2022 Vol. 39, No. 1

2022, 39(1): 1-2.
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DRILLING FLUID
Effect of Water on BaSO4 Particles/GTL Suspensions
ZHANG Xuemei, ZHANG Guilei, GUO Xiaoxuan, GENG Tie, LI Bin, FENG Zongtao, SUN Dejun
2022, 39(1): 1-7. doi: 10.12358/j.issn.1001-5620.2022.01.001
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The dispersion state of weight material has a great effect on the rheology of oil based drilling fluids. In laboratory experiment, the effects of water on the settling stability and the viscosity of the suspension were studied. The suspension used in the experiments was formulated with fatty alcohol polyoxyethylene ether carboxylic acid (C12E9Ac) as the dispersant, BaSO4 as the dispersed phase and a gas to liquids (GTL) as the dispersing medium. It was found through the experiments that with the increase in the water content in the suspension, the dominant forces between the dispersed particles can be turned from repulsive force to attractive force. When the water is added in a concentration that is less than 0.5%, the settling stability and viscosity of the suspension are almost not affected, and the re-dispersibility of the suspension is enhanced. When the water is added at a concentration between 0.5% and 2.5%, water will not only cause the particles in the suspension to aggregate, the “big particles” formed by the aggregation of the particles will connect with each other through water bridge to form a complex network structure. When the water is added at a concentration greater than 25%, part of the particles in the suspension is dispersed in the water phase, decreasing the network structures formed by the particles, and hence the viscosity of the suspension. Thus, adding some water into a suspension stabilized by the C12E9Ac will help improve the re-dispersibility of the sediments in the suspension without disturbing the dispersion stability and viscosity of the suspension. The conclusions drawn from these experiments have provided a research method for controlling the settling stability of the particles in an oil based drilling fluid.
Study on Rheological Modifier of High Temperature High Density Clay-free Oil-based Drilling Fluid
SHI He, SHI Haimin, NI Xiaoxiao, CHENG Rongchao, ZHANG Jiaqi, WANG Jianhua, YAN Lili
2022, 39(1): 8-14. doi: 10.12358/j.issn.1001-5620.2022.01.002
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Aiming at the problem of insufficient settlement stability of oil-based drilling fluids in high temperature environments, a small molecule fatty acid amide type rheological modifier FAA which can be used in high temperature environment was synthesized by reacting dimer fatty acids and diethylene triamine at a molar ratio of 1∶2, with the structural characterization, mechanism analysis and performance evaluation were also carried out. The results of rheological experiments and microscopic observations show that the FAA effectively improves the structural strength of the oil-based drilling fluid system by bridging the emulsion droplets to form a gel-like network structure, thereby effectively improving its solid-phase suspension ability and settlement stability. The evaluation results in the diesel-based drilling fluid system show that the FAA can effectively improve the yield point, φ6/φ3 revolution reading and yield point/plastic viscosity ratio of the system, and can effectively improve the high-temperature sedimentation stability of the system, making it standing at 220℃ for 5 days with the sedimentation factor SF less than 0.52 and no obvious sedimentation phenomenon occures.
Mechanisms of Oleamide as Thinner in Oil Based Drilling Fluids
WANG Jing, ZHANG Shuncong, LI Changling, SHU Jia, ZHONG Dehua, LU Fuwei
2022, 39(1): 15-22. doi: 10.12358/j.issn.1001-5620.2022.01.003
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In laboratory experiment, different types of clay were added to a base mud to investigate the effect of formation clays on the viscosity of the base mud, and an asphalt filter loss reducer was added to a base mud at different concentrations to investigate the effect of asphalt on the viscosity of the mud. After adding 5% organophilic clay and 15.5% asphalt filter loss reducer into the base mud, the plastic viscosity of the base mud was increased by 100%, and the yield point of the base mud was increased by at least 370%. An oleamide type thinner was then added into the base mud contaminated with organophilic clay at 1% and the viscosity of the base mud was reduced by 10%, and the yield point reduced by at least 80%. After adding 1% oleamide type thinner into the base mud treated with 15.5% asphalt, the yield point of the base mud was reduced by at least 73%. These experimental results indicate that oleamide is able to disassemble the network structure formed by the low quality solids in the mud. An oil based mud (density 2.25 g/cm3) sample was taken from a well and was treated with 1% oleamide thinner, the viscosity and yield point of the mud were reduced by 15% and at least 30%, respectively. The major role of the oleamide thinner in the oil based mud sample is to disassemble the network structure formed by the low quality solids in the mud, the mechanism of viscosity reducing is the same as that of the mud contaminated with excessive amount of organophilic clay and asphalt. Rheology test at high temperature high pressure conditions has shown that at 205 °C, oleamide can still reduce the viscosity of an old oil based mud by 4.76% and the yield point of the old oil based mud by 8.70%. The oleamide thinner disassembles the excessive network structure in the mud taken from the rig-site and effectively improves the rheology of the mud.
Effects of the Molecular Structure of Block Polymer Developed through RAFT Polymerization on Filtration Property of Drilling Fluids
YANG Lili, WANG Aijia, JIANG Guancheng, AO Tian, ZHAO Zhengguo, TANG Runping
2022, 39(1): 23-28. doi: 10.12358/j.issn.1001-5620.2022.01.004
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A series of isomeric zwitterionic filter loss reducers have been developed for investigating the effects of the molecular structure of polymers on their filtration control performance. These isomeric zwitterionic filter loss reducers were synthesized through reversible addition-fragmentation chain transfer polymerization (RAFT) with monomers such as AMPS (ionic monomer), 1-vinyl-3-ethylimidazollium bromide (VeiBr, as cationic monomer) and acrylamide (AM, as neutral monomer). By adjusting the sequence of adding different monomers, three copolymers, which are a random copolymer, a partial block polymer and a full block copolymer, respectively. These three copolymers have precise molecular structures, different bonding sequence (of atoms) and narrowly distributed and controllable molecular weights. Laboratory performance evaluation of these copolymers have shown that under the same test conditions, the random copolymer has the best filtration control performance, while the block copolymers can be used to make high YP/PV ratio flow pattern modifiers. By changing the concentration of the chain transfer agent, the molecular weight of the copolymers can be effectively adjusted, and this helps analyze the effects of copolymers with the same molecular structure and different molecular weights. It was found that the higher the molecular weight, the higher the viscosity and the better the filtration control performance of the copolymers. It is thus concluded that block polymers with random sequence structure are more suitable for filtration control in drilling fluids, and polymers with higher molecular weight will perform better in this aspect. This study has provided a theoretical base for developing high efficiency molecular structure oriented filter loss reducers.
Study on Mechanisms of Carbon Nanotube as a Nanosized Plugging Agent in Water Based Drilling Fluids
CHEN Lili, GUO Jianhua, XIE Gang
2022, 39(1): 29-35. doi: 10.12358/j.issn.1001-5620.2022.01.005
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Micron-scale plugging agents are unable to effectively plug the nanosized fractures. To overcome this problem, aminated multi-walled carbon nanotubes were selected as the nanosized plugging agent. The effects of the aminated multi-walled carbon nanotubes on the rheology of drilling fluids were studied using the micron-scale ultrafine CaCO3 as a comparison. The plugging mechanism of the aminated multi-walled carbon nanotubes was studied through filtration test on artificial mud cakes and osmosis experiment on artificial cores. The study results showed that the carbon nanotube has almost no effect on the rheological parameters of the drilling fluid, and addition of ultra-fine CaCO3 into the drilling fluid made its rheology deteriorated. Plugging of the artificial mud cakes with the aminated multi-walled carbon nanotube becomes improved with the increase in the amount of the nanotubes added. When the concentration of the aminated multi-walled carbon nanotube was 3%, 77.70% of the mud cakes can be plugged, while the addition of the same concentration of ultra-fine CaCO3 only plugged 45.28% of the artificial mud cakes. Experiment on artificial cores showed that at a concentration of 3% aminated multi-walled carbon nanotube, the core was plugged by 79.41%, while at a concentration of 3% ultra-fine CaCO3, the core was plugged only by 61.76%. These experimental results fully demonstrate that the nanosized plugging agents are much better than micron-scale plugging agents in terms of plugging; the calcium carbonate can only accumulate on the face of a fractured surface, while the aminated multi-walled carbon nanotube can penetrate into the nanosized fractures and form bridges therein. By tightly adsorbing on the surfaces inside the fractures with the amino groups, the aminated multi-walled carbon nanotube prevents the filtrate from going into the fractures.
Viscoelasticity of Polymers and Carrying Capacity of Drilling Fluids When Sidetracking through Surface Casing
FU Jianmin, ZHANG Peng, GUO Lei, PENG Sanbing
2022, 39(1): 36-40. doi: 10.12358/j.issn.1001-5620.2022.01.006
Abstract:
Through-casing sidetracking is one of the important technical methods for production and efficiency enhancement. When opening windows on the walls a several layers of casing strings, large quantities of iron fillings are produced, imposing a challenge to the hole cleaning capacity of the drilling fluid used. The iron fillings produced in the windowing operation have high density and are therefore settling fast in the drilling fluid. Meanwhile, the iron fillings have different shapes, when carried up the annular space they tend to intertwine with each other to form cage-shaped structures, further increasing the difficulty of borehole cleaning. Several polymer solutions, each with different concentrations of the same polymer, have been evaluated on a laboratory dynamic carrying efficiency tester for their ability to carry the iron fillings. Through these tests, the rheological property of the polymer solutions affecting the carrying of the iron fillings during window-opening operation was studied from the viscoelasticity aspect of these polymers.
Research on Preparation Technology of Temperature-Controlled Expansion Plugging Agent Based on Shape Memory Polymer
WANG Baotian, YANG Qianyun, YANG Hua
2022, 39(1): 41-45. doi: 10.12358/j.issn.1001-5620.2022.01.007
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A kind of temperature-controlled expansion plugging agent based on temperature-triggered shape-memory material is prepared to achieve expansion bridging in fractured stratum after the temperature reaches the excitation temperature point. This paper discusses the preparation technology of the temperature-controlled expansion plugging agent. Firstly, an oligomer resin monomer and different high-temperature cross-linking agents are mixed to reaction by a catalyst under different heating temperature and time, then the mixture will be solidified through crosslinking. Secondly the reaction product after taking off the mold is pressed in the specific temperature in order to reserve deformation memory function. Finally the new polymer is crushed and granulated into various particle sizes according to demand at room temperature. The new plugging agent prepared has adjustable glass transition temperature, adjustable particle size, large compressive strength, large expansion at high temperature and high pressure, and the particle size growth rate of D90 after aging at 150 ℃ and 20 MPa is 44.71% ~ 54.17%. It can adapt to crack size to bridging, moreover, block leaking channels deformed by squeezing to improve the retention capacity and pressure endurance capacity of the plugging fluid.
Study and Application of a High Efficiency Liquid Pipe Freeing Agent in Pakistan
LI Wei, JI Yongzhong, YANG Gang, LI Ling, CHEN Wenbo
2022, 39(1): 46-52. doi: 10.12358/j.issn.1001-5620.2022.01.008
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Black Magic is a widely used pipe freeing agent in Pakistan. Problems existed with the use of this pipe freeing agent include long time of preparation, weighting agents in the pipe freeing slurry which are easy to settle, poor compatibility of the Black Magic with drilling fluids used and low success rate of pipe freeing operations. A new high efficiency pipe freeing agent, ZL SPOT, was selected to solve these problems based on three evaluation parameters, say, degree of mud cakes broken down by the pipe freeing agent, time spent penetrating the mud cakes and extreme pressure friction coefficient. By studying the effects of oil/water ratio, pipe freeing agent and viscosifier on the break-down and penetration of the mud cakes, a weighted pipe freeing slurry was formulated with 0# diesel oil, ZL SPOT, water and organophilic clay. Laboratory experimental results showed that for unweighted pipe freeing slurry, at a concentration of the pipe freeing agent between 1% and 2.5%, the extreme pressure friction coefficient was 0.069, time for 100 mL pipe freeing slurry to penetrate the mud cakes was only 15 min, and after soaking in the pipe freeing slurry, mud cakes were obviously developed with fracture network on the surfaces, indicating the ZL SPOT is superior to the dry pipe freeing agent Black Magic. For weighted pipe freeing slurry, addition of solids into the slurry greatly affects the efficiency of freeing a stuck pipe. However, when the concentration of the ZL SPOT was increased to 8%, the mud cakes were developed with fracture network after being soaked in the pipe freeing slurry. When stood still for 16 h at 120 ℃, the pipe freeing slurry with its density between 1.32 g/cm3 and 1.80 g/cm3 showed no signs of barite settling. When mixed with water based drilling fluid at a ratio of 1∶1, the pipe freeing slurry basically did not affect the rheology and filtration rate of the drilling fluid. This liquid pipe freeing agent has been successfully used on two wells drilled in Pakistan, proving its pipe freeing ability. Field operation with this pipe freeing agent is easy, and the application of this pipe freeing agent will popularize in the future.
Study and Treatment on Carbonate/Bicarbonate Pollution in Shale Gas Wells in Sichuan
LI Wentao
2022, 39(1): 53-58. doi: 10.12358/j.issn.1001-5620.2022.01.009
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Shale gas drilling in Sichuan basin is moving from the block Wei-202 to block Wei-204, where the water based drilling fluids used in the second interval were generally contaminated with CO32- and HCO3-. The source of the contamination is the Changxing, Longtan and Maokou formations. Contamination of the drilling fluids resulted in fast increase in viscosity and gel strengths, and it was difficult to bring under control the increase in viscosity and gel strengths. To deal with this problem, the source of CO32- and HCO3- was first analyzed. It was believed that CO2 invasion took place in drilling the Changxing and Longtan formations, and some mud materials contain high concentration of HCO3- (>10,000 mg/L). Measures have been taken to prevent the contamination from mud materials. Using pH meter, the concentrations of CO32- and HCO3- can be accurately measured. Preventing measures and two treatment methods (CaO and CaCl2) were discussed, and it was concluded that CaCl2 is the best additive to deal with the contamination. Previously CaO had been used to treat out the CO2 contamination on well Wei-204H23-5 and well Huang-206, but the results were not satisfactory. After using CaCl2 to treat out the CO2 contamination, the concentration of HCO3- was reduced from 15,420 mg/L to 1120 mg/L, and the viscosity of the mud was reduced from above 300 sec to 54 sec, which was the viscosity of the mud before HCO3- contamination. The viscosity of the mud in well Huang-206 was 180 sec after HCO3- contamination, and was reduced to 57 sec, as that before the contamination. This method of eliminating CO2 contamination has the advantages of is high efficiency, cost-effective and strong pertinence. Keep in mind that the technical measures should be well prepared to avoid contamination of the mud by both Ca2+ and HCO3-.n recent years, with the transfer of the construction block from Wei202 to Wei204, the pollution problem of carbonate/bicarbonate in the water base drilling fluid was widely encountered. The pollution occurred mainly in Changxing, Longtan and Maokou, and the viscosity/shear increased rapidly and was difficult to control. In view of this problem, the sources of pollution were firstly discussed, and the analysis showed that CO2 intrusion and coal interlayer in Changxing and Longtan were important pollution sources of carbonate/bicarbonate. Some materials contained a large amount of bicarbonate (>10 000 mg/L), and measures had been taken at present. The accurate test of carbonate/bicarbonate can be achieved by using a pH meter. Secondly, preventive measures and two treatment schemes are discussed, and it is suggested that CaCl2 treatment is more suitable for this block.Finally, the CO2 pollution treatment technology of Wei 204H23-5 and Huang 206 was explored. Two wells were treated with the CaCl2 solution when the CaO treatment was not ideal. HCO3 in Wei 204H23-5 decreased from 15,420 mg/L to 1120 mg/L, FV >300 s decreased to 54 s as pre-pollution state. After the pollution, the FV of Huang 206 well was up to 180 s, and after the treatment, the FV was reduced to 57 s as pre-pollution state. This method has the advantages of high efficiency, economy and strong pertinence, but technical measures should be implemented to avoid the double contamination of drilling fluid by Ca2+ and HCO3.
CEMENTING FLUID
Development of Strength of Set Aluminate Cement in Liquid and Gaseous CO2 Environment
FAN Baitao, WU Zhiqiang, ZHANG Dangsheng
2022, 39(1): 59-64. doi: 10.12358/j.issn.1001-5620.2022.01.010
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In in-situ combustion operation, the set cement has to experience temperatures up to 500 ℃, under which the silicate cement is unable to retain its stability, and large amount of corrosive gas will be produced in the wellbore. To deal with these problems, the calcium aluminate cement (CAC) modified with slag was chosen to study its mechanical feasibility in cementing high temperature wells. The strength development pattern of the slag CAC was studied in a simulated real in-situ combustion work condition. The material composition and micromorphology of the slag CAC before and after corrosion were tested using X-ray and SEM, and the strength development of the slag CAC under simulated in-situ combustion work condition was investigated. It was found that with the increase in the amount of slag in the CAC, the compressive strength of the set cement first increased and then decreased, a top value was obtained at slag concentration of 30% in the cement. At elevated temperatures, the slag CAC can still retain higher compressive strength, and after secondary curing at high temperature, the strength of the set slag CAC was further developing, indicating that the slag cement has good high temperature resistance. In 50 ℃ liquid environment, corrosion of the set cement produced calcium carbonate and in the set cement there were pores and micro fractures because of the corrosion, all these damaged the integrity of the set cement and caused the strength of the set cement to reduce. In high temperature gaseous environment, CO2 did not cause corrosion damage to the set cement. This study has provided a theoretical base for optimizing the mechanical performance and improving the CO2 corrosion resistance of the set CAC under in-situ combustion work condition.
Application of Autonomous Healing Cement Slurry System in Sichuan
YANG Bingxiang, LIU Haoya, WEI Haoguang, ZENG Min, HE Shiming
2022, 39(1): 65-70. doi: 10.12358/j.issn.1001-5620.2022.01.011
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Aiming at the problem of damage effect of cementing isolation caused by formation of crack in cement sheath during the development of oil and gas wells, the hydrocarbon-triggered swelling polymer was used as self-healing particles to form an autonomous healing cement slurry system. The experimental results show that when the self-healing particle size is 200-250 nm and the amount is about 10%, the cement stone has better oil absorption healing effect and mechanical properties: the cement stone crack healing rate is 70%-100% within 8 days, and the 2 d compressive strength is 16.2 MPa, elastic modulus 6 GPa. Seepage experiments show that the flow rate of oil and gas in cracks of cement stone larger than 0.1 mm is reduced from 9 g/min to 6 g/min, and the flow rate of cracks smaller than 0.1 mm can be reduced from 6 g/min to 0. This shows that once the autonomous healing cement is damaged, the oil and gas molecules infiltrated into the crack and the self-healing particles spontaneously expand and adhere, then the cracks are gradually repaired. It can realize that the cement has self-healing function. The smaller the crack, the better the self-healing effect. The field application in Sichuan shows that the cementing quality of the autonomous healing cement system reached 88.9%, and the technical casing pressures after cementing and fracturing were not appeared, showing good application effects.
Research on A New Material to Prevent the Strength Decline of Set Cement Under Ultra-High Temperature
ZHOU Chongfeng, FEI Zhongming, LI Dewei, ZHAO Jiangbo, JIANG Shiwei, LIU Huiting, XU Ming
2022, 39(1): 71-75. doi: 10.12358/j.issn.1001-5620.2022.01.012
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In wells with bottomhole temperatures of 200 ℃ or higher, the strength of the set cement with sand will inevitably decrease with time, causing the zonal isolation by the cement sheaths to fail. Wells with this kind of problem will not be able to produce for the designed long time. Researches have been done to investigate the mechanisms of strength retrogression of sanded set cement, showing that the root cause of strength retrogression is the increase in the porosity of the set cement resulted from the generation of parallel loose xonotlite from the hydration of that cement at ultra-high temperatures. To deal with this problem, a new material against strength retrogression of set cement at ultra-high temperatures, DRB-4S, has been developed with optimized aluminum mineral having nanometer crystal layer spacing and nanotube materials. At 240 ℃, a set cement containing 10%–20% DRB-4S has a strength of 50 MPa and does not decrease. Studies on the mechanisms of DRB-4S against strength retrogression of set cement with SEM, XRD and pore structure analysis showed that the use of the nanometer crystal layer spacing aluminum mineral in DRB-4S helps the production of chalcomorphite, a hydration product that is stable at elevated temperatures, in the set cement. The nanotube used in DRB-4S inhibits the conversion of tobermorite to xonotlite and reduces the porosity of the set cement through bridging and filling. Cement slurries treated with DRB-4S have filter loss of less than 50 mL, easy-to-adjust thickening time, good stability and operational performance, all these are of great technical support to the long-term production of high-temperature oil and gas wells.
Study on Thermally Viscosifying Copolymer as a High Temperature Stabilizer for High Density Cement Slurries
LI Xiaolin, LI Jianhua, YANG Hongbin, LIU Wenming, QI Ben, LI Zhe, YU Jingyu
2022, 39(1): 76-81. doi: 10.12358/j.issn.1001-5620.2022.01.013
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To dela with the loss of settling stability of cement slurries at elevated temperatures, a high temperature high density cement slurry stabilizer based on a thermally viscosifying copolymer was developed. A new hydrophobic monomer was introduced into the molecule of the thermally viscosifying copolymer. To understand the thermal viscosification mechanisms of this copolymer, the rheology of the copolymer solution was tested at different temperatures. The apparent viscosity of the copolymer solution increases with temperature, and reaches its maximum value at 115-125 ℃. Continued increasing the temperature, the apparent viscosity of the copolymer solution was slightly decreasing, however, the apparent viscosity of the solution at 150 ℃ was still two to four times the apparent viscosity of the solution at the beginning of the test, indicating that the copolymer has good thermally viscosifying effect. A high temperature suspending stabilizer for high density cement slurries was developed with this copolymer and other additives. In laboratory experiment, the effects of the stabilizer on the settling stability of cement slurries were evaluated, the rheology, filter loss, free water content, thickening performance as well as compressive strength of the cement slurry containing the stabilizer were measured. The experimental results showed that a 2.5 g/cm3 cement slurry treated with 1% stabilizer had its differential density at 150 ℃ reduced from 0.58 g/cm3 to 0.07 g/cm3, and the differential density of the corresponding set cement reduced to less than 0.08 g/cm3. The thinning effect of the cement slurry at elevated temperatures was mitigated and the stability of the cement slurry was significantly improved. After treatment with the stabilizer, the high density cement slurry had low filter loss and free water content, and the stabilizer had only minor effect on the thickening time, rheology and compressive strength of the cement slurry. The overall properties of the cement slurry treated with the stabilizer have satisfied the needs of field operations.
A High Efficiency Oil Wash Spacer for Shale Gas Wells in Changning Oilfield
TU Siqi, XIE Feiyan, AO Kangwei, ZHANG Tianyi, ZHEN Keli
2022, 39(1): 82-86. doi: 10.12358/j.issn.1001-5620.2022.01.014
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The oil based drilling fluids used in horizontal drilling of shale gas wells in Changning oilfield are poorly compatible with the cement slurries, resulting in the mixture of the drilling fluid and cement slurry flocculated and difficult to displace from the annular spaces. To solve this problem, an oil wash additive BCS-130L was developed based on the types, functioning principles and HLB levels of surfactants. A high efficiency oil wash spacer was developed using BCS-130L, which is suitable for use in Changning. This spacer, with its density ranging between 1.5 g/cm3 and 2.4 g/cm3, can work normally at temperatures between 70 ℃ and 180 ℃; it cleans the oil based drilling fluids held up on the surface of the annular spaces and reverses the wettability of the surfaces. The spacer has good rheology and stability and is compatible with the drilling fluid and the cement slurry in use, it has satisfied the requirements of shale gas well cementing in Changning oilfield.
The Technology of Interval Push Clay-Cement Slurry to Lost Circulation in Water Bearing Formation
ZHANG Dongqing
2022, 39(1): 87-91. doi: 10.12358/j.issn.1001-5620.2022.01.015
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Abstract:
Drilling into formations containing flow water is always accompanied with severe mud losses, and conventional mud loss control methods are seldom succeeded in controlling this kind of mud losses. To control this kind of mud losses, a bentonite cement slurry lost circulation material (LCM) was developed. By increasing the content of the bentonite in the mixture slurry, the viscosity of the slurry can be increased, thereby improving the ability of the LCM to resist thinning by the flowing water. Research on the rheology, compressive strength and flow property of the bentonite cement slurry has shown that the optimum bentonite concentration in the mixture is 2% – 2.5% provided that the compressive strength of the slurry has met the operational requirements. The mobility of the bentonite cement slurry is apparently reduced after standing for 10 min before initial gelling, at this time it is in high viscosity state. Based on the property of the bentonite cement slurry, a pulse squeeze method is designed for field operation. By adjusting the flow rate of squeezing the slurry and the time interval between two squeezes, the high viscosity bentonite cement slurry is squeezed into the loss channels. If the slurry at its initial gelling time is pushed into the loss channels, it will stay there and become cementing, in this way a high success rate of operation can be achieved. Application of this technique in a field operation in Huabei Oilfield has shown that the bentonite cement slurry, combined with the pulse squeeze technique, is able to control severe mud losses into formations with flowing water successfully at the first try. This low-cost technique is easy to operate and has high success rate in field application.
ACIDIZING FLUID & FRACTURING FLUID
Preparation and Performance Study of an Adsorptive Retardant for Acid Job
LIU Jing, YU Yangyang, YU Menghong, ZHANG Xia, SONG Xianmin, QUAN Hongping, LIU Yi
2022, 39(1): 92-99. doi: 10.12358/j.issn.1001-5620.2022.01.016
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Acid job has long been faced with a series of problems such as fast acid – rock reaction, difficulties in flowing back the residue acids as well as high secondary formation damage etc. To deal with these problems, an adsorptive retardant for acid job was developed through emulsion polymerization with raw materials such as allyl polyoxyethylene ether (APEE), an ester monomer EX and acrylamide (AM). The optimum reaction condition for the synthesis reaction obtained through single-factor optimization is as follows: m(AM)∶m(APEE)∶m(EX) = 10.66∶1.05∶0.17, the total mass fraction concentration of the monomers is 15%, the mass fraction concentration of the initiator 0.25%, the reaction temperature 50 ℃, and the reaction time 6.0 h. The molecular structure of the retardant was characterized with IR spectroscopy and studies were done on the effects of several factors, such as the concentration of the retardant in acid, temperature and concentration of calcium salts, on the retardant’s ability to retard the acid – rock reaction. It was found in the studies that when the mass fraction concentration of the retardant is 0.8%, the acid – rock reaction time can be extended to 120 min. The retardant was able to show good retarding performance at 70 ℃. The retarded acid prepared with the retardant has excellent resistance to calcium salts. SEM observation has shown that the retardant is adsorbed on the surfaces of the rocks, effectively retarding the contact of the hydrogen ions with the surfaces of calcium carbonate rocks and hence reducing the reaction rate between the acid and the rocks.
Study on Relationship between Rheology of HPAM Solution and Friction Reduction
GAO Hang, FANG Bo, XU Ke, LU Yongjun, YU Luyao, LIU Boxiang
2022, 39(1): 100-106. doi: 10.12358/j.issn.1001-5620.2022.01.017
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An equation describing the friction of polymer solutions was developed through the studies on the rheology and friction of HPAM solutions of different concentrations and molecular weights of HPAM. HPAM solutions formulated with five different HPAM concentrations and HPAM with four different molecular weights were measured for their steady-state shear viscosity, thixotropy and flow curves. The friction data of the HPAM solutions were calculated by measuring the differential pressures of these solutions in a pipe with inner diameter of 0.77 cm at flow rates ranging between 3 L/min and 9 L/min. The effects of the molecular weight and concentration of the polymer on friction reduction of solution were analyzed. Based on these studies, a friction coefficient equation describing the relationship among the friction coefficient f, the generalized Reynolds number Re and the flow pattern index n of the polymer solutions was established.
Preparation of a High Molecular Weight Polymer Thickening Agent and Its Use in Fracturing Fluids
YAN Jie, ZHANG Han, GUO Zhijie, MA Guangdong, HUO Jinhua
2022, 39(1): 107-113. doi: 10.12358/j.issn.1001-5620.2022.01.018
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A high molecular weight polymer thickening agent, FTW-1, for fracturing fluids has been developed through water solution polymerization using 2-acrylamido-2-methylpropane sulfonic acid (AMPS), acrylamide (AM), sodium p-styrenesulfonate (SSS) and dimethyl diallyl ammonium chloride (DMDAAC) as polymerization monomers. Several factors, such as the reaction temperature, the pH of the reaction system, reaction time, concentrations of monomers, as well as the concentration of the initiator, were studied for their effects on the performance of FTW-1. The molecular structure of FTW-1 was characterized with FTIR, TG etc. It was found that the optimum conditions for the polymerization reaction are as follows: the mass concentration of the monomers = 35%, the pH of the reaction system = 7.8-8.0, the concentration of the initiator = 0.12%, the reaction temperature = 50 ℃, and the reaction time = 4 h. FTIR and TG analyses showed that the molecular structure of the reaction product FTW-1 meets the expectations. The viscosity average molecular weight of FTW-1 is 1.8 × 106. FTW-1 has good thermal stability; it satisfies the need of operation at 180 ℃. Studies on the performance of the FTW-1 treated fracturing fluids showed that the solubility, thickening and crosslinking performance, high temperature and shearing resistance, resistance to biodegradation, as well as gel breaking capacity of FTW-1 all meet the requirements of relevant industrial standards.
Study and Application of Self-diverting Fracturing Fluid Containing Highly Deformable Temporary Plugging Agents
LIU Yi, YANG Hui, WU Zuohao
2022, 39(1): 114-120. doi: 10.12358/j.issn.1001-5620.2022.01.019
Abstract(513) HTML (189) PDF (3805KB)(37)
Abstract:
The natural fractures abundantly developed in the pyroclastic rocks in the Nanpu No. x structure are conducive to the construction of complex fractures and the improvement of the effect of stimulated reservoir volume fracturing. In previous self-diverting temporary plugging fracturing operation, the effect of temporary plugging has been unsatisfactory. To resolve this problem, the temporary plugging agent was optimized using silicone monomer which forms a highly deformable gel through micellar polymerization. The gel, after shearing, granulating, drying and pulverizing was turned into highly deformable expandable temporary plugging agent of different particle sizes to temporarily plug the mouth (inside) of fractures. This pulverized temporary plugging agent can automatically solidify at elevated temperatures to form a filter cake through condensation, thereby improving the effect of temporary plugging inside the fractures. The optimum ratio of different particles in the final plugging agent formulation (between two well clusters) through laboratory experiment is: deformable particle (5 – 6 mm) ∶ fiber ∶ powder (100 – 200 mesh) = 5∶1∶1, and the highest breakthrough pressure of this temporary plugging agent is 56.3 MPa. The deformable particles in the temporary plugging agent can expand after absorbing water, and has good elasticity, which greatly increase the likelihood of stress diversion. This temporary plugging agent, a nanometer powdered product, can produce a plugging barrier withstanding a pressure of up to 54 MPa. The temporary plugging agent has been used in the operation in volcanic rock reservoirs without the need of special fracturing trucks. The temporary plugging agent did not affect the pump efficiency, and pumps did not get stuck during field operation. The success rate of the temporary plugging agent was 100%. Pressure increases because of temporary plugging between two well clusters are obvious, averaged between 4 and 16 MPa. The pressure increases inside the fractures because of the temporary plugging were 2 – 4 MPa in average. Fracturing curves of field operation and micro-seismic monitoring showed that the diverting efficiency was high.
Research and Application of Fracturing Flowback Fluid Reuse Technology in Sulige Gas Field
LI Bin
2022, 39(1): 121-125. doi: 10.12358/j.issn.1001-5620.2022.01.020
Abstract(488) HTML (191) PDF (2316KB)(40)
Abstract:
According to the characteristics of fracturing flowback fluid in Sulige gas field and the water quality requirement of treated flowback fluid used to prepare fracturing fluid, a series of treatment processes including pretreatment, coagulation & sedimentation, double filtration and sterilization & inhibition, had been established. After treatment, the suspended solid in the flowback fluid could be controlled to less than 20 mg/L, the content of calcium and magnesium ions is less than 30 mg/L, and the COD is also be reduced to lower than 100 mg/L. Viscosity decreasing rate of the guar gum fracturing fluid prepared by the treated water is less than 20% after 72 h. The treated water is used to prepare both guar gum based and polymer based fracturing fluid, whose temperature and shear resistance, viscoelasticity and gel-breaking properties could meet the requirements of the general industry standards. Both rapid and fine treatment within a treating speed of 150~300 m3/d can be realized by selectively combining each module and processing unit. In the last three years, more than 36,000 m3 fracturing fluid were prepared by using the treated flowback fluid and the field application effect is remarkable.
COMPLETION FLUID
Experimental Research on Prediction and Prevention of Scaling in Lingshui 25-1 Gas Reservoir
LIU Zhengkai, QIU Zhengsong, LI Jia, XING Xijin, HE Song, GAO Jian
2022, 39(1): 126-132. doi: 10.12358/j.issn.1001-5620.2022.01.021
Abstract(420) HTML (194) PDF (2688KB)(40)
Abstract:
In order to solve the prominent problems of high salinity and serious scaling of formation water in Lingshui 25-1 gas field, through the scaling trend calculation and experimental evaluation, the scaling risk of Lingshui 25-1 gas field is analyzed, the quantitative evaluation indexes of scaling degree such as adhesion coefficient are established, the experimental research on its influence law is carried out, and the scale inhibitor with good scale inhibition effect is optimized. The results show that there is a serious scaling risk in Lingshui 25-1 gas field under the conditions of formation temperature and pressure. The core test results show that the scale sample has a small adhesion coefficient and is easy to migrate with the fluid. The critical flow rate is 0.25 cm3/min. with the increase of displacement time, the core permeability gradually decreases and reaches equilibrium at about 1200 min. the maximum permeability change rate is 82.17%. With the increase of temperature, the scaling trend of formation water will be exacerbated, and the maximum permeability change rate is 81.86%; The preferred scale inhibitor ethylenediamine tetramethylene phosphonic acid (EDTMPA) has a good scale prevention effect on the static and dynamic scale prevention of formation water in different layers of Lingshui 25-1 gas field through strong metal chelation and lattice distortion.