scale, and the dissolution rate is greater than 70% at 60℃ for 48h; At the same time, the dissolution rate of reservoir rock powder can reach 20%, which will not cause significant damage to the reservoir skeleton; The dissolution rate of reservoir rock powder can reach 20%, which will not cause obvious damage to the reservoir skeleton; The corrosion rate of N80 steel is 0.5g/(m2.h), which has good corrosion inhibition; In-door core damage removal rate is 90%. On site application of 6 wells, the average single well apparent water absorption index increased by 2m3/d MPa, the pressure reduction rate was 30%, the cumulative injection increased by 36000 cubic meters, and the validity period exceeded 400 days. This technology can effectively remove inorganic and organic blockages in the near wellbore zone, restore oil water permeability, improve water drive development effectiveness, and provide a new safe and low-cost means for increasing injection in oilfield water injection wells.

The tight oil reservoir of X5 fault block in Jidong oilfield is characterized by multi-thin and inter-bedded reservoir with poor physical property and strong heterogeneity. Vertical wells located in study area are facing production problems such as poor water injection efficiency, rapid decline and short stable production periods after fracturing, and well-controlled reserves are relatively low. Multi-staged horizontal well fracturing is an effective way to increase single well productivity. Therefore, research on geo-engineering integrated fracturing technology was carried out. First of all, a geo-engineering integrated fracturing design optimization process is proposed, the tight oil reservoirs were categorized into Class I, II and III and a differentiated parameters design chart for different reservoir quality was established considering both economic output and productivity. Moreover, a mudstone interlayer breakthrough fracturing experiment was innovatively proposed to maximize horizontal well productivity. Simulation research was carried out to explore the relationship between fracturing parameters and single well EUR, and also to study the effect of different proppant combinations on conductivity of fracture network. Laboratory experiments were conducted to evaluate different surfactant and fracturing fluid performance since displacement and imbibition played important roles in the recovery of tight oil reservoir. After series of simulation and laboratory experiments, the geo-engineering integrated tight oil fracturing technology was successfully applied in the development of X5 tight oil in Jidong Oilfield, and have provided valuable guidance for tight oil fracturing.

Tight sandstone gas reservoirs are generally characterized by poor reservoir physical properties, fine pore and throat volume and high clay content. Most of the tight reservoirs are water-sensitive. Conventional hydraulic fracturing using water based fracturing fluid may cause formation damage such as clay swelling and water blocking, and affect stimulation effect. Research on non-aqueous fracturing technologies have been carried on recent years. Quasi-dry CO2 fracturing is a waterless fracturing technology which uses a highly viscous mixture of emulsion that contains 100% liquid CO2 and a small amount of water-based fracturing fluid to avoid damage to water-sensitive reservoir, and no solid residue during flowback process. The main characteristics of the quasi-dry CO2 technology including fluid composition and sand-carrying capacity were studied, temperature and shear resistance of quasi-dry CO2 fracturing fluid were tested. The new fluid system has less formation damage, excellent fracture making ability and sand carrying capacity that can meet all the requirements of large scale fracturing construction. Meanwhile, using carbon dioxide as fracturing fluid have more economic and environmental significance. Pilot test was conducted in a deep tight sandstone gas reservoir of Nanpu No.5 structure in Ji dong oilfield. The fracturing operation was successful indicating that quasi-dry CO2 technology is operationally feasible. After fracturing, the pilot well achieved excellent stimulation effect with the daily oil and gas production increased 2.5 times and 8.6 times respectively, which has instructive significance to the development of similar reservoirs.

The scaling of produced Wells is one of the main problems faced by ASP flooding technology. At present, the determination is mainly based on the pH value of produced liquid and the concentration of scaling ions. There are many problems such as too many discriminant parameters, subjective factors and difficult operation. Therefore, in this paper, the main components of scale were determined by scale sample analysis. Based on Oddo-Tomson saturation index method, the prediction method of calcium scale formation in ASP flooding was established by modifying with the temperature, pressure, pH value and ionic strength of the produced liquid, which could quantitatively predict the scale situation of mechanical production well, so that the scale prediction could achieve a quantitative description. Through the field application of saturation index scaling prediction technology, the detection period of ASP flooding block reached 598 days, extending 133 days. Pump detection rate was 30.2%, down 13.4 percentage points.

Volume fracturing is an effective means to improve the development effect of low permeability tight reservoir. While forming one or more main fractures, natural fractures can be continuously expanded to realize the communication between natural fractures and rock bedding and improve the reconstruction effect. In this paper, according to the characteristics of low permeability tight reservoir in the second member of Kong2 formation in Dagang area, reservoir characteristics analysis and volume fracturing process parameters were carried out, and key fracturing process parameters such as fracturing scale, injection rate and sand-liquid ratio suitable for the target block were optimized. The idea and technology of multi-stage and multi-fracture support for complex fractures are put forward to optimize the proppant types of fractures at all levels in the fracture network. The flow rate - temperature - concentration coupled graph was established to form the whole process of slickwater continuous sand addition. The field application effect of this technology is obvious, and it has important guiding significance to improve the reconstruction effect of similar reservoirs..

Fracturing reservoir technology has become a powerful tool for low and ultra-low permeability reservoir reconstruction, and is an important and indispensable technical means for oil and gas exploration and development. In view of the shortage of water resources and the increasing of produced water in oilfield fracturing operation, it is urgent to study the use of oilfield produced water to prepare fracturing fluid, so as to solve the problem that the produced water can not form glue or the viscosity is low. Through improving the dissolving ability of thickener in produced water as the starting point, the idea of “removing interference factors” and “strengthening the function of thickener” was obtained by using the innovative ARIZ method. The modified guar gum was used as the thickener and the rigid salt-resistant and supramolecular side groups were introduced into the polymeric monomer combined with the characteristics of some reservoirs in Erian Oilfield. A formula system of produced water fracturing fluid suitable for erlian oilfield reservoir transformation is developed. When the temperature is less than 80 ℃, the technical indexes of the system meet the technical requirements of SY/T6736, effectively solve the winding effect of calcium and magnesium ions on polymer chain, and improve the quick solubility, thickening and heat resistance of polymer thickener. The application results in Erlian oilfield show that the viscosity of the base fluid prepared with produced water is close to or higher than that prepared with clear water, guar gum has good swelling ability in produced water, stable pressure during field construction, good sand carrying performance, and the productivity after pressure reaches the expected effect. The fracturing system has a broad application prospect.

In order to clarify the micro control mechanism of the macro drag reduction performance of drag reducing agents, a large number of micro characterization of the aggregate structure formed by different types of polymer drag reducing agents were carried out by environmental scanning electron microscope. Combined with the test of the drag reduction performance of the system, the micro mechanism of the effect of concentration on the drag reduction performance of different drag reducing agents systems was revealed from the level of polymer molecular aggregation structure. It is found that most of the aggregation forms of slick water fracturing fluid drag reducing agents are net like network structures surrounded by polymer skeleton structures, but the network structures formed by different types of drag reducing agents are different. Among them, emulsion and suspension type drag reducing agents have the most complete network structures, while powder type drag reducing agents have uneven distribution of aggregated network structures and low network strength due to slow dissolution speed. At low concentration, the average mesh wall thickness of the network structure formed by the three drag reducing agents is about 0.1 ~ 0.3 μm. With the increase of the concentration of drag reducing agents, the mesh shape of the system gradually changes from irregular to polygonal. Some drag reducing agents can form a circular network support structure with high strength and good stability. The mesh size decreases and the mesh wall thickness increases. When the concentration of drag reducing agents increases to 0.05%, the mesh wall thickness can reach 0.3 ~ 0.9 μm. The strength of network structure has been significantly improved. The aggregation structure characteristics of drag reducing agents will have an important impact on the drag reduction performance of the system. The over dense or sparse mesh of polymer network is not conducive to the exertion of the drag reduction performance of the system. Only the network structure with appropriate size will deform properly under the action of shear, effectively store the energy of solution turbulence, significantly reduce the energy dissipation in the flow process, and finally achieve a good drag reduction effect.

In Fengxi tight oil field of Qaidam Basin, long horizontal well + close cut volume fracturing is the main technology, which has achieved certain results. However, there are still some problems, such as unclear main controlling factors of oil well productivity and undetermined development technology. Fengxi N21-III-3 has two sets of targets, the upper target is thin layer algal limestone + lamellar limestone, and the lower target is thick layer lamellar limestone. The two sets of targets have their own advantages. FH1 of oil group III encountered the upper and lower target formations with about 81% water cut after production. In 2021, all three horizontal Wells will be put into production in the upper target zone, with water cut of more than 90%. In view of this phenomenon, the post-compaction effect of N21-III-3 layer is analyzed from geological and engineering perspectives, so that the lower target layer is a better sweet spot. According to the analysis of fracturing parameters, it is considered that the fracturing technology is a combination of fist, and the fluid volume, sand volume, displacement and cluster spacing should be guaranteed. However, under the overall cost limitation, the fluid volume of single cluster should be guaranteed first.

In order to solve the difficulty of high energy consumption during heavy oil lifting, the mathematical model of using electrical heating petroleum pipeline technology to reduce the viscosity is build, the bore temperature field of pipeline is calculated, and the optimization technology of electric heating pipeline is given. It is shown that the energy consumption of lifting could be significantly reduced after optimizing the heating depth and heating power to the electric heating system. The well A was taken as an example to verify this optimization calculation. The results indicated that the optimal heating depth is 890 m and the optimal heating power is 29.6 kW. After the optimization, the energy consumption fell down 7.5%.The optimization technology of electric heating pipeline given by this paper can make the high energy consumption equipment run with lower energy.

With the continuous development of unconventional resources, offshore heavy oil has attracted wide international attention. Heat fluid huff and puff and dual packer completion technology are often used in offshore heavy oil production. However, the annular pressure buildup caused by heat transfer and fluid expansion in the production has become a serious problem. It has brought a great threat to safe production of heavy oil. In this paper, regarding the dual packer completion and N2 injection, the temperature field in the production string is analyzed based on the heat transfer theory and energy conservation. The prediction method of APB is proposed considering the influence of the axial force and the cemented casing on the annular volume. At last, the mechanical strengths of the tubing and casing strings are evaluated. Analysis results indicate APB in C-annular is higher than that in the other annuli. The bottom of the un-cemented section of each string is most likely to be of failure. With the increase of N2 injection, APB decreases at a declining rate. The comparisons between the calculated value of APB by the proposed method and the measured data show high consistency with prediction errors less than 10%. The model developed in this paper is of referential value for annular pressure buildup mitigation and optimizing cementing operation.

At present, more than 90% of the total number of directional wells in the newly put into operation block of Y Oilfield are directional wells. The wellbore structure of directional wells causes complex mechanical effects of the rod and column, making it difficult to accurately predict the hanging point load of the pumping unit. This leads to unreasonable selection of pumping units during the construction of the new area, low load utilization rate, high energy consumption, and high investment. In order to improve the scientific design of directional well beam pumping unit selection, this article takes into account the influence of well deviation on the load of the pumping unit, and applies analytical method to calculate the maximum and minimum axial load of the directional well pumping rod. A directional well pumping unit selection chart is drawn. The on-site application situation shows that the model designed using the directional well pumping unit selection chart has increased the load utilization rate by 17.6% compared to the previous design models, Make the design of Y oilfield pumping unit models more reasonable and scientific.

At present, the crude oil in the newly put into production block of Y Oilfield has a high gum and wax content, and directional wells account for more than 90% of the total number of oil wells. The wellbore structure of directional wells leads to complex mechanical effects of the rod string, making it difficult to accurately predict the hanging point load of the pumping unit, resulting in unreasonable design of the rod string in newly put into production oil wells. The phenomenon of eccentric wear and rod breakage of the pumping rod often occurs. In order to improve the scientificity of sucker rod design for directional wells with high pour point crude oil, a computational mathematics model for calculating wellbore temperature field of high pour point crude oil electric heat tracing viscosity reduction process was established using the basic theory of heat transfer, the distribution of viscous force on sucker rod was analyzed, the influence of well deviation on suspended point load was considered, and the technical method for axial maximum and minimum load of sucker rod in directional wells was given. According to the modified Goodman diagram, the reasonable rod string combination for directional wells was optimized, Make the lifting plan design of directional wells more reasonable and scientific.

It is difficult to guarantee the downhole oil-water separation performance of a hydrocyclone in single-well injection-production technology system with ultra-high liquid inlet flow rate. An innovative downhole de-oiling equipment of hydrocyclones (EHC) is proposed to encounter the technical bottleneck of down hole oil water separation caused by ultra-high inlet flow rate. The computational fluid dynamic method and the response surface method (RSM) are used to analysis the characteristics of EHC flow field and improve its performance. Herein, the optimization analysis of significant structural parameters is conducted via RSM. The optimal structural parameters of EHC are obtained to enhance the separation performance. The results show that when the inlet length L2 = 41.25 mm, inlet diameter ϕ1 = 22.5 mm, the overflow diameter ϕ4 = 4.5 mm, and the center tube diameter ϕ3 = 30 mm the separation efficiency of EHC can reach the maximum value 94.98%. The separation efficiency of optimal EHC is 6.18% higher than the original one. The indoor experiments of separation performance are carried out to verify the reliability of numerical simulation results. The simulation results is in good agreement with experimental ones, the feasibility of optimal EHC and the reliability of simulation method are verified.

Fracturing and acidification are widely used as stimulation methods in conventional and unconventional fields. After the fracturing fluid or acid enters the formation, the fracturing fluid or acid enters the flowback reservoir through the wellbore and flowback line. To prevent contamination, flowback fluids are usually treated for fracturing or acidizing in adjacent Wells or discharged after meeting discharge standards. In the process of flowback, the performance and parameters of flowback fluid can reflect the effect of fracturing or acidification and guide the recovery and reuse of flowback fluid. Sand content, breaking properties (viscosity), density, PH, flow rate, salinity, acidity, and other solids and residue content are the most important parameters for engineers to focus on. These parameters are usually obtained in the field by sampling from a flowback pool or other location. The data error obtained by this method is large, and the monitoring index is not comprehensive, systematic and continuous. Aiming at this phenomenon, the author developed a set of real-time monitoring system for fracturing and acidizing flowback fluid, which can calculate and analyze the parameters of flowback fluid in real time. The research results show that the device can obtain the parameters of fracturing or acidizing flowback fluid in real time and continuously, improve the accuracy of monitoring data of parameters of flowback fluid, reduce labor intensity, and promote the informatization and intelligent construction of fracturing and acidizing field.

As the development of major offshore oilfields enter the mid to late stage, the workload of platform operations gradually increases. Conventional injection and production technology has low efficiency in wire testing and adjustment, making it difficult to meet the demand of efficient reservoir development. In view of the above issues, and combining the characteristics of large well deviation, large flow rate and small diameter of oil and water wells in Bohai oilfield, the whole set of data communication device is integrated into the downhole intelligent working cylinder through the design of mechanical structure, flowmeter, circuit composition and seal protection, and real-time communication is established with the ground control system by means of a single-core cable, realizing real-time reading and efficient regulation of downhole stratified data such as temperature, pressure and flow rate in platform control center. On this basis, through the further research and development of land terminal monitoring system, ultimately achieving remote monitoring and control of oil and water wells on offshore platforms, allowing reservoir engineers to have access to first-hand on-site information in the office. The test results show that the technology is not limited by well deviation and the number of injection and production layers, and the efficiency of testing and adjustment is improved by 96% compared to the conventional separate injection and production technology. The maximum flow rate of a single layer can reach 800m3/d, which can meet the requirements of large flow rate and small diameter in Bohai Oilfield. Up to now, the cable-control intelligent injection and production technology has been applied to over 180 wells in Bohai Oilfield, greatly improving the various indicators of fine water injection and oil stability and water control, providing strong technical support for promoting the intelligent and digital process and the construction of intelligent oilfield in Bohai oilfield.

At present, 229 gas Wells have been put into production in X gas field, which has entered the middle and late stage of development successively. The demand for various measures reaches 8000 Wells per year. Well locations are scattered and management is difficult. By establishing an intelligent decision-making platform for gas Wells, efficient integration of dynamic and static data resources for gas field development, establishment of multi-data source comprehensive working condition diagnosis algorithm model, three-dimensional analysis of reservoir-wellbore-surface working conditions, comprehensive perception of gas well production dynamics, “manual analysis “into” intelligent decision-making”. The intelligent parameter adjustment algorithm model is established to form the remote measurement and control technology, so as to realize the status monitoring and remote dosing of gas well automatic dosing device, changing “traditional dosing “into” intelligent bubble row”. It is expected to form an intelligent demonstration area for the number of Wells in X gas field, with a total economic benefit of more than 9.3 million yuan and a cumulative gas increase of 5 million square meters. The research results can realize the comprehensive fine analysis and decision-making of gas Wells in Daqing oilfield and the key monitoring of measure Wells, improve the analysis and decision-making level of gas production technology, and help the gas field to leap from digitalization to intellectualization, which has a wide range of application prospects.

In order to solve the problems of poor balance, high system energy consumption and low efficiency for operation of conventional pumping units, several variable speed optimization operation technologies have been studied and applied in Y oilfield. Through the research of variable speed kinematic model of pumping unit, based on the saddle-shaped law of ‘large load deceleration, small load acceleration’, the balanced power operation mode is formed. Through the system dynamics analysis under different operating parameters, the combined optimization mode of crank continuous rotation and crank swing is formed. According to the optimization demand of variable speed within a single cycle of oil well, the segmented speed regulating operation mode is formed. Field test results have shown that the spike power of the power curve of the pumping unit is decreased by 56.0% and the spike torque is decreased by 3.3%, and the vibration of the pumping unit is decreased obviously for the balanced power operation. The spike power of the crank shaft is decreased by 77.6% and the spike torque of the crank shaft is decreased by 66.5% for the crank swing operation. The spike value of active power is increased by 39.6%, the spike value of crank shaft torque increases by 10.5%, and the maximum load of suspension point increases, and the vibration amplitude of pumping unit increases for the segmented speed regulating operation, All the field test would provide important technical guidance for the optimization of variable speed operation and energy saving of pumping unit.

Shale oil had been mostly explored deep underground, ESPCP (electric submersible PCP) was more adaptive to low output, high viscosity and deep well. So far hundreds of shale wells were equipped with ESPCP. However, motors and PCP were subject to harsh downhole environment, faults like tubing choked by wax and rubber over swelling were common, how to diagnosis these two faults correctly meant a lot to the measures ensued, since tubing choked by wax called for downhole heating while rubber problem required its replacement.In this paper, an algorithm was developed to identify these two faults, relevant software was completed to make the judgement automatically, finally field applications were trialed.The algorithm was based on the change of D-value of electrical current between the real and the theoretical, as well as the liquid output, usually the D-value of output dropped if tubing was waxed seriously, while the value remained even or raised if the rubber swelled abnormally. The calculation process involved additional parameters of downhole pressure, rotating speed and water percentage, meanwhile data like well structure, oil viscosity, and pump specifications were also taken into account. The software could make the judgement with the input of at least 25 days information. According to the field trial, faults could be identified whether it was tubing or PCP that went wrong provided the operation parameters were smooth, the future electric current could be predicted and the tendency was correct in short term. Model training had been completed and its application were expanding.The software prescribed in the paper helped improve the integrity of ESPCP system by predicting its future operation status, it also served as an important reference to the next move when it came to downhole accidents.

The diaphragm type submersible reciprocating pump lifting technology is a new technology and equipment for rodless oil production proposed for “three low” reservoirs, highly deviated wells, and horizontal wells. It is currently in the initial stage of experimental research and has a broad application prospect. This paper conducts research on the operating mechanism of diaphragm type submersible reciprocating pumps, gives the characteristic curve of the diaphragm pump, according to the operating characteristics of diaphragm type submersible reciprocating pumps, proposes a special inverter control device design and research, and development plan, and finally analyzes the unique technology determined by the special diaphragm chamber structure design Advantages: Propose a technical solution for harmonic control of the inverter and design a non-standard dedicated sine wave filter. Two wells were tested on site. The maintenance-free periods were 812 days and 654 days, respectively. The average pump efficiency was 89.8%, the power saving rate was 45.78%, and the system efficiency was 25.18%.The harmonic control effect of the sine wave filter is good, which effectively verifies the reliability, adaptability and economy of the process, and highlights the good technical advantages. The downhole working condition monitoring and fault diagnosis method, low-cost wax removal and prevention method and process, intelligent cable laying composite coiled tubing and other technologies are proposed, which lays the foundation for in-depth scientific research and field tests in the future, points out the direction of scientific research, and is conducive to the development of a diaphragm submersible reciprocating pump in the direction of intelligence and digitization.

Beam pumping unit has simple structure and high reliability, and has played a very important role in the history of petroleum development. In view of the problems such as the decrease of liquid production in most production. Wells and the shortage of liquid supply in middle and low production Wells, Intelligent operation control system of pumping unit for supply and production balance of production well is developed. In this system, motor control, operation control and fault diagnosis and early warning modules are added to the measurement and control device, so as to improve the dynamic balance of variable speed pumping unit. Through the electrical parameter conversion indicator diagram, mass production, liquid level calculation, intelligent operation control and fault diagnosis and early warning are realized. The field test shows that The Intelligent operation control system of pumping unit for supply and production balance of production well can improve the system efficiency of the mechanical production well by 3.0 percentage points. The application of the Intelligent operation control system of pumping unit for supply and production balance of production well can effectively reduce the peak torque and fluctuation range, keep the pumping unit with high operation efficiency and make the convention pumping unit realize digitization, information and intelligence, which is of great significance to boost the upgrading of the intelligent operation technology of the pumping unit.

The submersible direct-drive plunger pump is a kind of high-efficiency rodless lifting equipment with small displacement, which is popularized and applied in low production and low permeability oilfield in recent years. It has the advantages of being energy saving, environmentally-friendly and eliminating eccentric wear of rod and tube. For years, there was a lack of effective indoor detection methods for permanent magnet submersible linear motors, the core part of submersible direct drive plunger pump, and the unit failure occured at well sites due to insufficient lifting force and excessive vibration regularly. This test system is on the basis of indoor test and designed to test and analysis various technical specifications of submersible linear motor systems (including the submersible linear motor and its control cabinet), mainly including test efficiency, rated parameters testing, limit test, and mechanical vibration. Moreover, the drawing of the dynamic thrust, velocity and accelerating curves under different frequencies can be realized, based on which the best working point for the field application of submersible direct drive plunger pump can be found.

Recent years, more electric submersible progressive cavity pump (ESPCP) were used in China. Compared with sucker-rod pump, they had outstanding benefits on energy conservation, safety and environmental protection. It needed the sheathed oil-submersible cables tied up outside steel tube to provide power for pumps. But the collisions during running tube and corrosions by well fluid cause serious damages to the cable which is one of the problems for pump inspection.In this paper, ESPCP technology combined with intelligent composite tube was proposed to provide an easy solution of power supply, data gathering and heating function. The tube is constituted of outer covering, structure layer and functional inner layer. The power cables and heating cables are embedded to isolation with wellbore environment. Compared with traditional steel tube, this intelligent composite tube is anti-corrosion, anti-friction, and power cables embedded. It also can be easily operated by special coiled string coiled tubing unit to reduce the operation time. Maximum length of single tube is 2,000 m. Minimum bending radius is 1 m. Work temperature of this composite tube is from −58 to 90 centigrade. Maximum axial tension strength is 200 KN. Maximum internal pressure is 50 MPa. Maximum external pressure is 10 MPa. The heating power is 30 kW.This technology has been successfully applied to four platform wells in Jinlin oilfield, China. The field measured pump efficiency was increased by 33.6% compared to the original pumping unit pump efficiency. The temperature pressure sensor was installed to monitor the temperature of pump output, and control the heating function to prevent the paraffin precipitation caused by low downhole temperature.

The main development target layer of Y oilfield is low permeability Fuyang oil layer, which has poor water flooding development effect and low oil well productivity. Carbon dioxide has the characteristics of reducing the viscosity of crude oil and expanding the volume of crude oil. CO2 flooding technology uses this characteristic to achieve the purpose of greatly improving the recovery rate of low permeability reservoirs. In order to explore the effective utilization of reserve, since 2007, Y oilfield has carried out CO2 flooding test and achieved good development results, forming a series of CO2 flooding supporting oil production engineering technology. The CO2 flooding layered injection technology, gas well treatment technology, wellbore plugging removal technology and corrosion protection technology applied in Y oilfield are summarized and evaluated. The main existing problems and research directions are analyzed, which has certain reference significance for the development of CO2 flooding oil production engineering technology.

In response to the problems of unsatisfactory measures and formation damage caused by blockage during the transformation of tight reservoirs in W oilfield using fracture network fracturing technology, on-site tests of liquid CO2 composite fracturing were conducted. The use of liquid CO2 to create branch fracture networks, increase energy efficiency, and hydraulic fracturing to create main fractures, improve the conductivity of the fracture network, and alternate slug injection of the two to achieve an increase in the transformation volume and effective utilization of tight oil. By utilizing the unique physicochemical properties of liquid CO2 and drawing on the ideas of W oilfield fracture network fracturing design, targeted improvements have been made in the fracturing fluid system, construction displacement, proppant, and other aspects, optimizing the scheme design. The experimental results were analyzed from phase changes, swept volume, and fracture stimulation effect, and the applicability of liquid CO2 composite fracturing in W oilfield was evaluated. After fracturing well A, initial daily oil increase reached 7.7 t, and final cumulative oil increase reached 2500 tons, achieving good stimulation effect and economic benefits. It provides a new idea for the effective production of tight reservoir in W oilfield, and has a certain reference value for the development of tight oil in onshore oilfield.

Pre-CO2 fracturing is a prominent technique for enhancing production in tight oil and gas reservoirs by enlarging stimulated reservoir volume and improving single-well productivity. This paper aims to investigate the influence of different injection pressures of pre-CO2 on the flowback of fracturing fluids. Flowback experiments, with the pre-CO2 being the displacing fluids, were conducted to compare and analyze the flowback rate under different injection pressures. Using nuclear magnetic resonance testing analysis, the flowback characteristics of fracturing fluids in different scales of pore spaces were clarified. The experimental results show that pre-CO2 has a significant effect on the flowback of fracturing fluids. As the injected pressure exceeds the supercritical state, the flowback rate of fracturing fluids decreases with the increasing pre-CO2 pressure. The flowback rate of fracturing fluids is the largest (85.53%) when the injection pressure is 10 MPa. During pre-CO2 assisted flowback, the fracturing fluid in large pores is mainly displaced, while more fracturing fluid remains in small pores and cannot be mobilized. This study reveals the migration mechanism of fracturing fluid in different pore spaces in the presence the pre-CO2 operation and provides a theoretical basis for designing a reasonable flowback scheme and improving the tight oil and gas recovery.

CO2 dry fracturing technology utilizes waterless and harmless liquid CO2 as sand-carrying fracturing fluid. Conventional water-based fracturing fluid causes major damage to reservoirs due to intrusion of large amount of water, greatly impacting the stimulation effects of water-sensitive reservoirs. In contrast, CO2 dry fracturing technology realizes waterless fracturing, achieves the purpose of being nearly harmless to the formation, and can augment production and energy in a sound manner. This paper studies the rock-breaking mechanism of the technology, its functions of changing reservoir fluid properties, and its application effects home and abroad, presenting its technological advantages and a promising application future. CO2 dry fracturing technology is an important technical means to improve the development effects of unconventional oil and gas reservoirs thanks to its strong rock-breaking ability, excellent fluidity, and tendency to form complex shear fractures. The application home and abroad shows obvious production enhancement and a large amount of water saved. Despite some room for improvement, the technology is a new one worth spreading and application. It has satisfied the construction requirements of energy conservation, emission reduction, environmental protection, high efficiency and production enhancement, and hence is of great significance to the clean and efficient development of strongly water-sensitive and strongly water-locked unconventional oil and gas reservoirs.

In view of the disadvantages of the separation technology in the same well injection -production technology, the downhole two-stage series hydrocyclone separation technology is put forward in order to overcome the shortcomings of the existing downhole oil-water separation technology which is not suitable for the well conditions. Using computational fluid dynamics (CFD) software to simulate the movement process of the fluid, analyze the movement state of oil-water two-phase liquid in the separation process, and focus on exploring the influence of the split ratio, treatment capacity and water content change on the technical performance of the downhole two-stage series cyclone separation. When the water content reaches 97% and the total split ratio reaches 36%, the separation performance increases with the increase of the flow. Through laboratory test and research, the best operation parameters are determined as total diversion ratio of 30%–35%, treatment capacity of 4.8 m3/h–5.1 m3/h, the best separation efficiency of downhole two-stage series hydrocyclone separation technology is over 92%, and the pressure loss is less than 0.4 MPa. Through the numerical simulation analysis and laboratory test, the feasibility of the downhole two-stage series hydrocyclone separation technology is proved in theory and practice, which lays a solid foundation for the further improvement and promotion of the technology.

This paper focuses on the new sleeve - taking technology of oil and water Wells. On the basis of breaking through the traditional sleeve milling and milling technology, the spiral cutting is the main means to make full use of the space inside the pipe, and the casing is wound and removed as a whole. The main methods and steps areas follows: screw pitch and cutting. Angle are calculated according to the force; plasma cutting machine is used to cut the casing helically; fixed-point connection of the casing collar is carried out to expand the sleeve; after the casing is formed as a whole, the ground mechanical equipment is used to lift the end of the casing vigorously, so that each casing can be taken out as a whole. This technology breaks through the traditional technology and overcomes the accidents such as large diameter of casing pipe, large friction resistance, easy to drop block and stuck drill, etc. By calculating reasonable pitch and cutting Angle, the surface casing can be cut smoothly with plasma cutting machine. This process has been carried out in the laboratory to simulate the spiral cutting sleeve experiment, the relevant data provided a strong evidence for the field. The innovation point of this process is: inspired by the reverse use of spiral welded pipe forming principle, spiral cutting of casing, fixed-point connection, integral sleeve taking method, can effectively shorten the construction period, reduce underground accidents.

Conventional pure mechanical sliding sleeve switch tools are limited by wellbore size and series difference requirements, and most of them can only be opened for a single time, unable to meet the operating conditions of requiring remote intelligent control and repeated switching. Its field application has certain limitations. In order to solve the above deficiencies and further improve the automation and intelligent level of sliding sleeve switch tools, a kind of electric-driven downhole intelligent switch tool is designed and developed. The intelligent switch tool has the advantages of unified internal diameter, no series difference limit in multiple applications, infinite pole string operation, remote control and repeated switching and so on. Through laboratory test and field test, the reliability of the intelligent switch tool is further verified. The intelligent switch tool can realize repeated switching and infinite pole string operation, greatly improving the flexibility and efficiency of field construction operations, reducing labor intensity and operating costs, and it has broad application prospect.

With the maturity of surface driven rod screw pump production technology, many new forms of injection and production processes have been applied to screw pump wells, such as downhole oil water separation systems with twin screw pumps. Due to the significant increase in torque required to drive the normal operation of the entire system compared to conventional screw pump wells, higher requirements are placed on the mechanical properties of matching hollow sucker rods, and their failure parts during use are mainly concentrated at the joints. This paper analyzes the stress characteristics of the screw joint of a 34 mm diameter hollow sucker rod used in the downhole oil water separation system of a twin screw pump. Based on the analysis results, the shape of the screw root is optimized, improving the stress distribution of the screw joint threads of the hollow sucker rod, and improving the mechanical properties of the screw joint of the hollow sucker rod.

The elastic development or water flooding of tight oil reservoir in Daqing oilfield is not effective, and it is difficult to establish an efficient displacement percolation system after production, and the reservoir energy cannot be effectively supplemented, leading to rapid production decline and low stage recovery. Based on the understanding of imbibition mechanism and the analysis of the main influencing factors, the technology and method of increasing reservoir energy and improving fracture-controlled volume are put forward. By referring to the core concept of volumetric fracturing technology, through the combination of laboratory experiments and numerical simulation, with the goal of increasing EUR of a single well, personalized fracture placement strategy was developed according to the fine division of reservoir types, the enhanced energy fracturing fluid system was optimized and evaluated, and the key parameters of the volumetric fracturing technology for fracturing and energy Enhancement were optimized. An integrated fracturing energy enhancement and production enhancement technology with the core of pre-frac energy supplement, multi-stage temporary plugging steering during fracturing, and post frac imbibition replacement is formed. The average daily oil gain in the initial stage of horizontal Wells tested in field is 19.0t, and the application effect is remarkable. This technology can provide technical reference for the efficient development of the same type of unconventional tight oil.

Particle bridging is ubiquitous in many fields of oil and gas field development engineering, such as fracture plugging for lost circulation control and proppant bridging as well as temporary plugging agent bridging in hydraulic fracturing. In this work, the resolved computational fluid dynamics coupled with discrete element method (Resolved CFD–DEM) is used to capture the formation and evolution of particle bridging structures in a T-shaped fracture, and to study the effects of inlet particle concentration, fracture geometry and friction coefficient of particle on the particle bridging behaviors in the T-shaped fracture. The results indicate that both threshold particle concentration and critical particle concentration are two important parameters to describe particle bridging and are significantly influenced by friction coefficient of particle and fracture geometry. Three-particle arch structure is the main particle bridging type when the ratio of particle size to fracture width is 0.5. With the increase in friction coefficient of particle, the mean formation time of particle bridging decreases. In this work, high-resolution numerical modeling of the particle bridging in a T-shaped fracture is realized based on the resolved computational fluid dynamics coupled with discrete element method, and can be used to provide theoretical guidance for temporary plugging and diversion fracturing and lost circulation control in fractured reservoirs.

The super deep fracture-cavity carbonate reservoir in Tarim Basin has copious amounts of oil and gas, in which karst cave is the main reservoir space. It is necessary to communicate with karst cave through hydraulic fractures to realize efficient development due to the deep burial, poor physical properties, random distribution of natural fractures and caves, complex location relationship between wells and caves. Therefore, it is of great significance to study the hydraulic fracture propagation mechanism in fracture-cavity carbonate reservoir. In this research, a novel laboratory simulation method for water injection propagation was established based on true tri-axial hydraulic fracturing equipment. Using this method, the law of fracture connecting cave under different experimental conditions were analyzed, and the relationships between water injection volume and cave volume were clarified. The results show that: low stress difference, small included angle (between cave and horizontal maximum stress) and the use of temporary plugging agent have huge contribution to improve the number of caves that connected with hydraulic fractures; the critical turning condition of hydraulic fracture is sensitive to factors such as the position relationship of well and cave, horizontal stress difference and included angle. This study has certain theoretical guiding significance for fracturing design and water injection parameter optimization in fracture-cavity carbonate reservoir.

Multi-cluster fracturing technology of horizontal well has become an important means for effective development of tight oil reservoirs. However, the influence of engineering parameters and perforation parameters on multi-cluster fracture extension is not clear. Based on the multi-cluster fracture propagation model considering the effects of hole abrasion and induced stress field, the influence of different proppant concentration,fiuid displacement and perforation cluster parameters on fracture propagation morphology was studied in tight oil block X in Daqing Oilfield. The results show that: (1) With the increase of proppant concentration, the abrasion degree of pore diameter increases and the propagation uniformity index of multiple fractures decreases.(2)With the increase of fluid displacement, the abrasion degree of pore diameter increases, and the propagation uniformity index of multiple fractures first increases and then slightly decreases. (3) With the decrease of the number of single cluster holes, the uniformity index of multi-cluster fractures increases gradually. The overall low perforation density in multi-cluster fracture stages is conducive to the uniform propagation of multi-cluster fractures. (4) With the decrease of the aperture, the uniformity index of each perforating cluster increases. Appropriately reducing the perforating aperture can effectively balance the negative effect of stress induced by multi-cluster fractures, which is conducive to the uniform propagation of multi-cluster pressure fractures within the segment. This research method and theory can provide certain reference and guidance for the effective development of similar tight oil reservoirs.

The paleo-central uplift zone in the northern Songliao Basin is the key area of risk exploration because of the wide realm and bright prospects for the exploration of gas and oil. The reservoir has the characteristics of complex lithology and compact matrix structure which make the poor result of well stimulating using conventional fracturing and low exploration level. We shall, therefor, explore targeted fracturing measures to improve the reservoir connectivity. We analyzed and compared the influence of different geological and engineering parameters in hydraulic fracturing, in order to maximize the effect of fracture reconstruction in basement rock fractured reservoir. In this paper, the large-scale true triacial hydraulic fracturing simulation system is carried out to analysis the influencing factors of fracture propagation in basement rock fractured reservoir and provide an important reference for optimization design of fracturing construction.

In view of the problems such as eccentric wear of pipe and rod and short pump inspection cycle in the application of rodless oil production technology in Jiyuan low permeability oilfield, 6 rodless oil production technology tests wells of coiled tubing electric submersible pump are carried out in G43 and G155 blocks. The comparison with the rod production process shows that the pump inspection period of the rod less oil production process is significantly extended, and the average pump inspection period of the four comparable oil wells is extended from 127 days to 219 days, which is still effective. The rodless oil production technology can effectively reduce the frequency of pump inspection, improve the production rate, and indirectly reduce the cost of wellbore maintenance and downhole operation. The daily power consumption of rodless oil production technology is greatly reduced, and the effect of energy saving is obvious. On average, 71.4KWh of electricity was saved per day for a single well, 428.6 KWh of electricity was saved per day for six wells in total, and 54000 yuan of electricity was saved in stages, which still kept stable operation. The rodless oil production technology of coiled tubing electric submersible pump occupies less land and is simple to install. Through optimization of the technology, the adaptability is improved and the application prospect in Jiyuan Oilfield is good.

Guar gum and high viscosity slippery water are the most widely used fracturing liquid system in ultra-low permeability reservoir of Changqing Oilfield, and which produced amount of backflow liquid. In view of its high treatment cost, incomplete gel-breaking resulting in secondary pollution of reservoirs and other problems, a clean fracturing liquid system has been invented. The experimental results show that the gluing time of the fracturing fluid is less than 20 s at water temperature 20 ℃. At the shear rate of 100 ℃ and 170 s−1, the viscosity is more than 50 mPa·s after 60 min, and the settlement speed of 20–40 mesh quartz sand under static is 0.056 mm/s. Compared with the reservoir damage of guar gum and high viscosity slippery water, the results show that the residue content of the clean fracturing liquid is 3.8% after gel-breaking, and the damage rate to the reservoir core is 8.14%. The compatibility between the gel-breaking liquid and the formation water is good and has no impact on oil and water emul. The clean fracturing fluid system has been popularized and applied in 8 wells and increased oil production 228 tons per well in that year. The average construction displacement was 2.5 m3/d, and the viscosity of the wellhead gel-breaking was 2.7 mPa·s in all test wells. The wells were put into production 2 days later, and the blowout liquid directly entered the ground collection and transmission system with three-phase separator operated normally. The practice shows that the clean fracturing fluid can realize non-flowback in the well site, which greatly reduces the cost of discharge treatment, and has good promotion value and prospects under the current environmental protection situation.

Foam drainage gas recovery technology is one of the most important technologies in drainage and gas production of shale gas wells. The effect of foam drainage which the main component of foaming agent is surfactant mainly depends on the type and performance of the foaming agent. In Jidong, Zhejiang and other oilfields, the salinity of formation water is high, which has strong inhibitory effect on the activity of surfactants. Therefore, it is necessary to select surfactants with high salt resistance as foaming agents. In this paper, we screened a foaming agent that can be dissolved and stable in the formation water with high salinity by evaluating the foaming ability, stability, liquid carrying capacity, compatibility and surface activity of four different types and concentrations of foaming agents with Roche foam tester, liquid carrying rate tester and other relevant instruments. The results show that the foaming agent has good foaming and stability, better liquid carrying capacity and surface activity, and it can be used less with higher economic benefits than others, which provides a feasible scheme for the selection of foaming agent in shale bubble drainage process.

Surfactants of various types are frequently used in the development of gas fields. It will result in significant emulsification of oil and water in the generated fluid. To achieve the goal of oil and water separation, the condensate emulsion must be demulsified. A nano-demulsifier based on nanocrystalline cellulose was created by grafting modification on its surface, and employed in the chemical demulsification process of condensate emulsion. The results showed that the produced demulsifier has a nanocrystalline cellulose fiber structure and good demulsification capability. The dehydration rate of condensate emulsion might reach 94% at the concentration of 0.5 wt.%. The demulsifier has a lower applied concentration, a better demulsification effect, and a higher separation efficiency when compared to commercial products. It will effectively handle the demulsification problem of gas field condensate emulsion and give technological support for long-term and steady gas well production.

Deployment of infill horizontal wells is an effective way to further tap the remaining reserves between potential wells and enhance oil recovery. However, compared with the initial volume fracturing of horizontal wells, the fracturing impact during infill well fracturing seriously affects the production of old wells and the effect of infill well reconstruction. However, the fracturing impact can be effectively avoided and the balanced expansion of infill well fractures can be achieved through the injection of liquid energy into old wells (parent wells). Taking the deployment area of infill well in well block Ma 131 of Mahu tight conglomerate reservoir in Xinjiang as an example, through reservoir geostress field simulation, explore the effect of water injection energy enhancement on reservoir geostress field and pore pressure field, and then take particle size distribution, reducing oil-water interfacial tension and static permeability displacement as performance evaluation indicators, select nano-surfactants for energy enhancement of old wells, and finally based on numerical simulation and indoor evaluation results, Optimize and design the nano-flooding synergistic fracturing scheme for 3 old wells and 2 infill wells. The simulation shows that the in-situ stress field and pore pressure field can be effectively reconstructed by injecting water of 0.75 –1 times deficit volume in the old well; The laboratory experiment shows that the average particle size of G-2 nano-surfactant is 73.6 nm. When the mass concentration is higher than 0.2%, the oil-water interfacial tension can be reduced to 10−2mN/m, and the static imbibition flooding efficiency of 0.2% concentration can reach 28.35%; The field application results show that the average daily oil production of three old wells is 93% higher than that before the energy increase, and the average daily oil production of two infill wells after fracturing is more than 20t, with significant effect. The relevant research can provide technical reference for improving the development effect and greatly improving the recovery factor of Mahu tight conglomerate and similar reservoirs.

Effective evaluation of the ability of reservoirs to form complex fracture networks is the foundation for shale oil extraction. Currently, there is no effective evaluation method or system developed domestically or internationally. At present, the brittleness coefficient is commonly used domestically and internationally to characterize the compressibility of shale oil reservoirs, but brittleness is not sufficient to characterize the compressibility of reservoirs. The Yingxiong Ridge shale oil reservoir has the characteristics of strong heterogeneity, large horizontal two-phase stress difference, undeveloped natural fractures, and relatively developed bedding. In order to accurately identify the engineering dessert interval, a comprehensive compressibility model was established, and matrix brittleness evaluation index, horizontal stress difference index, and fracture development index suitable for the Ganchaigou of the Yingxiong Ridge were proposed. Research has shown that although the lithology of the Yingxiong Ridge shale oil is complex and the horizontal two-phase stress difference is large, But the content of brittle minerals is high, microcracks are relatively developed, and the overall compressibility is good. Applying this method to evaluate the compressibility of CP1 well and selecting fracturing intervals based on geological desserts is of great significance for guiding the volume fracturing of shale oil horizontal wells.

With the deepening of oilfield development, Daqing Oilfield has applied the short-radius lateral drilling technology in the horizontal well on a large scale to solve the problem that the development effect of remaining oil with conventional measures are not ideal, due to the fault barrier, interwell oil remaining and oil uncontrolled by well pattern. The field test results show that the short-radius lateral drilling technology in the horizontal well is inapplicable to the ultra-low permeability reservoir development. With the increasing number of wells in different types of reservoirs, stimulation measures such as fracturing are needed to achieve an average daily-increment oil of more than 3 tons per well.In order to improve the stimulation effect of lateral drilling technology in ultra-low permeability reservoirs, a variety of technical tests, such as proper scale fracturing, large scale fracturing, and positioned multistage fracturing, have been taken. Different stimulation measures and scales have achieved incremental oil effect. Therefore, the optimal design method of fracturing technology in lateral drilling wells of different reservoirs has been established to realize the precise stimulation of low permeability or ultra-low permeability reservoirs.The field test results show that the fracturing technology applied in lateral drilling to horizontal well of ultra-short radius can realize the directional stimulation of the fixed reservoir. This technology can also improve the seepage area of the low permeability reservoir effectively and provide a powerful technical means for the remaining oil development in Daqing oilfield.

Horizontal Wells of intermediate-basic volcanic gas reservoir in Songliao Basin have low production after fracturing and weak stable production ability. How to set fracture spacing reasonably and improve recovery percent is the key to increase production. Based on the seepage theory, three methods of productivity maximization, orthogonal factor Z-value maximization and seepage interference theory are used to study and analyze the reasonable fracture spacing matching relationship between reservoirs with different permeability conditions.The results show that, with the decrease of fracture spacing, the recovery percent increases, but the growth is getting smaller and smaller. When the fracture spacing decreases to a certain value, the recovery percent is very small with the increase of fracture spacing, which is called the critical fracture spacing (90% of the maximum recovery percent), and the smaller the reservoir permeability, the smaller the critical fracture spacing. In a certain permeability level, there is an optimal fracture spacing value, the best fracturing effect. The optimal fracture spacing chart of intermediate-basic volcanic rocks was established and the functional relationship between the optimal fracture spacing, corresponding optimal recovery percentand reservoir permeability was fitted, which can provide reference for the optimization design of fracturing process parameters of similar reservoir.

In the nanoscale pore mud shale reservoir in Daqing, proppant embedded prone to make artificial fracture diverting capacity, therefore, to develop different closure pressure, concentration of different particle size and composition, sanding proppant’s influence on the flow conductivity of the experiment, analyze the effect of mud shale reservoir proppant embed change rules of flow conductivity. The results show that, with the increase of closing pressure, the embedment and flow conductivity both decrease to different degrees. The flow conductivity decreases rapidly in the range of 0–10 h. After 30 h, the flow conductivity basically reaches a steady state, the morphology between particles is stable, and the flow channel changes little. Different particle size of proppant on closure pressure is low, diverting capacity difference is very big, the particle size, the greater the conductivity will be high, with the increase of closure pressure, large diameter occurred more broken, different particle size of proppant diverting capacity gap is also gradually reduced, at the same time, increasing the sanding concentration can significantly reduce the embedded degree of proppant. Studying the quantitative influence of proppant embedment on fracture conductivity can provide a basis for optimization of fracturing scheme and parameter design of shale reservoir.

Tight oil reservoir in Daqing oilfield has low permeability, small pore throat radius, high gelatinous and waxy content of crude oil in the reservoir, and low fluidity of crude oil. Conventional guanidine gum fracturing fluid used in hydraulic fracturing has some problems, such as poor reservoir adaptability, low utilization degree and fast production decline. In this paper, through the research of oil displacement viscosity reduction fracturing system, micro and nano oil displacement agent and viscosity reduction agent are organically combined to reduce the interfacial tension, so as to achieve the wettability effect of tight oil reservoir, and obtain the oil displacement viscosity reduction system XYJ01 with good oil displacement and viscosity reduction effect. Performance evaluation experiments were carried out on the amount of displacement viscosity reduction system, core permeability and the influence of different fluids on the efficiency of self-imbibition and oil washing, and the compatibility of fracturing fluid, reservoir rock and reservoir fluid was comprehensively analyzed. The experimental results show that when the oil displacement viscosity reduction system is 0.20%, the self-imbibition efficiency reaches 17.62%. With the increase of water content, the viscosity reduction effect becomes more obvious. When the oil-water ratio is 7:3, the emulsification viscosity reduction rate can reach 36.23%. The displacement viscosity reducing system has no effect on the rheological property of fracturing fluid and the performance of suspended sand. The oil displacement viscous-reducing system has good compatibility with reservoir rocks. After the addition of oil displacement viscous-reducing system, the damage of fracturing fluid to reservoir core is reduced to a certain extent. It is proved that the hydraulic fracturing fluid system with oil displacement and viscosity reduction has obvious effect on the fracturing reconstruction of tight oil reservoir, which is conducive to improving the oil and gas recovery efficiency of tight oil reservoir and realizing the efficient exploitation of tight oil.

In the process of oilfield development, some casing-damaged wells occur, and the remaining oil controlled by them requires fine subdivision fracturing to tap the potential. Developed Φ95 mm small-diameter packer, added additives to rubber barrels, optimized the combination of cords, and combined the steel body with the salt-bath graded quenching heat treatment process to improve the overall pressure-bearing and fatigue resistance of the packer. At the same time, a small-diameter pressure guiding Sandblaster, the sandblasting port adopts the oblique section porous structure design, which reduces the abrasion. The oil pipe blowout prevention valve is designed, and the repeated switching and sealing mechanism are optimized. Through the indoor and field evaluation tests, the casing-damaged wells with finely divided fracturing process as a whole achieved a temperature resistance of 120 °C and a pressure of 70 MPa, the sand volume of a single set of sandblasters was 230 m3, and there were 11 stages of subdivision fracturing in a single trip, it can be suitable for fracturing wells with casing damage over Φ100 mm, and has been applied to 106 wells in Daqing Oilfield. The technology has successfully solved the technical problems of wellbore shrinkage after casing damaged well repair, fracturing tools need to take into account the technical problems of small diameter, high passing capacity and fine layered fracturing. The network improvement has played a positive role, and the process can also be extended to fine layered fracturing of small cased wells with the same well diameter.

The main problem K Oilfield is the formation degassing and rapid decline in production caused by insufficient formation pressure. The main problems of the early acidizing process in K oilfield are low acidizing intensity, large reservoir thickness and general transformation, resulting in small stimulation radius, uneven vertical transformation of reservoir and low efficiency of measures. In order to improve the transformation effect, it is proposed to increase the acid adding strength to increase the stimulation radius, and adopt the diverting acid process to improve the vertical transformation uniformity of the reservoir. Through practice, it is recognized that increasing the distance between the upper edge of the perforation and the oil and gas interface is conducive to reducing the production gas-oil ratio, but the long-term gas-oil ratio control still needs to supplement the formation energy; Increasing the strength of acid addition and the length of wormhole can effectively increase the yield and improve the effect of stable yield, and the economic benefits are considerable; The long acidizing and acid fracturing drainage period of old wells is related to the remaining oil saturation near the well zone and the insufficient formation energy; Multiple rounds of acidification failed to effectively act on the deep part of the reservoir, and the acidification effect gradually decreased.

Shale oil was first identified in the upper member of Paleogene Lower Ganchaigou Formation of Yingxiongling area, Qaidam Basin in 2021. It is a low porosity and ultra-low permeability reservoir, which needs to take fracturing stimulation measures to obtain industrial oil flow and development value. It is an effective way to develop shale oil in this area to “break reservoir” and improve reservoir seepage capacity through horizontal well volume fracturing technology. In the process of horizontal well volume fracturing, it is difficult to evaluate the engineering sweet spot accurately. This greatly affects the effect of fracturing. The techniques of mineral composition analysis, rock mechanics experiment and fracability evaluation of reservoir are studied and applied. Based on micro-hyperspectral test and micro-nano indentation test, the mineral element composition, content and rock mechanics parameters are obtained by scanning, testing and analysis of rock cuttings. Combined with the characteristics of Yingxiongling shale oil reservoir and previous fracturing experience, based on logging interpretation and rock cuttings gene scanning test results, The brittleness index, horizontal stress difference coefficient and micro-fracture density were taken as the evaluation indexes of fracturing performance, and the weights of the parameters was determined by the analytic hierarchy process (AHP). A fracability evaluation model suitable for Yingxiongling shale oil was established, and the evaluation technology of engineering sweet spot with “cuttings mineral analysis technology and fracturing analysis technology” as the core of Yingxiongling shale oil in Qaidam was formed. After the application of the engineering sweet spot evaluation technology, the average daily oil production of vertical Wells reached 14.7 tons and that of horizontal Wells reached 55.23 tons. It helped make new breakthroughs in shale oil exploration and development.

Tight glutenite reservoirs are rich in resources and have bright prospects for exploration and development. Its basic characteristics are large oil-bearing coverage area of the reservoir, strong heterogeneity, low natural productivity, and difficult development. At present, volumetric fracturing technology of horizontal wells is the main production method. Optimizing fracture parameters and increasing stimulated reservoir volume are important in the long-term and efficient development of tight glutenite reservoirs. Based on the characteristics of tight glutenite reservoirs, the fracture complexity after fracturing and fluid mechanics, the mathematical equations for gas and water phases of artificial fractures, micro fractures and matrices, and numerical model of tight glutenite reservoir are established. On this basis, the three main factors affecting the stimulated reservoir volume of tight glutenite reservoirs are studied. The results show that: long fractures can effectively improve the stimulated reservoir volume for low permeability reservoirs; increasing the stage distance can effectively improve the stimulated reservoir effect for high-permeability reservoirs; tight gas reservoirs do not need too high conductivity. The research results of this paper have certain theoretical significance and provide important basis for the design of fracturing schemes for tight glutenite reservoirs.

Tight sandstone gas reservoir is a very important unconventional oil and gas resource, but its reservoir physical property is poor, permeability is low, and exploitation is difficult. The existing fracturing and completion process can no longer meet the on-site technical requirements. According to the reservoir characteristics of Xujiahe Formation and Shaximiao Formation in Hechuan Gas Field, vertical well high-pressure and large-displacement multi-layer fracturing string and vertical well high-pressure and large-displacement multi-layer fracturing gas lift string are designed. The critical tool is Y344 self-releasing pressure-guided sandblasting packer, which integrates abrasion resistant, sealing and self-releasing functions. Large-scale fracturing construction was carried out on the site, and the results show that the two fracturing completion processes and reservoirs are highly compatible, it can not only meet the requirements of “large displacement”, but also ensure the safety and reliability of the pipe string. To provide technical support for the development of Shaximiao and Xujiahe reservoirs in Sichuan and Chongqing areas.

The oil production technology of PCP has the advantages of low investment costs, less area occupancy and high system efficiency, but due to the serious eccentric wear of rod and tubing, which restricts the further expansion of the application scale. The matching rod and tubing reducing eccentric wear technology is formed by improving the supporting process of the PCP. Firstly, the anti-rotation torque anchor is used to replace the support clips, to stretch the tubing column naturally, reducing the contact probability of the rod tubing and avoid partial eccentric wear; Second, the internal sprayed tubing is applied to improve the anti-friction ability and prolong the service life. Indoor experiment shows: the dynamic test platform is used to test torque, when the torque is 4000 N $$\cdot$$ · m, the anti-rotation torque anchor and casing have no relative sliding and the process is reliable. Ordinary N80 pipe, internal sprayed tubing and plastic lined tubing were tested by MC-2000 friction testing machine, the friction amount of the internal sprayed tubing is 0.82 mm and the sucker rod coupling is 0.006 mm, which are the lowest in different sorts, the wear resistance and self-lubricating performance of the internal sprayed tube is verified. The field application of 57 wells, 7 wells with anti-rotation torque anchor extended the pump inspection cycle by 282 days, 50 wells of internal sprayed tubing extended the pump inspection cycle by 149 days. The anti eccentric wear technology of PCP had reduced the number of operations, which can be further promoted and applied.

The existing screw pump anti-rotating anchor can only one-way limit screw pump rotation, positive screw pump and reverse screw pump need to equip with anti-rotating anchor separately, and no having blowout prevention function, in the construction of the liquid is easy to spill out of the wellhead, causing pollution of the environment, at the same time the production of a certain security risks. For this reason, the development of screw pump two-way anchoring blowout preventer anchor, which is composed of central pipe, elastic ring, rotating shell, moving slip, fixed shell, fixed slip, bolt; Circumferential slide way is arranged on the rotating shell of anti-rotating anchor. The rotating shell drives the moving slip to rotate in both directions. The Angle between the moving slip and the fixed slip ranges from 0 to 135˚. Eight Wells were successfully anchored at one time. The average operation time was 542 days. No failure occurred during the operation, and the repeated utilization rate was 100%. With the continuous improvement and application of two-way anchoring anti-rotating anchor, the convenience, safety and reliability of screw pump well construction can be effectively improved, and the efficient lifting of screw pump well can be well realized.

Aiming at the problem that a new type of all metal soluble bridge plug metal sealing ring is not tightly sealed, resulting in the overall pressure bearing performance of the bridge plug not meeting the design index, simulation analysis, size optimization, and experimental verification of the sealing performance of the metal sealing ring were carried out. Using finite element analysis software, the cone, metal sealing ring, auxiliary ring, and casing models were established to analyze the pressure bearing performance under sealing conditions. It was concluded that the direct reason for the failure of the bridge plug pressure to meet expectations was the low maximum contact stress between the metal sealing ring and the casing, and the poor sealing effect. In order to improve the sealing effect of the metal sealing ring and the overall pressure bearing performance of the bridge plug, the structural dimensions of the metal sealing ring were optimized. Based on the optimized size of the metal sealing ring, a pressure bearing laboratory test of the bridge plug prototype was conducted. The test results showed that the pressure bearing capacity of the bridge plug was 90 MPa without leakage, and the sealing effect was good, meeting the pressure bearing index requirements. This study provides a reference basis for the structural design of metal sealing rings for all metal soluble bridge plugs.

The flow path for hydraulic fracturing is usually generated in the toe position of one long-reached horizontal well by perforation using coiled tubing, which exhibits high deploying risk and operation cost. Some foreign toe sleeves have been introduced to domestic oil and gas fields to form first flow path instead of complicated intervention such as perforation. The drawbacks including expensive service and low reliability have negative effect on large-scale applications of traditional toe sleeves. Research Institute of Petroleum Exploration and Development (RIPED) innovatively developed delayed-opening toe sleeve with dissolvable components. The time-delay controlling component based upon dissolvable alloy will degrade after contacting with down-hole fluids. The pressure test of casing can be performed during degrading of the components and the sleeve can be finally activated to form the flow path between wellbore and reservoir. With the adjusted dissolvability the delay period is able to be modified to meet the demand on customizing pressure test. As one alternative to current technique like perforation, the toe sleeve with dissolvable components exhibits the advantages of high flow rate, high reliability, adjustable time delay and low-pressure specification of embedded rupture discs. The novel toe sleeve performs flow-path opening of the first stage with temperature rating of 150 ℃, pressure rating of 120 MPa and delay-time range of 30–60 min with three different specifications of 4.5 in, 5 in and 5.5 in. The field trials of delayed-opening toe sleeves have been carried out in five wells of unconventional resources so far without any failure in the toe depth. This paper proposed the technique solution of delayed-opening toe sleeve, workbench qualification and field validations in unconventional reservoirs including shale gas and shale oil. Furthermore, future trend of casing toe valves is also put forward in this paper.

The heavy oil block in Dagang oilfield has high viscosity and poor flowability, which easily causes organic plugging in the wellbore during production, leading to difficulties in lifting and transportation. It is also easy cause pump blockage and self-shutdown, leading a short free period for maintenance for single well. Additionally, due to poor flowability, the crude oil in reservoir easily forms organic plugging in the near-wellbore area, affecting the production rate of single well, even shutdown of single well.Through crude oil property analysis, screening of viscosity reducers, and performance evaluation of formula systems for reservoir protection, a heavy oil dispersing and reducing technology has been developed. This technology can significantly reduce the viscosity of heavy oil, with a viscosity reduction rate of over 96% at 50 ℃ and a viscosity reduction rate of 94.9% at 20 ℃ under flowing conditions. The surface tension of the system is low, with an anti-swelling rate of over 90%, and a washing oil rate of over 90%. It also has good compatibility with formation water. Supporting technologies include viscosity-reducing injection, manual dosing, and online viscosity reduction processes. This technology has been applied to 44 wells using three injection methods, with a 100% effective rate, significantly reducing the viscosity of crude oil and achieving cold production and transportation of heavy oil, effectively extending the interval for individual well maintenance and ensuring safe and stable oil production.

Accurate acquisition of rock mechanics parameters for unconventional reservoirs is a very important work in fracturing design. Glutenite is a typical strongly heterogeneous reservoir. The rock mechanical properties of gravel and matrix in glutenite are quite different due to the differences in mineral composition. However, due to the limitation of experimental conditions, the research on mechanical parameters of gravels is relatively lacking. This article establishes a new micro-scale method for measuring the mechanical parameters of irregular gravels, and this method compensates for the shortcomings of conventional mechanical instruments that cannot measure the mechanical parameters of non-standard samples such as gravels. The load-displacement curve of each gravel is measured by the micron indentation instrument, and the microscopic Young’s modulus and microscopic fracture toughness of gravels are calculated by the relevant formulas. Based on the experimental statistical data, a converting method is used to obtain the macroscopic Young’s modulus and macroscopic fracture toughness of gravels. Taking the glutenite reservoir in the Western China as an example, the macroscopic Young’s modulus of gravels is calculated to be 9824 to 17014 MPa, and the fracture toughness ranges from 0.777 to 1.846 MPa·m0.5. The results show that the mechanical parameters of gravels are generally stronger than those of matrix. The method established in this paper can not only be applied in glutenite reservoirs, but also provides a new idea for determining the distribution of rock mechanical parameters in all heterogeneous reservoirs. Moreover, this method has low cost, less time consumption, and has strong promotion value.

Massive hydraulic fracturing in horizontal wells plays significant role in high-efficient recovery of unconventional oil and gas reservoirs. Besides Plug & Perforation (PnP) process, Packer & Sleeve (PnS) multi-staged fracturing and Cemented Casing Sleeve (CCS) multi-staged fracturing technology were also widely used in the unconventional fields. Ball-activated sliding sleeve is one key tool frequently applied to perform selective completion and massive fracturing. However, down-hole intervention and milling-out job for ball seats are required which leads to drawbacks of high operation cost and low efficiency. In addition, CO2 fracturing gradually draws attention of operator for well productivity and recovery enhancement. Down-hole BHA is faced with corrosion issue. One innovative sliding sleeves with dissolvable ball seat was developed as the alternative to existing tools. Two different materials were proposed in this paper. The matrix body of ball seat using magnesium-aluminum-based dissolvable alloy or iron-based dissolvable alloy was evaluated in the lab according to mechanical properties, anti-corrosive and anti-erosive properties. Surface treatment was performed by plasma spraying process to form tungsten-carbide protective coating. Magnesium-aluminum-based dissolvable alloy was characterized with compressive yield strength of 640 MPa. Iron-based dissolvable alloy features with Vickers hardness of 300 HV, compressive yield strength of 760 MPa and slower dissolving rate of 4.3 mm per year. Sleeve prototypes were validated in the lab with maximum holding pressure of 74 MPa when engaging with balls. After ball seat dissolves completely, sleeve I.D. reaches 90 mm. As a slow-dissolvable material, modified iron-based alloy is considered as the optimal candidate. In field trial, one PnS multi-stage fracturing string with four new sleeves was tripped into one mature oil well. Ball engaging with seat, activating sleeve and proppant pumping were successfully performed in fracturing operation. Almost no ball-seat fragment was found in the flow-back fluid. It is proven that the novel technology exhibits advantage of corrosion resistance prior to fracturing, erosion resistance during fracturing and intervention less operation such as milling-out job of ball seats.

For the water-producing sand gas well, the law of gas-liquid carrying sand flow in the wellbore is the key basic problem in the process of carrying sand production. In order to master the law of gas-liquid carrying sand flow in the wellbore and its influencing factors, an experimental study on the law of gas-liquid carrying sand flow is carried out for the single section wellbore. In order to guide the engineering design more intuitively, the critical gas flow rate in the shaft is defined when the gas flow rate is lower than a certain limit value. The gas-liquid two-phase sand carrying experiment shows that the sand particle is completely entrained in the liquid phase, and its movement law is related to the liquid transport speed. The key to whether the sand particle deposit lies in the average transport speed of the liquid phase and the average sinking speed of the sand particle. In the process of gas-liquid two-phase sand carrying, the liquid flow rate is the main control factor of the critical gas flow rate of sand carrying. The greater the liquid flow rate, the smaller the critical gas flow rate of sand carrying. Overall, the inclination angle has a relatively small effect on the critical velocity of gas-liquid two-phase sand.

In response to the problem of low production and low energy in the late production period of volume fracturing transformation of horizontal wells in tight oil reservoirs, energy-enhancing water injection and throughput technology is proposed. In order to solve the problems of poor throughput effect, rapid production decline and limited recovery improvement, the study on the mechanism of oil enhancement and the influence factors of multi-round energy-enhanced water injection and throughput were carried out. Based on a tight oil block in an oil field, we analyzed the pore structure characteristics of the reservoir using high-pressure mercury pressure technology and nuclear magnetic resonance technology. Comparative experiments were conducted to analyze the elastic and percolation-displacement mechanisms in the throughput process. The effect of each factor on the recovery rate was investigated at core scale and single well scale through multiple rounds of indoor experiments and numerical simulations of energy-enhanced water injection and throughput. The results show that the target block is a dense mesoporous reservoir, and the 1–3 rounds are highly efficient oil recovery stages, with elastic drive contributing the main recovery. The recovery rate shows a parabolic relationship with the injection pressure, which increases and then decreases; with the increase of the transfer pressure, the recovery rate increases and then decreases; in a certain range with the increase of the fracture density, the recovery rate gradually increases. Numerical simulations of single-well-scale horizontal fractured well injection and throughput concluded that the fracture network density is the key parameter to improve the recovery of low-permeability reservoirs, and injection pressure and stewing time are the main parameters affecting the recovery rate. The paper further analyzes the oil enhancement mechanism of multi-round energy-enhancing water injection and throughput, clarifies its main control factors, and provides implications for the subsequent program optimization..

In order to achieve economies of scale build productivity of polymer flooding upturn development, based on geological characteristics and mining status, aiming at the development difficulties of the injection and production well of class II reservoir in La oilfield, such as high completion cost, complex well condition and difficulty in plugging, and high energy consumption of conventional pumping unit, oil production engineering scheme revolves around the guiding ideology of “design the most efficient scheme with the best technology”. In accordance with the concept of promoting new technologies to improve development effects and benefits, the key oil production processes are considered and systematically optimized, and the combination of large pore volume and deep penetration perforating technology, expansion tube plugging technology, and ultra-long stroke oil production technology are optimized. Field implementation showed that through the comparison of the whole process, multi-dimension and multi-scheme optimization and technical and economic analysis, the well completion investment was saved 11.25 million yuan, the plugging investment was saved 20.4 million yuan, the later production and operation cost was reduced 440,000 yuan, and the accumulated oil increase was 97,800 tons, achieving a good development effect. It has formed a series of supporting technology of oil recovery engineering suitable for the economical and effective development of the Class II reservoir, which provides a technical reference for the excavation of latent remaining oil from the third stage of oil recovery in the old area of Chang yuan, and plays a leading role in oil production engineering scheme.

For the early drilling completion time of L gas storage wells in Daqing and the material selection of casing without considering the long-term anticorrosion demand, the corrosion failure of casing after many years of service caused surface gas leakage. In order to clarify the corrosion failure mechanism of casing, the fracture of casing thread was analyzed by macroscopic and microscopic morphology observation, physical and chemical properties, energy spectrum and XRD detection after sampling. The results show that the crack of casing thread is stepped along the circumference. The mechanical properties and chemical composition near the fracture were in line with the relevant standards, and the metallographic structure was not abnormal. The corrosion products near the fracture contain ferrous sulfide, and the fracture morphology shows that the fracture source region has typical brittle fracture characteristics of intergranular leavage. Combined with the analysis of casing service condition, it is considered that the cracking of casing thread is the stress corrosion cracking caused by the contact between hydrogen sulfide gas inside the casing and the water outside the casing at the gap between the top and bottom of the thread teeth after the tightness of the thread decreases, which is caused by corrosion environment and axial tensile load. At the same time, the paper puts forward some suggestions on corrosion protection measures for L gas storage well, which can guarantee long-term production safety of L gas storage well.

Daqing Gulong shale oil has newly increased proven geological reserves of 1.268 billion tons, which is an important replacement resource for the construction of a century-old oilfield. The timely pumping of shale oil well after fracturing can effectively maintain the reservoir energy and extend the well life. Due to the high wellbore pressure after fracturing, there is a bottleneck problem that can not be pumped into production in time. The existing blowout prevention technology has blowout prevention defects, which can not meet the high-pressure blowout prevention needs of shale oil. Therefore, based on the technical idea of “reliable high-pressure sealing and effective repeated opening and closing”, the metal and non-metallic double sealing blowout prevention mechanism was innovatively designed to ensure the effective repeated opening and closing. The chip mounted carbide slip mechanism was invented to achieve reliable anchoring of high hardness casing. The blowout prevention tool can bear the pressure of 35 MPa and the temperature of 120 ℃. Six wells were tested in Gulong shale oil field. The success rate of blowout prevention was 100%, and the success rate of fishing was 100%. The blowout prevention of the whole wellbore was effectively realized, providing technical support for green, efficient and low-cost operations of early pumping and production and subsequent pump inspection after fracturing.

In the daily production of oil field, the theoretical displacement of pumping unit can be changed by optimizing and adjusting the production parameters of pumping unit, that is stroke and frequency of stroke, and then the pumping intensity can be adjusted to ensure the efficient production of oil wells. After years of development in Y block of X Oilfield, the production conditions of production wells are constantly changing and the operation rules are becoming more complicated due to various factors such as the demand of development situation, the change of injection-production mode and the change of replacement mode. The simple adjustment mode of increasing parameters with high flowing pressure and decreasing parameters with low flowing pressure cannot effectively achieve the purpose of adjusting the pumping intensity, resulting in some wells with no drop in flowing pressure with parameter increasing and no rise in flowing pressure with parameter decreasing, as well as a significant increase in energy consumption of the system after adjustment. At the same time, with the demand of controlling production cost and reducing cost and increasing efficiency, improving production well system efficiency and reducing energy consumption have become the key tasks of oil recovery engineering in recent years. As energy-saving equipment gradually becomes popular, the potential for energy saving from process modification gradually decreases. How to optimize and reduce energy consumption under the most basic production management mode has become a new research direction. In this paper, we analyze the optimization method of production parameters with the highest pump efficiency as the core, and through the comparison of theoretical calculation and experimental results, we find the way to achieve efficient operation of oil wells by optimizing production operation parameters on the basis of not affecting production and not increasing input.

As an important component of unconventional oil and gas, shale gas has gradually become a hot spot in the world’s energy development in recent years. Sichuan Basin, with 44.39 trillion cubic meters gas amount, accounts for 51.3% of China's shale gas geological resources. However, the tubing corrosion such as perforation and fracture frequently occurred in the development of shale gas well. The tubing may even fail within 57 days, which seriously threatened wellbore safety.This paper summarized the downhole corrosion situation of typical shale gas blocks in Sichuan Basin. The main influencing factors and corrosion types were analyzed by scanning electron microscope (SEM), X-ray energy dispersive spectroscopy (EDS) and X-Ray Diffraction (XRD) technologies, and the corresponding corrosion mechanism was explained. In addition, the main detection technologies of wellhead/ wellbore corrosion and application effects in shale gas wells of Sichuan Basin were emphatically introduced. The application effect of ultrasonic energy spectrum leak detection technology was evaluated in the typical case well.The results showed that: (1) The main corrosion types of tubing in shale gas well were SRB corrosion and CO2 corrosion. Tubing corrosion mainly occured in the upper part (0–1000 m) and the middle part (2000–2500 m). The upper corrosion part of the tubing was mainly caused by the coupling effects of SRB corrosion and CO2 corrosion, while the middle and lower parts was mainly caused by CO2 corrosion. (2) The wellhead corrosion testing results showed that the overall wall thickness of each wellhead valve was uniform; (3) The source of B annulus sustained pressure in the Well X was identified by the ultrasonic energy spectrum leak detection technology.Through comprehensive analysis, for those wells that have been put into production with tubing in the early stage, it is necessary to regularly conduct wellhead and wellbore corrosion testing to get the service status of the well barrier; For those wells without tubing, further research on tubing material selection and anti-corrosion technology should be conducted to prevent tubing corrosion.

It has been nearly 30 years since China petroleum entered into overseas cooperative development. The Middle East and Central Asia are the main cooperative areas, and carbonate reservoirs are the main reservoir types. After more than 20 years production, most projects have entered the late stage of oil and gas field development. High output, high water cut, high recovery, and low production rate, low pressure and low efficiency are the recent facing development problems. How to tap the potential of remaining oil economically and effectively is a key point that restricts the sustainable and efficient development of oil and gas fields.Through reservoir static evaluation, reservoir numerical simulation, reservoir elaborate description, residual oil and dominant channel inversion, the remaining oil enrichment area is optimized and determined, and the targeted development strategy is determined. The technical system of directional sidetracking and staged completion, staged fracturing, integrate production system of old wells was established. Corresponding key tools, such as large-size and high-pressure gas lift valves were developed. Aiming at the residual oil in the thin layer, low permeability and low pressure area at the edge of the structure, the key tools and technical system of coiled tubing drag acid-fracturing are developed. The integrated stimulation technology series of reservoir, drilling and completion, fracturing and gas lift oil production is established.The directional tapping technology of residual oil in carbonate reservoir has been applied in Central Asia project for 42 wells. The oil production has been increased by over 450,000 tons. It is of great practical significance to achieve the aim of effective development of residual oil and gas in reservoir.

Shale gas is an important unconventional energy. Because of its special geological structure and complex well depth structure, it is difficult to exploit and will produce wellbore fluid accumulation in the production process. These problems can be effectively solved through drainage and gas production technology. Foam drainage-gas recovery technology is a relatively mature technology, which is widely used in major shale gas fields in China and abroad. The critical part of the technology is the selection and filling of foaming agent. For the foam drainage gas production technology for shale gas wells, investigated the technical status, studied the process optimization method and foam drainage agent injection method, and introduced the latest intelligent foam drainage and composite drainage and production technologies which are based on the characteristics of shale gas. Besides that, the article described the characteristics of foam drainage agent are summarized, and the preparation and application of high-performance composite foam drainage agent with temperature resistance, salt resistance, acid resistance, good stability and strong liquid carrying capacity and proposed the development direction of intelligent foam drainage, combined drainage technology and composite foam drainage agent. This research provides references for the foam drainage-gas recovery technology in shale gas wells in China.

Research of data processing technology in water injection is carried out in order to solve the issues that the injection data of RML oilfield is not complete and can not carry out the analysis and optimization of single well injection. PROSPER software is used to establish the water injection model based on percolation and hydraulics theory. By analyzing the pressure variation and head loss of single well, the water injection rate and pressure are calculated. Pipe&net optimization software is used to establish a network model of water injection station and well, and the parameter changes of multi-branch manifold are simulated and calculated. The single well model and water injection station are organically combined to form a complete set of pressure and water injection distribution system. The author establishes an IPR-VLP model of 26 Wells to calculate injection pressure and water absorption index by calculating the pipeline roughness and reservoir pressure. The injection rate is calculated by the curve fitting analysis, and the pipe&net optimization model is used to distribute the injection rate and pressure. Analyses of single well injection and scheme adjustment are carried out by processing the data of 5 water injection stations with this technique. The pertinence and effectiveness of water injection scheme and measures are obviously improved. This technique can be applied to the injection data processing of oilfields with imperfect metering methods in both China and overseas, providing an effective means of data analysis and optimization for oilfield water injection development.

A nanoparticle depressant (NPPD) was synthesis by grafting octadecyl methacrylate maleic anhydride on nano-silica. This nano composite depressant was evaluated on the pour point and viscosity of Shengli crude oil to reveal its functional mechanism by comparing with poly (octadecyl methacrylate-maleic anhydride) (MPPD). The results showed that at 400 ppm, MPPD effectively lowered the pour point of the crude oil by 6 ℃, while NPPD reduced it by 14 ℃, and the corresponding decrease in viscosity stood at 16% versus 41.2% (30 ℃). By polarizing microscope and particle size analysis, it was shown that, when MPPD was added, the wax crystal was petal-like and its size ranged from 10 to 17 μm. While NPPD was used, the wax crystal tended to be spherical and more compact, and its size was mainly distributed in the range of 5–12 μm. The above differences can be ascribed to different microscopic mechanism: for MPPD, its polymer chain bonds on the surface of wax crystals by adsorption between octadecyl side chain and wax crystals, then hindering their further growth, and finally they flocculate into pedal-like shape by the polar moiety attraction. For NPPD, the octadecyl chains attached on the particle surface act as nucleus or adsorption dot for wax crystals which leads to the formation of wax crystals that possess a higher degree of regularity and compactness, and accordingly with smaller size, thus resulting into its lower viscosity and lower pour point.

Under the goal of “carbon peaking and carbon neutrality”, the technology of multiple thermal fluids is widely used to develop heavy oil reservoirs at home and abroad for its advantages of low carbon and environmental protection. The multicomponent thermal fluids mainly contain nitrogen, carbon dioxide and steam. In the formation, multi-components play an important role in the huff and puff effect. In order to improve the development effect of extra-heavy oil reservoir, the optimization of each component ratio must be further studied. Based on the single factor analysis method and orthogonal test method, this paper designs 40 groups of multi-component thermal fluids numerical simulation schemes with different component proportions. CMG software simulates the influence of steam injection rate, gas-steam ratio, CO2-N2 ratio and other injection parameters on the development effect of multi-component thermal fluids. The results show that the ratio of CO2 to N2 is the significant factor affecting the huff and puff effect, and the sensitivity order is CO2 to N2 ratio, gas-steam ratio and steam injection rate. The optimal injection parameter combination is as follows: the steam injection rate is 200 t/d, the gas-steam ratio is 300 m3/t, and the ratio of CO2 to N2 is 70%:30%. Viscosity deduction of muti-component thermal fluids has two regions: high temperature viscosity reduction and CO2 dissolution viscosity reduction region. The results of this study have theoretical guiding significance for the optimization of injection-production parameters of multiple thermal fluids huff and puff, and can be further applied to field practice.

Carbonate reservoirs are characterized by heterogeneous natural fractures and complex lithology, Acid rock reaction kinetics parameters are key parameters in the analysis of reaction characteristics, evaluation of acid fluid system effect and reservoir reconstruction design. This article conducted acid rock reaction kinetics experiments on the cores of dolomite and limestone reservoirs at 140 ℃ through indoor experiments. The acid rock reaction kinetics equations for two common carbonate rocks, dolomite and limestone, were established under the same experimental conditions. The experimental results showed that the reaction rate, reaction rate constant K, reaction order m, and mass transfer coefficient De of both increased with the increase of acid concentration and rotational speed, The reaction rate constant of limestone is 1.2 times faster than that of dolomite, but the reaction order is 0.77 times slower, indicating that the reaction rate of limestone is less affected by acid concentration than that of dolomite. At the same time, with the increase of limestone composition, the reaction rate of acid rock increases significantly, the activation energy is 1.2 times lower than that of dolomite, and the H+ transfer coefficient is twice as high as that of dolomite. In summary, for the high temperature reservoir with both dolomite and limestone, the pre-treatment of cooling and filtration should be given priority in reservoir reconstruction process, and then acid fracturing construction should be carried out according to different engineering objectives. If the engineering goal is to dredge the near wellbore fractures and cavities, measures can be taken to increase the acid strength of the main acid solution after cooling and filtering pretreatment, fully communicating with the reservoir fractures and cavities; If the engineering goal is to communicate with the distant well fracture cavity, the acid fracturing process of alternating injection of cooling and filtering pre fluid and main acid fluid can be adopted. At the same time, the targeted use of temporary plugging technology in the fracture can increase the drainage area by creating long fractures, attempting to communicate with the distant well fracture cavity, and fully improving the efficiency of communication with the fracture cavity body.

Gas well effusion is an important cause of low production and a common problem in the later production period. It seriously threatens the stability of gas well and even causes the shutdown, which greatly reduces the recovery rate of gas field. Plunger lift with the advantages of simplicity, reliability and economy is widely used in gas well effusion. Liquid leakage is an important problem that causes the inefficiency and even failure of the deliquification. Based on the Navier-Stokes equation for annular gap flow, a new liquid leakage model of plunger lift during the deliquification considering pressure loss of plunger-tubing annulus is established. The fourth-order complex Simpson formula to simplify the leakage volume and render it more practical. The analysis of simulated data using Gupta et al. indicates that the liquid leakage rate averages around 1% during the upward movement of the plunger. Additionally, considering the upward movement of the plunger, the resulting leakage volume greatly impacts the plunger's discharge efficiency. The velocity and flowrate of liquid leakage are quantified, which accurately simulate the liquid loss during the plunger gas lift process and predicting gas well productivity and optimizing plunger lift parameters. It not only helps to accurately characterize the leakage process during the dynamic process of plunger gas lift, but also can be used in the design of plunger structure, description of gas well effusion and evaluation of plunger lift.

With the gradual implementation of the state’s governance of underground overexploited areas and the South-to-North Water Diversion Project, it has become an inevitable trend to raise water resources tax and completely disable self provided water source wells. H oil area is located in Langfang area. According to the local policy requirements, the water source wells will be stopped in the near future, and the water charge will triple. At present, there are 15 water injection stations in the whole plant. If all of them rely on tap water to meet the water injection demand, on the one hand, the use cost of clean water will be greatly increased, on the other hand, the water injection volume will be limited by the local water supply capacity, there is a greater risk of water injection failure, and the effect of oilfield water injection development cannot be guaranteed. Therefore, on the basis of analyzing the current situation of water injection system in H oil area, it is of great significance to determine the potential capacity of produced water resources, plan the adjustment plan of water injection flow direction in the oil area in advance, improve the research of supporting water treatment process and carry out the field implementation work.

For asphaltene - containing reservoir, the existence of asphalt leads to poor reservoir properties. According to field logging data, the asphalt content is inversely proportional to the production capacity of gas wells. The asphalt in the reservoir occupies a portion of the storage space of the reservoir and damages the pore structure. Which will not only reduces the porosity of the reservoir, but also significantly reduces the permeability of the reservoir, seriously affecting the physical properties of the reservoir and the production productivity of the well. In this paper, rock mechanics experiment and acid rock reaction dissolution rate, acid rock reaction rate and acid corrosion fracture conductivity experiment are carried out to clarify the acid rock reaction mechanism and related parameters of rock mechanics, obtain the acid corrosion fracture conductivity of the corresponding acid system, and provide key parameters for reservoir reconstruction design. And through laboratory experiments, the main acid system that can improve the conductivity of acid corrosion cracks was optimized, and the acid pressing process suitable for asphaltene reservoir is formed.

E31 reservoir in Gaskule Oilfield in the Qaidam Basin has entered the high water cut stage. In order to further increase the recovery rate, an oxygen-reduced air gravity flooding development test has been attempted since 2019. Affected by high temperature, high pressure, and high salinity conditions in the reservoir, the corrosion evaluation and prevention of gas injection pipe string has become a key factor affecting whether the oxygen-reduced air gravity drive can be carried out successfully. In this paper, the characteristics of oxygen corrosion of J55, N80, P110 and 13Cr steels in Gasikule E31 reservoir conditions and 0–21% oxygen concentration were studied by weight loss method combined with scanning electron microscope; Analysis of Corrosion Products of Gas Injection String Using XRD Method; Evaluate the mine field corrosion behavior according to the corrosion failure of the gas injection pipe string. The results show that: under the conditions of 126 ℃, 30 MPa, and reservoir flood water conditions, the 13Cr material tubing can meet the anti-corrosion requirements (annual corrosion rate ≤0.076 mm/a) when the oxygen content is less than 1%, and other materials cannot meet the requirements. When the oxygen concentration exceeds 3%, the corrosion rate of each material increases rapidly. The current corrosion types in the test area include oxygen corrosion, CO2 corrosion, H2S corrosion and under-deposit corrosion, mainly oxygen corrosion. The pipe string above the packer is combined with the existing anti-corrosion measures, and the corrosion is controllable. The corrosion of the pipe string below the packer is more complicated, and the prevention and control methods are limited, and further research is needed.

The sources of uncertainty in the determination of phosphorus and sulfur in sucker rod by spectrograph are analyzed, the mathematical model is established, and the uncertainty of the determination result is evaluated. In order to improve the accuracy of the chemical composition analysis results of phosphorus and sulfur elements in the sucker rod bell, the environment, power supply, argon, analysis sample, standard sample, control sample, electrode, spark table, condenser and personnel were analyzed, and the countermeasures were formulated. The uncertainty assessment provides a reliable reference basis for improving the laboratory detection and control ability, and the analysis of influence factors and countermeasures provide a reference for improving the accuracy and reliability of the analysis results of phosphorus, sulfur and other elements.

Carbonate reservoirs in Sichuan and Chongqing are characterized by deep burial depth (>4500 m), high formation temperature (>130 ℃), multiple layers, low porosity, low permeability, and high sulfur content, How to deeply modify reservoirs and reduce costs is the most prominent issue faced by current exploration. Based on the wellbore integrity evaluation design, different degree of cloud, geological requirements, and acid fracturing design of the reservoirs in the Sichuan-Chongqing gas province, establish different acid fracturing completion process strings. The integrated process of single stage acid fracturing and completion is adopted for strong micatization,and the integrated process of multi stage fracturing and completion is adopted for weak micatization. This process can meet the requirements of temperature resistance of 160 ℃, pressure difference of 90 MPa, and long-term resistance to H2S and CO2 corrosion, Field tests were conducted in Well X, and the production was tested after the transformation, resulting in a gas production of 96.91 × 104m3/d, The technical goal of stimulation and reconstruction of this well has been achieved, providing technical support for exploration and development in Sichuan-Chongqing gas province.

Currently, Samandepe Gas Field on the right bank of Amu Darya River in Turkmenistan is in the middle-late period of development, and the oil pressure of some gas wells is close to the pipe network pressure, with an annual decline rate of 39% in production. In order to ensure the stable production of the gas field and improve recovery ratio, this paper has studied pressurization optimization. In view of such problems as unbalanced distribution of gas field pressure, unknown amount of resource loss, large pressurization range, large investment and difficulty in making optimization decisions, this paper analyzes the geological characteristics and dynamic production characteristics of the gas field, as well as the gathering & transmission pipe networks. Based on this, four key technologies, namely quantitative dynamic description technology for cross-border gas field, adjustment mode of pressurized production system, optimization method of pressurized production scheme and wide-area pressurized production support technology for high-sulfur gas field are available to guide the construction of booster station works. Conclusions are: ① Compared with a conventional gas field, the recovery ratio of Samandepe Gas Field after pressurized production is greatly improved, with an expected increase rate of 32%. ② Commercial gas production increases by 12.898 billion m3 after pressurization in 2017–2022 ③ pressurized production optimization technology and engineering practice experience of Samandepe Gas Field can be applied to other gas fields on the right bank of Amu Darya River.

There is great potential for heavy oil production in the world. However, heavy oil has large viscosity and poor liquidity under conventional conditions. Some heavy oil wells need to be effectively developed by auxiliary thermal recovery, so higher requirements are put forward for artificial lift equipment. Beijing petroleum machinery Co., Ltd carries out all-metal PC pump technology research according to the heavy oil exploitation needs for artificial lift equipment and a hydraulic leakage model is established. The high-performance All-metal PC Pump that developed has the characteristics of high temperature resistance and strong ability of lifting, the single stage pressure capacity increased by more than double compared with PC Pump with elastomer stator. The deviation between the experimental efficiency on the test bench and the theoretical calculation data according the hydraulic leakage model is 1.1% at the target pressure point, which shows the effectiveness of the theoretical modeling and has guiding significance for the study of the performance of the all-metal PC pump. All-metal PC pump system in heavy oil cold production has good adaptability and in the thermal recovery steam huff and puff technology of heavy oil can realize the integration of injection and production of immovable string, which can save energy and increase production effect. So far, it has been successfully applied in some oil fields. At the same time, this paper discusses the possibility of application of all-metal PC pump technology in high temperature and deep wells. Combined with carbon emission reduction, the application prospect of CO2 huff and puff heavy oil viscosity reduction is proposed to help green production.

Barite blockage formed by drilling fluid filter cake with barite weighting agent as the main component is one of the main factors causing oil and gas reservoir damage and affecting oil and gas production. Conventional acidification measures are difficult to dissolve the barite blockage, and the development of a cost-effective non-acid chelating removal agents and the formulation of a scientific blocking removal construction process are effective engineering means to solve the barite blockage. Amino carboxylic acid chelating agent forms strong chelate with barium ions on the surface of barite, promotes the rapid dissolution of barite, and helps to relieve the blockage of barite filter cake. However, key technologies such as the commercial selection of chelating removal agents, the material chemical design of chelating removal agents, the evaluation method of chelating removal agents, and the construction technology of chelating removal agents, seriously affect the engineering application value of barite blocking removal. In this paper, the structural characteristics of the special chelating agent for barite blocking removal are summarized, the main factors affecting the blocking removal effect of the chelating removal agents are reviewed, the guiding principles for designing the product formulation of the chelating removal agents, the product performance evaluation method and the potential industrial by-product raw materials that can be used for the preparation of the chelating removal agents are proposed, and the construction process design method and control essentials of on-site blocking removal are analyzed. Finally, through the analysis of two typical application cases in sandstone and carbonate reservoirs, it provides readers with new ideas for the chemical design of chelating removal agents for barite filtrate cake and field-removing techniques.

The deep high-temperature carbonate gas reservoirs represented by the Gaomo block in Central Sichuan and the Penglai Gasfield have become an important support for the Southwest Oil & Gasfield Company to increase reserves and production on a large scale. However, there are many technical problems in the acidizing transformation of high-temperature reservoirs, such as fast acid rock reaction speed, preferential acid etching distance, strong corrosivity and so on. In this paper, the mechanism of autogenous acid generation and its reaction with acid rock are revealed, the kinetic equations and thermodynamic equations are constructed, and the technical countermeasures for the research of high temperature autogenous acid resistance are put forward. A series of autogenous acid systems with controllable concentration of autogenous hydrochloric acid and autogenous organic acid have been developed respectively. The controllable acid concentration is 6−12% and the temperature resistance reaches 180 ℃. The generated acid systems have the performance advantages of long acid generation time and high effective corrosion rate, which can significantly slow down the acid rock reaction rate, improve the acid etching distance, and achieve the purpose of deep penetration. A series of authigenic acids and their supporting technologies have been successfully popularized and applied in deep carbonate reservoirs in Sichuan, serving more than 100 wells and using more than 10000 m3 of acid, effectively solving the technical problems existing in the acidizing transformation of high-temperature reservoirs, and achieving remarkable economic benefits.

The problems caused by asphaltene deposition, such as wellbore blockage, pump jamming, and spot corrosion, directly affect the development and exploitation of oil fields, which may increase the difficulty and cost of oil extraction operations. It is one of the important problems that urgently need to be solved in the oil extraction process. Herein, based on the real oil well blockage samples, the composition and properties of crude oil was analyzed, and the molecular structures of crude oil saturates, aromatics, resins and asphaltenes were designed. The mechanism of each component deposition to form blockage was researched from the molecular scale, and the microscopic mechanism of dispersant stabilizers in preventing deposition was explored. The results indicated that the adsorption energy order of the four fractions of crude oil on the simulated pipe wall was: asphaltene > aromatic > saturate > resin. Compared with other molecules, asphaltene had the lowest binding energy at the interface and was most easily adsorbed at the interface. Driven by the structure of heteroatoms and multi-aromatic rings, most asphaltene molecules accumulated at the interface in a “lying flat” form. The centroid distance between the simulated crude oil molecules and the simulated pipe wall significantly increased after adding dispersant stabilizers, effectively preventing the adsorption and deposition of asphaltene and aromatic. The mechanism of the deposition of the four fractions in crude oil to form blockages was explored, which would provide a theoretical basis for further research on the removal of asphaltene deposition and new ideas for the design of efficient dispersion stabilizers.

In order to solve the problem of oil well production being unable to recover due to fluid leakage during the workover operation of low-pressure and large pore reservoirs in Dagang Oilfield, an elastic and changeable temporary plugging agent was developed to improve the pressure bearing capacity of the system. At the same time, based on the “strong chain” and “ideal filling theory”, it was mixed with biodegradable plant temporary plugging materials to increase the temporary plugging capacity of the system. In addition, a certain amount of auxiliary agents such as anti-swelling agent, thickener, drainage aid, etc. to form a temporary plugging and leakage prevention technology suitable for millimeter hole leakage. The technology is effective at the aperture is below 3 mm, the pressure is below 5 MPa. The API is 15 ml/30 min, the recovery of permeability exceeds 90%. So far, the technology was successfully applied in 8 wells, success rate is 100%, the average recovery rate of the well yield is 100%. The problem of leakage in high permeability reservoirs has been effectively resolved.

At present, there are not all testing methods for well testing steel wire. Non magnetic well testing steel wire can only be used to determine the mechanical properties of the steel wire by cutting the front end of the wire and conducting tensile and torsional performance experiments. The damage of the entire disc can be judged through visual observation, which is different from the actual use of the well testing steel wire and cannot fully reflect the changes in the well testing steel wire, resulting in safety hazards in wire operation. In response to the above issues, an online detection device for well testing steel wire has been developed, which consists of four parts: a cleaning system, a detection system, a marking system, and a control system. The cleaning system completes surface dirt cleaning without damaging the steel wire, ensuring that there are no attachments on the surface of the steel wire, and preventing detection misjudgment; The detection system is mainly composed of three profilers, which use laser scanning technology and center positioning algorithm to determine the center of the circle in real-time, calculate the diameter of the well testing steel wire and the size of surface defects. The operation speed is within 30 m/min, and can detect various types of well testing steel wires with a diameter of 2 mm−5 mm, with a detection accuracy of no more than 0.05 mm; The marking system marks the abnormal parts detected for secondary diagnosis. At the same time, the overall device is lightweight and easy to carry, with simple installation and operation. It can be directly stuck on the testing steel wire, and can be detected from any section of the testing steel wire, without being affected by the shaking of the steel wire during the operation process. It achieves real-time online detection on the job site, enabling steel wire operators to timely grasp the overall performance of the steel wire, providing strong safety guarantees for steel wire operations.

The reservoir of M Oilfield in SongLiao Basin has high clay mineral content (27.3% on average) and strong sensitivity (water sensitivity index 0.87–0.97), therefore, conventional water-based fracturing fluid can lead to serious formation damage and is difficult to meet the stimulation requirements.In order to improve the stimulation effect of X layer, the modified ethylene glycol fracturing fluid was studied by using DMC and AMPS copolymer with good solubility as thickener and safe, environmental protection, stable performance modified ethylene glycol as solvent. The overall performance of fracturing fluid, compatibility with reservoir rock and the recycling performance of flowback fluid were carried out.The experimental results show that the modified ethylene glycol fracturing fluid has good sand-carrying performance and gel breaking capacity, the shear viscosity of the fracturing fluid is 210.9 mPa.s after continuous shearing at 45 ℃ for 60 min, the viscosity of the gel breaking fluid is 3.86 mPa.s after 8 h at formation temperature, and the residue content is only 7.4 mg/L. It behaves the properties of low surface and interface tension, which has a surface tension of 24.7 mN/m and an interface tension of 1.17 mN/m, with a characteristics of low damage, strong sand carrying capacity and wide application range, and the flowback fluid can be reused with excellent crosslinking performance, which can meet the requirements of the stimulation of the X sensitive reservoir.Modified ethylene glycol fracturing fluid has improved the effect of reservoir stimulation and achieved effective utilization of strong water sensitive reservoirs. 10 wells field tests were carried out with an average oil production of 4.8 t/d after fracturing, which has a good oil increase effect and providing a technical support for the reserve submission of Daqing Oilfield middle-shallow layer.

This paper analyzes the composition of the scale samples from the injected water and the pipe strings of Qinghai Gasi Oilfield and determines that the scale samples are mainly composed of carbonate components and contain 8%–10% ferrous sulfide. When hydrochloric acid is used as a scale solvent, it reacts with ferrous sulfide to generate highly toxic hydrogen sulfide gas, causing pipe string corrosion and personal injury. This paper presents the solution of synthesizing hydrogen sulfide absorbers to address this problem and systematically evaluates their various performances. In addition, the compatibility between the absorbent and the existing acid solution system is studied. The results show that the average sulfur capacity of the two hydrogen sulfide absorbents (BY-A, BY-B) is higher than 0.03 mg/g, and the average desulfurization efficiency is greater than 90%. In a hydrochloric acid solution with a concentration of 15%–25%, when a hydrogen sulfide absorbent with a concentration of 1% (volume ratio) is added, the hydrogen sulfide absorption efficiency is greater than 90%. By adding 0.5% (volume ratio) hydrogen sulfide absorbent to the existing acid system in the oilfield, the hydrogen sulfide absorption efficiency is greater than 90%. The hydrogen sulfide absorption speed is fast, which can meet the requirements for hydrogen sulfide concentration during the backflow of acidizing treatment. The hydrogen sulfide absorbent has good compatibility with the acid system and it does not affect the corrosion inhibition effect of the inhibitor. Furthermore, a rapid evaluation method for hydrogen sulfide absorbers has been designed and developed, and it is simple, feasible and reliable in results. This study innovatively develops efficient hydrogen sulfide absorbents, which have important practical significance for safe and efficient pickling and acidizing treatment of sulfur containing pipelines and reservoirs.

Daqing Oil Field belongs to unconsolidated sandstone reservoir. Due to small fluid output of single well, poor sand carrying capacity and frequent sand production in the reservoir, sand control screen pipe plugging, pump jamming and other problems are caused. This article obtains a prediction formula for the sand settling rate of reservoirs near the wellhead through fluid sand settling experiments, and corrects the non-uniform shape of sand in the reservoir using this method. The correlation between the sand settlement rate under different formation pressure and the average velocity of flow field in well is obtained through calculation and the corresponding calculation formula is given. Based on the optimization of the production process of the traditional rod pumping unit, an optimal design scheme of the production process parameters of the rod pumping unit is presented, and the scheme is reasonable and reliable. The practice has proved that the sand settlement and the height of sand column in the pump chamber can be predicted well during sand production, Which Practice has proved that during sand production, the sand production settlement and the sand column height in the pump chamber can be well predicted, and the minimum sand carrying capacity of the oil well under the reservoir pressure and production pressure difference can be calculated, which provides a basis for reasonable selection of sand production well string.

Aiming at the problem of difficult scaling and high risk in experimental determination under high-temperature and high-pressure conditions, a prediction model of calcium carbonate scaling under high-temperature and high-pressure was established. The model starts from chemical equilibrium conditions, based on the carbonate gas-liquid-solid three-phase equilibrium conditions, considering the interaction between carbon dioxide concentration and various ions, using the solubility product rule to establish, using the Pitzer model to solve the compound activity coefficient, and calculating the parameters such as equilibrium constant and gas activity in the solution through the experimental regression model. The model can accurately predict the solubility of calcium carbonate in different aqueous solutions, which the error in pure water and barium chloride solution is within 5%, and the error considering the influence of carbon dioxide partial pressure is 14%. Using the model can accurately predict the scaling situation of the system under high temperature and high pressure, and has theoretical guiding significance for the implementation of downhole scale prevention process.

Songliao basin is rich in shale oil resources. However, there is little research on the mechanical characteristics and development technology of shallow shale oil reservoir. Through the study and analysis of the density distribution and rock mechanical characteristics of 13 groups of core samples from 4 wells in the shallow shale oil reservoir in Songliao Basin, it is found that the shallow shale oil reservoir in the basin has low density and belongs to the soft shale with general compaction in mechanics. High density interlayer exists locally. High elasticity in shale and strong brittleness. Large Poisson’s ratio in shale and strong deformation capacity. The strength is grade D and belongs to low strength rock. Good shearing property. According to the test core formation, the fracturing analysis and suggestions are put forward, that is, the development of oil shale horizontal well has certain advantages, and the segmented fracturing technology of horizontal well is the key to the successful development of shallow shale oil. The clear water fracturing fluid or slippery hydraulic fracturing fluid should be selected, and the optimization and performance evaluation of other main agents are completed.

It has a large amount of ultra-deep shale gas in Wufeng-Longmaxi Formation in southeast Sichuan (TVD > 4500 m), which is the key field of exploration and development in the future. At present, a breakthrough has achieved for deep shale gas (3500 m < TVD < 4500 m). However, as the deep burial depth of ultra-deep shale gas formation, the ambient temperature and pressure, structural characteristics and rock brittleness characteristics become complex. Based on the analysis of geological conditions and fractured well for ultra-deep shale gas reservoir in southeast Sichuan, the challenges of ultra-deep shale gas fracturing are sorted out. The deep buried environment increases the rock strength and rock plasticity, in which the fracture tends to be in the single shear fracture mode. Meanwhile, the high horizontal two-direction stress difference limits the transformation of hydraulic fractures. These factors all affect the complexity of hydraulic fractures, which cause the SRV in ultra-deep shale gas reservoir smaller than that in middle-shallow and deep shale gas reservoirs. Also, the large married deep increases the fracturing pressure, which has exceeded the the pressure limitation of common equipment. The high pressure limits the displacement lifting during fracturing process, resulting in the problems of insufficient net-pressure in the fracture, small longitudinal sweep range, small fracture width and difficult proppant adding. What is more, high closure stress of ultra-deep shale gas reservoir leads to rapid loss of fracture conductivity, causing the insufficient long-term production capacity. In order to solve the above problems, several aspects are proposed to improve the fracturing efficiency of ultra-deep shale gas, such as improving the prediction of the “sweet spot” for ultra-deep shale gas reservoir, reducing the fracturing pressure, increasing the net-pressure to promote fracture complexity, and lifting fracture long-term conductivity. The research and understanding have important theoretical and practical significance for the exploration of ultra-deep shale gas in southeast Sichuan.

The low permeability reservoir in Dagang oilfield has deep burial depth and poor physical property, and the effectiveness of waterflood development is low. In order to realize the effective development of deep low permeability reservoir and explore the transformation from traditional water drive development to the new development mode of “volume transformation + effective displacement”, it is necessary to deepen the research on the volume fracturing technology and parameters. Based on the reservoir data of the GD6X1 block and the induced stress field mathematical model, this paper compiled the stress field software to form the feasibility identification method of volumetric fracturing, and carried out the optimization of volumetric fracturing process parameters with the main contents of segment cluster perforation optimization, proppant optimization, and fluid volume and displacement optimization. The query chart of intercluster fluid intake ratio with different stress difference, different displacement and different perforation number was established to ensure uniform fluid intake of each cluster and improve the transformation effect. After the field test pressure, the daily increase of oil is 16.1 t, and the cumulative oil is 6724.89 t, which provides an important guiding significance for the volume fracturing reform of deep low permeability reservoir.

The natural gas supply and demand in Daqing oilfield varies greatly with the seasonal variation. The production in winter is 2–3 times that in summer, and the gas field’s supply protection pressure is huge. During the 13th Five-Year Plan period, the peak is adjusted 132 times, with an annual average of 130 days. Foam drainage gas production technology is the most important drainage and production measure to ensure the continuous liquid-carrying production of water-producing gas Wells in Xushen Gas field. Therefore, it is more important to give full play to the supporting role of drainage gas production technology, so as to provide guarantee for the production increase of gas Wells in winter, the reduction of gas field supply protection pressure and the continuous steady production decline control of old Wells. Due to the low temperature in winter, the water solution of foaming agent is easy to freeze, and some of the foaming process is limited, which affects the effect of foaming. Through laboratory tests, the foaming stability performance, dynamic liquid carrying capacity and low temperature antifreezing performance of the bubble extractor were evaluated, the main agent of the bubble extractor was selected, the process filling system was optimized, and the process parameters of fine filling were determined. Under the temperature of −20 °C~−30 °C, the average daily gas production of a single well is increased by 15%, and good test results are obtained, which further improves the field adaptability of gas field bubbling process in winter.

Sichuan Basin is rich in shale oil resources. Resources is mainly distributed in Lianggaoshan Formation of Jurassic, which the reservoir lithology is shale and sandstone interbedding, Showing obvious lithological interbedding characteristics. (Young’s modulus of sandstone is 35.6–45.3 Gpa, Poisson’s ratio is 0.24–0.30, Young’s modulus of shale is 38–50 Gpa, Poisson’s ratio is 0.16–0.3). As a result, hydraulic fracturing is faced with the problems of complex hydraulic fracture extension law, unclear main control factors of fracture extension, and great difficulty in layer penetrating reconstruction. In this study, the outcrop of sand and shale interbedding in the field is selected to carry out the true triaxial physical model experiment. The experimental results show that the interface strength, stress difference and liquid viscosity are the main influencing factors; According to the geological engineering parameters of typical wells, the finite element+cohesive element is used to carry out the numerical simulation of fracture extension. The simulation results show that when the interface strength is lower than 4 MPa, the hydraulic fracture is easy to activate the bedding interface. When the inter-layer stress difference is greater than 6 MPa, the longitudinal extension of hydraulic fracture is blocked. The hydraulic fracture can be effectively extended longitudinally by using high viscous fluid combined with large displacement. This study has formed a through-layer fracturing process of large displacement+high viscous pre-fluid, The process has been applied for many times, and the microseismic monitoring results show that the vertical penetration is successful, and the length of the reconstructed fracture reaches 130–160 m, and the process effect is obvious.

The emulsions of crude oil can seriously affect the efficient production of oil wells. The formation of emulsions is closely related to the properties of crude oil and production water. It is an importantly practical significance to study the emulsification mechanism of crude oil with different properties and select efficient demulsifiers. Using EBS oilfield crude oil as the research object, the fractions and properties of different crude oils were tested. Indoor simulation of emulsion formation was conducted to investigate the effects of different factors, such as water content, pH value and temperature, on the emulsification of different crude oils. Through bottle test experiments, the demulsification effect of block polyether demulsifiers on different crude oil emulsions was evaluated. The results showed that the higher the content of asphaltene and resin in crude oil, the closer the asphaltene molecules may be arranged at the oil-water interface, the higher the strength of the oil-water interface facial mask formed, the more stable the emulsion, and the greater the viscosity. The water content of crude oils with different properties varied when they reached complete emulsification. The stability of the emulsion may deteriorate under acidic conditions or when the temperature increased. With the addition of effective demulsifier, block polyether molecules could replace asphaltene molecules at the oil-water interface, reduce the strength of interfacial facial mask, and achieve oil-water separation. The study revealed the mechanism of crude oil emulsification in EBS oilfield, clarified the influence rules of different factors on crude oil emulsification, and selected demulsifiers with strong adaptability and high demulsification efficiency.

In the acid fracturing stimulation of ultra-high temperature carbonate reservoirs, conventional acid has problems such as fast acid-rock reaction rate, and inability to achieve deep penetration. Therefore, this paper uses methyl acetate (agent A) and ammonium chloride (agent B) as the matrix of the autogenic acid. The acid is an in-situ sustained-release acid with a temperature resistance of 180 °C. The volume ratio of autogenic acid system is optimized using standard sodium hydroxide solution titration experiment. The effects of different temperature and reaction time on the ability of autogenic acid to acid production are studied. The acid-rock kinetics of autogenic acid is studied using the cores of the Maokou limestone and Dengying dolomite in the Sichuan Basin. The acid-rock reaction kinetics parameters of autogenic acid are measured using a self-made high temperature and high pressure rotating reactor. The results show that mixing the agent A and the agent B at a 1.5:1 volume ratio provide the optimal results as the amount of the acid production is the highest. The autogenic acid has a low acid production capacity at low temperatures and only exhibits excellent acid production ability at high temperatures of 180 °C.The effective H+ concentration released from the autogenic acid at 180 °C is maintained at 2.24 mol/L after 4 h. The reaction time of autogenic acid is long, meeting the requirements of sustained-release at ultra-high temperatures.The acid-rock reaction rate of autogenic acid with the core of the limestone at 180 °C is 9.40522 × 10−7 mol/(s·cm2) and with the core of the dolomite is 6.85752 × 10−7 mol/(s·cm2).The autogenic acid reacts with both carbonates at similarly low rates, verifying that the acid has some retardation properties. The autogenic acid system has a slow acid rock reaction rate and a long acid production time, while it is not affected by carbonate lithology. It can realize the purpose of undifferentiated deep acidizing of ultra-high temperature carbonate reservoirs.

Corrosion performance of petroleum sulfonate type surfactant (KPS) and betaine type surfactant (BTS) were evaluated by static weightlessness method, electrochemical test method and surface topography analyses, respectively. Influence of corrosion parameters such as temperature and pH value on the corrosion performance were also investigated. The corrosion mechanism analysis were investigated using Electrochemical Impedance Spectroscopy (EIS) and the corrosion product analysis was further analyzed by X-ray photoelectron Spectroscopy (XPS). Corrosion performance evaluation indicated that KPS and BTS showed certain corrosion inhibition properties on the carbon steel. Moreover, the KPS displayed better corrosion inhibition effect than BTS. Corrosion mechanism research indicated that the corrosion reaction on the surface of carbon steel was mainly controlled by the charge transfer process and the addition of KPS and BTS did not change the original corrosion mechanism. Corrosion products analysis showed iron (Fe), carbon (C), oxygen (O) elements were the main components, which inferred that the corrosion products were main carbonate and rust iron oxide substances.

To understand the sealing characteristics of temporary plugging agents (TPA) in the borehole, a system was established for simulating high pressure temporary plugging experiments. The influence of the type and the concentration of TPA, the carrying liquid viscosity and the pump displacement on the sealing characteristics are studied, and the comparison and selection experiments of TPA are also performed. It can be concluded from experimental results that i) the higher viscosity of carrying liquid leads more TPA to going into the low-angle-borehole, resulting in better sealing characteristic; ii) the larger pump displacement causes more boreholes blocked by the TPA (especially the number of blocked low-angle-boreholes are more than that of blocked high-angle-boreholes); iii) both low-angle-borehole and high-angle-borehole are filled with more TPA duo to the higher concentration of TPA; iv) the sealing efficiency of TPA-knot is the highest, followed by TPA-particle and TPA-ball, and the TPA-fiber is the lowest. For obtaining the excellent sealing efficiency, it is recommended the mixed use of TPA-knot, TPA-particle and TPA-ball.

The characteristics of Ordos basin is large vertical span, poor connectivity, small effective reservoir thickness, poor reservoir physical properties, low clay mineral content, small pore throat radius and low pressure coefficient. Fracturing technology must be used to realize effective development of this tight gas reservoir. In order to solve the problems of the current fracturing fluid system, the integrated fracturing fluid system is studied. A new thickener agent was prepared by emulsion polymerization of acrylamide, 2-acrylamide-2-methypropanesulfonic acid, acrylic acid and auxiliary agent-1.The experimental evaluation of viscosity increase, drag reduction, suspended sand, temperature and shear resistance, gel breaking, additive compatibility, anti-swelling and surface tension of integrated fracturing fluid system is carried out, and the field application effect of integrated fracturing fluid is analyzed. The results show that the viscosity of the integrated fracturing fluid system is flexible and adjustable. The viscosity increases with the increase of the concentration of the integrated thickener, and the viscosity adjustment range is 3−100 mPa $$\cdot$$ · s. The high viscosity liquid has excellent suspended sand performance, and the viscosity of 0.8% concentration integrated fracturing fluid is more than 60 mPa.s under the condition of $$60\,^\circ {\text{C}}$$ 60 ∘ C and 100 S−1 shears. The drag reduction rate >70%, anti-swelling rate >70%, salt tolerance rate under standard salt water >40%. Surface tension <32 mN/m and the damage rate to shale formation was only 2.8%. Its integration is mainly reflected in functionality and application. In terms of function, it integrates slick water, linear glue and cross-linked hydraulic fracturing fluid system, which can meet the different requirements of tight gas reservoir fracturing reconstruction processes for fracture making, drag reduction, anti -swelling, sand carrying and rapid flow-back. The integrated fracturing fluid was used in 163 wells and 437 section. The average fracturing fluid of single section is 370 m3, the average sand addition is 51.4 m3, and the average sand addition strength is 6.9 m3/m. 84 gas wells were tested which the open flow rate was 71300 m3/d, the average daily production was 23900 m3/d. The integrated fracturing fluid promotes the tight gas fracturing process test, improves the fracturing effect, and shows good adaptability to all kinds of gas reservoirs and fracturing process.

Focusing on the matching of temporary plugging agent and hydraulic fracture width, a multi-scale optimal design method of temporary plugging agent was established to control the permeability and strength of plugging layer by optimizing the particle size composition and particle size distribution of the temporary plugging agent. The ideal particle size distribution for the stable accumulation of temporary plugging agents under different hydraulic fracture widths was determined by combining the d1/2 theory and the 5/6 matching principle. By changing the maximum, minimum and median particle size of the temporary plugging agent, the particle size distribution can meet the required permeability and strength of the plugging layer. Laboratory experiments and field applications were carried out using the optimal design method. The laboratory experiments found that the relative errors between the experimental and predicted values of the permeability and strength of the plugging layer were 9.09% and 6.06%, respectively, indicating that the optimal design method was highly reliable. The field application found that the bottom hole pressure increased from 88.4 MPa to 93.2 MPa after the temporary plugging agent entered, and the surface microseismic results after fracturing showed that the SRV was about 96.37 × 106 m3, indicating that the combination of temporary plugging agents successfully turned the fractures and effectively improved the complexity of the fractures.

In view of the large number of horizontal Wells with casing loss and casing leakage, conventional pumping bridge plug or coiled tubing bottom seal drag fracturing technology is often unable to be implemented, If the method of casing subsidy or conventional double-sealing and single-layer fracturing is used, There are many problems such as many procedures, high labor intensity, low construction efficiency and high operation cost. To solve the above problems, This paper presents a hydraulic injection double-seal single-card drag fracturing technique for tight oil horizontal Wells, Dragged string multi-stage hydraulic sandblast perforation and double seal fracturing can be achieved in a single trip string, Through process and tool optimization, At present, the highest design of this technology string is level 3, And can meet the 4–6 stage perforation fracturing construction. Field tests show that this technology can meet the demand of efficient fracturing and reconstruction of tight oil horizontal wells with casing loss and casing leakage.

The Su 43 area is a low porosity, low permeability, low pressure, and low saturation tight gas reservoir with significant reservoir differences, complex gas water distribution, and frequent issues such as low gas water production after compression. According to initial production data, the water production rate is high, reaching 6:1 (m3/104 m3). How to avoid flooding and maintain efficient development of gas reservoirs is a key issue. This article combines the production characteristics of gas wells in Block Su 43 to carry out automatic data collection of plunger systems, online analysis of wellbore fluid accumulation, and adaptive optimization and adjustment of operating systems to improve the effectiveness of intelligent plunger gas lift. By analyzing the relationship between water and gas recovery rates, and under long-term stable production conditions, controlling a reasonable working liquid level, and using the collected bottom hole pressure and liquid level data, iterative algorithms are used to deeply correlate and calculate the optimal plunger operating system. The production system can be automatically generated, diagnosed, and corrected. After on-site testing, the feasibility of beam pumping unit drainage has been fully proven, providing a new approach for large-scale development in the Su 43 area.

In order to solve the reservoir pollution during the workover operation in the complex fault block oilfield of Dagang Oilfield, especially the high pour point oil blocks represented by Xiaoji and Duanliubao, multiple damages such as water sensitivity, crude oil emulsification, and retention coexist, leading to serious reservoir pollution problems, Through the research of high-efficiency pour point depressing, wetting and dispersing technology, a technical system of anti-emulsification oil washing workover fluid is formed. The results show that the technology can effectively reduce the freezing point of crude oil by more than 9 ℃, and the oil washing rate is increased from 60.7% to 90.2%, achieving the dual effect of not only cleaning the wellbore to ensure the smooth operation, but also increasing the production recovery rate. This technology has been applied 20 wells in Dagang Oilfield. The average production recovery rate of applied wells has been increased from 77.7% to 97.6%, and the average recovery period is 2.8 days, which shows that the reservoir protection effect is significant.

This article summarizes the current status of technical applications of hydraulic pumping units both domestically and internationally, and clarifies the structures, working principles, technical advantages and disadvantages of the three widely used hydraulic pumping units. At the same time, the on-site application effects of three types of hydraulic pumping units were tracked and evaluated, and the application effects were measured from the perspectives of power saving rate and economy. Finally, the technical challenges and future development trends faced by the research and design of hydraulic pumping units were summarized, laying the foundation and indicating the direction for the diversified development of hydraulic pumping units, finalizing technical series and management models, improving the research and design level of scientific researchers, and achieving promotion and application. The cluster hydraulic pumping unit lifting technology has the advantages of energy conservation and emission reduction, green and low-carbon, safety and environmental protection, high intelligence, low cost, manpower saving, and small land occupation. It has significant technological advantages and good application prospects, and is suitable for intensive production, factory operation, and intelligent control of small and medium-sized displacement oil wells.

In view of the problems of the existing power supply module of downhole tools, such as narrow output voltage range and difficult to meet the complex power supply requirements, a new intelligent production distributor multi-channel power supply method was studied. The voltage conversion chip which can adapt to the underground working environment is selected as the core component of the power supply module, and a set of power supply scheme which can be multi-channel stable power supply is developed. By building the software and hardware experimental environment, the power supply stability, driving ability and communication compatibility of the scheme are tested. In the experiment, the voltage output of each branch of the power supply scheme is stable and the driving capacity is sufficient, which has no obvious influence on the communication quality of the intelligent generator. Experimental results show that the proposed scheme can supply power smoothly to the surface communication module, the underground intelligent production distributor and other tools as expected, and meet the power supply requirements of the intelligent production distributor.

The fracture is the main reservoir space of fractured reservoirs, the oil and gas content and seepage space are ideal. The natural fractures can be communicated, oil and gas migration channels with high permeability can be formed, and oil and gas production capacity of reservoir can be improved by volume fracturing. It is very important to fully communicate natural fractures to ensure the stimulated effect of fractured reservoir. Therefore, based on the geological conditions of fractured reservoirs, this paper fully considers the influence of geostress, natural fracture density, angle, brittleness index, injection rate, fracturing fluid viscosity. The research results show that the horizontal stress contrast and natural fracture characteristics are the main geological parameters that determine the fracture propagation shape of horizontal well volume fracturing in fractured reservoirs; The horizontal stress contrast is less than 8MPa, the hydraulic fracture is easy to extend along the natural fracture trend, forming a complex fracture network, and the stimulated volume of single stage can reach 30 × 104m3; High injection rate (≥16 m3) is conducive to the simultaneous initiation and expansion of multiple clusters of fractures in horizontal wells and the communication of natural fracture system, reducing fracturing fluid filtration and increasing stimulated reservoir volume (SRV); The use of high viscosity liquid (base fluid) for fracturing in the early stage will help to improve the efficiency of dense perforation cluster and cut down the filtration of fracturing fluid. The injection of low viscosity liquid (slippery water) in the later stage will promote the opening of natural fractures. The optimal proportion of slippery water is 60%–70%. The research results of this paper provide a basis for the fracturing scheme design of fractured reservoirs.

In this paper, the electrochemical corrosion behavior of 80S steel in the produced fluid of low sulfur gas well was studied. The effects of temperature and sulfur content on the corrosion of 80S steel were studied by potentiodynamic polarization and electrochemical impedance spectroscopy. The results show that with the increase of temperature, the corrosion potential (Ecorr) of 80S steel decreased, and the corrosion current density increased first and then decreased. With the increase of sulfur content in the medium, the corrosion potential of 80S steel showed a negative trend, and the corrosion current density increased. The Nyquist diagram of 80 S steel at 40 ℃ shows the characteristics of capacitive reactance arc in medium-high frequency region and inductive reactance arc in low frequency region. At 65 ℃ and 90 ℃, the capacitive reactance arc in medium-high frequency region and capacitive reactance arc in low frequency region are presented, and the inductive reactance arc disappears. With the increase of temperature, the charge transfer resistance (Rt) shows a trend of decreasing first and then increasing slightly, that is, the corrosiveness of the medium increases first and then decreases. With the increase of sulfur content in the medium, the capacitance arc of 80S steel shows a decreasing trend. After adding different sulfur contents, the maximum phase angle of Bode spectrum in the basic medium moves to the direction of increasing frequency. After adding different amounts of Na2S·9H2O, the charge transfer resistance (Rt) of 80S steel is greatly reduced compared with the Rt value in the basic medium, that is, the corrosion of the medium to 80S steel is greatly increased.

In order to solve problems such as sand blockage, equipment wear, and residue damage associated with the current fracturing technology, we develop a method to form self-propping solid (SPS) proppant under formation situation based on phase change. After the liquid material is injected in reservoir, the reservoir temperature stimulates the generation of SPS particles. The size, density, morphological change under pressure, crushing rate, and conductivity of propped fractures were tested to evaluate the SPS performance. The test results show that the size distribution of different types of SPS varies greatly. Therefore, SPSs of different sizes can be formed through adjusting the ratio of raw materials to effectively prop relatively wide tensile fractures, medium wide branch fractures and relatively narrow microfractures. With an apparent density ranging between 1.0g/cm3 and 1.12g/cm3 which is close to that of water, the SPS can be easily carried by fracturing fluid. With a crushing rate between 0.45% and11.65%, which is lower than that of quartz sand and ceramsite, the SPS is used for fracturing of deep reservoirs to prevent crushed parts migrating or blocking the flow channel. The conductivity of different types of SPS is quite different and it is better than that of quartz sand and ceramsite at a closure pressure of 55Mpa. Because the crushing rate of 6/20-mesh SPS-5 samples is high, their fracture conductivity is less than that of other SPSs with a size of 20/40 mesh and 40/70 mesh. Due to the high strength, even being placed in one layer, the SPS can effectively prevent the crushing and embedding of proppant. Compared with conventional proppant, the SPS has distinct advantages.

Gulong shale oil reservoir is rich in resources, high in clay minerals, and densely developed bedding fractures. Generally, reverse composite volume fracturing technology is used to establish oil and gas flowing channel, in which slickwater is beneficial to opening bedding fractures and improving the complexity of artificial fractures. The microscopic damage and adaptability research of slickwater on reservoir are of great significance for improving fracturing effect. This paper take the microscopic damage and adaptability of slickwater to Gulong shale reservoir as research object. Micro damage experiments of five kinds of slickwater were conducted to research the micro damage and adaptability of slickwater to Gulong shale reservoir. The results of nuclear magnetic resonance and CT analysis show that the binding degree of type B, C, and E slickwater is small, the pore damage is small, the total porosity increases greatly, and the number of fractures increases, which is conducive to the fracturing fluid backflow. The scanning electron microscope analysis results show that the chemical element adsorption of type B and E slickwater is relatively light, pore filling is not serious, element migration is prominent, and intergranular pores increase. Comprehensive analysis shows that type B and E slickwater have good adaptability to Gulong shale oil reservoir. The research results are of great significance to the optimization of hydraulic fracturing fluids for the Gulong shale, the identification of the characteristics of pore throat damage caused by fracturing fluids, and the adaptability of fracturing fluid to reservoirs, which are conducive to improving the effectiveness of reservoir stimulation.

Downhole gas compression (DGC) is a novel artificial lift technology for gas wells since it can increase the gas flow rate and decrease the abandonment pressure. The downhole gas compression realizes the gas pressurization by installing the downhole gas compression device at the bottom of the well. The process parameters of DGC directly affect the application effect. This article introduced the multi-parameter optimization method for DGC system. Three factors, the device installation depth, the tubing inner diameter and the compression ratio, were selected as the optimization parameters. Two evaluation indexes, the gas flow rate and the abandonment pressure, were considered simultaneously for the optimization. Based on the orthogonal experimental design method, a L16(43) table was implemented to improve the optimization efficiency. The evaluation indexes were obtained based on the results of node analysis. The range analysis was performed to get the optimal combinations of process parameters and the influence degree of each process parameter on evaluation indexes were obtained. The synthetic analysis was conducted to get the multi-parameter optimized combination. The verified simulations were conducted to validate the proposed optimization. The simulated results indicated that the optimal process combination achieved better gas flow rate and lower abandonment pressure at the same time. The comprehensive optimization of two evaluation indexes can be achieved and it provides a potential method for DGC application optimization.

The large-scale volume fracturing is commonly believed as an effective way to recover oil from thin, low porosity and ultra-low permeability tight reservoirs. However, the proprietary single-stage & single-cluster drag type fine control fracturing technology is not suitable for the large scale fracturing application for the existence of such problems as serious wear & corrosion of the tools, tools broken accident, and the conventional mechanical Y211 bottom packer cannot meet the requirements of low setting force and high differential pressure. The dual-packer drag type tubing fracturing technology and the coiled tubing single-packer drag type casing fracturing technology are innovatively developed through the mechanical analysis, numerical simulation, and tool structure optimization design. The key tools such as K344-105 packer, large sand volume pressure-transmitting sand jet, series of tubing BOP, new Y211 bottom packer and hydraulic sand jet perforating gun with high performance are designed. Lab testing and field runs have confirmed that the dual-packer drag type fine control multi-stage fracturing technology rated up to differential pressure of 70 MPa at 120 ℃. Up to 18 stages of fracturing can be executed in one trip with the flowback circulation rate of below 8 m3/min and sand loading volume scale of 516 m3 during operation. The technology has been applied to 716 well times in the field application. The coiled tubing single-packer drag type casing fracturing technology rated up to differential pressure of 70 MPa at 150 ℃. Up to 94 stages of fracturing can be executed in one trip with the flowback circulation rate of over 8 m3/min, and the technology has been applied to 538 wells in the field application. The drag type fine control multi-stage fracturing technology for horizontal wells has become the domain fracturing technology in Daqing Oilfield.

In this study, an integrated rapid analysis scheme for inorganic and organic fluoride components in oilfield chemicals were established based on visual colorimetry method. Fluoride components were extracted from different types of oilfield chemicals under microwave and then pretreated by microwave digestion to convert the organic fluoride components into inorganic fluoride components. Organic and inorganic fluoride components were rapid analyzed using visual colorimetry. The scheme realized the integrated rapid detection of inorganic and organic fluoride components for different oilfield chemicals including water-soluble, oil-soluble and insoluble oilfield chemicals. The method was convenient, low dependence on instruments and suitable for batch processing, while the results were precise and accurate. The scheme solved the existing fluoride analysis problems of oilfield chemicals, such as poor integration, high labor intensity and low analysis efficiency, which were great significance for identification of contaminated fluoride components and environmental risk control for oilfield chemicals.

The corrosion damage of natural gas pipelines will seriously reduce the structural strength, load-bearing capacity, and reliability of pipelines, shorten their service life, and increase operational risks. In response to the current situation of natural gas pipeline corrosion, conventional manual testing can no longer meet on-site needs. The current online monitoring technologies for natural gas pipelines have limitations, such as excavation and testing of the remaining wall thickness of natural gas pipelines, which will inevitably have a certain negative impact on the pipeline in addition to high costs. A natural gas pipeline corrosion online monitoring system has been developed, and the article introduces the composition of the online monitoring system Calculation and online monitoring steps for corrosion measurement. The corrosion data collector analyzes and processes the corrosion signals of natural gas pipelines, uploads them to the remote control center, and after processing by the monitoring system, obtains accurate corrosion data and calculates the corrosion situation, determines the corrosion status of natural gas pipelines, locates the anti-corrosion layer, evaluates the aging status of the corrosion layer, identifies the operating parameters of natural gas pipelines, guides the selection and use of corrosion inhibitors, and adjusts the injection of corrosion inhibitors, Guide the implementation plan of forced impressed current cathodic protection for natural gas pipelines, and conduct online parameter warning through remote monitoring of SCADA system. This system has the characteristics of fast, accurate, and highly automated detection of corrosion resistance, effectively controlling the corrosion of natural gas pipelines.

Due to the high viscosity of produced fluid, especially the high concentration polymer, the fluid flow resistance greatly affects the production. At the same time, the plunger downward resistance increases, the rod bending deformation is obvious, and the rod and tube bias wear range is increased. Therefore, an integrated visity-reducing and oil-increasing device is developed, which is mainly composed of gas-liquid separator, magnetic field processor, acoustic wave generator and check valve. The device has physical effects on the flowing liquid, which can reduce the viscosity of well fluid, realize gas-liquid separation and increase liquid fluidity. Field test results show that the viscosion-reducing and oil-increasing integrated device can reduce the liquid viscosity and gas influence of the poly flooding pumping unit, and increase the liquid production. Thirteen test Wells were carried out in the field. After the measure, the average daily liquid production increased by 3.1 m3, the average pump efficiency increased by 4.13% points, and the average pump detection period extended by 126 days. With the continuous improvement and application of the integrated device of viscosity reduction and oil increase, it has considerable economic benefits for the efficient exploitation of polymer flooding pumping unit.

The lower Paleozoic Majiagou Formation reservoir, located in the southern area of the Ordos Basin, is a typical tight carbonate gas reservoir with an average burial depth of about 3000 m, a formation pressure coefficient of 0.8, a porosity of 3.16%, and a permeability of 0.13 mD. The gas production was generally low after hydraulic fracturing at early-stage development, and the proportion of wells with industrial gas capacity is less than 25%. During the fluid discharge phase, the flowback rate was generally low (less than 30%), the bottom hole flow pressure was small (less than 7 MPa), and the flowback pressure difference was large (more than 15 MPa). Because the initial water saturation of tight reservoirs is usually less than the irreducible water saturation, the retention of a large amount of undischarged fracturing fluid in the formation causes the increase of water saturation in the near-well area, resulting in damage to gas permeability. The ‘water trapping effect’ is serious in the near-well area, and no liquid was produced during the later stage of drainage, making it impossible to obtain the true production capacity of the reservoir. In order to improve the effectiveness of fracturing, a soak test after hydraulic fracturing was carried out in the tight carbonate gas reservoir. After 50 days of soaking and pressure diffusion, the fracturing fluid in the near-wellbore area was dispersed to the deep formation by capillary force. As the diffusion area increased, the water saturation in the near-wellbore area was reduced, and the gas permeability was effectively restored. The daily gas production increased from 4,678 m3 to 8,424 m3 after soaking under pressure. The successful trial of this technology has a significant reference for improving the effectiveness of hydraulic fracturing and understanding the true production capacity of tight gas reservoirs .

Fracturing fluid is an important part of fracturing technology, and the breaking property of fracturing fluid directly affects the effect of fracturing construction. In the case of low temperature gas reservoir, conventional gel breaker has some problems, such as not timely breaking and incomplete backflow. In this paper, through in-depth research on the concentration of the fracturing liquid system thickening agent, high efficiency breaking agent accelerator, waterproof locking agent and other functional additives, forming a low-temperature rapid gel breaking fracturing fluid formula, which reduces the difficulty of fracturing fluid breaking, reduces the residue content of breaking fluid, and reduces reservoir damage caused by wellbore fluids. The system has been successfully applied in 9 Wells in Jidong Oilfield, achieving a technical breakthrough in tight gas reservoir fracturing fluid system, and forming a low temperature and rapid gel breaking fracturing fluid technology system suitable for this region.Large-scale fracturing is one of the efficient ways to explore and develop tight gas reservoirs in Jidong Oilfield [1–5].The average reservoir temperature of Jidong tight gas reservoir ranges from 40℃ to 80℃,and the geothermal gradient is 2.24℃ to 2.82℃/100 m. The reservoir temperature of Shiqianfeng Formation is the lowest, reaching 45℃ (the well test temperature of Qian5 Member is 45.2℃).At present, Jidong Oilfield mainly uses low concentration hydroxypropyl guanidine gum fracturing liquid system [2–6],the concentration of hydroxypropyl guanidine gum is 0.35–0.45%,and the operating temperature is 110℃-140℃.The system is difficult to break rubber under 70℃,with high concentration of breaker and incomplete break rubber. In order to meet the system requirements of tight gas development in Jidong oilfield, such as fast break rubber, fast flow back, low residue and low cost [6–8], the research on fracturing fluid of guanidine gum system with low temperature fast break rubber was carried out on this basis.

Ganchaigou is a Paleogene Source rock in the Qaidam Basin, which was formed in the inland saline lake basin environment. It is a typical large-scale lithologic reservoir in the source. The production mode after fracturing has a significant impact on the oil production effect. Field statistics show that well plugging can make the shale oil reservoir have a stable production increase period, but there is no clear guidance for well plugging time and flowback system.This article focuses on the dynamic changes of the reservoir during the closed well period after the pressure of the Ganchaigou. Based on the theory of fracture dynamic changes and seepage, a closed well simulation model is established. Through the development of reservoir numerical simulation software, the closed well process of the fracturing well is simulated, and the variation of the fracturing fluid coverage range under different closed well times is studied to determine the optimal closed well time. The study shows that the optimal closed well time is inversely proportional to the permeability, and positively correlated with the injection displacement and injection volume, The optimal lockdown time for Ganchaigou is 18–30 days; Based on the analysis of the force acting on the proppant in hydraulic fractures after compression and the starting conditions, the critical flowback velocity for controlling backflow is determined. A flowback optimization model is established and the flowback working system is optimized. The factors affecting flowback are analyzed. Research shows that there is a maximum value for the diameter of the nozzle during the flowback process after compression, which may lead to backflow of the proppant, thereby affecting the flowback efficiency. During the closure period of the Ganchaigou crack, it should be used no more than 5mm nozzle, after the crack is closed, it should be used no more than 8mm nozzle ensures maximum flowback rate while reducing the risk of proppant backflow. The research results of this article are closely related to production practice, and study the dynamic changes and stimulation mechanisms of shale oil reservoirs after volume fracturing from the perspective of the entire life cycle. This has a good engineering guiding role in optimizing the actual well shut-in time after fracturing and determining the backflow system.

The oil and gas production process in onshore oil fields mainly includes multiple production process, including underground oil extraction, surface heating and transportation [1], liquid separation and sedimentation, sewage treatment, and sewage reinjection. Surface heating requires a large amount of crude oil, natural gas, and electricity [3–5], and energy consumption expenses account for about 20% of the production and operation costs of oil extraction units. Heating equipment is an important thermal equipment for oil and gas production, especially when old oil fields enter the later stage of development, facing the characteristics of a large number of production wells, a large base of supporting heating equipment, and a variety of types, improving their technical management level has become an important topic. Based on years of experience in selecting matching heating equipment and energy-saving management, this article analyzes and explores the selection of wellhead heating equipment, hoping to provide some reference for improving the quality and efficiency of oilfield surface process technology management.

Horizontal well volume fracturing is an important technique for the development of tight oil reservoirs. Accurately predicting post-fracturing production capacity is of great significance for optimizing fracturing design and evaluating its effectiveness. To address the problem of the complexity of the fracturing process leading to numerous influencing factors and difficulty in predicting production capacity, a production capacity prediction method based on weighted clustering and XGBoost is proposed. This method proposes weighted correlation coefficient to extract the dominant factors of reservoir data and fracturing construction data, then assigns weights to the reservoir data based on the extraction results. K-means algorithm is introduced for weighted clustering of reservoir data, thus horizontal wells are clustered based on reservoir similarity. The XGBoost model is trained by the clustering results, fracturing construction data, and cumulative production data for predicting production capacity. Experimental results show that compared with single XGBoost, SVR and other models, the proposed method has higher predictive performance.

Low output wells were located in reservoirs with poor physical properties and generally had a low production capacity for a single well. Insufficient fluid supply to the formation during continuous pumping by the pumping unit results in the well being in an ineffective suction condition, further leading to lower pump efficiency, causing increased downhole pump failure rates and ultimately increasing well recovery costs. In this paper, a production model for low ouput wells in low permeability reservoirs was developed. By analysing the inflow and outflow performance of the wellbore, a reasonable intermittent production system was established and the intermittent production working time and well downtime for low ouput wells was calculated using the developed “Intermittent Production Optimisation Simulation System for Low Output Wells”. The intermittent production of low output wells has been verified in production operation site and the wells produced at more than 95% of the original continuous production rate according to the intermittent production time determined by the system, resulting in significant economic benefits in terms of energy savings.

Gas Wells in the south area of Sulige Gas field generally produce water and accumulated liquid. The main drainage gas recovery measures such as plunger gas lift and foam drainage have low efficiency in the water-rich area of the gas field, which seriously restricts the scale benefit development of medium-high production water gas reservoirs. Therefore, it is urgent to carry out research on the production recovery measures of severely accumulated liquid Wells and flooded Wells. The concentric pipe jet pump drainage gas production process is introduced. This paper mainly analyzes and compares the drainage and production process design, jet throat combination, application effect, scale inhibitor optimization, etc., and evaluates the application effect of concentric pipe jet pump in middle-high yield water and gas Wells (reservoirs) in Sulignan District.

According to unbalanced steam injection in in horizontal wells, this paper studies the structure of the balanced steam injection devices (BSID) and the improvement effect of the unbalanced steam injection. Firstly, the structure of the BSID is designed, and then an optimization model is established to study the optimization method of structural parameters. Finally, the optimization model is verified by numerical simulation software. The research shows that the optimization model of BSID established in this paper can effectively complete the calculation of the parameters related to the steam injection process. The maximum relative error is 1.11% of the steam quality in the gas injection tube compared with CMG model. According to the analysis of the calculation results of the steam injection using the BSID and steam injection in the conventional tube in A well group in Liaohe Oilfield, it can be determined that the pressure in the annulus of the conventional tube decreases sequentially from the “toe” to the “heel”. While the annular pressure using the BSID fluctuates with the physical properties of the formation, which demonstrates that the pressure in the high-permeability section is low and the pressure in the low-permeability section is high. The higher daily oil rate and cumulative oil could be acquired when BSID are installed, and the faster oil recovery rate, the higher recovery efficiency, a better development effect are emerged in production.

Daqing Oilfield weak alkali ternary composite flooding to improve oil recovery but also brought a certain oil well scaling problem, into the peak period of scaling, frequent pickling and scaling measures, coupled with residual acid reflux treatment, the cost increased significantly, And affected by rain and snow weather, some wells due to untimely scaling operations lead to card pump operation, seriously affecting the operation rate of machine mining, according to statistics, the success rate of card solving within 4 h of shutdown is more than 90%, and the success rate of card solving within 4 h is only 50%. For this reason, the development of weak base ternary composite displacement and prevention integrated agent suitable for wellhead dosing process, through low concentration complex free Ca2+ ions, to prevent it from combining with CO32− to produce carbonate scale microcrystals and then produce scaling, in addition, for the carbonate scale microcrystals that have been formed in the production solution, by increasing the concentration of the agent The strong complex group in the component is used to destroy the carbonate microcrystalline skeleton, recapture Ca2+ ions, prevent the growth of microcrystallites, and achieve the effect of molecular state scaling. Field tests show that after the on-site wellhead dosing of the integrated cleaning and prevention agent, the calcium ion content in the production solution has a significant upward trend, from the initial 24.47 ppm to 66.84 ppm, the on-site scaling rate reaches 96.3%, the effective action time of scaling cleaning can reach more than 6h, and it is directly transferred to the production trunk line without backdraining. Which can realize all-weather scale prevention and selective and timely scaling cleaning of machine wells, which greatly improves the efficiency of oil well cleaning and scale prevention, and ensures the stable operation of machine well mining in the chemical flooding stage.

In order to further improve the motor driving ability and the stability of the control module of the intelligent production controller and prolong the service life of the equipment, a new motor driving method using TB6612FNG driving chip as the motor driving chip in the intelligent production controller is Studied. Aiming at the problems of easy heating, low integration and the like of the traditional motor driving chip in the prior art, a TB6612FNG chip which can adapt to the underground working environment is found and used as a novel motor driving chip, the driving capability and stability of the TB6612FNG driving chip are tested by building a software and hardware testing environment. In the test, the output waveform of TB6612FNG driver chip is smooth, and it works stably when dealing with the possible voltage jump, long-term rotation, motor resistance and other conditions in the actual underground working conditions. The test results show that TB6612FNG chip can adapt to the actual working conditions, and can effectively improve the working stability, test the quality and prolong the service life of the intelligent production controller.

With the extension of production time, severe wax deposition occurred in some horizontal well developmentreservoirs in Changqing Oilfield. Conventional dosing measures have poor effect and high frequent cost of hot washing. In order to ensure the normal production of oil wells, a low surface energy wax prevention technology is proposed according to the wax deposition characteristics of horizontal wells and the factors affecting wax deposition. By coating the inner surface of the tubing with hydrophobic and smooth inner coating, the inner wall of the tubing with low surface energy is formed to prevent wax crystal adsorption and play the rule of wax prevention. At the same time, the influencing factors of wax prevention effect of coated tubing were studied, the critical surface energy of low surface energy wax prevention technology was determined, and the coating selection chart under different working conditions was formulated to guide the field application.

The Suijing Oil Field is characterized by its typical extra-low and ultra-low permeability reservoirs. In order to maximize reservoir producing degree and the production of single well, while also managing the increase in water content, a novel approach of plugging old seams and compressing new ones has been implemented. This involves the use of interlayer and intralayer multi-stage temporary plugging and fracturing technology. To assess the effectiveness of multi-stage temporary plugging and fracturing construction and its process adaptability, an evaluation matrix was developed. This matrix evaluated the temporary plugging and fracturing effect based on 9 parameters: formation pressure, sand amount, displacement, sand ratio, oil well production, temporary plugging agent dosage, fracturing pressure, relative change rate of daily oil production, and relative change rate of water content. Fuzzy comprehensive evaluation was conducted for the oil wells constructed in the Triassic Chang-6 reservoir of the Suijing Oil Field formation. The study determined the adaptability effectiveness of the multi-stage temporary plugging and fracturing process system. Based on the principle of membership degree determination, the effectiveness of multi-stage temporary plugging and fracturing in the Suijing Oil Field can be classified into 5 grades: ‘excellent, good, moderate, poor, and bad.’ These results offer valuable insights for optimizing parameters in the subsequent implementation of ‘multi-stage temporary plugging and fracturing’ in similar reservoirs.

Over the past decade, shale gas has become a significant source of energy supply worldwide. However, due to the ultra-low permeability of shale reservoirs, the estimated primary recovery factor through horizontal drilling and multistage hydraulic fracturing technologies remains low. This research studied CO2-enhanced shale gas recovery (ESGR) as an alternative technique to evaluate its impact on shale gas recovery in different fracture arrangements attributed to various well patterns. The study involved building a 3D dimensional reservoir model using CMG-GEM 2015 simulation software and analyzing the influence of reservoir and hydraulic fracture parameters. The results showed that CO2 gas is a promising stimulation method to improve the recovery of methane gas, as well as being sequestrated in unconventional shale gas reservoirs. During continuous injection, the fracture arranged in a staggered well pattern showed to be a promising pattern for methane recovery with 7% more increased recovery compared to the fracture arrangements in an aligned well placement pattern. During huff and puff injection involving different injection scenarios, the results showed that five cycles of injection had the highest recovery of more than 2% for the fracture arrangement in an aligned well pattern compared to the fracture arrangement in staggered well patterns. In addition, injection start time after 10 years of production had higher methane gas recovery in both fracture arrangements for both well patterns, followed by injection after 5 years of production, 3 years, and during the first year of production. Sensitivity analysis was performed using CMG CMOST 2015, and the results show that methane gas production and carbon dioxide gas storage are highly dependent on reservoir and hydraulic conditions. The information obtained from this research work can further help improve the recovery factor during shale gas recovery with different fracture arrangements as a result of well placement patterns, improve the efficiency of optimization and history matching processes, save time and cost to operators, simulate more research, as well as facilitate the mitigation of global warming through CO2 geo-sequestration.

The goal of petroleum production engineering is to optimize oil and gas output while keeping costs as low as possible. Production engineers must possess a deep comprehension of the petroleum production systems they operate in order to accomplish this goal. Production engineers need to be well-versed in the properties of the fluids they create, as well as the fundamentals of how all the major parts of producing wells and surface facilities operate, in order to do their jobs properly. Understanding production engineering and its application techniques has a direct and independent relationship to other important disciplines of petroleum engineering, including reservoir engineering, drilling engineering, and formation evaluation. The following are the main components of the production system, which is a phrase used to describe the complete production process: the reservoir (its producing capacity and dynamic production characteristics over the expected life of the development), Since every reservoir, whether natural or artificial, has a drive mechanism to produce oil and gas, the ideal scenario is for the drive mechanisms to help recover the hydrocarbons from the porous media of the reservoir. Drive mechanisms can be classified as either internal or external. Internal drives use the reservoir configuration’s internal energy, while external drives utilize the invasion of pore spaces by a replacement fluid; this sort of drive is referred to as “Enhanced oil recovery” or “secondary recovery.” Primary recovery, also referred to as internal drive, consists of three driving mechanisms: water drive, external gas cap drive, and depletion or internal gas drive. Simply put, “well completion” describes the procedures used to seal a recently drilled well in order to produce reservoir fluids to surface production facilities in a safe and effective manner. Typically the following steps are involved in completing a well: (A technique for ensuring effective communication between the borehole and reservoir, The tubular (casing and tubing) design that will be inserted into the well, A suitable technique for pumping reservoir fluids to the top, The planning and installation of numerous well-related components that enable effective production, such as pressure integrity testing, reservoir monitoring, emergency fluid containment, barrier placement, well maintenance, and well kill, as well as the installation of safety devices and equipment that will automatically shut down a well in the case of an emergency. Essentially, there are three primary approaches to well completion: (1) Open-hole completion, (2) Cased-hole completion, and (3) Liner completion, which can involve two different forms of completion: (1) Screen and liner completion, and (2) Perforated liner completion. Actually, there are benefits and drawbacks to every well completion technique. Completion equipment is known to consist of the following: subsurface control equipment, wellhead/Christmas tree, production tubing, production packer, liner, and sliding sleeves. After the reservoir is drilled, production casing or a liner is often run into the well and cemented in place to complete the completion. It will be necessary to drill holes through the cement sheath, the casing wall, and into the formation in order to provide a communication line between the reservoir and the wellbore. This is achieved by a process known as perforating. A sequence of explosive charges must be lowered into the well using either a drill string, tubing, or an electric conductor (wireline cable). Once the charges are at the necessary depth, they must be detonated to create a series of perforations through the cement sheath and the casing wall. Actually, there are three main perforating methods of cased wells (Bullet Perforators, Jet perforators, and Hydraulic perforators). Thus, well completion operations come to an end with the completion of well drilling and cementing the production casing. Because well completion operations are so crucial, it is important to consider all potential risks and issues in the well completion program and to supply all necessary equipment and tools. Drilling or work-over rigs are used to complete the operations, and occasionally firefighters are needed on the site.

The key goal of the work is to optimize the process of flowback in wells after multi-stage hydraulic fracturing in fields with unconventional oil reserves. The procedure for selecting the optimal flowback operation is to tune the model based on field data, adapt the fracture cleanup model using sensitivity analysis on input parameters, and select the most effective scenario of bottomhole pressure decreasing. This article can be separated into three parts. The first one consists cleanup model description. The second one shows sensitivity analysis of the results of flowback modeling with respect to key input parameters. The last one includes optimization and history matching methods to fit the modeling and field data. Model adaptation to field data is carried out using iterative Newton's method (MSE < 10% for the first 30 days of flowback). The results of model adaptation to the well in unconventional hydrocarbon reservoir of Western Siberia showed that several additional physical phenomena have to be considered as compared to those describing flowback in traditional terrigenous reservoirs including increased permeability of near-fracture reservoir due to presence of natural fractures and oil-water emulsion. Our preliminary results show that the developed flowback model can be used to describe flowback in unconventional wells both qualitatively and quantitatively.

Because nanoparticles can increase foam stability, only a small amount of surfactant or polymer is required to control gas mobility in the reservoir. It was decided to look into the foam stability and foam ability of black rice husk ash in order to improve foam production and stability. Shows how important the high silica content of black rice husk ash (BRHA) is for stability and foam ability. Under varied circumstances, black rice husk ash, SDBS (Sodium Dodecylbenzensulfonate), and (Sodium Dodecyl Sulfate) surfactants were used. Making a dispersion of black rice husk ash with SDBS surfactant. To begin, distilled water was mixed with a specific quantity of black rice husk ash nanoparticles, and the mixture was then uniformly dispersed for 10 min using an ultrasonic dispersive spectrometer. The SiO2 dispersion was then mixed with a specific quantity of SDBS surfactant Foaming agent for 10 min. In order to achieve the surfactant SDBS's equilibrium of adsorption on the surface of the black rice husk ash nanoparticles the behavior of the foam made from black rice husk ash. Black rice husk ash's high silica concentration has the potential to increase foam stability, which is favorable for bubble uphold position for nanoparticles in oil recovery.

This study aims to assess the effectiveness of using low-salinity water flooding to improve the recovery of oil from a sandstone reservoir in an excessively high-water cut stage. The experiments were conducted on six sandstone cores, each representing a different water cut level, ranging from 70% to 95%. Initially, formation water was injected to adjust the water content to the desired level before switching to low-salinity injection. Sodium chloride (NaCl) brines with concentrations ranging from 2000 mg/L to 20,000 mg/L were used. The selected cores had porosity levels between 27% and 28% and permeability values between 280 mD and 300 mD. Different injection rates for the brines, ranging from 0.5 cm3/s to 3 cm3/s, were also investigated.The results show that low-salinity water flooding had significant potential for increasing oil recovery in a reservoir at a high water cut stage. However, the proper timing of low-salinity water flooding was crucial to limit excessive displacement of porous particles caused by continuous water flooding. Initiating low-salinity injection early effectively mitigates this issue, reduces high water content, and maximizes oil recovery. Moreover, brines with NaCl concentrations between 200 mg/L and 5,000 mg/L yielded higher oil recovery compared to brines with higher salinity levels, between 10,000 mg/L and 20,000 mg/L. This difference can be partly attributed to the Jamin effect, which occurs during fluid flow at high water cut levels. Low-salinity brines alter the interaction between the reservoir rock and oil, leading to more efficient displacement and improved oil recovery.Additionally, the discussion on three models for rising water rates to optimize the timing of injection and prevent the detachment of porous particles from the sandstone was tackled. These models provide valuable insights into the reservoir's behavior, helping reservoir engineers determine the best timing for low-salinity water injection to maximize oil recovery. These findings contribute significantly to the understanding of the potential benefits of low-salinity water flooding in sandstone reservoirs with high water content. The optimized injection strategy, considering early injection timing and appropriate brine salinity levels, offers essential guidance for reservoir engineers looking to enhance oil recovery in similar reservoir conditions.

The target of the work was to determine the safe operating mode for the injection wells to prevent the propagation of hydraulic fractures beyond the target interval into a cup rock in environmentally sensitive offshore oilfield. The ranges of injection pressures and rates as well as monitoring techniques to ensure a cap rock integrity based on geomechanics was defined.The following steps have been taken to achieve the objectives: retrospective analysis of injection history; analysis of injection tests performed at selected wells; analysis of the evolution of closure pressure, friction pressures and fracture net-pressure; calibration of existing mechanical earth model to account for actual geomechanical state at specific point of injection history; modeling of self-induced hydraulic fractures in novel state-of-the-art planar 3D fracture simulator; comparison of fracture height with independent estimation methods such as DTS, SNL and others; sensitivity analysis of various injection modes. Our research has shown that previous injection modes have caused propagation of self-induced fractures. In addition, modeling such fractures in the novel planar 3D fracture simulator has excellent convergence with observations of DTS and SNL studies, and shows no fractures propagation beyond the interval of interest. The application of this approach makes it possible to assess the risks associated with top-seal integrity during water injection in the long terms.Use of the latest simulator based on the advanced planar 3D model to simulate the development of self- induced fractures coupled with DTS and SNL monitoring methods proves viability of top-seal integrity control. The study of fall-off tests at different stages of long-term injection allows to determine the current stress-strain state.

At present, separate-layer Waterflooding process is still one of the key technologies for improving oil displacement efficiency. The separate-layer Waterflooding process has developed from traditional technologies such as fixed type, downhole casting and fishing type, integrated text and adjustment to the current real-time monitoring and control technology on the surface. This paper introduces the development of the separate-layer Waterflooding process and Understand its the advantages and disadvantages, At the same time, it comprehensively analyzes the application status and problems of separate-layer Waterflooding technology in Yanchang Oilfield, combines the geological characteristics, well conditions and Waterflooding characteristics of Yanchang oilfield, selects the injection process suitable for different regions and different well conditions according to different conditions, and gives the development direction of the application of separate-layer Waterflooding technology in Yanchang oilfield in the future.

In order to effectively utilize GuLong shale oil, it requires large-scale fracturing. However, the problems caused by casing deformation, such as section loss, severely restrict the efficiency and effectiveness of its development. To clarify the casing deformation mechanism in GuLong shale oil, a comprehensive analysis of various factors that may affect casing deformation is conducted. The analysis shows that factors such as casing strength, wellbore curvature, and cementing quality are not the main controlling factors of casing deformation in GuLong shale oil wells. The deformation mechanism is induced by fracturing, which activates the fracture and causes the formation to slip along the fracture, leading to shear deformation of the casing. Based on the understanding of the casing deformation mechanism, targeted risk prediction and control measures for casing deformation are proposed. Firstly, multiple seismic attributes are used for detailed interpretation and prediction of fracture activation to assess the risk of casing deformation. Secondly, temporary plugging and reduction of construction displacement during the fracturing process, as well as optimization of cementing systems to improve the compacting effect of cement sheath, are employed to control the risk of casing deformation. The research findings can provide important guidance for the prevention and control of casing deformation in GuLong shale oil and similar shale reservoirs during fracturing operations.

At present, the exploration and development of Gulong shale oil has entered the deep water zone, and significant breakthroughs have been made in the exploration of the lower oil formation. The upper oil formation has started comprehensive development. However, in order to achieve efficient production and fine development of Gulong shale oil, in-depth research and technical breakthroughs are needed in shale oil drilling, hydraulic fracturing, and lifting and drainage. This article takes the on-site testing of the core engineering technology of Gulong shale oil as the research object, elaborates on the current understanding and related research results of Gulong shale oil, and conducts in-depth analysis and research on the current problems of shale oil. The aim is to reveal the engineering technology requirements of continental sedimentary shale reservoirs and provide technical support for unconventional oil and gas extraction in China.