Current Articles

2024, Volume 41,  Issue 2

FORUM
Application and Prospect of Deep Eutectic Solvent Inhibition in Shale Hydration
BAI Jiajia, GU Tianshuai, TAO Lei, FENG Xiao, CHEN Mingjun
2024, 41(2): 141-147. doi: 10.12358/j.issn.1001-5620.2024.02.001
Abstract:
Shale hydration during drilling often leads to serious downhole safety accidents, and improving the stability of shale borehole will greatly improve the success rate of drilling. As a new type of green reagent, deep eutectic solvent (DES) has similar properties to ionic liquids and is widely used. However, its potential as a water-based drilling fluid additive in inhibiting shale hydration has not attracted enough attention. Compared with other water-based drilling fluid additives, DES has the advantages of non-flammable, non-explosive, non-toxic, easy degradation, good electrochemical and thermal stability, and DES is cheap and comes from a wide range of sources. In this paper, on the basis of comprehensively summarizing the physical and chemical properties of DES, the mechanism of DES as a water-based drilling fluid additive to inhibit shale hydration is discussed, and the application potential of DES to inhibit shale hydration is clarified by analyzing the cost, the influence of DES on the performance of drilling fluid, and the application of DES. The results of this study are of great significance for the application and promotion of DES in inhibiting shale hydration.
DRILLING FLUID
A Polymer Water Based Drilling Fluid for 220 ℃ Bottomhole Temperature
LIU Fengbao, SUN Jinsheng, LIU Jingping, HUANG Xianbin, MENG Xu
2024, 41(2): 148-154. doi: 10.12358/j.issn.1001-5620.2024.02.002
Abstract:
The efficient development of the abundant deep oil and gas boasted by China is of great significance for ensuring the national energy security. The regular polymer drilling fluids presently used generally have temperature resistance of less than 220 ℃. Salts, which are commonly used in formulating water-based drilling fluids, greatly damage the performance of the fluids. Deterioration of the properties of a drilling fluid during drilling causes downhole accidents and economic losses to the development of deep oil and gas. To deal with the deterioration of the properties of drilling fluid at high temperatures and high salinities, a high temperature zwitterionic polymer and a high temperature anionic polymer are synthesized. The two polymers have synergistic effect, and control and adjust mud rheology through high-strength network structures. To improve the plugging performance and filtration control property of a drilling fluid, an ultrahigh temperature high efficiency plugging agent is developed to plug pores in the formation, thereby stopping the transmission of pressure across the borehole wall. A water-based polymer drilling fluid is formulated with these three core additives to work in ultra-high temperature (220 ℃) environment. Laboratory evaluation of the performance of this drilling fluid shows that it has good rheology, filtration property, suspending capacity, plugging capacity and lubricity; the high-temperature high-pressure (HTHP) filtration rate is only 9.6 mL. The viscosity and gel strengths of the drilling fluid remains stable at HTHP, and the settling factor of the drilling fluid after being aged for 72 hours is only 0.5113 in testing with the test cell in an upright position. In sand-bed test the depth at which the drilling fluid invades into the sand-bed is only 6 mm. The friction coefficient of the drilling fluid after being aged and the mud cake frictional coefficient are 0.1224 and 0.0875, respectively. This drilling fluid has good high temperature resistance and stability, and is of great importance to the development of deep oil and gas development.
Formation Damage in High Temperature Dense Glutenite Reservoirs by Salt Sensitivity and Salt Precipitation
HE Ruibing, TAN Weixiong, BAI Ruiting, KANG Yili, LI Hongru, LI Xinlei, YOU Lijun
2024, 41(2): 155-165. doi: 10.12358/j.issn.1001-5620.2024.02.003
Abstract:
Ultra-low permeability tight glutenite reservoirs are widely distributed in the Bohai Bay, China. Compared with conventional sandstone reservoirs, the tight glutenite reservoirs are rich in clay minerals, highly developed with dissolved pores and microfractures, and have strong heterogeneity. Invasion of injected fluids into the glutenite reservoirs easily induces formation damage and blocking of pore throats, thereby reducing the flow capacity and the production rates of oil and gas. Cores taken from the glutenite formation in the BZ19-6 block were evaluated for salt sensitivity damage according to the industrial standards and high temperature high back-pressure steady-state method. The types and in-situ characteristics of the sensitive minerals and salt minerals were analyzed using SEM. The experimental results show that the salt sensitivity of the Kongdian glutenite is moderately strong to strong. Since the lower the permeability of the core, the higher the damage to the porosity and permeability of the core by salt precipitation, it is thus recommended that for dense cores with permeability less than 0.1 mD and reservoirs temperature higher than 100 ℃, the high temperature high back pressure steady state evaluation method be used to evaluate the flow sensitivity of the reservoir rocks. The clay minerals in the Kongdian formation are mainly silky/filamentous illite, altered kalinite and mixed illite/montmorillonite which exist in the dissolution pores in the form of comb shell type, dispersed filling and bridging etc., and are the main causes of salt sensitivity of the reservoirs. High temperature accelerates the evaporation of formation water, causing salt precipitation near the wellbore. The precipitated salts are mainly potassium salt and halite which exist on the surfaces of the mineral particles and walls of the pores, and cause the pore throats to be easily clogged. The main mechanisms of dense glutenite formation damage by salt precipitation include static evaporation of formation water which leads to clogging of the dense pore throats, salt crystal migration during dynamic displacement which clogs the pore throats and the weakening of the rock strengths by salt precipitation which leads to particle migration. To minimize reservoir damage by salt sensitivity, KCl-salt saturated polymer sulfonate and zwitterionic polymer drilling fluids are recommended as the drill-in fluids, the filtration rates of the drilling fluids should be reduced, and the crystallization and nucleation of salts in the drilling fluids be inhibited.
Experimental Study on Degradable PGA as Temporary Plugging Agent in Drill-in Fluids
DONG Xiaoqiang, JIN Bingyao, LIU Yuhan, QIAN Xiaolin, YU Fuchun
2024, 41(2): 166-171. doi: 10.12358/j.issn.1001-5620.2024.02.004
Abstract:
Polyglycolic acid (PGA) has good environment protection property. In laboratory study, the mechanical property, the particle sizes, the thermal stability of the PGA molecules and the crystal density of PGA before and after high temperature soaking are analyzed, the thermal stability of PGA in water and oil is studied, and the application potential of PGA as a temporary plugging agent for drill-in fluids is evaluated. It was found that the physiochemical properties of PGA are highly affected by the liquid environment of a drilling fluid and temperature. In water-based drilling fluids, PGA will degrade at 100 ℃ to oligomers because of the pH of the drilling fluid, and the thermal stability of the PGA molecules and the mechanical strength of PGA are all decreased as well. Strong acid (pH< 5) and strong base (pH< 9) both accelerate the degradation of PGA, and PGA degrades faster in strong base environment than in strong acid environment. In high temperature oil-based drilling fluids, the PGA particles first swell and then peel and break, and the main body of the PGA particles turns from plastic to brittle, resulting in a decrease in the tensional and compressive strengths of the particles to some extent. PPA plugging experiment shows that after 8 d of soaking in an oil environment, the PGA particles exhibit good plugging performance. These studies show that PGA is more suitable for use in oil-based drilling fluids than in water-based drilling fluids.
A High Temperature Comb and Zwitterionic Polymer Thinner
DENG Zhengqiang, ZHANG Tao, HUANG Ping, LUO Yufeng, WANG Guoshuai, HE Yinbo, JIANG Guancheng
2024, 41(2): 178-183. doi: 10.12358/j.issn.1001-5620.2024.02.006
Abstract:
In deep and ultra-deep well drilling, high density water based drilling fluids are often faced with rheological problems of high viscosity and thickening at elevated temperatures. To solve these problems, a high temperature comb zwitterionic polymer thinner ZT-1 was developed with monomers including sodium p-styrene sulfonate, 2-acrylamido-2-methylpropane sulfonic acid, 2-allyl-2-methylammonium chloride and allyl polyoxyethylene ether. Characterization of the molecular structure of the thinner by IR spectrum shows that the synthesis of the comb zwitterionic polymer is successful. GTA characterization of the thinner demonstrates that ZT-1 has decomposition temperature of 250 ℃. Excellent properties of ZT-1 include high temperature stability and resistance to salt and calcium contamination; ZT-1 functions normally at temperatures up to 240 ℃, and it is resistant to salt contamination to saturation and to calcium contamination to 2% CaCl2, respectively. A base mud treated with 0.3% ZT-1, after aging at 200 ℃, has its viscosity reduced by 77.7%. High density (2.4 g/cm3) drilling fluids can have their viscosity reduced by 33%, plastic viscosity reduced by 14% and yield point reduced by 67% with ZT-1. The performance of ZT-1 is better than that of the sulfonated tannin, XY-27 and ADS, the latter two being regular linear ionic zwitterionic polymers. This comb zwitterionic polymer thinner has good application in ultra-high density drilling fluids for ultra-high temperature drilling.
A High Performance Constant Rheology Oil Based Drilling Fluid for Ultra Deep Water Drilling in Lingshui Block
LIU Zhiqin, XU Jiafang, PENG Wei, XU Chao, YU Xiaodong
2024, 41(2): 184-190. doi: 10.12358/j.issn.1001-5620.2024.02.007
Abstract:
Low temperature, borehole wall instability, narrow safe drilling window as well as difficulty in cleaning borehole in ultra-deep water drilling impose tough requirements on the properties of drilling fluids. In dealing with these difficulties, a new emulsifier KMUL with both emulsification and flow pattern control effects has been developed based on molecular design of emulsifiers. Use KMUL as the major additive, a high performance constant rheology oil-based drilling fluid has been developed for use in ultra-deep water drilling in the Lingshui block in the west of the South China Sea. Laboratory evaluation of this drilling fluid shows that it has good constant rheology characteristics. The rheology of this drilling fluid is stable at temperatures between 2 ℃ and 150 ℃ and at pressures between 0 MPa and 56 MPa. The drilling fluid has strong ability to resist contamination; when cuttings and sea water content in the drilling fluid reaches 15%, the properties of the drilling fluid are still comparatively stable. In core test, the permeability recovery of cores flooded with this drilling fluid is at least 92%, indicating that it has good reservoir protection capability. The drilling fluid has low biotoxicity and is environmentally friendly. The use of this drilling fluid on the well LS-C drilled in ultra-deep waters shows that the rheology of the drilling fluid and the electric stability of the drilling fluid in different well depths are all stable, the ECD of the drilling fluid is all the way maintained at low level. The well was drilled smoothly, the borehole drilled was a gauge hole, and no downhole troubles have ever been encountered during drilling. It is concluded that the high performance constant rheology oil-based drilling fluid has satisfied the requirements of drilling the ultra-deep water Lingshui block.
An Oil-Based Drilling Fluid with Varied Particle Size Plugging Agents for Use in the Borehole Collapse and Mud Loss Coexisting Wells in Hongxing Block
WANG Changqin, LI Zhongshou, HUANG Tao, LI Guanglin, ZHANG Yong, WEI Shijun
2024, 41(2): 191-197. doi: 10.12358/j.issn.1001-5620.2024.02.008
Abstract:
The Hongxing block, a main gas production area of the Jianghan oilfield in the Jiannan structure, is an important shale gas development area of Sinopec. After many years of development, the matrix stresses of the Feixianguan formation and the Changxing formation become very low, and the Wujiaping formation is highly developed with nanometer-sized fractures and fissures. When drilling with oil-based drilling fluids, mud losses and borehole wall collapse take place frequently and are difficult to deal with. To solve these problems, an oil-based drilling fluid with particles of varied sizes to form dense plugging is developed. This oil-based drilling fluid is characterized with strong plugging capacity, low activity, low viscosity and high gel strengths. It is formulated with 4% nanometer- and micrometer-sized rigid particles, 0.5% graphene flake material, 1.5% spherical gelled MPA, 1% ultra-fine mineral fibers. These materials work together to plug and seal the micrometer-sized and nanometer-sized fractures in the formations and coat the borehole wall with dense mud cakes, thereby controlling the high temperature high pressure filter loss of the drilling fluid below 3 mL. High concentration CaCl2 solution (≥ 36%) as the water phase of the oil-based drilling fluid lowers the activity of the drilling fluid to below that of the formation waters and thus improves the inhibitive capacity of the drilling fluid. The emulsifier used has the ability to increase the gel strengths of the drilling fluid to the required level, hence effectively carrying the drilled cuttings and the sloughing out of hole. In field operation, this drilling fluid effectively mitigates the severity of mud losses and borehole wall collapse. An obvious application result is that the time spent in dealing with downhole troubles is reduced by 90.34%.
High Viscosity Characteristics of Heavy Oils Produced in Tahe Oilfield and Treatment of Drilling Fluids Contaminated by Invasion of the Heavy Oils
LIU Xianghua, FAN Sheng, ZHANG Shuxia, LI Shuanggui, YU Yang, MU Baoquan, LIU He
2024, 41(2): 198-204. doi: 10.12358/j.issn.1001-5620.2024.02.009
Abstract:
High viscosity heavy oil invasion in the Tahe block have caused serious damage to the properties of the drilling fluids. To deal with this problem, the key properties of the Tahe heavy oils and those of the typical poor quality heavy oils were compared, and the change of the viscosity of the Tahe heavy oil asphaltenes in toluene solution with the concentration of the heavy oils was studied. It was found that the high viscosity of the Tahe heavy oils comes from high asphaltene content and high aromaticity. Based on this finding, two programs were prepared; one is, at the time when there is only slight heavy oil invasion, a compound additive containing appropriate dispersants and aromatic fraction can be added into the contaminated drilling fluid to disperse the heavy oils. This treatment has been best done in the 5# drilling fluid. In drilling the well TH121155X, the dispersity of the heavy oils in the solids-free drilling fluid was more than 99%. The other treatment involves the contamination of drilling fluids by large amount of heavy oils. In this treatment the heavy oils are wrapped up by wrapping agents and therefore lose their adhesiveness. The adhesiveness of the wrapped heavy oils on the surfaces of the drilling tools is minimized and the heavy oils can thus be effectively and efficiently separated out by the shale shakers. Study results show that wrapping agent BGJ-2-4 has good wrapping capacity for the treatment of heavy oils found in the well TH12471H, and the adhesion rate on the walls of mud tanks is only 0.3%.
Researching the Borehole Instability of Upper Variegated Mudstone Strata and Optimizing Drilling Fluid in Xihu Sag
ZHANG Haishan
2024, 41(2): 205-214. doi: 10.12358/j.issn.1001-5620.2024.02.010
Abstract:
The drilling complication of trip block or backreaming difficulty is occurred frequently when the variegated mudstone stratas of Longjing Formation & Huagang Formation are drilled at Φ311.15mm interval in Xihu Sag of the East China Sea Basin. The lithological fabric characteristics, mechanical properties, physical chemistry are researched by X-ray diffraction, scan with electric mirror, Mercury intrusion porosimetry, compressive strength test. It is indicated that the variegated mudstone is an extremely instability characteristic. Experimental study about sealing wellbore capacity, wellbore stability capability, wettability and lubricity of oil-based drilling fluid on site, the main controlling factors are discovered that the drilling fluid is insufficient performances of glueing and sealing and wettability. Targeting formation characteristics and insufficient properties of drilling fluid, optimization countermeasures determined for the drilling fluid are strengthening the sealing and wall fixing properties to improve the bearing capacity of the formation, and optimizing emulsifiers to improve the high-temperature stability and wettability. Optimized oil-based drilling fluid system can effectively seal micro and nano pore cracks in mudstone, improve wellbore stability and the lubricity of mud cakes, and reduce the risk of trip block. The good application results have been achieved on stability of wellbore, smooth tripping and casing running, improvement 96%~353% tripping efficiency compared to offset wells. As a result, the problem of borehole wall instability in the upper variegated mudstone formation is solved effectively.
COMPLETION FLUID
The Experimental Methods to Evaluate the Fluids Sensitivity Damage of Ultra-deep and Ultra-tight Gas Reservoirs
ZHANG Dujie, JIN Junbin, LI Daqi, ZHANG Dong, JIN Zhongliang
2024, 41(2): 172-177. doi: 10.12358/j.issn.1001-5620.2024.02.005
Abstract:
Ultra-tight gas reservoirs are characteristic with deep buried depth, high formation temperature and strong potential fluids sensitivity damage, and the ultra-low permeability of matrix lead to the industry standard method not being applied to evaluate the formation fluids sensitivity damage. In this study, sandstone cores from ultra-tight gas layers were selected. Meanwhile, modified pressure decay method was proposed. In addition, the normal pressure decay method and modified steady-state fluid sensitivity test method were used to evaluate the water sensitive damage degree as a comparison. The results indicates that the water sensitivity damage degree obtained by the normal pressure decay method is middle to weak, the water sensitivity damage degree obtained by the modified pressure decay method is middle to strong, which is consistent with the modified steady-state fluid sensitivity test method. Moreover, the experiment time was reduced by nearly 40%. The analysis showed that the modified pressure decay method could simulate the stratum high temperature environment with the clear principle and obtained reliable result. The new method makes up for the deficiency that the normal pressure decay method cannot efficiently inject the working fluid into the core, improves the testing accuracy and shorts the experimental time, and has reference significance for the damage evaluation method of ultra-tight oil and gas reservoir.
CEMENTING FLUID
Development of An Epoxy Phosphate Retarder and A High Temperature Cement Slurry Resistant to 220 °C
LIN Xin, LIU Shuoqiong, XIA Xiujian, MENG Renzhou
2024, 41(2): 215-219. doi: 10.12358/j.issn.1001-5620.2024.02.011
Abstract:
In designing the molecular structures of cement slurry retarders, monomers with the target groups are selected to produce retarders which can control the thickening time of oil well cement slurries at stable values at temperatures above 200 °C. The molecular structure is designed on the basis of functional structure of the polymers. A high temperature penta-polymer retarder NPAAS-1 is developed based on the molecular structure design clue with five monomers, which are AMPS, SAS, NVP, AM and epoxypropyl phosphate. Characterization of the molecular structure of NPAAS-1 shows that the final product is the expected product. Weight loss on heating of NPAAS-1 at 300 °C is only 22.30%. NPASS-1 has good retarding capacity at temperatures above 200 °C, and the thickening time of the cement slurry is in a linear relationship with the concentration of NPSSA-1. A cement slurry of moderate density working normally at 220 °C was formulated with NPAAS-1 as the retarder, HTFLA-A as the filter loss reducer, HTDA-6 as the dispersant and HTSA-2 as the suspending agent. At concentration of 3.5% NPAAS-1, the thickening time of the cement slurry is 297 min; while at concentration of 4.5%, the thickening time becomes 530 min. Using this retarder NPAAS-1, the hydration speed of cement can be effectively controlled at ultra-high temperatures.
Sealing Integrity of Cement Sheath under the Condition of CO2 Corrosion–Stress Coupling
WU Zhiqiang, WU Guang’ai, XING Xuesong
2024, 41(2): 220-230. doi: 10.12358/j.issn.1001-5620.2024.02.012
Abstract:
In geologically sequestrating CO2, the reaction between the CO2 and the water in the confining rocks produces a chemical that causes the cement sheath to corrode, the coupling of the corrosion damage and the pressure (stress) inside the casing string greatly affects the seal integrity of the cement sheath. In CO2 corrosion test, the mechanical parameters of the set cement with different corrosion severities are obtained. The stress-strain behavior of the cement sheath before and after corrosion is described using the concrete damaged plasticity (CDP) constitutive model and the Mohor-Coulomb criterion. Using the ABAQUS software, a finite element analysis model for the wellbore assembly (casing-cement sheath-confining formation rocks) is established taking into account the coupling of CO2 corrosion and stress. The effects of internal pressure of the casing and corrosion time on the integrity of cement sheath are investigated. It is found that at high internal pressure of casing, the cement sheath undergoes elastic-plastic deformation, structural damage is found in the cement sheath, and micro-gaps are easy to be generated in the interfaces between the casing and the cement sheath. The coupled action of corrosion and internal pressure of casing causes the integrity of the cement sheath to fail easily. Compared with the cement sheath that undergoes no corrosion, the cement sheath with corrosion damage after being pressurized has higher radial stress, higher equivalent plastic strain, wider micro-gap and more serious tensile and compressive damages. On the other hand, the plastic radius decreases, and the corrosion time does not significantly affect the micro-gap and the tensile and compressive damage.
A Model for Predicting Wellbore Pressure during the Managed Pressure Cementing Injection Stage
LIU Jinlu, LI Jun, LI Hui, YANG Hongwei, LIU Gonghui
2024, 41(2): 231-238. doi: 10.12358/j.issn.1001-5620.2024.02.013
Abstract:
Managed pressure cementing (MPC) technology has significant advantages in dealing with cementing challenges in formations with narrow density windows, but there are fewer studies on the prediction model of wellbore pressure during the injection stage. The cement slurry injection stage, based on the process of MPC, is divided into four substages. Based on rheological theory, wellbore heat transfer theory and pressure field theory, a model coupling temperature, pressure and fluid property is established taking into account the differences in the rheology of multiple fluids during the injection stage. The model is solved using four-loop iterative method. Using the parameters from the MPC operation of well X, the model was solved, and the prediction errors are small. Analyses of the temperature field, pressure field and ECD in the annulus during MPC show that the effects of the temperature field on the backpressure at wellhead are different in different time periods; when the fluid column in the annulus is a multi-liquid column, the effects of temperature on the backpressure at wellhead are relatively small. The change of the wellbore pressure is greatly affected by the distribution of fluid position. When other conditions remain constant, increasing injection rate will increase the operating density window, while the maximum ECD in the annulus remains basically unchanged. Corresponding improvement ideas are proposed based on the results for better design of the pressure control parameters..
Controlled Release of Calcium Chloride from Compounded Waterglass-Calcium Chloride Lost Circulation Material
YIN Hui, LIU Huajie, AN Chaofeng, BU Yuhuan, GUO Shenglai, SONG Wenyu, QU Junfeng, SU Guoping
2024, 41(2): 239-245. doi: 10.12358/j.issn.1001-5620.2024.02.014
Abstract:
Waterglass-calcium chloride compound is a commonly used lost circulation material. When use this material to control mud losses, the waterglass reacts instantly with calcium chloride as soon as the two chemicals are brought together. Thus, mud loss control with waterglass-calcium chloride compound can only be performed in a complicated “two-liquids” method. To make things easy, the release of calcium chloride from the compound lost circulation material is controlled to try to pump the mixture of waterglass and calcium chloride in one operation. In this study, a resin is used to wrap calcium chloride for controlled release of calcium chloride. By changing the quantities of calcium chloride and the crosslinking agent as well as the type and ratio of the monomers, the effects of these factors on the release of calcium chloride can be understood. The study shows that when wrapping calcium chloride with the resin, if the mass ratio of calcium chloride and the monomer is 1∶4 and the concentration of the crosslinking is 6%, then the time for the waterglass-calcium chloride system to lose fluidity can be extended to 105 min. When the powdered resin wrapping up calcium chloride is rewrapped, if the mass ratio of calcium chloride and the monomer is 1∶2, and the concentrations of the crosslinking agent are both 6% in the first and secondary wrapping, the time for the waterglass-calcium chloride system to lose fluidity can then be extended to 115 min. If sodium chloride is added in the secondary wrapping, then the time for the system to lose fluidity can be extended to 180 min. Analyses with IR spectrum and SEM show that the water-absorbing resin retards the reaction between calcium chloride and waterglass by reducing the contact area between the two chemicals, while the resin itself does not participate in the reaction between waterglass and calcium chloride.
A Device for Quantitatively Evaluating the Hydration of Cement in Impacting Stability of Hydrate Layers and a Case Evaluation
MA Rui, BU Yuhuan, LU Chang, LIU Huajie, GUO Shenglai, GUO Xinyang
2024, 41(2): 246-255. doi: 10.12358/j.issn.1001-5620.2024.02.015
Abstract:
A new device is developed aimed at evaluating the effect of the hydration heat of the cement on the amount of the dissociated hydrate during well cementing operation. In developing this device, the contact manners of the cement slurries with the hydrate are fully considered. Using this device, hydrates at low temperature and high pressure can be generated, the cement slurry can be pumped under pressure into the wellbore while in contact with the hydrate layers, and the effect of the hydration heat of the cement slurry which is directly in contact with the hydrate layers on the formation temperature and pressure is directly measured. By calculating the gas saturation of hydrates and the amount of gas released from the dissociation of hydrates, a method of developing simulated hydrate formation is established taking into account the properties of the device, and a method is formulated for evaluating the effect of the hydration of cement on the stability of hydrate layers. In laboratory experiments, a simulated hydrate formation is constructed based on the geology of the shallower formations in south China Sea, three different cement slurries (a blank class G oil well cement slurry, a low-density cement slurry and a low-heat cement slurry) are pumped into the simulated hydrate formation. The experiment results show that in the setting process of the cement slurries, the quantities of the gas released from the hydrate by the heat from the hydration of the three kinds of cement are 0.7356, 0.1091 and 0.0649 mol/L, respectively. These results show that the low-heat cement slurry can greatly shorten the time required for the cement slurry to set. This study has provided a method of directly testing the effect of cement hydration on the hydrates in the shallower formations, and it also shows that low-heat cement should be used in cementing the hydrate formations in deep water drilling.
FRACTUREING FLUID & ACIDIZING FLUID
A Low Cost High Temperature Seawater-Based Guar Gum Fracturing Fluid
GONG Dajun, WU Zhiming, BAI Yan, ZHU Mingshan, WANG Xuewen, YUAN Zhe
2024, 41(2): 256-261. doi: 10.12358/j.issn.1001-5620.2024.02.016
Abstract:
In offshore fracturing operation, formulating a fracturing fluid with fresh water results in high transportation cost and long time of formulation. If seawater is used to formulate the fracturing fluid, a large amount of chelating agents which crosslink in alkaline environment shall be used, and this results in high material cost, while the ability of the fracturing fluid formulated to resist high temperature may not be satisfactory. To solve this problem, an organic titanium zirconium crosslinking agent is stepwise synthesized with reactants tetra-isopropyl titanate and zirconium sulphate etc. Characterization of the reaction product with NMR and SEM (after precipitation of the crosslinking agent) shows that the crosslinking agent is an organic chelating agent. The particle sizes of the crosslinking agent are distributed in a range of 1 nm to 100 nm, as measured with dynamic and static synchronous laser scattering instrument, and this indicates that the crosslinking agent has excellent reactivity. This crosslinking agent can crosslink in neutral conditions, a good property for formulating fracturing fluids with high salinity waters such as seawater. The microstructure of the crosslinking product is a stable honeycomb-like hexagonal grid structure. With this organic titanium-zirconium crosslinking agent, the fracturing fluids formulated have better viscoelasticity than the fracturing fluids formulated with crosslinking agents containing only titanium. The high temperature resistance of the fracturing fluids formulated using the organic titanium-zirconium crosslinking agent is 180 ℃. Field application of this new crosslinking agent in formulating a fracturing fluid with seawater for fracturing a high temperature well of CNOOC in south China Sea has obtained good results.
Preparation and properties of A Guanidine Gel Fracturing Fluid System for Wellbore Reconstruction
DAI Xiulan, WEI Jun, YAN Xiu, WANG Bing, YAN Shiting, TANG Yu
2024, 41(2): 262-269. doi: 10.12358/j.issn.1001-5620.2024.02.017
Abstract:
In reconstructing wellbores by refracturing of the reservoirs, several problems such as high cost of the fracturing fluids as well as difficulties in controlling friction and adding sands into the fracturing fluids, need to be solved. In this study a guar gum modified by graft and a multilevel chelating crosslinking agent are synthesized and are used to formulate a guar gum fracturing fluid for reconstructing wellbores through refracturing. This fracturing fluid has good swelling property, its 3 min viscosity can be as high as 87% of its maximum viscosity. The viscosifying capacity of this new guar gum is better than that of the conventional guar gum; A fracturing fluid treated with 3.8 g/L of this new guar gum has viscosity that is the same as the fracturing fluid treated with 6 g/L conventional guar gums. This new guar gum reduces the friction of fracturing fluids by at least 70% and the content of residues left in a used fracturing fluid is less than 70 mg/L. After shearing at 150 °C for 2 h, the viscosity of the fracturing fluid is 50 mPa∙s or higher. The fracturing fluid has good sand carrying capacity, almost no settling of proppants is found after 2 h of standing of the fracturing fluid. This fracturing fluid has been applied on the first well fractured with equipment and facilities that are all homemade. In the fracturing operation, the flowrate of the fracturing fluid was 16 m3/min, the highest sand/fluid ratio was 30%, and the sand used in one fracturing segment was averaged at 220 m3, solving the difficulty of adding sand into the fracturing fluid. Good application results are achieved in this operation.
Development and Corrosion Inhibition Mechanisms of a Corrosion Inhibitor for Self-Diverting Acids
CUI Bo, FENG Puyong, YAO Erdong, RONG Xinming, ZHOU Fujian
2024, 41(2): 270-278. doi: 10.12358/j.issn.1001-5620.2024.02.018
Abstract:
Self-converting acids are widely used in the acid fracturing of carbonate reservoirs. Conventional corrosion inhibitors used in self-converting acids have, because of the unique molecular structure of the viscoelastic surfactants (VES), poor compatibility with other components, thereby drastically reducing their corrosion inhibitive performance. In this study, two pyridine quaternary ammonium salt corrosion inhibitors, SI-1 and SI-2, are synthesized with 1-chloromethylnaphthalene, 4-ethyl pyridine, benzyl chloride and 2, 3-cyclopentenopyridine. Using corrosion tester and rheometer, the corrosion inhibitive performance of SI-1 and SI-2 in self-diverting acids is studied. Also studied are the effects of SI-1 and SI-2 on the viscosity of the diverting acids. Using SEM, EDS, atomic force microscope and X-ray photoelectron spectroscopy, the surface morphology and chemical components of the steel plates before and after corrosion are analyzed from a microscopic point of view. The corrosion inhibition mechanisms of SI-1 and SI-2 are investigated using molecular dynamic simulation method. The results of these studies show that the two pyridine quaternary ammonium corrosion inhibitors have good corrosion inhibitive performance in self-converting acids and they only very slightly affect the viscosity of the self-converting acids being studied. The two corrosion inhibitors have wide applicability and are cost-effective. Compared with SI-1, SI-2 is a better corrosion inhibitor. At 90 °C, the corrosion rate of the steel plates in 1% corrosion inhibitor is 1.04 g/(m2∙h), at 120 °C, the corrosion rate is 7.43 g/(m2∙h), the final viscosity of the VES residual acids is 190 mPa∙s or higher, and the operation cost can be reduced by 20%. When adding 1% corrosion inhibitor SI-1 or SI-2 into the self-convert acid, no apparent corrosion can be found on the surface of the steel plates, and the Fe content is greatly increased, indicating a significant reduction in surface roughness. When SI-2 is used, the Fe content is increased from 86% to 94%, and the Ra value reduced from 137 nm to 84 nm. In both cases, C-N and carbonyl C=O are detected on the surface of the steel plates, indicating the existence of adsorption membranes formed thereon by the corrosion inhibitors. Molecular dynamic simulation results show that SI-2 has small energy gaps and big adsorption energy, and when the SI-2 molecules are adsorbed on the surface of the metal, a dense adsorption membrane is generated, isolating the contact between the corrosion media and the surfaces of the steel, hence remarkably inhibiting the corrosion of the steel. The application of SI-2 in the Bohai oilfield and the Iraq Missan oilfield has been very successful.