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2024, Volume 41,  Issue 3

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DRILLING FLUID
The Development and Application of Nitrogen-Containing Graphene for Oil-Based Drilling Fluids
ZHANG Honghu
2024, 41(3): 279-287. doi: 10.12358/j.issn.1001-5620.2024.03.001
Abstract(28) HTML (5) PDF (3683KB)(7)
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The marine facies Leikoupo formation in the west of Sichuan Province is a broken formation, in the later stage of horizontal drilling, it is frequently unable to exert weight on the drill bit, and borehole wall instability is another problem that haunts the drilling engineers. Analyses of these problems show that the oil-based drilling fluids presently in use have plugging capacity and lubricity that are unable to satisfy the needs of operation. To improve the plugging capacity and lubricity of the oil-based drilling fluids, based on molecular structure design, a nitrogen-containing graphene is developed through a combination of nitrogen doping modification and molten salt method. Using experimental methods, such as thermal stability measurement, dispersibility stability measurement, XRD, IR spectrum and particle size analyzer etc., the thermal stability, dispersibility, structure, functional group and particle sizes of the nitrogen-containing graphene are studied. The nitrogen-containing graphene was tested for its compatibility, plugging capacity, lubricity and high temperature resistance in active oil-based drilling fluids, and its functional mechanisms in oil-based drilling fluids are analyzed. Experimental results show that when the concentration of the nitrogen-containing graphene in an oil-based drilling fluid is 0.5%, the high temperature high pressure filter loss of the drilling fluid can be reduced by 76.2%, and the coefficient of friction reduced by about 50%. The nitrogen-containing graphene works normally at temperatures up to 180 ℃. In field operation, the use of the nitrogen-containing graphene significantly mitigated downhole problems such as the inability to exert weight on bit, high friction and borehole wall instability etc. The use of nitrogen-containing graphene has provided a new clue and technical support for solving the aforementioned drilling problems.
Study on Effects of Fluid Properties on Borehole Pressure under Temperature and Pressure Coupling in High Temperature Deep Wells
LIU Pingjiang, HE Jianyong, ZHANG Ye, BI Yi, ZHANG Ruihua, YANG Mou
2024, 41(3): 288-295. doi: 10.12358/j.issn.1001-5620.2024.03.002
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High temperature high pressure (HTHP) environment in deep wells plays an important role in mud rheology control; omitting its effects will lead to an inaccurate knowledge of hole pressures and a negative influence on safe drilling. Based on the principle of energy conservation, a borehole temperature computation model is established. In this model a method of computing borehole temperature by coupling the effects of temperature and pressure is built up taking into account the effects of the fluid flow state on temperature and pressure. The reliability of the model is verified using data acquired from field operations. The study results show that the effect of temperature on the density and rheology of a drilling fluid is more important than the effect of pressure. As a well becomes deeper, the density and yield point of the drilling fluid in the annulus are also increasing. As the circulation time increases, the bottom hole temperature is decreasing, the density, yield point and flow index of the drilling fluid in the annulus are increasing , while the thickening index is decreasing. The ECD of the drilling fluid in the annulus under coupled temperature and pressure condition is lower than the ECD of the fluid in the same annulus without considering the coupling of temperature and pressure, the difference between the two ECD is 0.067 g/cm3. Hence, if the effects of temperature and pressure coupling on the density and rheology of a drilling fluid are not considered, a mud density lower than that is necessary to balance the formation pressure will be designed, and well kick and blowout may be induced. The results and understanding of this study provide a key theoretical base for precise evaluation of temperature and pressure in an ultra-deep well.
A Model for Calculating Annular Pressure Loss in Slim Hole Taking into Account Tool Joint
CHEN Yufei, AN Jintao, ZHANG Hui, LI Jun, ZHOU Yingcao, LU Zongyu
2024, 41(3): 296-304. doi: 10.12358/j.issn.1001-5620.2024.03.003
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Slim hole drilling as an important technology is more and more used in developing deep oil and gas resources. In slim hole drilling, the much higher annular pressure losses impose a challenge to the annular pressure control. Accurate prediction of the annular pressure losses under the condition of eccentric rotation of drill string is an important theoretical and practical base for slim hole drilling. Conventional prediction models for this purpose have limited applicability and often omit the influences caused by the tool joints, thus cannot satisfy the requirements for accuracy in field operation. To solve this problem, a method of constructing empirical models with pressure loss correction factors is established based on the analyses of the effects of the tool joints on the flow-field and pressure losses in annular spaces using numerical simulation. The analyses show that the extra pressure losses produced by the tool joints are affected by the type of drilling fluid, rotary speed of drill pipe, eccentricity of drill pipe and annular flow velocity. Thus, when determining the pressure loss correction factor, the coupling of these effects should be taken into account. Using the result of numerical simulation of 152 sets of data, a model for predicting the annular pressure losses of the slim holes drilled in the Mahu oilfield in Xinjiang is established. The calculation using this model shows that there is a critical rotary speed at low drill pipe eccentricity, at which the annular pressure loss reaches maximum. At high drill pipe eccentricity, the annular pressure losses increase with rotary speed. The effects of the drill pipe eccentricity on the annular pressure losses will become complex because of the rotary speed. Using the annular pressure loss prediction model developed, the equivalent circulation density of the well MHHW-X in the Mahu oilfield was calculated and compared with the PWD data, the average error was only 1.18%, indicating that the model has high accuracy. The results of the study show that, the model established through numerical simulation for calculating annular pressure losses in slim holes, which takes into account the effects of tool joints, is able to satisfy the requirement of accuracy for field prediction of annular pressure losses, and to provide guidance to the annular pressure control in field operation.
Use Oil Based Drilling Fluid to Stabilize Borehole Wall and Prevent and Control Mud Losses in Fuxing Area
ZHOU Zhongya
2024, 41(3): 305-317. doi: 10.12358/j.issn.1001-5620.2024.03.004
Abstract(21) HTML (5) PDF (4984KB)(5)
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In shale gas drilling in the Fuxing area, downhole troubles, such as mud losses in the Lianggaoshan formation, coexistence of well kick and mud losses in the Dongyuemiao member of the Ziliujing formation as well as borehole wall collapse which resulted in frequent pump and top drive halt, have frequently been encountered. To solve these problems, rock samples of the Lianggaoshan formation taken from the well Xingye-L2HF and the well Xingye-1002HF as well as rock samples from the Dongyuemiao member of the Ziliujing formation are analyzed with XRD diffraction for their mineral composition. Using SEM, the micromorphology of these rock samples is analyzed. By studying the field operational data, the mechanisms of borehole wall collapse and mud losses are summarized. The oil-based drilling fluid previously used is improved based on the studies for its emulsion stability, friction reduction and plugging capacity. The new oil-based drilling fluid for the drilling operation in the Fuxing area has plugging PPA of less than 2 mL and invasion depth into the sand tube of less than 2 cm. Based on the sand blocking effect in fracturing job, a mud loss control slurry formulated with compound lost circulation material, inducing agent and suspending agent was developed. The pressure bearing capacity of the mud cakes formed by this mud loss control slurry is 7 MPa, making it suitable for controlling mud losses into formations with multiple fractures. Compared with the high density diesel oil-based drilling fluid used in drilling a well in the Fuxing area previously, this new oil-based drilling fluid has lower viscosity, lower gel strengths and higher lubricity, and the occurrence of the complex situations, such as mud losses and borehole wall instability, has significantly been reduced.
An Ultra-High Temperature Coordinate Bond Oligomer Thinner
HE Yinbo, LIANG Hao, JING Yujuan, DU Mingliang, LI Xiaoqing
2024, 41(3): 318-324. doi: 10.12358/j.issn.1001-5620.2024.03.005
Abstract(24) HTML (4) PDF (2518KB)(4)
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An ultra-high temperature coordinate bonding oligomer thinner AA-AMPS-TA (named PAAT) is synthesized as a way of dealing with the problems encountered in using high density water-based drilling fluids at elevated temperatures. These problems involve high filtration rate, high ECD and internal friction, poor mobility or even complete loss of the mobility of the drilling fluids. The thinner PAAT is synthesized through radical polymerization by introducing the molecules of tanning acids (TA) which are rich in catechol groups into the poly organic acid thinner AA-AMPS. The optimal synthesis condition of the thinner PAAT is determined through orthogonal experiment, and the thinning performance of the thinner is evaluated. The evaluation results show that after introducing TA into the molecules of the AA-AMPS, the IR spectrum of the product PAAT shows an intra-molecule hydrogen bond absorption peak, and the thermal stability of the PAAT molecules is greatly improved because of the introduction of large number of phenol groups; the decomposition temperature of the PAAT molecules is close to 500 ℃. PAAT has the ability to reduce the viscosity of low-concentration bentonite slurry and high clay concentration slurry such as one formulated with 7% bentonite and 8% kaolinite. Using PAAT, the viscosity of a high density water-based drilling fluid can be reduced by 26.5%, and after hot-rolling the water-based drilling fluid at 240 ℃, its viscosity can be reduced by 44.4%. The PAAT thinner reduces viscosity by molecule adsorption, as is verified by Zeta-potential measurement and particle size analysis. This thinner has been used in drilling the well Pengshen-101, and the viscosity and gel strengths of the drilling fluid were both satisfactorily under control at elevated temperatures.
Study on Damage by Drilling Fluid of Fractured Tighten Reservoirs in Bozhong Sag
ZHANG Yufei, WANG Chaoqun, XU Botao, MIAO Hailong, LUO Cheng, SU Junlin
2024, 41(3): 325-329. doi: 10.12358/j.issn.1001-5620.2024.03.006
Abstract(17) HTML (5) PDF (2483KB)(3)
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The evaluation of reservoir damage is important to reservoir protection and oil and gas yield improvement. Reservoirs in the Bozhong sag of the Bohai Bay Basin are naturally fractured tight reservoirs, coring in these reservoirs is difficult and many different methods of evaluating the reservoir damage are in use, resulting in difficulties in implementing effective reservoir protection measures. To deal with this problem, combined with the actual situation of reservoirs , design and manufacture 3D printed fractured cores with transparent and visible interior and reservoir damage evaluation devices. In evaluating reservoir damage by different drill-in fluids used in Bozhong, the flow-rate damage rate instead of the permeability damage rate is used. Experimental results show that the drill-in fluid EZFLOW, which is presently in field application, has stable rheology and good filtration property. Compared with 3% bentonite drilling fluid, the EZFLOW drill-in fluid imposes smaller damage to the reservoirs, the rates of reservoir damage imposed by the EZFLOW drill-in fluid are between 11.7% and 26.2%, which are weak reservoir damage. The rate of damage to the cores is decreasing with increase in the opening degrees of the cores; for different fractured cores, the longer the cores and the wider the fractures, the higher the damage rate.
Prediction of Gas Well Productivity Based on Attribution Analysis of Controllable Factors of HEM Water-Based Drilling Fluid to Gas Reservoir Damage
LIAO Gaolong, LIANG Hao, MA Shuangzheng, ZHANG Yaoyuan, SHEN Yuan, NAN Yuan, WANG Guanxiang, HE Yinbo
2024, 41(3): 330-336. doi: 10.12358/j.issn.1001-5620.2024.03.007
Abstract(17) HTML (4) PDF (2689KB)(3)
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As the depth of drilling increases, the prevention and control of reservoir damage caused by drilling fluids has become increasingly prominent, and reservoir protection has become a key factor in the full release of gas field production capacity. As the well depth deepens, the various properties of the deepwater drilling fluid change, causing the degree of reservoir damage to intensify and the direction of reservoir protection performance optimization becomes unclear. Therefore, this paper combines Pearson correlation analysis and grey relational analysis to perform attribution analysis of controllable factors of drilling fluids in reservoir damage, identify the main controlling factors, and establish a gas well productivity model. The results show that the solid particle size, surface tension, mineralization degree, and high-temperature and high-pressure fluid loss of drilling fluids are the main controlling factors causing reservoir damage. According to the attribution analysis results, an optimization method using a composite of different particle size distributions of calcium carbonate as a weighting agent is proposed, which increases the permeability recovery of drilling fluids by 12.1 to 19.68%. The applicability of the model is verified by collecting field parameters from wells Y8 and Y9, and the results show that the accuracy of the model established in this paper is over 94%.
A High-performance Waterproof Lock Agent For Low Permeability Reservoir
WANG Junping, CAO Qingtian, YANG Guodong, CHEN Liang, GUAN Yulong, XU Peng
2024, 41(3): 337-343. doi: 10.12358/j.issn.1001-5620.2024.03.008
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Low permeability reservoir has the characteristics of dense rock, poor physical properties and small pore throat. External fluid can enter the pore throats of the reservoir under the action of capillary force, causing water lock damage, which seriously affects the production of low permeability reservoir. To solve this problem, a new type of fluorocarbon waterproof lock agent (FS-1) was prepared with perfluorooctanoic acid, ethanolamine and sodium chloroacetate as raw materials, and its structure was characterized by infrared spectrum, and the effect of fluorocarbon waterproof lock agent on the water-locking performance of brine solution in core pores was studied. The results showed that the waterproof lock agent can significantly reduce the surface tension of the brine solution (＜15 mN/m), and increase the contact angle of the distilled water on the sandstone surface to 85.3°, indicating that the developed waterproof lock agent can change the core surface wettability from hydrophilic to neutral wet, and effectively reduce the water locking damage to the cores. In addition, the waterproof lock agent (FS-1) contains multiple adsorption and salt-resistant groups, which can improve the adsorption ability of the molecule on the rock surface and makes its salt tolerance reach 7% (NaCl). Imbibition experiment, permeability test experiment and nuclear magnetic resonance experiment found that the waterproof lock agent (FS-1) slowed down the self-imbibition of the core, reduced the binding ability of the core pores to salt water and the water locking damage of the core, and improved the recovery rate of the core permeability.
Synthesis of Sulfurized Fatty Acid Ester and its Application in High TemperatureHigh Pressure Drill-in Fluids
XIA Xiaochun, ZOU Yang, WANG Zhiyong, ZHANG Zitong, SONG Yu, DAI Yuanjing
2024, 41(3): 344-349. doi: 10.12358/j.issn.1001-5620.2024.03.009
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In high temperature extended reach well drilling, the water-based drilling fluids are generally treated with liquid lubricants to alleviate friction. In high density, high salinity and high temperature conditions, the lubricity of the liquid lubricants is not enough to reduce the friction to the required level, causing from time to time downhole troubles such as halting of drilling string, stuck pipe and wear and tear of drill tools. To solve these problems, a sulfurized fatty acid ester is synthesized in laboratory and is compounded with lubricants to obtain a compound lubricant QT311. Adding the lubricant QT311 into the HTFlow high temperature high pressure water-based drilling fluid greatly improves the lubricity of the drilling fluid. Testing the QT311 treated HTFlow drilling fluid on four-ball friction tester shows that treatment of 1%QT311 reduces the coefficient of friction by 64% and the diameter of the wear scars is reduced by 43%. These results indicate the QT311 as a lubricant is superior to several widely used commercial lubricants. Analysis of the surface of the friction pair with SEM shows that QT311 react chemically with iron during friction to form sulfur-iron extreme pressure membrane, thereby improving the friction-reducing performance of the drilling fluid. The laboratory experiments also show that QT311 has excellent compatibility with the HTFlow drilling fluid, anti-hydrolysis performance, salt resistance and high temperature resistance. The experimental results have provided a reference for further studies on drill-in fluid lubricants.
Use of Compound Desulfurizing Agent in High Sulfur Feixianguan Formation Drilling in Northeast Sichuan with Oil Based Drilling Fluids
XIAO Jinyu, ZHOU Huaan, BAO Dan, WANG Wei, YANG Lanping, JIANG Xianjun
2024, 41(3): 350-356. doi: 10.12358/j.issn.1001-5620.2024.03.010
Abstract(17) HTML (5) PDF (2022KB)(4)
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The Feixianguan gas reservoir in northeast Sichuan is a high to ultra-high sulfur content reservoir. Based on the analyses of the geology of the Feixianguan formation and the difficulties in drilling fluid operation, a desulfurization measure is presented for field operation with oil based drilling fluids. High performance desulphurizing agents are first selected through laboratory experiment, and studies on the compounding of these agents are conducted to develop a compound desulphurizing agent. Evaluation of the performance of the compound desulphurizing agent to remove sulfur at elevated temperatures shows that the compound desulphurizing agent containing 3%YT-3+3%CLC-2 and 3%JD-2 has percent H2S prevention of 99.14% and percent H2S removal of 100%. The zinc-based desulfurizing agent in the formula reacted with H2S in the drilling fluids to produce insoluble chemical ZnS. The triazine and alcohol ether amide desulfurizing agents mainly remove H2S through fast and irreversible physical and chemical reactions. This desulfurization technology has been successfully applied on the well Po-005-X4 and the well Po-002-H5 when drilled into the high sulfur content Feixianguan formation, no H2S has been detected during drilling and during circulation after tripping for degassing, and the S2− content of the drilling fluid is zero throughout the whole drilling operation. The successful field operation fully demonstrates that the technology has a significant desulfurization performance and can meet the requirements of drilling high sulfur wells.
CEMENTING FLUID
A Low Temperature Early Strength Gel Material Based on Reconstruction of Hydrate Layer Frame
XU Hongzhi, SONG Weichen, BU Yuhuan, XIANG Changyou, LIU Huajie, LU chang
2024, 41(3): 357-363. doi: 10.12358/j.issn.1001-5620.2024.03.011
Abstract(15) HTML (3) PDF (2069KB)(4)
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In the trial production of natural gas hydrate resources, sand production often forces the operation to terminate. A study, aimed at the construction of low temperature early strength gel materials through reconstruction of hydrate layer frames, is conducted based on the experiences gained in the second trail production of hydrate resources and the theory of intralayer reinforcement and sand control. In the study, the low temperature early strength, the long-term length and the particle size distribution of three kinds of cement, which are Jiahua class G, ultra-fine cement and early strength cement, are compared. Based on satisfying the requirements of reconstructing pore sizes through intralayer reinforcement of frames, the components of the low temperature early strength gel materials are designed. The early strength of the solidification body is increased to a degree that is as high as possible taking into account the fluidity of the cement slurry, the early strength and the cost as the main design targets, thereby leaving more space for the strength decline in subsequent permeability improvement. By studying the ratio of the ultra-fine oil well cement to the Jiahua class G cement, optimizing the early strength agents and their concentrations, a low temperature early strength gel system is developed. The low temperature early strength gel system has 24 h compressive strength in 15 ℃ water bath of 12.86 MPa, good fluidity and controllable thickening time and filtration rate. Compared with other low temperature early strength cement slurries introduced in relevant literatures, this cement slurry has better permeability enhancement and high strength characteristics. This study has laid the material foundation for subsequent researches on frame reconstructing high permeability high strength working fluid systems within hydrate layers.
Preparation and Evaluation of an H2S Corrosion Inhibitor for ZnFe-LDHs Oil Well Cement
HE Minhui, YAO Ming, YAN Yubo, MEI Kaiyuan, CHENG Xiaowei
2024, 41(3): 364-373. doi: 10.12358/j.issn.1001-5620.2024.03.012
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In developing the highly acidic oil and gas resources which are abundant in China, the set cement in the wellbore will long endure the erosion of the acid media such as H2S, and the this seriously threatens the safe operation and production of the oil and gas wells. To deal with this problem, a ZnFe-LDHs type corrosion inhibitor against the corrosion by the H2S is developed through hydrothermal coprecipitation method. Set cement samples containing the selected ZnFe-LDHs are soaked in 5% Na2S solution at room temperature and 60 ℃ for 1 d, 3 d, 7 d, 14 d and 28 d, respectively. The ability of ZnFe-LDHs to resist H2S corrosion and the mechanisms of this resistance are then studied through compressive strength measurement, XRD and SEM. The study shows that the ZnFe-LDHs made at crystallization of 90 ℃ and Zn/Fe molar ratio of (1–4):1 has satisfactory corrosion control performance; it increases the compressive strength of the set cement and the compressive strength of the set cement increases with increase in the molar ratio of Zn/Fe, that is, the ZnFe-LDHs with Zn/Fe molar ratio of 4:1 has the best effect on the compressive strength of the set cement; the compressive strength of the set cement is increased by 10.11%. When the set cement sample are soaked in Na2S solution, the early strength of the set cement decreases. After soaking for 7 d, the compressive strength of the set cement soaked at room temperature and at 60 ℃ is increased by 8.73% and 4.96%, respectively. When the soaking time is longer than 7 d, the compressive strength of the set cement becomes stable, the reason for this is that ZnFe-LDHs is able to promote hydration reaction, and in the later stage of the soaking, ZnFe-LDHs react with Na2S to produce ZnS, thereby increasing the density of the set cement and preventing the corrosion of H2S to the set cement.
Well Cementing Technology for Salt Cavern Energy Storage
LIU Ziru, XIAO Yao, CHEN Xu, HAO Huazhong, LING Yong, AO Mingming
2024, 41(3): 374-382. doi: 10.12358/j.issn.1001-5620.2024.03.013
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Compressed air energy storage (CAES) technology is a large-scale, flexible and low carbon energy storage technology that utilizes compressed air for energy storage. All injectors and producers in the Yunying energy storage are faced with well cementing difficulties such as low formation temperature, large hole diameter, potential losses of cement slurry during well cementing, frequent alternation between injection and production, as well as strict requirements for long-term isolation of the wellbore etc. To solve these difficulties, well cementing techniques suitable for the CASE wells drilled in Yingcheng, Hubei Province are studied. A low-temperature salt-resistant tough cement slurry suitable for cementing the injectors and the producers drilled for the salt cavern energy storage is developed based on the close packing design theory and the induction of crystal phase structure design method. A set of well cementing technique based on this new cement slurry is developed. The density of the cement slurry can be adjusted between 1.88 g/cm3 and 1.93 g/cm3. The thickening time of the cement slurry is easy to be changed to meet the operation requirements. The cement slurry has no density difference between the top and the bottom, zero free water and API filter loss of less than or equal to 50 mL. Contamination by salt to semi-saturation is of no influence to the performance of the cement slurry. The 7 d elastic modulus is less than 6.13 GPa. At temperatures lower than 30 ℃, the strength of the cement slurry can develop in less than 10 h. The 24 h compressive strength of the set cement is greater than 14 MPa. This cement slurry and the well cementing techniques have been used in the cementing of the surface casing and the production casing of the injectors and the producers drilled for the CAES in the Yunying basin in Hubei. The cementing job is 100% qualified and 95% of which is excellent.
Effect on Water-Resistant Cement Slurries by Materials Non-Dispersible in Water
JIAO Yajun, ZHANG Hua, GUO Xueli, ZHANG Xiaobing, LIU Bo, DENG Tian’an, ZHANG Shunping
2024, 41(3): 383-389. doi: 10.12358/j.issn.1001-5620.2024.03.014
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In the Chuanyu area, the shale gas producing Jialingjiang Formation is developed with plenty of fractures and formation water. This leads to a mud loss problem which greatly prolongs the drilling time and hinders the safe and efficient development of the shale gas. Cement slurries non-dispersible in water have been studied to deal with the mud loss problem encountered in the shale gas drilling. By evaluating the water non-dispersibility of five polysaccharide polymers and organic polymers, key materials and their quantity ratio are selected, and a low-density cement slurry non-dispersible in water is formulated for cementing water-bearing loss zones. In well cementing with this cement slurry, pressure balance loss control technique was used, and the cement slurry, after being displaced into the well, is not displaced and washed away by the formation water from the loss zones, hence realizing effective sealing of the loss zones and paving the way for subsequent operations. This low-density water non-dispersible cement slurry has been successfully used in cementing the well Z203H6-X drilled in the Chuanyu area, the equivalent circulating density (ECD) of the formation into which mud has been lost is increased from 0.99 g/cm3 to 1.21 g/cm3. In subsequent operations lost circulation slurries were used to enhance the compressive strength of the formation, and the ECD of the formation was further increased to 1.81 g/cm3. This cement slurry has provided a technical means to solve the lost circulation problem encountered in drilling the fractured water-bearing formations in shale gas drilling in the Chuanyu area.
Dual Prevention of Severe Losses of Cement Slurries in Cementing Long Open Holes
GAO Yuan
2024, 41(3): 390-395. doi: 10.12358/j.issn.1001-5620.2024.03.015
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Aiming at the cementing problem of long open hole malignant leakage wells, the thermo-sensitive shape memory loss prevention spacer and foam leakage prevention cement slurry were developed, which synergistically reduce the cementing loss risk of long open hole malignant leakage loss wells. The thermo-sensitive shape memory material was developed, which resistance temperature is 150 ℃ and deformation memory temperature is 80～110 ℃, the length of thermo-sensitive shape memory mesh particles after deformation is 10 times that of normal temperature, and the diameter of shape memory expansion ball after expansion is 3 times that of normal temperature. The thermo-sensitive leak-proof spacer was developed, and the bearing-capacity of 3mm crack can reach 8.5MPa. Foaming agent and foam stabilizer were selected, and foam cement slurry were developed, and the density can be adjusted from 1.12 to 1.31 g/cm3, the difference between the upper and lower parts was less than 0.01 g/cm3, and the compressive strength of 1.12 g/cm3 foamed cement stone can reach 6.6 MPa at 30 ℃/72 h, and bubbles in set cement are uniformly dispersed. The spacer duration design method that considering the equivalent plugging time and washing efficiency was established, and the foamed cement slurry section constant gas injection method was formed. Based on thermo-sensitive anti-leakage spacer and foam cement slurry, The leak-proof cementing technology has been applied for 2 Wells, and the one-time sealing section length exceeds 4000 m, and the spacer and cement slurry returned to the surface successfully and got good results.
FRACTUREING FLUID & ACIDIZING FLUID
In-Situ Displacement of Crude Oil by Fracturing Fluid in Chang-6 Reservoir in Xingzichuan
BAI Hao, ZHOU Fujian, WU Junlin, DING Zhiyuan, YANG SaSa, SHENG Lianqi, YAO Erdong
2024, 41(3): 396-404. doi: 10.12358/j.issn.1001-5620.2024.03.016
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The Chang-6 reservoir in the Yanchang formation in Xingzichuan area is characteristic of low oil saturation, strong oil wetting and strong heterogeneity (permeability = 0.10 – 1.0 mD). In fracturing operations in this area, it was found that the conventional fracturing fluids have weak wettability alteration ability and poor imbibition displacement effect. To efficiently develop this reservoir, it is imperative to use a fracturing fluid with the ability of production enhancement by imbibition. Using NMR T2 spectrum, chemicals of different compositions were tested for their ability to produce the crude oils stored in the micrometer-nanometer sized pores in the Chang-6 reservoir, and the factors affecting fracturing fluids’ in-situ displacement of crude oil as well as the imbibition mechanism of the in-situ displacement are investigated. The results of the study show that compared with other agents, AX-2, a negatively charged ionic surfactant agent, is more suitable for producing the low oil saturation Chang-6 reservoir. Using 0.10% of AX-2, the imbibition recovery of oil is greater than 30%, and the percent oil produced from the small nanometer-sized pores is 42.08%, while that from the large micrometer-sized pores is 22.62%. If AX-2 is used to formulate a 10-nanometer nanoemulsion AX-1, it has stronger anti-adsorption ability and better performance in producing the oil from the Chang-6 reservoir; the percent oil produced from the nanometer pores is increased to 58.26%, while that from the micrometer pores is increased to 29.7%. An AX-1 emulsion with surface tension of 1.5 mN/m is the best emulsion for producing the Chang-6 reservoir, since this emulsion has higher imbibition force and crude oil stripping capacity. The fracturing fluid optimized with the AX-1 emulsion is used in field fracturing operations, and good results were obtained, the average daily production rate of crude oil reached 26 tons.
Preparation and Application of Superhydrophobic Multifunctional Drag Reducing Agents for Slickwater Fracturing Fluids
FENG Qi, JIANG Guancheng, ZHANG Shuo, HUANG Shengming, WANG Quande, WANG Wenzhuo
2024, 41(3): 405-413. doi: 10.12358/j.issn.1001-5620.2024.03.017
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At present, conventional smooth hydraulic fracturing fluid systems generally have various functions such as drag reduction, sand carrying, salt resistance, and temperature resistance, but none of them have considered achieving reservoir protection by changing the surface wettability of the reservoir. Therefore, in this paper, a superhydrophobic multifunctional fracturing fluid drag reducing agent, named SHJZ-1, was synthesized using acrylic acid, acrylamide, self-made material 2-acrylamido-2-phenylethanesulfonic acid, and hydrophobic modifier as raw materials. The structure of the synthesized drag reducing agent was characterized by infrared spectroscopy, and its performance was comprehensively evaluated through various methods such as high-temperature and high-pressure core dynamic damage evaluation system, contact angle measurement instrument, Hack rheometer, and closed pipeline friction tester. The results show that the drag reducing agent SHJZ-1 had a short dissolution time and rapid adhesion. When the salinity of saline water reaches 40000 mg/L, the drag reduction rate of 0.5% SHJZ-1 solution was about 68%. The 0.15% SHJZ-1 solution can still achieve a drag reduction rate of over 70% after high-temperature aging at 140 ℃. Furthermore, the core treated with 1.3% SHJZ-1 solution exhibited superhydrophobic effect, with a core contact angle of 151.21°. Additionally, the average permeability damage rate of the core caused by this drag reducing agent solution was only 11.6%. The super hydrophobic multifunctional smooth hydraulic fracturing fluid system has been successfully applied on site in the HX-1 well. In fracturing engineering, the performance of smooth hydraulic fracturing fluid is relatively stable, and the production after fracturing is increased by more than 10% compared to the adjacent well. The effect is significant, achieving the goal of improving quality and efficiency.
Study on Evaluating Effects of Biocides in Fracturing Fluids with Optical Fiber Tweezer Method
WU Zhaoliang
2024, 41(3): 414-418. doi: 10.12358/j.issn.1001-5620.2024.03.018
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Abstract:
In summer fracturing operation, microorganisms such as bacteria can cause the guar gum fracturing fluids to spoil and lose their effectiveness. Bactericides have thus to be used in the fracturing fluids to kill the bacteria. Presently there is no technical means of evaluating the performance of the bactericides. In this study a method based on optical fiber tweezer (OFT) is presented to evaluate the performance of the bactericides. The saprophytic bacteria are first captured before and after adding a bactericide into a fracturing fluid with a conical OFT, the movement pattern of the bacteria is then analyzed at microscopic scale, and this process can be used to invert the effect of the bactericides. Experimental results show that this method can be used to effectively evaluate the activity of the saprophytic bacteria. After adding bactericides into a fracturing fluid, the cells of the saprophytic bacteria become inactive and the movement distance of the saprophytic bacteria is greatly reduced to about only 0.8 – 0.9 μm. For saprophytic bacteria without contacting with bactericides, the movement distance is generally about 12.1 μm. The study proves that the OFT method is effective in evaluating the performance of bactericides, and it provides a reliable theoretical base for the direct evaluation of the performance of bactericides.

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