The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
- Data Science & Engineering Analytics
The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
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Yao, Chuan-Jin (China University of Petroleum (East China) and Key Laboratory of Unconventional Oil & Gas Development (Corresponding author)) | Liu, Bai-Shuo (China University of Petroleum (East China) and Key Laboratory of Unconventional Oil & Gas Development) | Liu, Ya-Qian (China University of Petroleum (East China) and Key Laboratory of Unconventional Oil & Gas Development) | Zhao, Jia (China University of Petroleum (East China) and Key Laboratory of Unconventional Oil & Gas Development) | Lei, Zheng-Dong (Research Institute of Petroleum Exploration & Development, PetroChina) | Wang, Zhe (China University of Petroleum (East China) and Key Laboratory of Unconventional Oil & Gas Development) | Cheng, Tian-Xiang (China University of Petroleum (East China) and Key Laboratory of Unconventional Oil & Gas Development) | Li, Lei (China University of Petroleum (East China) and Key Laboratory of Unconventional Oil & Gas Development)
Summary Tight reservoirs are mainly developed by injecting various gases after fracturing. However, the formed fractures are complex, and different fracture conditions have an important impact on the gas injection effect. In addition, natural gas is considered to be suitable for the development of tight reservoirs in China because of the abundant gas source and no corrosion. For this paper, the natural gas injection experiments were studied by combining mercury intrusion porosimetry (MIP) measurements and nuclear magnetic resonance (NMR) measurements. The method can be used to study the distribution characteristics of core pore structure and the recovery characteristics of oil in different pore spaces. In this work, the tight cores of the Changqing Oil Field were selected for fracturing for the natural gas flooding experiments. At first, the distribution characteristics of the core pore structure were studied based on the MIP and NMR measurements. The conversion relationship between the core pore throat radius and the relaxation time (T2) was decided. The NMR T2 distribution was transformed into the distribution of oil in pore space with different throat radii. Then, the gasflooding experiments were conducted to study the oil recovery law of tight cores with different fracture conditions. Finally, the recovery characteristics of oil in different pore spaces were analyzed based on the NMR results of cores. The results show that the pore throat radius of the core is mainly distributed in the range of 0.001 to 10 μm. The oil is mainly stored in the pore space whose pore throat radius ranges from 0.01 to 1 μm. The natural gas also mainly drives the saturated oil in the pore space with a pore throat radius of 0.01 to 1 μm. The increase in fracture area improves the distribution of oil in the larger pore space. In the process of natural gasflooding, with the increase of gas injection, the oil began to be recovered, and then gas was observed at the end of the core. With the continuous injection of natural gas, the rate of recovering oil gradually slowed down, and finally gas breakthrough occurred. The displacement oil process of the nonfractured core was uniform and slow. However, the oil and gas rapidly flowed along the fracture when the natural gas displaced the oil in the fractured core. The oil in the matrix was poorly recovered. Gasflooding mainly recovered the saturated oil in the matrix of nonfractured cores and the saturated oil in the fracture of fractured cores. As the fracture length increased, the oil recovery became lower and the gas breakthrough occurred earlier. The higher fracture density increased the fracture area, which also increased the oil recovery and caused a more intense gas breakthrough. In this paper, the displacement law of tight oil cores by injecting natural gas and the recovery characteristics of oil in different space pores were illuminated. The results can provide theoretical guidance for the formulation of the natural gas injection development plan in tight reservoirs.
Li, Xingbao (The Second Gas Production Plant of Petro China Changqing Oilfield Company) | Ban, Fansheng (CNPC Engineering Technology R & D Company Limited) | Zhu, Yujie (The Second Gas Production Plant of Petro China Changqing Oilfield Company) | Luo, Jiangwei (China University of Petroleum) | Chen, Shaoyun (Drilling Engineering Technology Research Institute of Daqing Drilling and Exploration Engineering Company) | Jin, Sheng (Petroleum Engineering Research Institute of Dagang Oilfield) | Che, Zhenhua (Sinopec Zhongyuan Oilfield Engineering Service Management Center) | Dong, Jingnan (CNPC Engineering Technology R & D Company Limited)
ABSTRACT: Drilling mud loss is of crucial importance in drilling. Lost circulation will extend the well construction period, cause investment losses, and even cause serious downhole accidents. In the Mizhi block of Changqing Oilfield targeted by this research, serious leakage occurred in many wellbore drilling processes, which has seriously affected the development of the block and caused economic losses. This paper focuses the mud loss during the drilling process of more than 200 wells in the Mizhi block, and counts the key loss data such as the lost horizons, the amount of lost drilling fluid, the average leak rate, and the density of the drilling fluid, and fully analyzes the possible reasons of the lost circulation. Collecting logging data, modeling geomechanics of some key wells and formations and taking cores. Finally, the geomechanical model is established. Analyzing the logging data and the specific leakage situation, the leakage mainly comes from fracture, and the leakage horizons mainly locate at the bottom of the Liujiagou Formation, the entire interval of the Shiqianfeng Formation and the top of the Shihezi Formation. Most of the mud loss sections are sand-mudstone interbeds. Geomechanical analysis shows that the rock mechanical strength of the entire interval is difficult to support the stability of the wellbore under the drilling fluid density of 1.1 grams per cubic meter, but the block loss pressure is generally between 1.1 - 1.2 grams per cubic meter. Collapse and leakage coexist in the wellbore. This study gives the method of drilling fluid optimization, and gives the possible reasons for the leakage from the perspective of geomechanics, which has important guiding significance for the further development of the Mizhi block. 1. INTRODUCTION During drilling or completion operations, when the pressure of the effective drilling fluid density in the wellbore is greater than the formation pressure, the fluid will flow to the formation along the leakage channel around the wellbore, resulting in lost circulation. (MD Hashmat et al. 2016)Loss of circulation not only causes a large amount of drilling fluid loss, but also may cause a series of other drilling accidents, such as stuck pipe, blowout and even wellbore scrapped and other serious consequences.(Zhang et al.2016) Ultimately, it increases the non-operation time of drilling and causes huge economic loss. The time consumed to deal with lost circulation accounts for about 10% of drilling operation time, and the economic loss in drilling caused by lost circulation is as high as 2 billion US dollars every year.(Arshad Umar et al.2014) If the leakage appears in the reservoir, it will also cause reservoir damage, thus affecting the subsequent production of oil and gas. Therefore, lost circulation is regarded as one of the most complex and harmful accidents in drilling operations.
Qu, H. Y. (State Key Laboratory of Petroleum Resource & Prospecting, China University of Petroleum) | Lang, H. (State Key Laboratory of Petroleum Resource & Prospecting, China University of Petroleum) | Xue, X. J. (Oil and Gas Technology Institute, Petro China Changqing Oilfield Company) | Da, Y. P. (Oil and Gas Technology Institute, Petro China Changqing Oilfield Company) | Zhou, F. J. (State Key Laboratory of Petroleum Resource & Prospecting, China University of Petroleum) | Liu, X. Y. (State Key Laboratory of Petroleum Resource & Prospecting, China University of Petroleum)
ABSTRACT: Refracturing is an effective way to drain the unstimulated rock through diversion treatment. The refrac geometry is determined by the reorientation and change in the magnitude of the in-situ stress. However, the comprehensive impact of primary fracturing, water injection and oil production in well group on the stress redistribution has not been well understood. A three-dimensional heterogeneous geomechanical model coupled with unconventional fracturing and reservoir simulation was established. Following the primary hydraulic fracturing and water injecting according to the pumping and injection schedule of an inverted nine-spot well group, an automatic gridding algorithm was run. In addition, history match and 10-year production prediction were conducted through reservoir simulation. A 3D geomechanical finite element solver was utilized to compute the spatial and temporal change in the in-situ stress and deformation during fracture propagation and reservoir depletion, providing updated stress profiles. Refrac simulation scenarios were run after production of 1 year, 3 years, 5 years and 9 years to identify the most opportune time to refrac the well group. Results indicate that the impact of water injection on stress is consistent with hydraulic fracturing while opposite to that of the reservoir depletion. The magnitude of horizontal principal stresses increases around the injection well, while the stress contrast decreases during the water injection. Hydraulic fracturing induces tensional and compressional stress perturbation around the producing well in the vicinity of fracture tips and fracture walls while the stress is released as the well produces. In addition, the magnitude of stress variation in the well group increases with the depletion at the beginning, followed by a decrease. It is beneficial to refrac the well group 3 years after the first treatment. The impact of water injection, primary hydraulic fracturing and well depletion on the variation of in-situ stress was clarified through an integrated modeling in this study, providing insights for the design and evaluation of refracturing treatments to enhance the field development of the low permeable reservoirs.
Abstract The polymeric nanospheres (NS) is the conformance control agent significantly improving oil recovery through redistribution of water flows deep in reservoir. The operator took a decision to pilot nanospheres technology in their large sandstone Changqing oil field in China after the experimental program has been conducted proved its potential. The nanospheres pilot has been executed in the oil field, resulting in substantial oil recovery improvement and water-cut reversal. Full-field implementation began. Extensive experimental study was conducted to analyze the effect of nanospheres on oil displacement in the Changqing field. The focus of the program was on the impact of reservoir heterogeneity and effect of nanospheres on oil displacement at different permeability contrast. Coreflood experiments were conducted with dual-core set-up, where sand cores were mimicking permeability contrast of the target reservoir. The program resulted in selecting optimum injection concentration and volumes for the pilot. Nanospheres solution has been injected in the oil field, and dedicated surveillance program was executed. Water flooding is effective in heterogeneous reservoirs when the average permeability contrast is below 20. When the contrast is higher e.g. as in target reservoir with permeability ranging from 7 to 2900 mD, water flooding is less efficient, especially in low-permeability zones. Nanospheres can mitigate the negative impact of high permeability contrast by diverting flow into previously unswept reservoir layers. This improves oil recovery, chiefly from low-permeability areas. Coreflood experiments proved the feasibility – incremental oil recovery was observed at 34%. Optimum pilot injection strategy has been designed. The effectiveness of nanospheres with high permeability variation has been demonstrated in the field tests. The field results have confirmed the positive impact of nanospheres on water flooding. In one of the tests, an average oil production rate increased from 5.1 to 10.8 t/d while water-cut was reduced from 94% to 83%. Analysis confirmed that nanospheres provided efficient conformance control deep in reservoir and did not result in loss of injectivity. Chemical utilization factor achieved is more than 100 tons of oil produced per ton of chemicals injected. Treatment costs per pattern were significantly lower compared to other IOR/EOR techniques. The operator has decided to implement nanospheres for conformance control in all field. Dedicated experimental program to select and, more important, optimize conformance control in heterogeneous reservoirs will be presented. Further, the paper will describe the field trial conducted. Both experimental and field data demonstrate the relationship between the oil displacement efficiency and injection conditions for different permeability contrasts. Results of field implementation will be presented. The technology effectiveness has been confirmed and full-field implementation has started.
Wang, HaiYang (Xi'an Shiyou University) | Zhou, Desheng (Xi'an Shiyou University) | Xu, Jinze (Xi'an Shiyou University) | Liu, Shun (Xi'an Shiyou University) | Liu, Erhu (Yanchang Petroleum Group ExplorationCompany) | Gao, Qian (Xi'an Shiyou University) | Liu, Xiong (Xi'an Shiyou University) | Guo, Minhao (Northwest University) | Wang, Panfeng (China Petroleum Pipeline Engineering Co.,Ltd.)
Abstract Slickwater fracturing technology is one of the significant stimulation measures for the development of unconventional reservoirs. An effective proppant placement in hydraulic fractures is the key to increase the oil production of unconventional reservoirs. However, previous studies on optimizing proppant placement are mainly focused on CFD numerical simulation and related laboratory experiments, and an optimization design method that comprehensively consider multiple influencing factors has not been established. The objective of this study is to establish an optimal design algorithm for proppant placement based on the construction characteristics of slickwater fracturing combined with Back Propagation (BP) neural network. In this paper, a proppant placement simulation experimental device was built to analyze proppant placement form data. We established a BP neural network model that considers multiple influencing factors and used the proppant placement form data to train and calibrate the model, which the proppant placement form prediction model is finally obtained. Using the proppant placement form prediction model, we designed an algorithm that can quickly select the three groups of construction schemes with the best proppant-filling ratio based on the massive construction schemes. The results indicate that the prediction results of the algorithm for proppant placement form are consistent with the CFD simulation results and experimental results, and the numerical error of the balanced height and the distance between the front edge of the proppant sandbank and the fracture entrance is within 5%. After using this algorithm to optimize the design of the fracturing construction scheme for the C8 oil well in Changqing Oilfield, the stimulation performance of the C8 oil well after fracturing is 2.7 times that of the adjacent well. The optimal design algorithm for proppant placement established in this paper is an effective, accurate, and intelligent optimization algorithm. This algorithm will provide a novel method for hydraulic fracturing construction design in oilfields.
Li, Shiyuan (China University of Petroleum-Beijing) | Zou, Zhikun (China University of Petroleum-Beijing) | Zi, Huaiyou (China University of Petroleum-Beijing) | Xian, Sheng (Changqing Oil Company)
ABSTRACT: As a hot spot for oil and gas exploration and development, shale oil reservoirs are widely distributed in the domestic Changqing Oilfield, Xinjiang Oilfield and Daqing Oilfield. Shale oil reservoir rocks mainly include shale, mudstone and sandstone. This article carried out creep experiments on Chang-7 reservoir shale in Changqing Oilfield and Changning shale in Southwest Oilfield. In this study, shale specimens were studied through triaxial experiments and a power-law creep constitutive model was established. In the experiment, room temperature and indoor humidity were applied. The three loading stages include axial pressure and confining pressure acting on the specimen at the same time, and the deviator stresses are 10, 15 and 20 MPa, respectively. Each loading lasts for 8 hours, and one entire experiment lasts for 1 day overall. The experimental temperature is 110°C. Through the relationship between creep strain and time in the experiment, the creep law of shale rock can be obtained. The strain rate is mainly affected by differential stress and temperature. It can be seen from the results that at 110 °C, the shale creep of Chang-7 reservoir exhibits steady-state creep behavior within the experimental time range, and the creep rate increases with the differential stress. Under the condition of 20MPa, the creep rate is about 1.00×10s. Under the condition of 15MPa, the creep rate is about 5.28×10s. Under the condition of 10MPa, the creep rate is about 2.73×10s. For Changning shale rock, under the condition of 20MPa, the creep rate is about 1.9×10s. Under the condition of 15MPa, the creep rate is about 1.32×10s. Under the condition of 10MPa, the creep rate is about 9.08×10s. The main purpose of studying the long-term creep mechanical behavior of shale is to develop the change of fracture width after long-term production and its influence on the conductivity. Quantitative simulation research can be performed. The purpose of this study can make a prediction and assessment of the decline in production capacity.
Summary Progressing cavity pump (PCP) is the essential booster equipment in oil–gas mixing delivery. Changes in relevant parameters in PCP operations directly affect the working performance and service life of the pump. On the basis of computational fluid dynamics (CFD) in this study, we apply dynamic grid technology to establish a 3D flow field numerical calculation model for the CQ11-2.4J PCP, which is used in the field of the Hounan Operation Area in Changqing oil field, China. The effects of several operating parameters, such as oil viscosity, pump rotation speed, differential pump pressure, and void fraction of oil, on the pressure and the velocity distribution of the PCP flow field are examined. Various performance parameters in the transport of the oil–gas two-phase mixture are used in the analysis, including volumetric flow rate, slippage, shaft power, volumetric efficiency, and system efficiency. The results show that the pressure and speed distribution in the pump chamber of the PCP is relatively homogenous under different working conditions, whereas the pressure and speed exhibited sharp changes at the stator and rotor sealing line and adjacent areas in the pump chamber. Increasing the viscosity of the oil and the speed of the rotor can effectively improve the flow characteristics of the PCP, but extremely high pump rotation speed would cause a decline in system efficiency. Increasing the differential pressure and the void fraction of oil would result in a decrease in the volumetric flow rate and efficiency of the PCP. Considering the variation law of the PCP's performance parameters, the optimal interval for each operating parameter of the PCP is as follows: Oil viscosity at 50–100 mPa·s, pump rotation speed at 200–300 rev/min, differential pressure at 0.2–0.3 MPa, and the void fraction of oil not more than 50%. This research can provide technical support for the optimization of the working conditions of the PCP on site.
Wu, Tao (CNPC Chuanqing Drilling Engineering Co.LTD) | Fang, Hanzhi (Yangtze University) | Sun, Hu (CNPC Chuanqing Drilling Engineering Co.LTD) | Zhang, Feifei (Yangtze University) | Wang, Xi (Yangtze University) | Wang, Yidi (Yangtze University) | Li, Siyang (Yangtze University)
Abstract Unconventional reservoirs such as shale and tight sandstones that with ultra-low permeability, are becoming increasingly significant in global energy structures (Pejman T, et al., 2017). For these reservoirs, successful hydraulic fracturing is the key to extract the hydrocarbon resources efficiently and economically. However, the intrinsic mechanisms of fracturing growth in the tight formations are still unclear. In practice, fracturing design mainly depends on hypothetical models and previous experience, which leads to difficulties in evaluating the performance of the fracturing jobs. Therefore, an improved method to optimize parameters for fracturing is necessary and beneficial to the industry. In this paper, a data-driven approach is used to evaluate the factors that dominate the production rate from tight sandstone formation in Changqing Field which is the largest oil field in China. In the model, the input parameters are classified into two categories: controllable parameters (e.g. stage numbers, fracturing fluid volume) and uncontrollable parameters (e.g. formation properties), and the output parameter is the accumulated oil production of the wells. Data for more than 100 wells from different formations and zones in Changqing Field are collected for this study. First, a stepwise data mining method is used to identify the correlations between the target parameter and all the available input parameters. Then, a machine learning model is developed to predict the well productivity for a given set of input parameters accurately. The model is validated by using separate data-sets from the same field. An optimize algorithm is combined with the data-driven model to maximize the cumulative oil production for wells by tuning the controllable parameters, which provides the optimized fracturing design. By using the developed model, low productivity wells are identified and new fracturing designs are recommended to improve the well productivity. This paper is useful for understanding the effects of designed fracturing parameters on well productivity in Changqing Oilfield. Furthermore, it can be extended to other unconventional oil fields by training the model with according data sets. The method helps operators to select more effective parameters for fracturing design, and therefore reduce the operation costs for fracturing and improve the oil and gas production.
Xu, Hongxing (CCDC Changqing Down Hole Technology Co., CNPC) | Sun, Hu (CCDC Changqing Down Hole Technology Co., CNPC) | Wang, Zuwen (CCDC Changqing Down Hole Technology Co., CNPC) | Zhang, Mian (CCDC Changqing Down Hole Technology Co., CNPC) | Lan, Jianping (CCDC Changqing Down Hole Technology Co., CNPC) | Deng, Binqi (CCDC Changqing Down Hole Technology Co., CNPC) | Li, Yanhong (CCDC Changqing Down Hole Technology Co., CNPC)
Abstract Pulse hydraulic fracturing is a promising stimulation technology to enhance the effectively permeability of coal seams. The fundamental of pulse hydraulic fracturing is that fracturing fluids with a certain frequency are injected into coal, resulting in the rupture of coal and forming a well-distributed fracture network due to the pulse loading. Better effects of gas extraction using pulse hydraulic fracturing had been gotten compared with that of hydraulic fracturing. Accordingly, how to apply pulse hydraulic fracturing technology to improve the fracturing effect of tight and shale reservoirs is a question worth thinking about, although this is very challenging due to the totally different downhole operating conditions. In this paper, experimental apparatus for fatigue damage of quasi-triaxial rock under alternating loads was established. The maximum injection pressure is 50MPa, while the pulse pressure amplitude is greater than 5MPa, and the pulse frequency is adjustable from 0 to 50Hz. Rock failure experiments under pulsating load were carried out and the effects of different hydraulic pulse parameters and rock properties on rock damage were studied. Experimental results show that hydraulic pulse has different effects on rock compressive strength and fracture pressure of different properties. With the increase of hydraulic pulse frequency, the influence on rock compressive strength increases firstly and then decreases. With the increase of pulse pressure amplitude, the influence on rock strength increases. With the increase of hydraulic pulse processing time, the influence on rock fracture pressure increases firstly and then tends to stabilize. Hydraulic pulse has the greatest influence on the compressive strength and fracture pressure of He 8 reservoir, followed by Chang 8 and Chang 6 reservoir of Changqing Oilfield in China. Based on the experimental results, hydraulic pulse frequency is preferred to be about 18-20Hz, accordingly, a downhole hydraulic pulse generator is designed and manufactured. The indoor test results show that the generator performance meets the design requirements. Field tests of pulse hydraulic fracturing were carried out in 3 wells in Changqing tight oil reservoir. Encouraging results were obtained, the average construction pressure was reduced obviously and average daily production per well increased significantly compared to adjacent wells.
Yang, Kunpeng (CNPC Tianjing Bo-Xing Engineering Science&Technology Co., Ltd., CNPC Key Laboratory of Drilling Engineering, National Engineering Laboratory of Petroleum Drilling Technology) | Xin, Haipeng (CNPC Tianjing Bo-Xing Engineering Science&Technology Co., Ltd., CNPC Key Laboratory of Drilling Engineering, National Engineering Laboratory of Petroleum Drilling Technology) | Shi, Linglong (CNPC Tianjing Bo-Xing Engineering Science&Technology Co., Ltd., CNPC Key Laboratory of Drilling Engineering, National Engineering Laboratory of Petroleum Drilling Technology) | Sun, Fuquan (CNPC Tianjing Bo-Xing Engineering Science&Technology Co., Ltd., CNPC Key Laboratory of Drilling Engineering, National Engineering Laboratory of Petroleum Drilling Technology) | Zeng, Jianguo (CNPC Tianjing Bo-Xing Engineering Science&Technology Co., Ltd., CNPC Key Laboratory of Drilling Engineering, National Engineering Laboratory of Petroleum Drilling Technology) | Zou, Jianlong (CNPC Tianjing Bo-Xing Engineering Science&Technology Co., Ltd., CNPC Key Laboratory of Drilling Engineering, National Engineering Laboratory of Petroleum Drilling Technology)
ABSTRACT In order to effectively solve the problem of cementing the long sealing section of low-pressure volatile formations, and at the same time to adapt to the current low-cost strategy for oil and gas exploration, a lightening and strengthening material was developed. The material has the characteristics of good stability, high activity, high water storage, etc., and has a wide range of sources and low price. It is supplemented with appropriate admixtures to form a low-density cement slurry of 1.20 ∼ 1.60 g/cm. While expanding the liquid-solid ratio and reducing the density, it has excellent performance and greatly reduced costs. 60 °C/ 24 h compressive strength is greater than 8 MPa, 72 h compressive strength is above 10 MPa; slurry stability and pressure resistance are good; water loss is controllable and thickening time is adjustable to meet construction requirements. It has good prospects for promotion and application. INTRODUCTION Low-pressure and easily leaking complex oil and gas wells are commonly found in Changqing Oilfield, Tarim Oilfield, Jilin Oilfield, Qinghai Oilfield and offshore oilfields in China. Under the new safe production and environmental protection policies, each oilfield strictly requires the cementing of all well sections must be sealed and the cement slurry must return to the ground. This will undoubtedly result in high cementing costs due to the high consumption of low-density cement slurries. At the same time, the exploration and development costs of the "low oil price" market environment have been greatly reduced, so the contradiction between "high performance" and "low cost" of low-density cement slurry becomes more profound. Low-density cement slurry currently has two mature technologies: One is to expand the liquid-solid ratio (LSR) by adding superabsorbent materials and lightweight fillers such as bentonite, diatomaceous earth, expanded perlite, etc. Another technology is to add glass microbeads materials which have low densities, such as fly ash, floating beads, hollow beads, and so on. They can replace some of the cement to reduce the density of the slurry. Generally, the density of low-density systems has a minimum limit. For example, the minimum densities of bentonite, diatomaceous earth, fly ash, and floating bead cement are 1.60, 1.50, 1.55, and 1.38 g/cm (Liu, 2001), Below the above values, the performance of the cement slurry is poor, especially the compressive strength. According to the requirements of Cementing Technical Specifications of CNPC: The non-target layer cement stone of the production casing shall have a compressive strength of not less than 7 MPa at 24∼48 hours. In the low pressure and easily lost formation, the above system is difficult to meet the requirements. The cement slurry with artificial hollow microbeads has better performance and lower density, but the cost is higher, and it is difficult to promote and apply (Zhou, 2004). In summary, combining the two methods, with the goal of reducing cost and maintaining performance, a composite reinforcing material BCE-600S was developed using high water absorption, high activity and ultrafine materials. Its role is to expand the liquid-solid ratio, significantly reduce the cost of cement slurry and improve the performance of cement slurry. BCE-600S is used as a mitigating agent, and at the same time, it is used as an auxiliary material and an admixture to form an Low-density cement slurry with a low cost and excellent performance of 1.20∼1.30 g/cm, in order to cope with the current severe environmental protection requirement and low-cost development strategy.